Edgar Filing: HAWAIIAN ELECTRIC INDUSTRIES INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2007

¨	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, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x

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

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

APPLICABLE ONLY TO CORPORATE ISSUERS:

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


Class of Common Stock		Outstanding July 30, 2007
Hawaiian Electric Industries, Inc. (Without Par Value)		82,523,125 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 June 30, 2007

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 and six months ended June 30, 2007 and 2006	1
	Consolidated Balance Sheets (unaudited)—June 30, 2007 and December 31, 2006	2
	Consolidated Statements of Changes in Stockholders’ Equity (unaudited)—six months ended June 30, 2007 and 2006	3
	Consolidated Statements of Cash Flows (unaudited)—six months ended June 30, 2007 and 2006	4
	Notes to Consolidated Financial Statements (unaudited)	5

	Hawaiian Electric Company, Inc. and Subsidiaries
	Consolidated Statements of Income (unaudited)—three and six months ended June 30, 2007 and 2006	15
	Consolidated Balance Sheets (unaudited)—June 30, 2007 and December 31, 2006	16
	Consolidated Statements of Changes in Stockholder’s Equity (unaudited)—six months ended June 30, 2007 and 2006	17
	Consolidated Statements of Cash Flows (unaudited)—six months ended June 30, 2007 and 2006	18
	Notes to Consolidated Financial Statements (unaudited)	19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
	HEI Consolidated	39
	Electric Utilities	45
	Bank	65
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	70
Item 4.	Controls and Procedures	71

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	72
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	72
Item 4.	Submission of Matters to a Vote of Security Holders	72
Item 5.	Other Information	73
Item 6.	Exhibits	74
Signatures		75

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2007

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		Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI Properties, Inc., HEI Investments, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II (unconsolidated subsidiary), Hawaiian Electric Industries Capital Trust III (unconsolidated subsidiary) and The Old Oahu Tug Service, Inc. Former subsidiaries include HEIPC (discontinued operations, dissolved in 2006) and its dissolved 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 Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III (unconsolidated subsidiary) and Renewable Hawaii, Inc.

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., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II (unconsolidated subsidiary), Hawaiian Electric Industries Capital Trust III (unconsolidated subsidiary) and The Old Oahu Tug Service, Inc. Former subsidiaries include HEI Power Corp. (discontinued operations, dissolved in 2006).
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.
HEIPC		HEI Power Corp., a formerly wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the former parent company of numerous subsidiaries, the majority of which were dissolved or otherwise wound up since 2002, pursuant to a formal plan to exit the international power business (formerly engaged in by HEIPC and its subsidiaries) adopted by the HEI Board of Directors in October 2001. HEIPC was dissolved in December 2006.
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
IPP		Independent power producer
IRP		Integrated resource plan
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
O&M		Operation and maintenance
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
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
SOX		Sarbanes-Oxley Act of 2002
SPRBs		Special Purpose Revenue Bonds
TOOTS		The Old Oahu Tug Service, a wholly owned subsidiary of Hawaiian Electric Industries, 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 of collateral underlying loans and mortgage-related securities) 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 risks inherent in changes in the value of and market for securities available for sale and 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 American Savings Bank, F.S.B.’s (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; required corrective actions, restrictions and penalties (that may arise, for example, with respect to environmental conditions, renewable portfolio standards (RPS), capital adequacy and business practices);

•

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), continued regulatory accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force 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 rights 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 ability of consolidated HEI to generate capital gains and utilize capital loss carryforwards on future tax returns;

•

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 June 30						Six months ended June 30
	2007			2006			2007			2006
(in thousands, except per share amounts and ratio of earnings to fixed charges)
Revenues
Electric utility	$	492,712		$	503,967		$	940,390		$	979,023
Bank		107,526			102,556			211,986			202,560
Other		525			(1,554	)		2,410			(1,652	)

		600,763			604,969			1,154,786			1,179,931

Expenses
Electric utility		463,923			464,121			898,609			893,597
Bank		87,832			76,397			173,864			149,386
Other		3,699			3,722			8,463			7,068

		555,454			544,240			1,080,936			1,050,051

Operating income (loss)
Electric utility		28,789			39,846			41,781			85,426
Bank		19,694			26,159			38,122			53,174
Other		(3,174	)		(5,276	)		(6,053	)		(8,720	)

		45,309			60,729			73,850			129,880

Interest expense—other than on deposit liabilities and other bank borrowings		(19,282	)		(19,134	)		(39,793	)		(38,251	)
Allowance for borrowed funds used during construction		586			719			1,184			1,421
Preferred stock dividends of subsidiaries		(473	)		(473	)		(946	)		(946	)
Allowance for equity funds used during construction		1,202			1,588			2,434			3,136

Income from before income taxes		27,342			43,429			36,729			95,240
Income taxes		9,793			16,205			12,416			35,679

Net income	$	17,549		$	27,224		$	24,313		$	59,561

Basic earnings per common share	$	0.21		$	0.34		$	0.30		$	0.73

Diluted earnings per common share	$	0.21		$	0.33		$	0.30		$	0.73

Dividends per common share	$	0.31		$	0.31		$	0.62		$	0.62

Weighted-average number of common shares outstanding		81,907			81,100			81,679			81,041
Dilutive effect of stock options and dividend equivalents		217			332			227			319

Adjusted weighted-average shares		82,124			81,432			81,906			81,360

Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits								1.44			2.21

Including interest on ASB deposits								1.29			1.85

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(dollars in thousands)	June 30, 2007			December 31, 2006
Assets
Cash and equivalents	$	152,163		$	177,630
Federal funds sold		75,144			79,671
Accounts receivable and unbilled revenues, net		250,990			248,639
Available-for-sale investment and mortgage-related securities		2,301,360			2,367,427
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,887,739			3,780,461
Property, plant and equipment, net of accumulated depreciation of $1,705,833 and $1,651,088		2,656,139			2,647,490
Regulatory assets		132,605			112,349
Other		316,522			292,638
Goodwill and other intangibles, net		87,130			87,140

	$	9,957,556		$	9,891,209

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	171,941		$	165,505
Deposit liabilities		4,432,341			4,575,548
Short-term borrowings—other than bank		125,465			176,272
Other bank borrowings		1,718,027			1,568,585
Long-term debt, net—other than bank		1,230,824			1,133,185
Deferred income taxes		83,430			106,780
Regulatory liabilities		251,198			240,619
Contributions in aid of construction		281,944			276,728
Other		519,695			518,454

		8,814,865			8,761,676

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: 82,391,429 shares and 81,461,409 shares		1,048,562			1,028,101
Retained earnings		216,063			242,667
Accumulated other comprehensive loss, net of tax benefits		(156,227	)		(175,528	)

		1,108,398			1,095,240

	$	9,957,556		$	9,891,209

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)


	Common stock			Retained earnings			Accumulated other comprehensive loss			Total
(in thousands, except per share amounts)	Shares	Amount		Retained earnings			Accumulated other comprehensive loss			Total
Balance, December 31, 2006	81,461	$	1,028,101	$	242,667		$	(175,528	)	$	1,095,240
Comprehensive income:
Net income	—		—		24,313			—			24,313
Net unrealized losses on securities arising during the period, net of tax benefits of $1,989	—		—		—			(3,012	)		(3,012	)
Defined benefit retirement plans—amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of taxes of $2,622	—		—		—			4,108			4,108

Comprehensive income	—		—		24,313			1,096			25,409

Adjustment to initially apply a PUC D&O related to defined benefit retirement plans, net of taxes of $11,595	—		—		—			18,205			18,205
Adjustment to initially apply FIN 48	—		—		(228	)		—			(228	)
Issuance of common stock, net	930		20,461		—			—			20,461
Common stock dividends ($0.62 per share)	—		—		(50,689	)		—			(50,689	)

Balance, June 30, 2007	82,391	$	1,048,562	$	216,063		$	(156,227	)	$	1,108,398

Balance, December 31, 2005	80,983	$	1,018,966	$	235,394		$	(37,730	)	$	1,216,630
Comprehensive income:
Net income	—		—		59,561			—			59,561
Net unrealized losses on securities arising during the period, net of tax benefits of $16,697	—		—		—			(25,290	)		(25,290	)
Minimum pension liability adjustment, net of tax benefits of $30	—		—		—			(48	)		(48	)

Comprehensive income (loss)	—		—		59,561			(25,338	)		34,223

Issuance of common stock, net	292		4,598		—			—			4,598
Common stock dividends ($0.62 per share)	—		—		(50,310	)		—			(50,310	)

Balance, June 30, 2006	81,275	$	1,023,564	$	244,645		$	(63,068	)	$	1,205,141

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Six months ended June 30	2007			2006
(in thousands)
Cash flows from operating activities
Net income	$	24,313		$	59,561
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		74,057			70,574
Other amortization		4,576			4,211
Writedown of utility plant		11,701			—
Provision for loan losses		1,200			—
Deferred income taxes		(12,120	)		(7,498	)
Allowance for equity funds used during construction		(2,434	)		(3,136	)
Excess tax benefits from share-based payment arrangements		(259	)		(567	)
Loans receivable originated and purchased, held for sale		(19,174	)		(11,257	)
Proceeds from sale of loans receivable, held for sale		27,439			23,750
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease (increase) in accounts receivable and unbilled revenues, net		(2,351	)		1,656
Increase in fuel oil stock		(24,148	)		(28,024	)
Decrease in federal tax deposit		—			30,000
Increase in accounts payable		6,436			4,905
Decrease in taxes accrued		(7,136	)		(489	)
Changes in other assets and liabilities		(2,685	)		4,003

Net cash provided by operating activities		79,415			147,689

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(199,315	)		(175,000	)
Principal repayments on available-for-sale investment and mortgage-related securities		258,625			254,109
Net increase in loans held for investment		(114,094	)		(159,096	)
Net proceeds from sale of investments		8,775			—
Capital expenditures		(79,886	)		(97,691	)
Contributions in aid of construction		7,576			10,622
Other		458			1,436

Net cash used in investing activities		(117,861	)		(165,620	)

Cash flows from financing activities
Net decrease in deposit liabilities		(143,207	)		(10,564	)
Net increase (decrease) in short-term borrowings with original maturities of three months or less		(50,807	)		109,845
Proceeds from short-term borrowings with original maturities of greater than three months		—			44,890
Net increase in retail repurchase agreements		35,199			21,650
Proceeds from other bank borrowings		550,897			635,840
Repayments of other bank borrowings		(436,385	)		(608,595	)
Proceeds from issuance of long-term debt		221,327			—
Repayment of long-term debt		(126,000	)		(110,000	)
Excess tax benefits from share-based payment arrangements		259			567
Net proceeds from issuance of common stock		8,341			2,481
Common stock dividends		(40,480	)		(50,282	)
Decrease in cash overdraft		(9,098	)		(6,786	)
Other		(1,594	)		(842	)

Net cash provided by financing activities		8,452			28,204

Cash flows from discontinued operations-net cash provided by operating activities		—			6,846

Net increase (decrease) in cash and equivalents and federal funds sold		(29,994	)		17,119
Cash and equivalents and federal funds sold, beginning of period		257,301			208,947

Cash and equivalents and federal funds sold, end of period	$	227,307		$	226,066

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, 2006 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 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 June 30, 2007 and December 31, 2006 and the results of its operations for the three and six months ended June 30, 2007 and 2006 and its cash flows for the six months ended June 30, 2007 and 2006. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10–Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

(2)

Segment financial information


(in thousands)	Electric Utility		Bank		Other			Total
Three months ended June 30, 2007
Revenues from external customers	$	492,651	$	107,526	$	586		$	600,763
Intersegment revenues (eliminations)		61		—		(61	)		—

Revenues		492,712		107,526		525			600,763

Profit (loss)*		17,168		19,746		(9,572	)		27,342
Income taxes (benefit)		6,518		7,164		(3,889	)		9,793

Net income (loss)		10,650		12,582		(5,683	)		17,549

Six months ended June 30, 2007
Revenues from external customers		940,259		211,986		2,541			1,154,786
Intersegment revenues (eliminations)		131		—		(131	)		—

Revenues		940,390		211,986		2,410			1,154,786

Profit (loss)*		17,308		38,145		(18,724	)		36,729
Income taxes (benefit)		6,205		13,967		(7,756	)		12,416

Net income (loss)		11,103		24,178		(10,968	)		24,313

Assets (at June 30, 2007)	$	3,128,278	$	6,817,246	$	12,032		$	9,957,556

Three months ended June 30, 2006
Revenues from external customers	$	503,897	$	102,556	$	(1,484	)	$	604,969
Intersegment revenues (eliminations)		70		—		(70	)		—

Revenues		503,967		102,556		(1,554	)		604,969

Profit (loss)*		28,109		26,159		(10,839	)		43,429
Income taxes (benefit)		10,823		9,941		(4,559	)		16,205

Net income (loss)		17,286		16,218		(6,280	)		27,224

Six months ended June 30, 2006
Revenues from external customers		978,883		202,560		(1,512	)		1,179,931
Intersegment revenues (eliminations)		140		—		(140	)		—

Revenues		979,023		202,560		(1,652	)		1,179,931

Profit (loss)*		62,206		53,174		(20,140	)		95,240
Income taxes (benefit)		23,932		20,129		(8,382	)		35,679

Net income (loss)		38,274		33,045		(11,758	)		59,561

Assets (at June 30, 2006, including net assets of discontinued operations)	$	3,139,155	$	6,866,794	$	14,779		$	10,020,728

*	Income (loss) before income taxes.

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

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

(3)

Electric utility subsidiary

For HECO’s consolidated financial information, including its commitments and contingencies, see pages 15 through 38.

(4)

Bank subsidiary

Selected financial information

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

Consolidated Statements of Income Data (unaudited)


	Three months ended June 30				Six months ended June 30
	2007		2006		2007		2006
(in thousands)
Interest and dividend income
Interest and fees on loans	$	60,093	$	57,323	$	120,374	$	112,476
Interest and dividends on investment and mortgage-related securities		30,428		30,870		58,593		60,947

		90,521		88,193		178,967		173,423

Interest expense
Interest on deposit liabilities		20,832		17,001		41,570		32,394
Interest on other borrowings		18,581		18,308		36,987		35,470

		39,413		35,309		78,557		67,864

Net interest income		51,108		52,884		100,410		105,559
Provision for loan losses		1,200		—		1,200		—

Net interest income after provision for loan losses		49,908		52,884		99,210		105,559

Noninterest income
Fees from other financial services		6,885		6,742		13,386		13,182
Fee income on deposit liabilities		6,457		4,376		12,512		8,565
Fee income on other financial products		1,856		2,132		3,868		4,569
Other income		1,807		1,113		3,253		2,821

		17,005		14,363		33,019		29,137

Noninterest expense
Compensation and employee benefits		18,164		17,476		36,560		35,313
Occupancy		5,341		4,490		10,289		8,953
Equipment		3,785		3,636		7,263		7,132
Services		7,895		4,124		16,253		7,841
Data processing		2,646		2,547		5,203		5,007
Other expense		9,336		8,815		18,516		17,276

		47,167		41,088		94,084		81,522

Income before income taxes		19,746		26,159		38,145		53,174
Income taxes		7,164		9,941		13,967		20,129

Net income	$	12,582	$	16,218	$	24,178	$	33,045

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

Consolidated Balance Sheet Data (unaudited)


(in thousands)	June 30, 2007			December 31, 2006
Assets
Cash and equivalents	$	146,012		$	172,370
Federal funds sold		75,144			79,671
Available-for-sale investment and mortgage-related securities		2,301,360			2,367,427
Investment in stock of Federal Home Loan Bank of Seattle, at cost		97,764			97,764
Loans receivable, net		3,887,739			3,780,461
Other		223,072			223,666
Goodwill and other intangibles, net		86,155			87,140

	$	6,817,246		$	6,808,499

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	649,455		$	648,915
Deposit liabilities–interest-bearing		3,782,886			3,926,633
Other borrowings		1,718,027			1,568,585
Other		105,226			104,470

		6,255,594			6,248,603

Common stock		324,634			323,154
Retained earnings		283,094			280,046
Accumulated other comprehensive loss, net of tax benefits		(46,076	)		(43,304	)

		561,652			559,896

	$	6,817,246		$	6,808,499

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $971 million and $747 million, respectively, as of June 30, 2007 and $730 million and $839 million, respectively, as of December 31, 2006.

As of June 30, 2007, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 billion.

(5)

Retirement benefits

For the first six months of 2007, HECO contributed $4.2 million, ASB contributed $0.9 million and HEI contributed less than $0.1 million to their respective retirement benefit plans, compared to $5.1 million, $1.5 million and $0.1 million, respectively, in the first six months of 2006. The Company’s current estimate of contributions to its retirement benefit plans in 2007 is $13.1 million (including $12.1 million by HECO, $0.9 million by ASB and $0.1 million by HEI), compared to contributions of $12.9 million in 2006. In addition, the Company expects to pay directly $1.7 million of benefits in 2007, compared to $1.2 million paid in 2006.

The components of net periodic benefit cost were as follows:


	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
	2007			2006			2007			2006			2007			2006			2007			2006
(in thousands)
Service cost	$	7,751		$	8,236		$	1,209		$	1,278		$	15,504		$	16,327		$	2,440		$	2,549
Interest cost		14,444			13,645			2,774			2,578			28,864			27,121			5,634			5,310
Expected return on plan assets		(17,098	)		(18,089	)		(2,404	)		(2,493	)		(34,200	)		(35,842	)		(4,702	)		(4,959	)
Amortization of unrecognized transition obligation		1			1			784			785			2			2			1,569			1,569
Amortization of prior service cost (gain)		(49	)		14			4			4			(98	)		(142	)		7			7
Recognized actuarial loss (gain)		2,835			2,917			—			(18	)		5,690			6,028			—			206

Net periodic benefit cost	$	7,884		$	6,724		$	2,367		$	2,134		$	15,762		$	13,494		$	4,948		$	4,682

The Company recorded retirement benefits expense of $17 million and $14 million in the first six months of 2007 and 2006, respectively. The electric utilities charged a portion of the net periodic benefit costs to plant. Also, in an

interim order issued in April 2007, the amount of HELCO’s net periodic benefit costs to be recovered in rates was established. Thus, any costs determined under SFAS No. 87, as amended, that are over/under this amount are charged/credited to a regulatory asset. Further, under the interim order, a regulatory asset (representing HELCO’s 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. Retirement benefits expense for HELCO for the second quarter of 2007 was $1.3 million, but would have been $0.9 million if the pension and postretirement benefits other than pensions (OPEB) tracking mechanisms had not been adopted in the April 2007 interim order issued in HELCO’s 2006 test year rate case.

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

(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 (4,798,822 shares available for issuance under outstanding and future grants and awards as of June 30, 2007) 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 June 30,		Six months ended June 30,
($ in millions)	2007	2006	2007	2006
Share-based compensation expense ¹	0.4	0.3	0.7	0.9
Income tax benefit	0.1	0.3	0.2	0.5

¹	The Company has not capitalized any share-based compensation cost. For all share-based compensation, the estimated forfeiture rate is 1.3%.

Nonqualified stock options

Information about HEI’s NQSOs is summarized as follows:


June 30, 2007			Outstanding & Exercisable
Year of grant	Range of exercise prices		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price
1998	$	20.50	6,000	0.8	$	20.50
1999		17.61 -17.63	48,300	2.0		17.62
2000		14.74	52,000	2.8		14.74
2001		17.96	83,000	3.8		17.96
2002		21.68	134,000	4.6		21.68
2003		20.49	280,500	5.7		20.49

	$	14.74 -21.68	603,800	4.6	$	19.68

As of December 31, 2006, NQSOs outstanding totaled 660,000, with a weighted-average exercise price of $19.68. As of June 30, 2007, all NQSO shares outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $4.7 million.

NQSO activity and statistics are summarized as follows:


	Three months ended June 30,				Six months ended June 30,
	2007		2006		2007		2006
($ in thousands, except prices)
Shares granted		—		—		—		—
Shares forfeited		—		—		—		—
Shares expired		—		—		—		—
Shares vested		77,500		197,500		79,000		197,500
Aggregate fair value of vested shares	$	343	$	911	$	350	$	911
Shares exercised		36,700		110,500		56,200		116,500
Weighted-average exercise price	$	18.77	$	21.52	$	19.70	$	21.30
Cash received from exercise	$	689	$	2,378	$	1,107	$	2,482
Intrinsic value of shares exercised ¹	$	433	$	1,064	$	575	$	1,174
Tax benefit realized for the deduction of exercises	$	169	$	414	$	224	$	457
Dividend equivalent shares distributed under Section 409A		—		2,904		21,892		43,213
Weighted-average Section 409A distribution price		—	$	26.68	$	26.15	$	26.27
Intrinsic value of shares distributed under Section 409A		—	$	77	$	572	$	1,135
Tax benefit realized for Section 409A distributions		—	$	30	$	223	$	442

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 June 30, 2007, all NQSOs were vested.

Stock appreciation rights

Information about HEI’s SARs is summarized as follows:


June 30, 2007			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	4.6	$	26.02	280,000	4.3	$	26.02
2005		26.18	550,000	6.0		26.18	166,000	1.9		26.18

	$	26.02 – 26.18	875,000	5.5	$	26.12	446,000	3.4	$	26.08

As of December 31, 2006, the shares underlying SARs outstanding totaled 879,000, with a weighted-average exercise price of $26.12. As of June 30, 2007, the SARs outstanding and the SARs exercisable (including dividend equivalents) had no intrinsic value.

SARs activity and statistics are summarized as follows:


	Three months ended June 30,				Six months ended June 30,
	2007		2006		2007		2006
($ in thousands, except prices)
Shares granted		—		—		—		—
Shares forfeited		—		—		—		—
Shares expired		—		—		—		—
Shares vested		45,000		313,750		51,000		313,750
Aggregate fair value of vested shares	$	234	$	1,749	$	269	$	1,749
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		—		7,333		23,760		28,505
Weighted-average Section 409A distribution price		—	$	26.71	$	26.15	$	26.36
Intrinsic value of shares distributed under Section 409A		—	$	196	$	621	$	751
Tax benefit realized for Section 409A distributions		—	$	76	$	242	$	292

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 June 30, 2007, there was $0.8 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 1.7 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 six months ended June 30, 2007 and 2006, a total of 45,652 and 71,719 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, 2006, restricted stock shares outstanding totaled 91,800, with a weighted-average grant date fair value of $25.68. As of June 30, 2007, restricted stock shares outstanding totaled 142,200, with a weighted-average grant date fair value of $26.16. The grant date fair value of a grant of a restricted stock share is the closing price of HEI common stock on the date of grant.

During the first six months of 2007, 16,000 restricted stock shares vested, no restricted stock shares were forfeited, and 66,400 shares of restricted stock with a grant date fair market value of $1.7 million were granted. During the second quarter of 2007, 16,000 restricted stock shares vested and 57,700 shares of restricted stock with a grant date fair market value of $1.5 million were granted. For the quarter and six months ended June 30, 2006, no restricted stock shares vested or were forfeited and 60,800 shares with a grant date fair market value of $1.6 million were granted. The tax benefit realized for the tax deductions from restricted stock was $0.2 million for the first six months of 2007 and not significant for the first six months of 2006.

As of June 30, 2007, there was $2.9 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a weighted-average period of 3.3 years.

(7)

Commitments and contingencies

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

(8)

Cash flows

Supplemental disclosures of cash flow information

For the six months ended June 30, 2007 and 2006, the Company paid interest to non-affiliates amounting to $110 million and $95 million, respectively.

For the six months ended June 30, 2007 and 2006, the Company paid income taxes amounting to $3 million and $4 million, respectively.

Supplemental disclosures of noncash activities

Noncash increases in common stock for director and officer compensatory plans of the Company were $1.7 million and $1.5 million for the six months ended June 30, 2007 and 2006, 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 $10.2 million and nil for the six months ended June 30, 2007 and 2006, respectively. From March 23, 2004 to March 5, 2007, HEI satisfied the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the issuance of additional shares. On March 6, 2007, it began satisfying those requirements by the issuance of additional shares.

(9)

Recent accounting pronouncements and interpretations

Fair value measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies to fair value measurements that are already required or permitted under existing accounting pronouncements with some exceptions. SFAS No. 157 retains the exchange price notion in defining fair value and clarifies that the exchange price is the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability. It emphasizes that fair value is a market-based, not an entity-specific, measurement based upon the assumptions that market participants would use in pricing an asset or liability. As a basis for considering assumptions in fair value measurements, SFAS No. 157 establishes a hierarchy that gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). SFAS No. 157 expands disclosures about the use of fair value, including disclosure of the level within the hierarchy in which the fair value measurements fall and the effect of the measurements on earnings (or changes in net assets) for the period. SFAS No. 157 must be adopted by the first quarter of the fiscal year beginning after November 15, 2007. The Company plans to adopt SFAS No. 157 on January 1, 2008. Management has not yet determined what impact, if any, the adoption of SFAS No. 157 will have on the Company’s financial statements.

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. SFAS No. 159 must be adopted by January 1, 2008. The Company plans to adopt SFAS No. 159 on January 1, 2008. Management has not yet determined what impact, if any, the adoption of SFAS No. 159 will have on the Company’s financial statements.

Income Tax Benefits of Dividends on Share-Based Payment Awards

In June 2007, the FASB ratified the EITF consensus reached on EITF Issue No. 06-11, "Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards." The consensus applies to share-based payment arrangements in which the employee receives dividends on the award during the vesting period, the dividend payment results in a tax deduction, and the employer thereby realizes a tax benefit during the vesting period (e.g., restricted stock awards issued by the Company). Under SFAS No. 123R, dividends paid during the vesting period on share-based payments that are expected to vest are charged to retained earnings because the compensation cost

already reflects the expected value of those dividends, which are included in the grant date fair value of the award, but dividends on awards that do not vest are recognized as additional compensation cost. The consensus requires the tax benefit received on dividends associated with share-based awards that are charged to retained earnings to be recorded in additional paid-in capital and included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. A tax benefit recognized from a dividend on an award that is subsequently forfeited or is no longer expected to vest (and that is therefore reclassified as additional compensation expense) would be reclassified to the income statement if sufficient excess tax benefits are available in the pool of excess tax benefits in additional paid-in capital on the date of the reclassification. The consensus is effective for the tax benefits of dividends declared in fiscal years beginning after December 15, 2007. The Company will adopt this consensus on January 1, 2008 and the adoption is not expected to have an impact on the Company’s financial statements.

(10)

Income taxes

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” which prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate resolution with tax authorities) for the financial statement recognition and measurement of an income tax position taken or expected to be taken in a tax return. The Company adopted FIN 48 in the first quarter of 2007. The impact to the Company was a reclassification of certain deferred tax liabilities to a liability for tax uncertainties and a charge of $0.2 million to retained earnings as of January 1, 2007 for the cumulative effect of adoption of FIN 48.

In general, prior to January 1, 2007, the Company (except for ASB) recorded known interest and penalties on income taxes in “Interest expense – other than bank” (in “Interest and other charges” in HECO’s consolidated statements of income) and ASB recorded known interest and penalties on income taxes in “Expenses—Bank” (in “Other expense” in ASB’s consolidated statements of income). Since the adoption of FIN 48, the electric utilities and ASB record all (potential and known) interest and penalties on income taxes in “Interest and other charges” and “Other expense,” respectively, but the Company records such amounts in “Interest expense – other than on deposit liabilities and other bank borrowings.” For the first six months of 2006, interest accrued on income taxes was insignificant. For the first six months of 2007, $0.4 million of interest on income taxes was reflected in “Interest expense – other than on deposit liabilities and bank borrowings.”

As of January 1, 2007, the total amount of accrued interest and penalties related to uncertain tax positions and recognized on the balance sheet was $2.0 million.

As of January 1, 2007, the total amount of unrecognized tax benefits was $11 million, and of this amount, $0.6 million, if recognized, would affect the Company’s effective tax rate. Management concluded that it is reasonably possible that the unrecognized tax benefits will significantly decrease within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service. Management cannot estimate the range of the reasonably possible change.

Tax years 2003 to 2006 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii. HEIII, which owns leveraged lease investments in other states, is also subject to examination by those state tax authorities for tax years 2003 to 2006.

The Company’s effective tax rate for the first six months of 2007 was 34%, compared to an effective tax rate for the first six months of 2006 of 37%. The lower effective tax rate was primarily due to the impact of state tax credits (including the acceleration of the state tax credits associated with the write-off of a portion of CT-4 and CT-5 costs) recognized against a smaller income tax expense base.

(11)

Sale of shares in Hoku Scientific, Inc.

HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a materials science company focused on clean energy technologies. Shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005 and since then HEIPI had classified its Hoku shares as trading securities, carried at fair value with changes in fair value recorded in earnings. HEIPI began selling Hoku stock in February 2006 when HEIPI’s lock-up agreement expired. In the first six months of 2006, HEIPI recognized a $1.6 million loss (unrealized and realized, net of taxes) on its Hoku shares. As of December 31, 2006, HEIPI had carried its remaining investment in Hoku shares at $1.2 million. In January 2007, HEIPI sold its remaining Hoku shares for a net after-tax gain of $0.9 million.

(12)

Credit agreement

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. Any draws on the facility bear interest, at the option of HEI, at either the “Adjusted LIBO Rate” plus 50 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. The annual fee is 10 basis points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Senior Debt Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2.5 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1) would result in a commitment fee decrease of 2 basis points and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions which must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratio, as defined in the agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 27% as of June 30, 2007, as calculated under the agreement) and “Consolidated Net Worth” of $850 million (Net Worth of $1.3 billion as of June 30, 2007, as calculated under the agreement), if there is a “Change in Control” of HEI, if any event or condition occurs that results in any “Material Indebtedness” of HEI being subject to acceleration prior to its scheduled maturity, if any “Material Subsidiary Indebtedness” actually becomes due prior to its scheduled maturity, or if ASB fails to remain well capitalized and to maintain specified minimum capital ratios. HEI’s syndicated credit facility is maintained to support the issuance of commercial paper, but may also be drawn to make investments in and advances to its subsidiaries, and for the Company’s working capital and general corporate purposes. As of August 1, 2007, the $100 million credit facility remained undrawn.

See Note 10 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of HECO’s credit facility.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)


	Three months ended June 30						Six months ended June 30
	2007			2006			2007			2006
(in thousands, except for ratio of earnings to fixed charges)
Operating revenues	$	491,249		$	503,350		$	938,046		$	977,321

Operating expenses
Fuel oil		167,121			192,314			327,050			367,652
Purchased power		133,727			122,438			245,243			240,158
Other operation		53,643			47,934			100,836			89,953
Maintenance		29,869			22,382			57,205			39,434
Depreciation		34,272			32,542			68,539			65,075
Taxes, other than income taxes		44,903			46,218			87,450			90,741
Income taxes		6,492			11,020			10,998			24,244

		470,027			474,848			897,321			917,257

Operating income		21,222			28,502			40,725			60,064

Other income
Allowance for equity funds used during construction		1,202			1,588			2,434			3,136
Other, net		1,049			521			(5,149	)		1,430

		2,251			2,109			(2,715	)		4,566

Income before interest and other charges		23,473			30,611			38,010			64,630

Interest and other charges
Interest on long-term debt		11,390			10,776			22,886			21,554
Amortization of net bond premium and expense		646			543			1,192			1,086
Other interest charges		874			2,226			3,015			4,139
Allowance for borrowed funds used during construction		(586	)		(719	)		(1,184	)		(1,421	)
Preferred stock dividends of subsidiaries		229			229			458			458

		12,553			13,055			26,367			25,816

Income before preferred stock dividends of HECO		10,920			17,556			11,643			38,814
Preferred stock dividends of HECO		270			270			540			540

Net income for common stock	$	10,650		$	17,286		$	11,103		$	38,274

Ratio of earnings to fixed charges (SEC method)								1.58			3.16

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)


(in thousands, except par value)	June 30, 2007			December 31, 2006
Assets
Utility plant, at cost
Land	$	35,223		$	35,242
Plant and equipment		4,054,001			4,002,929
Less accumulated depreciation		(1,608,646	)		(1,558,913	)
Plant acquisition adjustment, net		67			93
Construction in progress		106,605			95,619

Net utility plant		2,587,250			2,574,970

Current assets
Cash and equivalents		4,861			3,859
Customer accounts receivable, net		132,737			125,524
Accrued unbilled revenues, net		83,198			92,195
Other accounts receivable, net		5,693			4,423
Fuel oil stock, at average cost		88,460			64,312
Materials and supplies, at average cost		33,594			30,540
Other		8,805			9,695

Total current assets		357,348			330,548

Other long-term assets
Regulatory assets		132,605			112,349
Unamortized debt expense		16,037			13,722
Other		35,038			31,545

Total other long-term assets		183,680			157,616

	$	3,128,278		$	3,063,134

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		710,735			700,252
Accumulated other comprehensive loss, net of income tax benefits		(104,776	)		(126,650	)

Common stock equity		990,560			958,203
Cumulative preferred stock – not subject to mandatory redemption		34,293			34,293
Long-term debt, net		863,824			766,185

Total capitalization		1,888,677			1,758,681

Current liabilities
Short-term borrowings–nonaffiliates		52,626			113,107
Accounts payable		102,379			102,512
Interest and preferred dividends payable		13,949			10,645
Taxes accrued		137,436			152,182
Other		34,877			43,120

Total current liabilities		341,267			421,566

Deferred credits and other liabilities
Deferred income taxes		103,359			118,055
Regulatory liabilities		251,198			240,619
Unamortized tax credits		57,854			57,879
Other		203,979			189,606

Total deferred credits and other liabilities		616,390			606,159

Contributions in aid of construction		281,944			276,728

	$	3,128,278		$	3,063,134

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 stock		Retained earnings			Accumulated other comprehensive loss			Total
(in thousands, except per share amounts)	Shares	Amount		Premium on capital stock		Retained earnings			Accumulated other comprehensive loss			Total
Balance, December 31, 2006	12,806	$	85,387	$	299,214	$	700,252		$	(126,650	)	$	958,203
Comprehensive income:
Net income	—		—		—		11,103			—			11,103
Defined benefit retirement plans – amortization of net loss, prior service cost and transition obligation included periodic benefit cost, net of taxes of $2,337	—		—		—		—			3,669			3,669

Comprehensive income	—		—		—		11,103			3,669			14,772

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

Balance, June 30, 2007	12,806	$	85,387	$	299,214	$	710,735		$	(104,776	)	$	990,560

Balance, December 31, 2005	12,806	$	85,387	$	299,214	$	654,686		$	(28	)	$	1,039,259
Net income	—		—		—		38,274			—			38,274
Common stock dividends	—		—		—		(29,381	)		—			(29,381	)

Balance, June 30, 2006	12,806	$	85,387	$	299,214	$	663,579		$	(28	)	$	1,048,152

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)


Six months ended June 30	2007			2006
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	11,643		$	38,814
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Depreciation of property, plant and equipment		68,539			65,075
Other amortization		3,836			3,801
Writedown of utility plant		11,701			—
Deferred income taxes		(12,484	)		(6,912	)
Tax credits, net		1,116			2,459
Allowance for equity funds used during construction		(2,434	)		(3,136	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		(8,483	)		6,404
Decrease in accrued unbilled revenues		8,997			2,966
Increase in fuel oil stock		(24,148	)		(28,024	)
Increase in materials and supplies		(3,054	)		(3,150	)
Increase in regulatory assets		(1,628	)		(1,587	)
Decrease in accounts payable		(133	)		(206	)
Increase (decrease) in taxes accrued		(14,746	)		9,723
Changes in other assets and liabilities		7,262			6,979

Net cash provided by operating activities		45,984			93,206

Cash flows from investing activities
Capital expenditures		(77,769	)		(91,394	)
Contributions in aid of construction		7,577			10,622
Other		—			193

Net cash used in investing activities		(70,192	)		(80,579	)

Cash flows from financing activities
Common stock dividends		—			(29,381	)
Preferred stock dividends		(540	)		(540	)
Proceeds from issuance of long-term debt		221,327			—
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		(60,481	)		27,311
Decrease in cash overdraft		(9,096	)		(6,786	)

Net cash provided by (used in) financing activities		25,210			(9,396	)

Net increase in cash and equivalents		1,002			3,231
Cash and equivalents, beginning of period		3,859			143

Cash and equivalents, end of period	$	4,861		$	3,374

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, 2006 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 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 June 30, 2007 and December 31, 2006 and the results of their operations for the three and six months ended June 30, 2007 and 2006 and their cash flows for the six months ended June 30, 2007 and 2006. 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 June 30, 2007 and December 31, 2006 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for six months ended June 30, 2007 and 2006 each consisted of $1.7 million of interest income received from the 2004 Debentures; $1.6 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or

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

Purchase power agreements

As of June 30, 2007, 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 six months ended June 30, 2007 totaled $245 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $71 million, $82 million, $32 million and $18 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 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, HECO has continued after 2004 its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006 and 2007, HECO and its subsidiaries again 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 again declined to provide the necessary information, except that Kalaeloa (see below) and Kaheawa Wind Power, LLC (KWP) have now provided their information. Management has concluded that MECO does not have to consolidate KWP (which began selling power to MECO in June 2006 from its 30 MW windfarm) as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.

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 is a Delaware limited partnership formed on October 13, 1988 for the purpose of designing, constructing, owning and operating a 200 MW cogeneration facility on Oahu, which includes two 75 MW oil-fired combustion turbines, two waste heat recovery steam generators, a 50 MW turbine generator and other electrical, mechanical and control equipment. The two combustion turbines were upgraded during 2004 resulting in an increase in the facility’s nominal output rating to approximately 220 MW. Kalaeloa has a PPA with HECO (described above) and a steam delivery contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978 (PURPA).

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.

Apollo Energy Corporation. In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total allowed capacity of 20.5 MW. In December 2005, Apollo assigned the PPA to a subsidiary, which voluntarily, unilaterally and irrevocably waived and relinquished its right and benefit under the PPA to collect the floor rate for the entire term of the PPA. The 20.5 MW facility began commercial operations in April 2007. Based on information available, management concluded that HELCO does not have to consolidate Apollo as HELCO does not have a variable interest in Apollo because the PPA does not require HELCO to absorb any variability of Apollo.

(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 six months ended June 30, 2007 and 2006, HECO and its subsidiaries included approximately $83 million and $87 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4)

Retirement benefits

For the first six months of 2007, HECO and its subsidiaries contributed $4.2 million to their retirement benefit plans, compared to $5.1 million in the first six months of 2006. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2007 is $12.1 million, compared to contributions of $9.8 million in 2006. In addition, HECO and its subsidiaries expect to pay directly $0.5 million of benefits in 2007, compared to $0.6 million paid in 2006.

The components of net periodic benefit cost were as follows:


	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
	2007			2006			2007			2006			2007			2006			2007			2006
(in thousands)
Service cost	$	6,360		$	6,819		$	1,179		$	1,247		$	12,691		$	13,359		$	2,379		$	2,482
Interest cost		12,864			12,135			2,696			2,510			25,686			24,174			5,483			5,169
Expected return on plan assets		(15,254	)		(16,301	)		(2,364	)		(2,452	)		(30,478	)		(32,233	)		(4,621	)		(4,879	)
Amortization of unrecognized transition obligation		1			—			783			783			1			1			1,565			1,565
Amortization of prior service gain		(191	)		(192	)		—			—			(381	)		(385	)		—			—
Recognized actuarial loss (gain)		2,620			2,635			—			(19	)		5,236			5,349			—			194

Net periodic benefit cost	$	6,400		$	5,096		$	2,294		$	2,069		$	12,755		$	10,265		$	4,806		$	4,531

HECO and its subsidiaries recorded retirement benefits expense of $14 million and $11 million in the first six months of 2007 and 2006, respectively. The electric utilities charged a portion of the net periodic benefit costs to plant. Also, in an interim order issued in April 2007 (discussed below), the amount of HELCO’s net periodic benefit costs to be recovered in rates was established. Thus, any costs determined under SFAS No. 87, as amended, that are over/under this amount are charged/credited to a regulatory asset. Further, under the interim order, a regulatory asset (representing HELCO’s 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.

In an April 4, 2007 interim Decision and Order (D&O) in HELCO’s 2006 test year rate case, the PUC approved on an interim basis the adoption of a pension tracking mechanism proposed by the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate). The mechanism is intended to smooth the impact to ratepayers of potential fluctuations in pension costs, and generally would require HELCO to make contributions to the pension trust in the amount of the actuarially calculated net periodic pension cost that would be allowed without penalty by the tax laws. A similar tracking mechanism for postretirement benefits other than pensions was also approved on an interim basis. As a result of these approvals, which are subject to the PUC’s final D&O, HELCO reclassified, beginning April 5, 2007, to a regulatory asset the charge for retirement benefits that would otherwise be recorded in accumulated other comprehensive income (pursuant to SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”). Retirement benefits expense for HELCO for the second quarter of 2007 was $1.3 million, but would have been $0.9 million if the pension and OPEB tracking mechanisms had not been adopted.

(5)

Commitments and contingencies

Interim increases

On September 27, 2005, the PUC issued an Interim D&O in HECO’s 2005 test year rate case granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges), which was implemented on September 28, 2005.

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.

As of June 30, 2007, HECO and its subsidiaries had recognized $110 million of revenues with respect to interim orders ($14 million related to interim orders regarding certain integrated resource planning costs and $96 million related to interim orders with respect to HECO’s and HELCO’s general rate increase requests based on a 2005 and 2006 test year, respectively, and HECO's interim surcharge to recover DG fuel and fuel trucking costs), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

Energy cost adjustment clauses

On June 19, 2006, the PUC issued an order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has 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 reviewed the automatic fuel rate adjustment clause in rate cases, Act 162 required that these five specific factors be addressed in the record. The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s ECAC that are raised by Act 162. The parties in the rate case proceeding are HECO, the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate), and the federal Department of Defense (DOD).

On June 30, 2006, HECO and the Consumer Advocate filed a stipulation requesting that the PUC not review the Act 162 ECAC issues in the pending rate case based on a 2005 test year since HECO’s application was filed and the record in the proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in the rate case (subject to PUC approval) included a provision allowing the existing ECAC to be continued. On August 7, 2006, an amended stipulation was filed in substantially the same form as the June 30, 2006 stipulation, but also included the DOD. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the amended stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162 or the timing of the PUC’s issuance of a final D&O in HECO’s pending 2005 test year rate case.

The ECAC provisions of Act 162 were reviewed in the HELCO rate case based on a 2006 test year and will be 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.

Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the electric utilities’ existing ECACs.

On April 23, 2007, the PUC issued an order denying HECO’s proposal to recover DG 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 power situation

In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. It 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 these units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.” As a result of the final resolution of various proceedings, CT-4 and CT-5 became operational in mid-2004, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work is ongoing to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate the generating units at Keahole as required to meet its system needs. Construction of a noise barrier is scheduled for completion by the end of 2007, which should allow the units to operate full time.

Settlement Agreement; ST-7 costs incurred. In 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposed the settlement) 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 (Settlement Agreement). The Settlement Agreement required HELCO to undertake a number of actions including expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction emissions control equipment, assisting the Department of Hawaiian Home Lands in installing solar water heating in its housing projects, supporting the Keahole Defense Coalition’s participation in certain PUC cases, and cooperating with neighbors and community groups (including a Hot Line service). Other than required payments to other parties to the settlement agreement, which were timely made, many of these actions are ongoing.

HELCO’s plans for ST-7 are progressing. In November 2003, HELCO filed a boundary amendment petition (to reclassify the Keahole plant site from conservation land use to urban land use) with the State of Hawaii Land Use Commission, which boundary amendment was approved in October 2005. In May 2006, HELCO obtained the County

of Hawaii rezoning to a “General Industrial” classification, and in June 2006, received approval for a covered source permit amendment to include selective catalytic reduction with the installation of ST-7. Management believes that any other required permits will be obtained and anticipates an in-service date for ST-7 in late 2009. HELCO has commenced engineering, design and certain construction work for ST-7. HELCO’s current cost estimate for ST-7 is approximately $92 million, of which approximately $3.7 million has been incurred through June 30, 2007.

CT-4 and CT-5 costs incurred. HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $110 million. The $110 million of costs was reclassified from construction in progress to plant and equipment in 2004 ($103 million) and 2005 ($7 million) and depreciated beginning January 1, 2005 and 2006, respectively, and 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 HELCO 2006 rate case proceeding, subject to PUC approval. Under the settlement, HELCO agreed to write-off approximately $12 million of plant-in-service costs, net of average accumulated depreciation, relating to CT-4 and CT-5, resulting in an after-tax charge to net income in the first quarter of 2007 of approximately $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 reflects the settlement agreement reached between HELCO and the Consumer Advocate, including the agreement to write-off a portion of CT-4 and CT-5 costs. However, the interim order does not commit the PUC to accept any of the amounts in the interim increase in its final order. If it becomes probable that the PUC, in its final order, will disallow additional costs incurred for CT-4 and CT-5 for rate-making purposes, 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. 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 $64 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervenor 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.

Subject to obtaining PUC approval and 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 2009, subject to the timing of PUC approval, and the completion date of the second phase is being evaluated.

As of June 30, 2007, the accumulated costs recorded for the EOTP amounted to $31 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $14 million for AFUDC. Management believes no adjustment to project costs is required as of June 30, 2007. 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 a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (which was expensed in 2001). 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 PRPs developed analyses of various remedial alternatives for two of the four remedial subunits of the Iwilei Unit. The DOH will use the analyses to make a final determination of which remedial alternatives the PRPs will be required to implement. The DOH is scheduled to complete the final remediation determinations for all remedial subunits of the Iwilei Unit by the end of 2007 or first quarter of 2008. HECO management developed an estimate of HECO’s share of the costs associated with implementing the PRP recommended remedial approaches for the two subunits covered by the analyses of approximately $1.2 million, (which was expensed in 2006).

As of June 30, 2007, the accrual (amounts expensed less amounts expended) related to the Honolulu Harbor investigation was $1.4 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 must develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, HECO, HELCO and MECO will evaluate the plan’s impacts, if any, on them. 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.

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 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. The EPA is considering an appeal of the decision to the U.S. Supreme Court. If the decision stands, the Court of Appeals ruling reduces the compliance options available to HECO. In addition, the EPA has not issued a schedule for rulemaking, which would be necessary to comply with the court’s decision. On March 20, 2007, the EPA announced it had “suspended” the rule pending appeal or additional rulemaking. On July 9, 2007, the EPA formalized its determination to suspend the rule in a Federal Register notice. In the 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. Due to the uncertainties raised by the court’s decision as well as the need for further rulemaking by the EPA, 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 June 30, 2007, approximately 58% of the electric utilities’ employees are members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. The current collective bargaining and benefit agreements cover a four-year term, from November 1, 2003 to October 31, 2007, and provided for non-compounded wage increases (3% on November 1, 2003; 1.5% on

November 1, 2004, May 1, 2005, November 1, 2005 and May 1, 2006; and 3% on November 1, 2006). Negotiations for new agreements are expected to begin in the third quarter of 2007.

(6)

Cash flows

Supplemental disclosures of cash flow information

For the six months ended June 30, 2007 and 2006, HECO and its subsidiaries paid interest amounting to $23.5 million and $22.7 million, respectively.

For the six months ended June 30, 2007 and 2006, HECO and its subsidiaries paid income taxes amounting to $5.2 million and $5.5 million, respectively.

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 $2.4 million and $3.1 million for the six months ended June 30, 2007 and 2006, 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)

Income taxes

The electric utilities record interest and penalties on income taxes in “Interest and other charges.” Interest accrued on income taxes was insignificant in the first six months of 2006 and $0.2 million in the first six months of 2007.

As of January 1, 2007, the total amount of accrued interest and penalties related to uncertain tax positions and recognized on the balance sheet was $0.6 million.

As of January 1, 2007, the total amount of unrecognized tax benefits was $4.7 million, and of this amount, $0.2 million, if recognized, would affect the electric utilities’ effective tax rate. Management concluded that it is reasonably possible that the unrecognized tax benefits will significantly decrease within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service. Management cannot estimate the range of the reasonably possible change.

Tax years 2003 to 2006 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii.

The electric utilities had an effective tax rate for the first six months of 2007 of 35%, compared to 38% for the first six months of 2006), primarily due to the low pre-tax income and the impact of state tax credits (including the acceleration of the state tax credits associated with the write off of a portion of CT-4 and CT-5 costs) recognized against a smaller income tax expense base.

(9)

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


	Three months ended June 30						Six months ended June 30
	2007			2006			2007			2006
(in thousands)
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	28,789		$	39,846		$	41,781		$	85,426
Deduct:
Income taxes on regulated activities		(6,492	)		(11,020	)		(10,998	)		(24,244	)
Revenues from nonregulated activities		(1,463	)		(617	)		(2,344	)		(1,702	)
Add: Expenses from nonregulated activities		388			293			12,286			584

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	21,222		$	28,502		$	40,725		$	60,064

(10)

Credit agreement

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. On March 14, 2007 the PUC issued a D&O approving HECO’s request to maintain the credit facility for five years (until March 31, 2011), to borrow under the credit facility with maturities in excess of 364 days, to use the proceeds from any borrowings with

maturities in excess of 364 days to finance capital expenditures and/or to repay short-term or other borrowings used to finance or refinance capital expenditures and to use an expedited approval process to obtain PUC approval to increase the facility amount, renew the facility, refinance the facility or change other terms of the facility if such changes are required or desirable.

Any draws on the facility bear interest, at the option of HECO, at either the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. The annual fee is 8 basis points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions that must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting HECO’s ability, as well as the ability of any of its subsidiaries, to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratios of 48% for HELCO and 43% for MECO as of June 30, 2007, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 54% as of June 30, 2007, as calculated under the agreement), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity. HECO’s syndicated credit facility is maintained to support the issuance of commercial paper, but it may also be drawn for general corporate purposes and capital expenditures. As of August 1, 2007, the $175 million credit facility remained undrawn.

On May 23, 2007, S&P lowered the long-term corporate credit and unsecured debt ratings on HECO, HELCO and MECO to BBB from BBB+ and 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.” The pricing for future borrowings under the line of credit facility did not change since the pricing level is "determined by the higher of the two" ratings by S&P and Moody's, and Moody’s ratings did not change.

(11)

Special Purpose Revenue Bonds (SPRBs)

On March 27, 2007, the Department of Budget and Finance of the State of Hawaii (the Department) issued (pursuant to a 2005 legislative authorization), at par, Series 2007A SPRBs in the aggregate principal amount of $140 million, with a maturity of March 1, 2037 and a fixed coupon interest rate of 4.65%, and loaned the proceeds to HECO ($100 million), HELCO ($20 million) and MECO ($20 million). Payment of the principal and interest on the SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company. Proceeds will be used to finance capital expenditures, including reimbursements to the electric utilities for previously incurred capital expenditures which, in turn, will be used primarily to repay short-term borrowings. As of June 30, 2007, approximately $44 million of proceeds from the Series 2007A SPRBs had not yet been drawn and were held by the construction fund trustee. HECO, HELCO and MECO’s long-term debt will increase from time to time as these remaining proceeds are drawn down.

On March 27, 2007, the Department issued, at par, Refunding Series 2007B SPRBs in the aggregate principal amount of $125 million, with a maturity of May 1, 2026 and a fixed coupon interest rate of 4.60%, and loaned the proceeds to HECO ($62 million), HELCO ($8 million) and MECO ($55 million). Proceeds from the sale were applied, together with other funds provided by the electric utilities, to the redemption at par on May 1, 2007 of the $75 million

aggregate principal amount of 6.20% Series 1996A SPRBs (which had an original maturity of May 1, 2026) and to the redemption at a 2% premium on April 27, 2007 of the $50 million aggregate principal amount of 5 7/8% Series 1996B SPRBs (which had an original maturity of December 1, 2026). Payment of the principal and interest on the refunding SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company.

(12)

Consolidating financial information

HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated.

HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) relating to the trust preferred securities of Trust III. 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 June 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	319,652		86,644		84,953		—		—		$	491,249

Operating expenses
Fuel oil		109,775		15,667		41,679		—		—			167,121
Purchased power		92,419		33,420		7,888		—		—			133,727
Other operation		36,845		8,156		8,642		—		—			53,643
Maintenance		17,639		5,405		6,825		—		—			29,869
Depreciation		19,745		7,523		7,004		—		—			34,272
Taxes, other than income taxes		29,264		7,944		7,695		—		—			44,903
Income taxes		3,085		2,326		1,081		—		—			6,492

		308,772		80,441		80,814		—		—			470,027

Operating income		10,880		6,203		4,139		—		—			21,222

Other income
Allowance for equity funds used during construction		1,044		68		90		—		—			1,202
Equity in earnings of subsidiaries		5,764		—		—		—		(5,764	)		—
Other, net		1,250		171		251		(14	)	(609	)		1,049

		8,058		239		341		(14	)	(6,373	)		2,251

Income (loss) before interest and other charges		18,938		6,442		4,480		(14	)	(6,373	)		23,473

Interest and other charges
Interest on long-term debt		7,324		1,915		2,151		—		—			11,390
Amortization of net bond premium and expense		400		106		140		—		—			646
Other interest charges		802		608		73		—		(609	)		874
Allowance for borrowed funds used during construction		(508	)	(34	)	(44	)	—		—			(586	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		8,018		2,595		2,320		—		(380	)		12,553

Income (loss) before preferred stock dividends of HECO		10,920		3,847		2,160		(14	)	(5,993	)		10,920
Preferred stock dividends of HECO		270		133		96		—		(229	)		270

Net income (loss) for common stock	$	10,650		3,714		2,064		(14	)	(5,764	)	$	10,650

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	339,213		80,736		83,401		—		—		$	503,350

Operating expenses
Fuel oil		130,757		18,035		43,522		—		—			192,314
Purchased power		86,527		30,118		5,793		—		—			122,438
Other operation		32,209		7,760		7,965		—		—			47,934
Maintenance		14,829		4,077		3,476		—		—			22,382
Depreciation		18,702		7,431		6,409		—		—			32,542
Taxes, other than income taxes		31,076		7,540		7,602		—		—			46,218
Income taxes		6,928		1,233		2,859		—		—			11,020

		321,028		76,194		77,626		—		—			474,848

Operating income		18,185		4,542		5,775		—		—			28,502

Other income
Allowance for equity funds used during construction		916		53		619		—		—			1,588
Equity in earnings of subsidiaries		6,376		—		—		—		(6,376	)		—
Other, net		918		58		284		(55	)	(684	)		521

		8,210		111		903		(55	)	(7,060	)		2,109

Income (loss) before interest and other charges		26,395		4,653		6,678		(55	)	(7,060	)		30,611

Interest and other charges
Interest on long-term debt		6,741		1,808		2,227		—		—			10,776
Amortization of net bond premium and expense		339		101		103		—		—			543
Other interest charges		2,168		650		92		—		(684	)		2,226
Allowance for borrowed funds used during construction		(409	)	(23	)	(287	)	—		—			(719	)
Preferred stock dividends of subsidiaries		—		—		—		—		229			229

		8,839		2,536		2,135		—		(455	)		13,055

Income (loss) before preferred stock dividends of HECO		17,556		2,117		4,543		(55	)	(6,605	)		17,556
Preferred stock dividends of HECO		270		133		96		—		(229	)		270

Net income (loss) for common stock	$	17,286		1,984		4,447		(55	)	(6,376	)	$	17,286

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Six months ended June 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	608,342		165,453		164,251		—		—		$	938,046

Operating expenses
Fuel oil		210,837		35,705		80,508		—		—			327,050
Purchased power		170,719		60,482		14,042		—		—			245,243
Other operation		70,330		15,322		15,184		—		—			100,836
Maintenance		34,017		10,973		12,215		—		—			57,205
Depreciation		39,484		15,047		14,008		—		—			68,539
Taxes, other than income taxes		56,966		15,307		15,177		—		—			87,450
Income taxes		5,055		2,864		3,079		—		—			10,998

		587,408		155,700		154,213		—		—			897,321

Operating income		20,934		9,753		10,038		—		—			40,725

Other income
Allowance for equity funds used during construction		2,131		133		170		—		—			2,434
Equity in earnings of subsidiaries		2,827		—		—		—		(2,827	)		—
Other, net		2,735		(6,692	)	257		(29	)	(1,420	)		(5,149	)

		7,693		(6,559	)	427		(29	)	(4,247	)		(2,715	)

Income (loss) before interest and other charges		28,627		3,194		10,465		(29	)	(4,247	)		38,010

Interest and other charges
Interest on long-term debt		14,449		3,772		4,665		—		—			22,886
Amortization of net bond premium and expense		748		205		239		—		—			1,192
Other interest charges		2,824		1,365		246		—		(1,420	)		3,015
Allowance for borrowed funds used during construction		(1,037	)	(65	)	(82	)	—		—			(1,184	)
Preferred stock dividends of subsidiaries		—		—		—		—		458			458

		16,984		5,277		5,068		—		(962	)		26,367

Income (loss) before preferred stock dividends of HECO		11,643		(2,083	)	5,397		(29	)	(3,285	)		11,643
Preferred stock dividends of HECO		540		267		191		—		(458	)		540

Net income (loss) for common stock	$	11,103		(2,350	)	5,206		(29	)	(2,827	)	$	11,103

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Six months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Operating revenues	$	657,558		160,187		159,576		—		—		$	977,321

Operating expenses
Fuel oil		246,492		38,137		83,023		—		—			367,652
Purchased power		171,981		58,164		10,013		—		—			240,158
Other operation		60,410		15,012		14,531		—		—			89,953
Maintenance		25,386		7,693		6,355		—		—			39,434
Depreciation		37,395		14,862		12,818		—		—			65,075
Taxes, other than income taxes		60,972		14,943		14,826		—		—			90,741
Income taxes		15,985		2,404		5,855		—		—			24,244

		618,621		151,215		147,421		—		—			917,257

Operating income		38,937		8,972		12,155		—		—			60,064

Other income
Allowance for equity funds used during construction		1,993		93		1,050		—		—			3,136
Equity in earnings of subsidiaries		13,033		—		—		—		(13,033	)		—
Other, net		2,159		128		511		(102	)	(1,266	)		1,430

		17,185		221		1,561		(102	)	(14,299	)		4,566

Income (loss) before interest and other charges		56,122		9,193		13,716		(102	)	(14,299	)		64,630

Interest and other charges
Interest on long-term debt		13,484		3,616		4,454		—		—			21,554
Amortization of net bond premium and expense		678		201		207		—		—			1,086
Other interest charges		4,038		1,232		135		—		(1,266	)		4,139
Allowance for borrowed funds used during construction		(892	)	(42	)	(487	)	—		—			(1,421	)
Preferred stock dividends of subsidiaries		—		—		—		—		458			458

		17,308		5,007		4,309		—		(808	)		25,816

Income (loss) before preferred stock dividends of HECO		38,814		4,186		9,407		(102	)	(13,491	)		38,814
Preferred stock dividends of HECO		540		267		191		—		(458	)		540

Net income (loss) for common stock	$	38,274		3,919		9,216		(102	)	(13,033	)	$	38,274

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

June 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI	Reclassi- fications and elimina- tions		HECO consoli- dated
Assets
Utility plant, at cost
Land	$	25,895		4,982		4,346		—	—		$	35,223
Plant and equipment		2,466,982		808,860		778,159		—	—			4,054,001
Less accumulated depreciation		(978,030	)	(310,855	)	(319,761	)	—	—			(1,608,646	)
Plant acquisition adjustment, net		—		—		67		—	—			67
Construction in progress		84,450		15,427		6,728		—	—			106,605

Net utility plant		1,599,297		518,414		469,539		—	—			2,587,250

Investment in subsidiaries, at equity		389,275		—		—		—	(389,275	)		—

Current assets
Cash and equivalents		2,290		1,212		1,109		250	—			4,861
Advances to affiliates		39,450		—		1,000		—	(40,450	)		—
Customer accounts receivable, net		87,340		24,627		20,770		—	—			132,737
Accrued unbilled revenues, net		54,592		15,054		13,552		—	—			83,198
Other accounts receivable, net		3,581		457		4,334		—	(2,679	)		5,693
Fuel oil stock, at average cost		59,737		10,762		17,961		—	—			88,460
Materials and supplies, at average cost		15,354		5,297		12,943		—	—			33,594
Other		7,504		1,008		293		—	—			8,805

Total current assets		269,848		58,417		71,962		250	(43,129	)		357,348

Other long-term assets
Regulatory assets		83,745		32,387		16,473		—	—			132,605
Unamortized debt expense		10,869		2,519		2,649		—	—			16,037
Other		26,148		4,175		4,715		—	—			35,038

Total other long-term assets		120,762		39,081		23,837		—	—			183,680

	$	2,379,182		615,912		565,338		250	(432,404	)	$	3,128,278

Capitalization and liabilities
Capitalization
Common stock equity	$	990,560		191,200		197,839		236	(389,275	)	$	990,560
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		555,800		143,159		164,865		—	—			863,824

Total capitalization		1,568,653		341,359		367,704		236	(389,275	)		1,888,677

Current liabilities
Short-term borrowings–nonaffiliates		52,626		—		—		—	—			52,626
Short-term borrowings–affiliate		1,000		39,450		—		—	(40,450	)		—
Accounts payable		66,484		18,409		17,486		—	—			102,379
Interest and preferred dividends payable		9,780		2,288		2,065		—	(184	)		13,949
Taxes accrued		82,609		26,679		28,148		—	—			137,436
Other		20,880		6,986		9,492		14	(2,495	)		34,877

Total current liabilities		233,379		93,812		57,191		14	(43,129	)		341,267

Deferred credits and other liabilities
Deferred income taxes		85,056		8,060		10,243		—	—			103,359
Regulatory liabilities		172,453		44,758		33,987		—	—			251,198
Unamortized tax credits		32,726		12,907		12,221		—	—			57,854
Other		120,216		54,581		29,182		—	—			203,979

Total deferred credits and other liabilities		410,451		120,306		85,633		—	—			616,390

Contributions in aid of construction		166,699		60,435		54,810		—	—			281,944

	$	2,379,182		615,912		565,338		250	(432,404	)	$	3,128,278

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2006


(in thousands)	HECO			HELCO		MECO		RHI	Reclassi- fications and elimina- tions		HECO consolidated
Assets
Utility plant, at cost
Land	$	25,919		4,977		4,346		—	—		$	35,242
Plant and equipment		2,428,155		807,474		767,300		—	—			4,002,929
Less accumulated depreciation		(953,187	)	(298,590	)	(307,136	)	—	—			(1,558,913	)
Plant acquisition adjustment, net		—		—		93		—	—			93
Construction in progress		80,298		9,745		5,576		—	—			95,619

Net utility plant		1,581,185		523,606		470,179		—	—			2,574,970

Investment in subsidiaries, at equity		367,595		—		—		—	(367,595	)		—

Current assets
Cash and equivalents		2,328		738		518		275	—			3,859
Advances to affiliates		54,400		—		—		—	(54,400	)		—
Customer accounts receivable, net		81,912		24,228		19,384		—	—			125,524
Accrued unbilled revenues, net		64,235		14,437		13,523		—	—			92,195
Other accounts receivable, net		3,210		1,097		773		—	(657	)		4,423
Fuel oil stock, at average cost		40,680		9,761		13,871		—	—			64,312
Materials & supplies, at average cost		13,959		4,892		11,689		—	—			30,540
Other		7,537		1,463		695		—	—			9,695

Total current assets		268,261		56,616		60,453		275	(55,057	)		330,548

Other long-term assets
Regulatory assets		82,116		15,349		14,884		—	—			112,349
Unamortized debt expense		9,323		2,282		2,117		—	—			13,722
Other		23,507		4,340		3,698		—	—			31,545

Total other long-term assets		114,946		21,971		20,699		—	—			157,616

	$	2,331,987		602,193		551,331		275	(422,652	)	$	3,063,134

Capitalization and liabilities
Capitalization
Common stock equity	$	958,203		175,099		192,231		265	(367,595	)	$	958,203
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,240		131,046		153,899		—	—			766,185

Total capitalization		1,461,736		313,145		351,130		265	(367,595	)		1,758,681

Current liabilities
Short-term borrowings-nonaffiliates		113,107		—		—		—	—			113,107
Short-term borrowings-affiliate		—		49,400		5,000		—	(54,400	)		—
Accounts payable		61,672		22,572		18,268		—	—			102,512
Interest and preferred dividends payable		7,269		1,907		1,717		—	(248	)		10,645
Taxes accrued		96,846		26,981		28,355		—	—			152,182
Other		27,012		5,971		10,536		10	(409	)		43,120

Total current liabilities		305,906		106,831		63,876		10	(55,057	)		421,566

Deferred credits and other liabilities
Deferred income taxes		92,805		13,285		11,965		—	—			118,055
Regulatory liabilities		164,617		43,596		32,406		—	—			240,619
Unamortized tax credits		32,359		13,126		12,394		—	—			57,879
Other		110,473		52,274		26,859		—	—			189,606

Total deferred credits and other liabilities		400,254		122,281		83,624		—	—			606,159

Contributions in aid of construction		164,091		59,936		52,701		—	—			276,728

	$	2,331,987		602,193		551,331		275	(422,652	)	$	3,063,134

Hawaiian Electric Company, Inc. and Subsidiaries

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

Six months ended June 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Balance, December 31, 2006	$	958,203		175,099		192,231		265		(367,595	)	$	958,203
Comprehensive income:
Net income		11,103		(2,350	)	5,206		(29	)	(2,827	)		11,103
Defined benefit retirement plans—amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of tax benefits		3,669		278		444		—		(722	)		3,669

Comprehensive income (loss)		14,772		(2,072	)	5,650		(29	)	(3,549	)		14,772

Adjustment to initially apply a PUC D&O related to defined benefit plans		18,205		18,205		—		—		(18,205	)		18,205
Adjustment to initially apply FIN 48, net of tax benefits		(620	)	(32	)	(42	)	—		74			(620	)

Balance, June 30, 2007	$	990,560		191,200		197,839		236		(389,275	)	$	990,560

Hawaiian Electric Company, Inc. and Subsidiaries

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

Six months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Balance, December 31, 2005	$	1,039,259		189,407		194,190		118		(383,715	)	$	1,039,259
Net income		38,274		3,919		9,216		(102	)	(13,033	)		38,274
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396			(29,381	)

Balance, June 30, 2006	$	1,046,152		190,452		196,884		16		(387,352	)	$	1,048,152

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2007


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	11,643		(2,083	)	5,397		(29	)	(3,285	)	$	11,643
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in (earnings) loss		(2,877	)	—		—		—		2,827			(50	)
Common stock dividends received from subsidiaries		50		—		—		—		—			50
Depreciation of property, plant and equipment		39,484		15,047		14,008		—		—			68,539
Other amortization		1,801		319		1,716		—		—			3,836
Writedown of utility plant		—		11,701		—		—		—			11,701
Deferred income taxes		(5,987	)	(5,078	)	(1,419	)	—		—			(12,484	)
Tax credits, net		749		433		(66	)	—		—			1,116
Allowance for equity funds used during construction		(2,131	)	(133	)	(170	)	—		—			(2,434	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		(5,799	)	241		(4,947	)	—		2,022			(8,483	)
Decrease (increase) in accrued unbilled revenues		9,643		(617	)	(29	)	—		—			8,997
Increase in fuel oil stock		(19,057	)	(1,001	)	(4,090	)	—		—			(24,148	)
Increase in materials and supplies		(1,395	)	(405	)	(1,254	)	—		—			(3,054	)
Decrease (increase) in regulatory assets		172		(248	)	(1,552	)	—		—			(1,628	)
Increase (decrease) in accounts payable		4,812		(4,163	)	(782	)	—		—			(133	)
Decrease in taxes accrued		(14,237	)	(302	)	(207	)	—		—			(14,746	)
Changes in other assets and liabilities		4,032		5,882		(634	)	4		(2,022	)		7,262

Net cash provided by (used in) operating activities		20,903		19,593		5,971		(25	)	(458	)		45,984

Cash flows from investing activities
Capital expenditures		(46,093	)	(20,875	)	(10,801	)	—		—			(77,769	)
Contributions in aid of construction		4,322		1,708		1,547		—		—			7,577
Advances to affiliates		14,950		—		(1,000	)	—		(13,950	)		—

Net cash used in investing activities		(26,821	)	(19,167	)	(10,254	)	—		(13,950	)		(70,192	)

Cash flows from financing activities
Preferred stock dividends		(540	)	(267	)	(191	)	—		458			(540	)
Proceeds from issuance of long-term debt		135,770		19,990		65,567		—		—			221,327
Repayment of long-term debt		(62,280	)	(8,020	)	(55,700	)	—		—			(126,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(59,481	)	(9,950	)	(5,000	)	—		13,950			(60,481	)
Decrease in cash overdraft		(7,589	)	(1,705	)	198		—		—			(9,096	)

Net cash provided by financing activities		5,880		48		4,874		—		14,408			25,210

Net increase (decrease) in cash and equivalents		(38	)	474		591		(25	)	—			1,002
Cash and equivalents, beginning of period		2,328		738		518		275		—			3,859

Cash and equivalents, end of period	$	2,290		1,212		1,109		250		—		$	4,861

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2006


(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and elimina- tions		HECO consoli- dated
Cash flows from operating activities
Income (loss) before preferred stock dividends of HECO	$	38,814		4,186		9,407		(102	)	(13,491	)	$	38,814
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings		(13,083	)	—		—		—		13,033			(50	)
Common stock dividends received from subsidiaries		9,446		—		—		—		(9,396	)		50
Depreciation of property, plant and equipment		37,395		14,862		12,818		—		—			65,075
Other amortization		2,152		214		1,435		—		—			3,801
Deferred income taxes		(3,675	)	(714	)	(2,523	)	—		—			(6,912	)
Tax credits, net		1,441		283		735		—		—			2,459
Allowance for equity funds used during construction		(1,993	)	(93	)	(1,050	)	—		—			(3,136	)
Changes in assets and liabilities
Decrease in accounts receivable		3,686		1,885		58		—		775			6,404
Decrease (increase) in accrued unbilled revenues		2,617		362		(13	)	—		—			2,966
Increase in fuel oil stock		(23,654	)	(1,126	)	(3,244	)	—		—			(28,024	)
Increase in materials and supplies		(891	)	(826	)	(1,433	)	—		—			(3,150	)
Decrease (increase) in regulatory assets		(319	)	141		(1,409	)	—		—			(1,587	)
Increase (decrease) in accounts payable		3,012		(3,525	)	307		—		—			(206	)
Increase in taxes accrued		5,192		204		4,327		—		—			9,723
Changes in other assets and liabilities		(594	)	4,931		3,382		35		(775	)		6,979

Net cash provided by (used in) operating activities		59,546		20,784		22,797		(67	)	(9,854	)		93,206

Cash flows from investing activities
Capital expenditures		(43,373	)	(18,151	)	(29,870	)	—		—			(91,394	)
Contributions in aid of construction		7,199		1,385		2,038		—		—			10,622
Advances from (to) affiliates		(6,900	)	—		5,250		—		1,650			—
Other		193		—		—		—		—			193

Net cash used in investing activities		(42,881	)	(16,766	)	(22,582	)	—		1,650			(80,579	)

Cash flows from financing activities
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396			(29,381	)
Preferred stock dividends		(540	)	(267	)	(191	)	—		458			(540	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		22,061		400		6,500		—		(1,650	)		27,311
Decrease in cash overdraft		(5,836	)	(950	)	—		—		—			(6,786	)

Net cash used in financing activities		(13,696	)	(3,691	)	(213	)	—		8,204			(9,396	)

Net increase (decrease) in cash and equivalents		2,969		327		2		(67	)	—			3,231
Cash and equivalents, beginning of period		8		3		4		128		—			143

Cash and equivalents, end of period	$	2,977		330		6		61		—		$	3,374

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 2006 Form 10-K and should be read in conjunction with the annual (as of and for the year ended December 31, 2006) and quarterly (as of and for the three months ended March 31, 2007, and as of and for the three and six months ended June 30, 2007) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

HEI, through HECO and its subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), provide the only electric public utility service to approximately 95% of Hawaii’s population. HEI also provides a wide array of banking and other financial services to consumers and businesses through its bank subsidiary, ASB, Hawaii’s third largest financial institution based on assets as of December 31, 2006.

In the first six months of 2007, net income was $24 million, or $0.30 per share, compared to $60 million, or $0.73 per share, in the first six months of 2006. The significant decline was due to lower electric utility and bank earnings.

The utilities’ earnings were impacted by higher expenses, which were expected and are expected to continue as they maintain the reliability of aging generating units as well as add new plant and supporting infrastructure. The utilities’ earnings were also impacted by a $7 million after-tax write-off of plant in the first quarter, but benefited from 1.7% higher kilowatthour (KWH) sales and interim rate relief at HELCO. Future improvement in utility earnings, however, is largely dependent on the amount and timing of further rate relief to cover the higher expenses.

ASB’s earnings were adversely affected by the challenging interest rate environment—a flat or inverted yield curve throughout 2006 and the first six months of 2007—and higher legal and other litigation expenses and costs to strengthen ASB’s risk management and compliance infrastructure, which are expected to continue. Although management works to further grow market share in select lines of business and continually assesses its asset/liability mix and efficiency ratio, ASB’s earnings are still largely dependent on the level of interest rates and the shape of the yield curve.

Further, the Company’s operations are heavily influenced by Hawaii’s economy, which is driven by tourism, the federal government (including the military), real estate and construction. See “Economic conditions” below.

RESULTS OF OPERATIONS


	Three months ended June 30,				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2007		2006		% change		Primary reason(s) for significant change*
Revenues	$	600,763	$	604,969	(1	)	Decrease for the electric utility segment, slightly offset by increases for the bank and “other” segments
Operating income		45,309		60,729	(25	)	Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment
Net income		17,549		27,224	(36	)	Lower operating income and AFUDC, partly offset by lower income taxes resulting from lower income before taxes and a lower effective income tax rate **
Basic earnings per common share	$	0.21	$	0.34	(38	)	Lower net income
Weighted-average number of common shares outstanding		81,907		81,100	1		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans


(in thousands, except per share amounts)	Six months ended June 30,				% change		Primary reason(s) for significant change*
(in thousands, except per share amounts)	2007		2006		% change		Primary reason(s) for significant change*
Revenues	$	1,154,786	$	1,179,931	(2	)	Decrease for the electric utility segment, slightly offset by increases for the bank and “other” segments
Operating income		73,850		129,880	(43	)	Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment
Net income		24,313		59,561	(59	)	Lower operating income and AFUDC and higher “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by lower income taxes resulting from lower income before taxes and a lower effective income tax rate **
Basic earnings per common share	$	0.30	$	0.73	(59	)	Lower net income
Weighted-average number of common shares outstanding		81,679		81,041	1		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 six months of 2007 was 34%, compared to an effective tax rate for the first six months of 2006 of 37% (see Note 10 in HEI’s “Notes to Consolidated Financial Statements”).

Dividends

On May 3, 2007, HEI’s Board of Directors maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2006 and the first six months of 2007 were 93% and 207%, respectively. Historically-low net income for the first six months of 2007 resulted in a dividend payout over two times greater than net income. Net income for the first six months of 2007 was affected by a number of factors, including higher other operation and maintenance (O&M) expenses and a $7 million (net of taxes) write-off of plant at the electric utilities and higher legal and consulting expenses at ASB (see “Results of Operations” in the “Electric Utilities” and “Bank” sections below). HEI’s Board and management continues to believe that HEI should achieve 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., Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).

Because HEI’s core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – tourism and the federal government, was estimated at 2.7% for 2006 and is forecast by DBEDT to further moderate to 2.6% for 2007.

According to the latest available data, Hawaii ranked fifth among the states in its receipt of federal government expenditures per capita. For the federal fiscal year ended September 30, 2004 (latest available data), total federal government expenditures in Hawaii, including military expenditures, were $12.2 billion or $9,651 per capita, increasing 8% and 7%, respectively, over fiscal year 2003. Military spending, which is 39% of federal expenditures in Hawaii, increased 6% in 2004 compared to 2003.

Tourism is widely acknowledged as a significant component of Hawaii’s economy. In 2006, visitor expenditures reached a record $12.3 billion, a 3% increase over 2005. 2006 visitor days were slightly lower, decreasing 0.3% when compared to the 2005 record-high level. State economists currently expect marginal visitor growth in 2007 due

to capacity constraints with projected increases of 1.2% in visitor days and 3.3% in visitor expenditures. Although visitor days year-to-date through May 31, 2007 were down 1.2% compared to the same period a year ago, visitor expenditures were up 1.6%.

The real estate and construction industries in Hawaii also influence HEI’s core businesses. The Oahu housing market is continuing to stabilize. The median home price on Oahu reached a new record high of $685,000 in June 2007 compared to the median of $639,000 in June 2006. However, total sales of single-family homes year-to-date through June 30, 2007 decreased 5.7% compared to the same period last year, in line with a stabilizing market.

Although construction is slowing as indicated by a 1.8% decrease in private building permits year-to-date through May 31, 2007 compared with the same period last year, local economists expect the 8% growth in the statewide total value of private building permits in 2006 to equate to healthy growth in Hawaii’s construction sector.

Overall, the outlook for Hawaii’s economy remains positive. However, economic growth is affected by the rate of expansion in the mainland U.S. and Japan economies and the growth in military spending, and is vulnerable to uncertainties in the world’s geopolitical environment. The projected real gross domestic product (GDP) growth for the U.S. and Japan in 2007 are 2.2% and 2.3%, respectively.

Management also monitors (1) oil prices, because of their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates, because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Crude oil was trading at an average price of $66.42 per barrel during the second quarter of 2007, compared to an average price of $70.28 per barrel in 2006, and is expected to continue trading at a premium due to geopolitical instability, particularly in Nigeria, and tight refining capacity in the U.S.

Long-term interest rates began to rise in the second quarter of 2007 with the 10-year Treasury yield trading in the 4.5%-5.3% range. At the end of June 2007, the yield curve began to slope upward which may signal concern for future inflation. The spread between the 10-year and 2-year Treasuries was 0.16% as of June 30, 2007, compared to spreads of 0.07% as of March 31, 2007, and (0.10)% as of December 31, 2006.

“Other” segment


	Three months ended June 30,						% change	Primary reason(s) for significant change
(in thousands)	2007			2006			% change	Primary reason(s) for significant change
Revenues	$	525		$	(1,544	)	NM	Unrealized loss on Hoku shares of $2.0 million in the second quarter of 2006 (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”)
Operating loss		(3,174	)		(5,276	)	NM	Prior year unrealized loss on Hoku shares
Net loss		(5,683	)		(6,280	)	NM	See explanation for operating loss, partly offset by higher interest expense primarily due to higher medium-term note interest


	Six months ended June 30,						% change	Primary reason(s) for significant change
(in thousands)	2007			2006			% change	Primary reason(s) for significant change
Revenues	$	2,410		$	(1,652	)	NM	Gain on the sale of Hoku shares of $1.4 million in the first half of 2007 compared to unrealized and realized losses on such shares of $2.6 million in the first half of 2006 (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”)
Operating loss		(6,053	)		(8,720	)	NM	Gain on the sale of Hoku shares versus prior year unrealized and realized loss, partly offset by higher consulting and other administrative and general expenses
Net loss		(10,968	)		(11,758	)	NM	See explanation for operating loss, partly offset by higher interest expense primarily due to higher medium-term note interest

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily 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. (HEIPI), 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.

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

Selected contractual obligations and commitments

Deferred tax liabilities ($83 million as of June 30, 2007 and $106.8 million as of December 31, 2006), FIN 48 liabilities ($11 million as of June 30, 2007) and accrued interest and penalties related to uncertain tax positions ($2 million as of June 30, 2007) have not and are not expected to be included in HEI’s consolidated table of “Selected contractual obligations and commitments” in HEI’s Form 10-K because the Company cannot reliably estimate when, and to what extent, cash settlement of these liabilities will occur.

Liquidity and capital resources

HEI believes that its ability, and that of its subsidiaries, to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper, lines of credit and bank borrowings, is adequate to maintain sufficient liquidity to fund the Company’s capital expenditures and investments and to cover debt, retirement benefits 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)	June 30, 2007				December 31, 2006
Short-term borrowings—other than bank	$	126	5	%	$	177	7	%
Long-term debt, net—other than bank		1,231	49			1,133	47
Preferred stock of subsidiaries		34	1			34	1
Common stock equity		1,108	45			1,095	45

	$	2,499	100	%	$	2,439	100	%

As of August 1, 2007, 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 also ranks business profiles from “1” (excellent) to “10” (vulnerable). In May 2007, S&P changed HEI’s business profile rank from “6” to “5” and stated that HEI has a satisfactory business profile of “5” and somewhat weak financial measures.

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

In December 2006, Moody’s confirmed its issuer ratings and stable outlook for HEI. 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 flow to suffer.”

As of June 30, 2007, $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.

HEI utilizes short-term debt, principally commercial paper, to support normal operations 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 six months of 2007 of $70 million and had $73 million outstanding as of June 30, 2007. HEI’s commercial paper increased during the first half of 2007 as a result of implementing a plan to not receive dividends from HECO during the second half of 2006 and the first half of 2007 in order to strengthen HECO’s capital structure. The decrease in HECO’s dividend during this period was partly offset by an increase in ASB’s dividend to100% of its net income. Management believes that if HEI’s commercial paper ratings were to be downgraded, it may be more difficult for HEI 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. See Note 12 of HEI’s “Notes to Consolidated Financial Statements” for a description of the $100 million credit facility. As of August 1, 2007, the line was 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 six months of 2007, net cash provided by operating activities of consolidated HEI was $79 million. Net cash used in investing activities for the same period was $118 million primarily due to purchases of investment and mortgage-related securities, partly offset by repayments, and a net increase in loans receivable at ASB and HECO’s consolidated capital expenditures. Net cash provided by financing activities during this period was $8 million as a result of several factors, including net increases in other bank borrowings and long-term debt and proceeds from the issuance of common stock under HEI plans, partly offset by net decreases in deposit liabilities, short-term borrowings and cash overdrafts and the payment of common stock dividends.

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 82 to 89 of HEI’s 2006 Form 10-K.

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 90 to 93 of HEI’s 2006 Form 10-K.

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

ELECTRIC UTILITIES

RESULTS OF OPERATIONS


(dollars in thousands, except per barrel amounts)	Three months ended June 30,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	492,712	$	503,967	(2	)	Lower fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($22 million), and discontinuation of DSM lost margin and shareholder incentives ($2 million), partly offset by interim rate relief ($6 million) and 1.7% higher KWH sales ($5 million)
Expenses
Fuel oil		167,121		192,314	(13	)	Lower fuel oil costs and fewer KWHs generated
Purchased power		133,727		122,438	9		Higher KWHs purchased and higher capacity and non-fuel charges, partly offset by lower fuel costs
Other		163,075		149,369	9		Higher other operation & maintenance (O&M) ($13 million) and depreciation expenses ($2 million), partly offset by lower taxes, other than income taxes ($1 million)
Operating income		28,789		39,846	(28	)	Higher expenses and discontinuation of DSM lost margin and shareholder incentives, partly offset by interim rate relief and higher sales
Net income		10,650		17,286	(38	)	Lower operating income and AFUDC, partly offset by lower interest expense and income taxes
Kilowatthour sales (millions)		2,501		2,460	2		Load growth and warmer weather
Oahu cooling degree days		1,255		1,081	16
Fuel oil cost per barrel	$	62.74	$	68.78	(9	)


(dollars in thousands, except per barrel amounts)	Six months ended June 30,				% change		Primary reason(s) for significant change
(dollars in thousands, except per barrel amounts)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	940,390	$	979,023	(4	)	Lower fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($50 million) and discontinuation of DSM lost margin and shareholder incentives ($4 million), partly offset by 1.1% higher KWH sales ($9 million) and interim rate relief ($6 million)
Expenses
Fuel oil		327,050		367,652	(11	)	Lower fuel oil costs and fewer KWHs generated
Purchased power		245,243		240,158	2		Higher KWHs purchased and higher capacity and non-fuel charges, partly offset by lower fuel costs
Other		326,316		285,787	14		Higher other O&M ($29 million) and depreciation expenses ($3 million) and write-off of HELCO plant in service ($12 million), partly offset by lower taxes, other than income taxes ($3 million)
Operating income		41,781		85,426	(51	)	Higher expenses, write-off of plant in service costs and discontinuation of DSM lost margin and shareholder incentives, partly offset by higher sales and interim rate relief
Net income		11,103		38,274	(71	)	Lower operating income and AFUDC, partly offset by lower income taxes
Kilowatthour sales (millions)		4,905		4,850	1		Load growth and warmer weather
Oahu cooling degree days		2,100		1,854	13
Fuel oil cost per barrel	$	60.43	$	66.20	(9	)

*	The electric utilities had an effective tax rate of 35% for the first six months of 2007, compared to 38% for the first six months of 2006 (see Note 8 in HECO’s “Notes to Consolidated Financial Statements”).

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

Results – three months ended June 30, 2007

Operating income for the second quarter of 2007 decreased 28% from the same period in 2006 due primarily to higher other O&M and depreciation expenses and the discontinuation of DSM lost margin and shareholder incentives, partly offset by interim rate relief granted to HELCO by the PUC in April 2007 ($6 million) and higher KWH sales. KWH sales in the second quarter of 2007 increased 1.7% from the same period in 2006, primarily due to new load growth (i.e., increase in the number of customers and new construction) and warmer weather. Other operation expense increased 12% primarily due to higher administrative and general expense, including retirement benefits expense. Pension and other postretirement benefit expenses for the electric utilities increased $1.5 million over the same period in 2006 primarily due to the adoption of a 50 basis points lower asset return rate as of December 31, 2006 by the HEI Pension Investment Committee and expenses related to the adoption of the pension and OPEB tracking mechanisms at HELCO, including the amortization of its prepaid pension asset, which became effective in April 2007 (approved on an interim basis by the PUC in HELCO’s test year 2006 rate case; see “Most recent rate requests”). Maintenance expense increased by 33% due to higher production maintenance expense ($5.9 million of the increase due to the greater number and scope of generating unit overhauls) and transmission and distribution maintenance expense ($1.3 million of the increase due to higher vegetation management and substation maintenance expenses). The remaining increase in other O&M expenses includes increased costs to ensure reliable operations and to

execute energy efficiency programs. Higher depreciation expense was attributable to additions to plant in service in 2006 (including HECO’s New Dispatch Center and Ford Island Substation, and MECO’s M18 generating unit).

Results – six months ended June 30, 2007

Operating income for the first six months of 2007 decreased 51% from the same period in 2006 due primarily to higher other O&M expenses, a first quarter 2007 write-off of plant in service costs associated with the CT-4 and CT-5 at the Keahole generating station (See “Most recent rate cases”) and the discontinuation of DSM lost margin and shareholder incentives, partly offset by higher KWH sales and interim rate relief granted to HELCO by the PUC in April 2007 ($6 million). KWH sales in the first six months of 2007 increased 1.1% from the same period in 2006, primarily due to new load growth and warmer weather. Other operation expense increased 12% primarily due to higher administrative and general expense, including retirement benefits expense. Pension and other postretirement benefit expenses for the electric utilities increased $2.5 million over the same period in 2006 primarily due to the adoption of a 50 basis points lower asset return rate as of December 31, 2006 by the HEI Pension Investment Committee and expenses related to the adoption of the pension and OPEB tracking mechanisms at HELCO, including the amortization of its prepaid pension asset, which became effective in April 2007 (approved on an interim basis by the PUC in HELCO’s test year 2006 rate case; see “Most recent rate requests”). Maintenance expense increased by 45% due to higher production maintenance expense ($13.2 million of the increase due to the greater number and scope of generating unit overhauls) and transmission and distribution maintenance expense ($3.3 million of the increase due to higher vegetation management and substation maintenance expenses). The remaining increase in other O&M expenses includes increased costs to ensure reliable operations and to execute energy efficiency programs. Higher depreciation expense was attributable to additions to plant in service in 2006.

The trend of increased other O&M expenses is expected to continue in 2007 as the electric utilities expect (1) higher DSM expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved pursuant to a final D&O in an energy efficiency DSM Docket) and integrated resource planning expenses, (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to support the higher demand that has occurred over the last five years.

As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability that is expected to continue until HECO installs its planned new generating unit in 2009. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. Generation reserve margins on Oahu continued to be strained, particularly during peak periods. HECO has taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding DG at some substations and encouraging energy conservation. The marginal costs of supplying growing demand, however, are increasing because of the decreasing reserve margin situation, and the trend of cost increases is not likely to ease.

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 October 2003, the PUC opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.

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.

On June 30, 2006, the PUC issued a decision in this proceeding, which included a proposed framework to govern competitive bidding as a mechanism for acquiring or building new generation in Hawaii and required the parties to submit comments on the proposed framework. On December 8, 2006, the PUC issued a decision which reviewed the parties’ comments and revised the competitive bidding framework, which became effective upon issuance of the decision. 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 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 this framework was adopted (provided that negotiations with the non-fossil producers are 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 Request for Proposal (RFP) or when the PUC otherwise determines, (9) 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, (10) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP 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 the first half of 2007, the utilities filed proposed tariffs containing procedures for interconnection and transmission upgrades, a list of qualified candidates for the Independent Observer position for future competitive bidding processes (which list the PUC has approved) and a proposed Code of Conduct.

Management cannot currently predict the ultimate effect of this decision 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.

On January 27, 2006, the PUC issued its D&O in the DG proceeding. In the D&O, the PUC indicated 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.

On March 1, 2006, the electric utilities filed a Motion for Clarification and/or Partial Reconsideration (DG Motion). On April 6, 2006, the PUC issued its decision on the electric utilities’ DG Motion and 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 currently evaluating several potential DG and combined heat and power (CHP, a form of 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. On September 11, 2006, the PUC issued a Schedule of Proceedings for its consideration of this CHP project. The Consumer Advocate did not object to approval of MECO’s application with the qualification that no determination be made at this time as to whether the costs associated with installation of the CHP system can be included in MECO’s revenue requirements. MECO’s response, filed in February 2007, explained that the Consumer Advocate’s conditions would not allow MECO to proceed with the project as such a conditional approval would not provide reasonable assurance that MECO will be able to include the associated costs in its revenue requirement. MECO requested that the PUC approve the CHP agreement, approve inclusion of the fuel and transportation costs and associated taxes in MECO’s ECAC and allow MECO to include the costs incurred in its revenue requirement for ratemaking purposes. In April 2007, MECO submitted a system economic analysis to the Consumer Advocate to address the Consumer Advocate’s concerns and to enable MECO and the Consumer Advocate to reach a stipulation on the issues in the docket. The parties are considering MECO’s submittal.

The 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 intervenor 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. As proposed by the electric utilities, the PUC also ordered the electric utilities to hold one or more technical meetings with the parties and directed the parties to submit a stipulation identifying the remaining issues, procedural steps and schedule for the proceeding. The parties held technical sessions in May, June and July 2007 to discuss the proposed interconnection and standby tariffs and the positions of the various parties. A stipulation between the parties identifying the agreed-upon remaining issues, procedural steps and schedule for this proceeding is due on August 10, 2007.

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 in 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 August 1, 2007, 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 11.40% for HECO (D&O issued on December 11, 1995, based on a 1995 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 for purposes of the interim rate increases in HECO’s and HELCO’s rate cases based on 2005 and 2006 test years, respectively, were both 10.70%.

For the 12 months ended June 30, 2007, the simple average ROACEs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 5.49%, 0.42%, and 7.58%, respectively; if accumulated other comprehensive income (AOCI) charges due to SFAS No. 158 were excluded, the ROACEs for HECO and MECO would have been 5.11% and 7.32%, respectively (HELCO’s ROACE calculation excludes the AOCI charges as a result of an interim D&O). HECO’s actual ROACE continues to be significantly lower than its allowed ROACE primarily because of increased other O&M expenses, which are expected to continue and have resulted in HECO seeking rate relief more often than in the past. The interim rate relief granted to HECO by the PUC in September 2005 (see below) was based in part on increased costs of operating and maintaining HECO’s system. HELCO’s ROACE was negatively impacted by the write-off of certain CT-4 and CT-5 costs and the fact that its electric rates did not change for the unit additions until the PUC granted interim rate relief, implemented on April 5, 2007, in the HELCO 2006 rate case (see below).

As of August 1, 2007, the return on rate base (ROR) found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). However, the RORs used for purposes of the interim D&Os in the HECO and HELCO rate cases based on 2005 and 2006 test years were 8.66% and 8.33%, respectively. For the 12 months ended June 30, 2007, the simple average RORs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 5.08%, 4.77% and 6.59%, respectively.

By reason of the adoption of SFAS No. 158, HECO and MECO had, and may in the future have, significant charges to AOCI related to the funded status of their retirement benefit plans, which decrease their common stock equity. Absent appropriate regulatory relief in rate cases to adjust for the impact on equity of these AOCI charges, the resulting increase in their RORs and ROACEs could impact the rates they are allowed to charge, which may ultimately result in reduced revenues and lower earnings. HELCO received an interim D&O in its 2006 test year rate case, which included the reclassification, beginning April 5, 2007, to a regulatory asset of the charge for retirement benefits that would otherwise be recorded in AOCI (see Note 4 of HECO’s “Notes to Consolidated Financial Statements”).

HECO.

2005 test year rate case. In November 2004, HECO filed a request with the PUC to increase base rates 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 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 remaining 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).

The following amounts were included in HECO’s rebuttal, the Consumer Advocate’s and the DOD’s testimonies and exhibits (as adjusted to exclude the transferred surcharge amount of $12 million); the settlement agreement with the Consumer Advocate and the DOD; and the PUC’s interim D&O:


	Pre-Settlement
(dollars in millions)	HECO rebuttal		Consumer Advocate		Department of Defense		HECO (per settlement)		Interim increase¹
Net additional revenues ²	$	51	$	11	$	7	$	42	$	41
ROACE (%)		11		8.5-10		9		10.7		10.7
ROR (%)		8.83		7.85		7.71		8.66		8.66
Average rate base	$	1,109	$	1,065	$	1,062	$	1,109	$	1,109

¹	Implemented on September 28, 2005, subject to refund with interest pending the final outcome of the case.

²	Excludes $12 million transferred from a surcharge to base rates for existing energy efficiency programs.

On June 19, 2006, the PUC issued a further order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162. Act 162, which became 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 proposed by stipulations filed on June 30 and August 7, 2006 not to reopen the record in the proceeding and address the factors in Act 162 since the record had been completed before Act 162 became law, but the PUC has not yet acted on the stipulation. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed by the parties or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162, the ultimate outcome of these issues, the effect of these issues on the operation of the ECAC as it relates to the electric utilities or the timing of the PUC’s issuance of a final D&O in HECO’s pending 2005 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., including 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. If the additional revenues from the interim increase were ultimately not included in rates in the final D&O in HECO’s 2005 test year rate case, the total increase requested would be $151.5 million. 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 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 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 to be added in the second quarter of 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 requests 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 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, which request was denied. HECO has proposed in the 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 is that a higher ROACE will be required. 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.

In March 2007, a public hearing on the rate case was held. In April 2007, the PUC granted the DOD’s motion to intervene. Evidentiary hearings are scheduled to be held in the week beginning October 29, 2007.

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 includes 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. The PUC granted Keahole Defense Coalition’s motion to participate in this proceeding. 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 submitted its rebuttal to the Consumer Advocate's testimony and the Keahole Defense Coalition's statement of position. In April 2007, Keahole Defense Coalition filed a responsive statement to HELCO’s rebuttal testimonies, which HELCO responded to in May 2007.

In March and May 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement and rate design issues in the HELCO 2006 rate case proceeding. The PUC may accept or reject the settlement agreements or any part of them. If the PUC does not accept the material terms of the agreements, either (or both) of the parties, may withdraw from the agreements and may pursue their respective positions in the proceeding without prejudice. 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 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 a return on average rate base of 8.33% (incorporating a rate of return on average common equity of 10.7%). In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms (see Note 4 of HECO’s “Notes to Consolidated Financial Statements”).

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 requests 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 proposes 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 July 2007, MECO proposed tracking mechanisms for pension and OPEB, similar to the mechanisms proposed by HECO in its 2007 test year rate case and 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.

The PUC held public hearings on MECO’s application in April 2007. Evidentiary hearings are scheduled for December 2007.

Other regulatory matters

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 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 surcharge, to become effective around January 2009. The PUC indicated that a new docket will be opened to select a third-party administrator and to refine details of the new market structure. Unlike the EE DSM programs, load management DSM programs (see below) will continue to be administered by the utilities. The utilities also may compete for implementation of the EE DSM programs and the RCEA Program and the PUC did not determine any of the parameters of the eligibility of HECO or its subsidiaries or the selection criteria that will be used in awarding program implementation.

The 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 Integrated Resource Plan (IRP) framework. Specifically, during the transition period under the current utility market structure, labor costs are to be recovered through base rates, while non-labor costs will be recovered via a surcharge. 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, and residential sectors. 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.

The PUC further indicated that a new docket will be opened to approve HECO’s periodic DSM program reports and field any of HECO’s requests for DSM program modifications. The issue of decoupling sales from revenues, which had been proposed by one party to the proceeding, was deferred to a future proceeding.

On March 8, 2007, HECO filed a motion for clarification and/or partial reconsideration of the D&O which requested, among other things, clarification of certain energy efficiency goals for 2007 and 2008, reconsideration of HECO’s request for budget flexibility which would allow HECO to increase its DSM program budget within certain limits without PUC approval, and clarification of the calculation of the DSM utility incentive. On May 21, 2007, the PUC clarified the 2007 and 2008 energy efficiency goals and the calculation of the DSM utility incentive, and rejected HECO’s request for budget flexibility, but did grant HECO the ability to request program modifications by letter request.

In 2004, HECO and the Consumer Advocate reached agreement on a residential load management program and a commercial and industrial load management program and the PUC approved HECO’s programs. Implementation of these programs began in early 2005. The 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 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. In addition, if HECO interrupts the load, an incentive is paid on the kilowatthours interrupted.

Avoided cost generic docket. In May 1992, the PUC instituted a generic investigation, including all of Hawaii’s electric utilities, 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/sell power from/to the electric utility. The parties to the 1992 docket include the electric utilities, the Consumer Advocate, the DOD, and representatives of existing or potential IPPs. In March 1994, the parties entered into and filed a Stipulation to Resolve Proceeding, which is subject to PUC approval. The parties could not reach agreement with respect to certain of the issues, which are addressed in Statements of Position filed in March 1994. In July 2004, the PUC ordered the parties to review and update the agreements, information and data contained in the stipulation and file such information. On December 29, 2006, the parties filed an Updated Stipulation to Resolve Proceeding 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. The parties were not in total agreement on certain other issues which will need to be decided by the PUC. HECO and its subsidiaries, the Consumer Advocate and the DOD filed a joint statement of position that they oppose retroactive compensation to Wailuku River Hydro for transformer losses, as proposed by Mauna Kea Power Company, Inc. and the Hawaii Agriculture Research Center. In May 2007, HECO provided the Consumer Advocate, in accordance with Exhibit A of the Updated Stipulation to Resolve Proceeding, authorization to acquire HECO’s specialized version of the production simulation software to enable the Consumer Advocate to perform independent analyses to verify HECO’s results.

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 integrated resource plans (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 can begin recovering 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 and HECO now recover IRP costs through base rates and MECO continues to recover its costs through a surcharge. The Consumer Advocate has objected to the recovery of $2.9 million (before interest) of the $8.4 million of incremental IRP costs incurred by the utilities during the 1997-2005 period, and the PUC’s decision is pending on these costs. In addition, MECO incurred approximately $0.7 million of incremental IRP costs for 2006, for which the Consumer Advocate has not yet stated its position. 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 (CIP) generating unit”). In addition, HECO currently plans for all existing generating units to remain in operation (future environmental 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 will 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. 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. 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.

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 include HELCO, the Consumer Advocate, an environmental organization and HREA. An evidentiary hearing is scheduled for the end of November 2007.

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 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. The parties to the IRP-3 proceedings include MECO and the Consumer Advocate, although other persons may file written comments on the plan by September 4, 2007. An evidentiary hearing is scheduled at the beginning of October 2007.

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, the parties agreed to not issue such a notice of termination resulting in the termination of the PPA prior to the end of 2014. MECO is currently evaluating the impact of this agreement with HC&S on the timing of the different energy solutions identified in its third IRP.

HECO’s 2009 Campbell Industrial Park (CIP) generating unit. In June 2005, HECO filed with the PUC an application for approval of funds to build a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and 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 2009, fueled by biofuels, 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. The contract allows HECO to terminate the contract at a specified payment amount if necessary CT project approvals are not obtained.

In July 2006, the Honolulu City Council adopted a resolution to amend the Public Infrastructure Map to include the new generating facility at CIP. 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 May 2007, the Hawaii Department of Health issued the final air permit, which became effective at the end of June 2007. 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 the steps necessary for HECO to reach that goal. In May 2007, the PUC issued a D&O approving the Project. 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.

Costs for the Project are preliminarily estimated at $142.3 million. As of June 30, 2007, accumulated Project costs for planning, engineering, permitting and AFUDC amounted to $5.4 million.

In conjunction with the Project, HECO is evaluating bids from potential suppliers of ethanol or biodiesel for the new unit. The PUC would need to approve any resulting ethanol or biodiesel fuel supply contract.

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 $8 million (through the first 10 years of implementation).

Adequacy of supply.

HECO. HECO’s 2007 Adequacy of Supply (AOS) letter, filed in February 2007, indicates that HECO’s analysis estimates its reserve capacity shortfall to be approximately 70 MW in the 2007 to 2008 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 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 anticipates the potential for continued reserve capacity shortfalls could range between 20 MW to 110 MW in the 2009 to 2012 period, 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 install additional firm capacity is required to proceed under the guidance of the Competitive Bidding Framework issued by the PUC in December 2006.

HECO’s gross peak demand was 1,327 MW in 2004, 1,273 MW in 2005, 1,315 MW in 2006 and 1,232 MW in the first six months of 2007. Although the gross peak demand in 2005, 2006 and the first six months of 2007 was lower than in 2004, 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 2007 Adequacy of Supply letter filed in January 2007 indicated that HELCO’s generation capacity for the next three years, 2007 through 2009, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

MECO. In December 2005, MECO’s Maalaea Unit 13, a 12.34 MW diesel generator, suffered an equipment failure. In February 2007, MECO filed its 2007 Adequacy of Supply letter, which indicated that MECO’s Maui island system should usually have sufficient installed capacity to meet the forecasted loads once Maalaea Unit 13 returns to service.

In April and August 2006 and June 2007, MECO experienced lower than normal generation capacity due to the unexpected temporary loss of several of its generating units, and issued public requests that its customers voluntarily conserve electricity. In July 2007, Maalaea Unit 13 was returned to service.

2006 outages. On June 1, 2006, due to the unanticipated loss of three generating units from an IPP and two HECO generating units, HECO shed power to 29,300 customers in various parts of the island. Power was restored to all customers within four hours.

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, including bringing 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. The PUC briefings took place 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 has 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 is currently conducting its review of the outages. Under the approved procedural schedule, the docket is scheduled to run at least until October 2007.

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. Preliminary issues of the investigation identified 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 and (7) addressing how rates would be set. Current parties to this proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative and the Consumer Advocate. Twelve parties (including the Department of Defense, the City and County of Honolulu and the Counties of Hawaii, Maui and Kauai) filed motions to intervene or participate. The parties (and intervenors and participants, if any) must file a stipulated prehearing (or procedural) order to govern the matters of this investigation by August 13, 2007 for the PUC’s review and approval.

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.

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. 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 standard (RPS) law to require electric utilities to meet a renewable portfolio standard 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 they 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 PUC must, by December 31, 2007, develop and implement a utility ratemaking structure, which may include, but is not limited to, performance-based ratemaking (PBR), 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 will no longer complete the rulemaking in a process initiated in November 2004, but will instead proceed by way of this RPS Docket to handle any issues related to the utilities meeting renewable portfolio standards. The parties in 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) should the framework include a provision that provides incentives to encourage utilities to exceed the RPS or to meet their RPS ahead of time or both. The parties filed preliminary position statements in April 2007. In a supplemental filing in July 2007, HECO, HELCO and MECO proposed a Renewable Energy Infrastructure Program, including a Renewable Energy Infrastructure surcharge mechanism, to encourage the funding of renewable energy infrastructure projects. Final position statements and proposed frameworks of the parties are expected to be filed in September 2007. The PUC has a deadline to issue a D&O by December 31, 2007. Management cannot predict the outcome of this process.

See “Renewable energy strategy” under “Other developments” below.

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, a renewable energy organization and a solar vendor organization. The PUC has approved a procedural schedule with panel hearings scheduled for October 2007. Depending on their magnitude, changes made by the PUC by rule or order could have a negative effect on electric utility sales. Management cannot predict the outcome of the investigative proceeding.

DSM programs. In 2006, the PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds currently collected by the utilities and included in their revenues through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. In February 2007, the PUC issued a D&O requiring that administration of EE DSM programs be turned over to a non-utility third party administrator in 2009, to be funded through such a public benefits surcharge. See “Demand-side management programs” above for a discussion of the D&O.

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. The 2007 Hawaii State Legislature passed a measure which establishes as state policy the requirement that by January, 1, 2020, statewide greenhouse gas emissions must be reduced to levels at or below the statewide emissions levels in 1990. The legislation also establishes a greenhouse gas emissions reduction task force to prepare a plan before December 1, 2009 for implementing the maximum practically and technically feasible and cost-effective reductions in emissions to meet the State's declared policy. The Director of the Hawaii Department of Health is also required to adopt rules, before December 31, 2011, which establish emission limits for specific sources or categories of sources of emissions and provide for reporting and verification of statewide emissions and monitoring and compliance. The legislation became law in July 2007. At this time, management cannot predict the impact of such legislation on the electric utilities and the Company.

On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts v. EPA, that, contrary to EPA’s position, the EPA has the authority to regulate greenhouse gases under the Clean Air Act. Although it is too early to assess the ultimate impact of the ruling, since the decision there have been reports that comprehensive legislation may be introduced in Congress this term to regulate greenhouse gas emissions.

Renewable energy. The 2007 Hawaii State Legislature passed a measure which states that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Potentially, 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.

Biofuels. The 2007 Hawaii State Legislature passed a measure which has the stated purpose to encourage 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).

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

Other developments

Advanced Meter Infrastructure (AMI). HECO is evaluating the feasibility of utility applications using wireless technologies for two-way communication.

HECO is currently partnering with Sensus Metering Systems to field test an Advanced Metering Infrastructure system that delivers two-way communications to advanced meters, which can enable automated meter reading, time-of-use pricing and conservation options for HECO customers. This pilot includes approximately 3,000 meters, which have been installed for residential and commercial customers. Other utility applications being evaluated include distribution system line monitoring and water heater and air conditioning load control for residential and commercial customers.

Renewable energy strategy. The electric utilities continue to pursue the following three-pronged renewable energy strategy: a) promote the development of cost-effective, commercially viable renewable energy projects, b) facilitate the integration of intermittent renewable energy resources and c) encourage renewable energy research, development and demonstration projects (e.g., photovoltaic energy and the electronic shock absorber (ESA) for wind generation). They are also conducting integrated resource planning to evaluate the increased use of renewables within the electric utilities’ service territories.

The electric utilities support renewable energy through their solar water heating and heat pump programs and the negotiation and execution of purchased power contracts with nonutility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems).

HECO received a U.S. patent in February 2005 for an ESA that addresses power fluctuations from wind resources. An ESA demonstration system was installed and tested at HELCO’s Lalamilo wind farm. The demonstration confirmed the viability of the technology on a small-scale wind farm, and management plans to pursue a larger scale project in the future. HECO has an intellectual property license agreement with S&C Electric Company (S&C), the party constructing the ESA demonstration system. S&C has the right to seek international patents for the design. On October 16, 2006, the ESA demonstration system sustained structural and fire damage and is no longer operational. The impact of the loss on the electric utilities’ financial statements is immaterial. Management cannot predict the amount of royalties HECO may receive from the sale of ESAs in the future.

In December 2002, HECO formed an unregulated subsidiary, RHI, with initial approval to invest up to $10 million in selected renewable energy projects. RHI is seeking to stimulate renewable energy initiatives by prospecting for new projects and sites and taking a passive, minority interest in third party renewable energy projects greater than 1 MW in Hawaii. Since 2003, RHI has actively pursued a number of solicited and unsolicited projects. 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 agreements with project developers, no investments have been made to date.

In February 2007, BlueEarth Biofuels LLC (BlueEarth) announced plans for a new biodiesel refining plant to be built on the island of Maui by 2009. The biodiesel plant will be owned by BlueEarth Maui Biofuels LLC (BlueEarth Maui), a planned new venture between BlueEarth and a to-be-formed non-regulated subsidiary of HECO. All of the HECO non-regulated subsidiary’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 the non-regulated subsidiary of

HECO 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 plans to negotiate a fuel purchase contract with BlueEarth Maui for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the lease agreement and biodiesel fuel contract will require PUC approval.

HECO is working with the Natural Resources Defense Council to develop an environmental policy for procuring sustainable biodiesel from palm oil and locally-grown feedstocks.

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 (which includes the impact of the sale of the SPRBs on March 27, 2007 and the application of the proceeds thereof (i) to reimburse the utilities for capital expenditures and their use of the reimbursements to paydown short-term borrowings and (ii) to provide a portion of the funds required to refund two series of SPRBs originally issued in 1996) was as follows as of the dates indicated:


(in millions)	June 30, 2007				December 31, 2006
Short-term borrowings	$	53	3	%	$	113	6	%
Long-term debt		864	44			766	41
Preferred stock		34	2			34	2
Common stock equity		990	51			959	51

	$	1,941	100	%	$	1,872	100	%

As of August 1, 2007, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:


	S&P	Moody’s
Commercial paper	A-2	P-2
Revenue bonds (senior unsecured, insured)	AAA	Aaa
HECO-obligated preferred securities of trust subsidiary	BBB-	Baa2
Cumulative preferred stock (selected series)	Not rated	Baa3

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+ 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 December 2006, Moody’s confirmed its issuer ratings and stable outlook for HECO. Moody’s stated, “The rating could be downgraded should weaker than expected regulatory support emerge, including the continuation of regulatory lag, which ultimately causes earnings and sustainable cash flow to suffer.”

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 June 30, 2007, HECO had $1 million of short-term borrowings from MECO and HELCO had $39 million of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first six months of 2007 of $77 million and had $53 million of commercial paper outstanding as of June 30, 2007. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult 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. See Note 10 of HECO’s “Notes to Consolidated Financial Statements” for a description of the $175 million credit facility. As of August 1, 2007, 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.

See Note 11 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the SPRBs issued in March 2007. 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 of long-term securities for HECO, HELCO and MECO, including notes or debentures issued by the electric utilities in connection with the issuance of SPRBs, taxable unsecured notes or trust preferred securities.

Operating activities provided $46 million in net cash during the first six months of 2007. Investing activities during the same period used net cash of $70 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $25 million, primarily due to the drawdown of $95 million in SPRBs, partly offset by a $60 million net decrease in short-term borrowings and a $9 million decrease in cash overdraft.

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The following updates HECO’s disclosures about material estimates and critical accounting policies on pages 90 to 92 of HECO’s 2006 Form 10-K.

A material estimate was revised in the first quarter of 2007 when HELCO and the Consumer Advocate reached a settlement of the issues in the HELCO 2006 rate case proceeding (see “HELCO power situation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”). Under the settlement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, resulting in an after-tax charge to net income of approximately $7 million in the first quarter of 2007. If it becomes probable that the PUC, in its final order, will disallow additional costs incurred for CT-4 and CT-5 for rate-making purposes, HELCO will be required to again revise its CT-4 and CT-5 costs estimated to be recoverable and record an additional write-off.

BANK

RESULTS OF OPERATIONS


	Three months ended June 30,				% change		Primary reason(s) for significant change
(in thousands)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	107,526	$	102,556	5		Higher interest income (resulting from higher average balances on loans and other investments and higher yields on earning assets, partly offset by lower average balances on investment and mortgage-related securities) and higher noninterest income
Operating income		19,694		26,159	(25	)	Lower net interest income and higher noninterest expense and provision for loan losses, partly offset by higher noninterest income
Net income		12,582		16,218	(22	)	Lower operating income, partly offset by lower income taxes

	Six months ended June 30,				% change		Primary reason(s) for significant change
(in thousands)	2007		2006		% change		Primary reason(s) for significant change
Revenues	$	211,986	$	202,560	5		Higher interest income (resulting from higher average balances on loans and other investments and higher yields on earning assets, partly offset by lower average balances on investment and mortgage-related securities) and higher noninterest income
Operating income		38,122		53,174	(28	)	Lower net interest income and higher noninterest expense and provision for loan losses, partly offset by higher noninterest income
Net income		24,178		33,045	(27	)	Lower operating income, partly offset by lower income taxes

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

Net interest margin

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. If the current interest rate environment persists, compression of ASB’s net interest margin will continue to be a concern. 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 June 30, 2007, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 11% commercial loans, 8% commercial real estate loans and 7% consumer loans. As of December 31, 2006, ASB’s loan portfolio mix, net, consisted of 72% residential loans, 12% commercial loans, 9% 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, but the amount of advances has trended downward over the last few years. As of June 30, 2007, ASB’s costing liabilities consisted of 72% deposits and 28% other borrowings. As of December 31, 2006, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings. Higher short-term interest rates and the inverted to flat yield curve have made it challenging to retain deposits and control funding costs. Deposit retention and growth will remain a challenge in the current environment.

Other factors primarily affecting ASB’s operating results include fee income, provision for loan losses and expenses from operations.

Although higher long-term interest rates 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 June 30, 2007 and December 31, 2006, 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 $38 million and $35 million, respectively. The increase in unrealized losses was largely due to movement in the general level of interest rates within the second quarter of 2007. 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 and six months ended June 30, 2007 and 2006.


	Three months ended June 30							Six months ended June 30
	2007		2006		Change			2007		2006		Change
($ in thousands)
Loans receivable
Average balances ¹	$	3,799,888	$	3,663,737	$	136,151		$	3,802,491	$	3,624,688	$	177,803
Interest income ²		60,093		57,323		2,770			120,374		112,476		7,898
Weighted-average yield (%)		6.33		6.26		0.07			6.35		6.22		0.13
Investments and mortgage-related securities
Average balances	$	2,375,904	$	2,583,133	$	(207,229	)	$	2,379,024	$	2,594,742	$	(215,718	)
Interest income		28,833		30,055		(1,222	)		55,539		59,228		(3,689	)
Weighted-average yield (%)		4.85		4.65		0.20			4.67		4.57		0.10
Other investments ³
Average balances	$	208,761	$	165,071	$	43,690		$	206,074	$	172,841	$	33,233
Interest and dividend income		1,595		815		780			3,054		1,719		1,335
Weighted-average yield (%)		3.03		1.95		1.08			2.95		1.98		0.97
Total earning assets
Average balances	$	6,384,553	$	6,411,941	$	(27,388	)	$	6,387,589	$	6,392,271	$	(4,682	)
Interest and dividend income		90,521		88,193		2,328			178,967		173,423		5,544
Weighted-average yield (%)		5.67		5.50		0.17			5.61		5.43		0.18
Deposit liabilities
Average balances	$	4,497,760	$	4,562,344	$	(64,584	)	$	4,514,699	$	4,556,555	$	(41,856	)
Interest expense		20,832		17,001		3,831			41,570		32,394		9,176
Weighted-average rate (%)		1.86		1.49		0.37			1.86		1.43		0.43
Other borrowings
Average balances	$	1,644,677	$	1,646,164	$	(1,487	)	$	1,640,442	$	1,630,220	$	10,222
Interest expense		18,581		18,308		273			36,987		35,470		1,517
Weighted-average rate (%)		4.51		4.45		0.06			4.53		4.38		0.15
Total costing liabilities
Average balances	$	6,142,437	$	6,208,508	$	(66,071	)	$	6,155,141	$	6,186,775	$	(31,634	)
Interest expense		39,413		35,309		4,104			78,557		67,864		10,693
Weighted-average rate (%)		2.57		2.28		0.29			2.57		2.21		0.36
Net average balance	$	242,116	$	203,433	$	38,683		$	232,448	$	205,496	$	26,952
Net interest income		51,108		52,884		(1,776	)		100,410		105,559		(5,149	)
Interest rate spread (%)		3.10		3.22		(0.12	)		3.04		3.22		(0.18	)
Net interest margin (%) ⁴		3.20		3.30		(0.10	)		3.14		3.30		(0.16	)

¹	Includes nonaccrual loans.

²	Includes loan fees of $1.2 million and $1.4 million for the three months and $2.4 million and $2.8 million for the six months ended June 30, 2007 and 2006, 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 June 30, 2007).

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

Results – three months ended June 30, 2007

Net interest income before provision for loan losses for the three months ended June 30, 2007 decreased by $1.8 million, or 3%, when compared to the same period in 2006. ASB continued to increase its loans, but higher short-term interest rates and the inverted to flat yield curve made it difficult to retain deposits and control funding costs and caused ASB to experience further margin compression. Net interest margin was 3.20% in the second quarter of 2007 compared to 3.30% in the second quarter of 2006 as the impact of higher balances on loans and other investments and higher yields on earning assets were more than offset by the impact of lower balances on investment and mortgage-related securities and higher funding costs in the second quarter of 2007 compared to the second quarter of 2006. The increase in the average loan portfolio balance was due, in part, to 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 in the second quarter of 2007 decreased by $65 million, or 1%, compared to the second quarter of 2006. The shift in deposit mix from lower cost savings and checking accounts to higher cost certificates, along with the repricing of deposits, has contributed to increased funding costs.

During the second quarters of 2007 and 2006, ASB recorded provisions for loan losses of $1.2 million (primarily due to one commercial borrower) and nil, respectively.

Second quarter of 2007 noninterest income increased by $2.6 million, or 18%, when compared to the second quarter of 2006, primarily due to increases in deposit fees.

Noninterest expense for the second quarter of 2007 increased by $6.1 million, or 15%, when compared to the second quarter of 2006, primarily due to higher costs to strengthen ASB’s risk management and compliance infrastructure.

Results – six months ended June 30, 2007

Net interest income before provision for loan losses for the six months ended June 30, 2007 decreased by $5.1 million, or 5%, when compared to the same period in 2006. ASB continued to increase its loans, but the combination of higher short-term and falling long-term interest rates have made the interest rate environment significantly more challenging than it was during the first six months of 2006 and caused ASB to experience further margin compression. Net interest margin was 3.14% in the first six months of 2007 compared to 3.30% in the first six months of 2006 as the impact of higher balances on loans and other investments and higher yields on earning assets were more than offset by the impact of lower balances on investment and mortgage-related securities and higher funding costs in the first half of 2007 compared to the first half of 2006. The increase in the average loan portfolio balance was due, in part, to 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 during the first six months of 2007 decreased by $42 million, or 1%, compared to the first six months of 2006. The shift in deposit mix from lower cost savings and checking accounts to higher cost certificates, along with the repricing of deposits, has contributed to increased funding costs.

During the first half of 2006, 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. During the first half of 2007, ASB recorded a provision for loan losses of $1.2 million primarily due to one commercial borrower. As of June 30, 2007, ASB’s allowance for loan losses was 0.82% of average loans outstanding, compared to 0.85% at December 31, 2006 and 0.84% at June 30, 2006. As of June 30, 2007, ASB’s nonperforming assets to total assets was 0.11%, compared to 0.03% and 0.02% as of December 31, 2006 and June 30, 2006, respectively.


Six months ended June 30	2007			2006
(in thousands)
Allowance for loan losses, January 1	$	31,228		$	30,595
Provision for loan losses		1,200			—
Net charge-offs		(1,106	)		(294	)

Allowance for loan losses, June 30	$	31,322		$	30,301

For the first six months of 2007 noninterest income increased by $3.9 million, or 13%, when compared to the first six months of 2006, primarily due to increases in deposit fees.

Noninterest expense for the six months ended June 30, 2007 increased by $12.6 million, or 15%, when compared to the first six months of 2006, primarily due to higher legal and other litigation expenses and costs to strengthen ASB’s risk management and compliance infrastructure, which are expected to continue.

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 June 30, 2007, 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. In May 2007, ASB received a cash dividend of $147,000. Previously, ASB had received a cash dividend of $98,000 in each of February 2007 and December 2006. No dividends were received by ASB from the FHLB of Seattle during the fourth quarter of 2004, the last three quarters of 2005 and the first three quarters of 2006.

FINANCIAL CONDITION

Liquidity and capital resources


(in millions)	June 30, 2007		December 31, 2006		% change
Total assets	$	6,817	$	6,808	—
Available-for-sale investment and mortgage-related securities		2,301		2,367	(3	)
Investment in stock of FHLB of Seattle		98		98	—
Loans receivable, net		3,888		3,780	3
Deposit liabilities		4,432		4,576	(3	)
Other bank borrowings		1,718		1,569	10

As of June 30, 2007, ASB was the third largest financial institution in Hawaii based on assets of $6.8 billion and deposits of $4.4 billion.

In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3. In doing so, Moody’s 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. In doing so, S&P 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 June 30, 2007, ASB’s unused FHLB borrowing capacity was approximately $1.6 billion. As of June 30, 2007, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 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 six months of 2007, net cash provided by ASB’s operating activities was $40 million. Net cash used during the same period by ASB’s investing activities was $57 million, primarily due to purchases of investment and mortgage-related securities of $199 million and a net increase in loans receivable of $114 million, partly offset by repayments of investment and mortgage-related securities of $259 million. Net cash used in financing activities during this period was $14 million, primarily due to a net decrease in deposit liabilities of $143 million and payment of $21 million in common stock dividends, partly offset by net increases in Federal Home Loan Bank advances, securities sold under agreements to repurchase and retail repurchase agreements of $17 million, $98 million and $35 million, respectively.

As of June 30, 2007, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.7% (5.0%), a Tier-1 risk-based capital ratio of 14.2% (6.0%) and a total risk-based capital ratio of 15.0% (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 94 to 96 of HEI’s 2006 Form 10-K.

ASB’s interest-rate risk sensitivity measures as of June 30, 2007 and December 31, 2006 constitute “forward-looking statements” and were as follows:


	June 30, 2007						December 31, 2006
	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	(4.6	)%	6.65	%	(405	)	(3.8	)%	7.83	%	(341	)
+200	(3.2	)	8.04		(266	)	(2.6	)	9.09		(215	)
+100	(1.7	)	9.45		(125	)	(1.3	)	10.29		(95	)
Base	—		10.70		—		—		11.24		—
-100	1.6		11.49		79		2.0		11.64		40
-200	1.7		11.45		75		1.8		11.27		3
-300	0.1		10.75		5		0.3		10.60		(64	)

* Change from base case in basis points.

ASB’s net interest income sensitivity as of June 30, 2007 shows an increase in liability sensitivity when compared to net interest income sensitivity as of December 31, 2006. The increase in liability sensitivity was primarily due to a shift in mix of assets and liabilities between December 31, 2006 and June 30, 2007 (see ASB’s “Consolidated Statements of Income Data” in Note 4 of HEI’s “Notes to Consolidated Financial Statements”).

ASB’s base net present value (NPV) ratio as of June 30, 2007 was lower than the NPV ratio as of December 31, 2006. Because the bank’s balance sheet is liability sensitive, the increase in the level of long term interest rates resulted in a greater decline in the value of assets than liabilities, causing the NPV ratio to decline. The NPV ratio sensitivity as of December 31, 2006 indicates that the NPV ratio was expected to decline as interest rates increased.

ASB’s NPV ratio sensitivity measures as of June 30, 2007 increased when compared to the NPV ratio sensitivity measures as of December 31, 2006. The increase in the level of long term interest rates resulted in slower prepayment expectations for many of the mortgage-related assets, causing the decline in asset values relative to liability values to increase in the rising rate scenarios, resulting in the increase in sensitivity.

The computation of the prospective effects of hypothetical interest rate changes on the net interest income (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 95 of HEI’s 2006 Form 10-K 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:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of June 30, 2007. Based on their evaluations, as of June 30, 2007, 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.

Internal Control Over Financial Reporting

During the second quarter of 2007, there has been 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 June 30, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

HECO:

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 June 30, 2007. Based on their evaluations, as of June 30, 2007, 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.

Internal Control Over Financial Reporting

During the second quarter of 2007, there has been 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 June 30, 2007 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

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 33 to 42 of HEI’s 2006 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 2006 Form 10-K, as updated on page v herein.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a) For the six months ended June 30, 2007, HEI issued an aggregate of 32,600 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective June 12, 2007 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,800 shares of HEI common stock (2,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (1,000 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

HEI did not register the shares issued under the director stock plan since their issuance did not involve a “sale” as defined under Section 2(3) of the Securities Act of 1933, as amended. Participation by nonemployee directors of HEI and subsidiaries in the director stock plans is mandatory and thus does not involve an investment decision.

Item 4.

Submission of matters to a vote of security holders

HEI: The Annual Meeting of Shareholders of HEI was held on April 24, 2007. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Exchange Act of 1934. As of February 26, 2007, the record date for the Annual Meeting, there were 81,473,510 shares of common stock issued and outstanding and entitled to vote. There was no solicitation in opposition to the Class II management nominees to the Board of Directors with terms ending at the 2010 Annual Meeting as listed in the proxy statement for the meeting and all such nominees were elected to the Board of Directors. Shareholders also elected KPMG LLP as HEI’s independent registered public accounting firm for 2007.

The record of the voting of shares at the Annual Meeting is as follows:


	Shares of Common Stock
	For	Withheld	Against	Abstain	Broker nonvotes
Election of Class II Directors
Thomas B. Fargo	71,943,189	1,615,879	—	—	—
Diane J. Plotts	71,552,232	2,006,836	—	—	—
Kelvin H. Taketa	66,987,848	6,571,220	—	—	—
Jeffrey N. Watanabe	68,798,143	4,760,925	—	—	—
Election of KPMG LLP as independent registered public accounting firm	71,869,273	1,073,429	—	616,366	—

Class III Directors—Don E. Carroll, Victor Hao Li, Bill D. Mills and Barry K. Taniguchi—continue in office with terms ending at the 2008 Annual Meeting. Class I Directors—Shirley J. Daniel, Constance H. Lau, A. Maurice Myers and James K. Scott—continue in office with terms ending at the 2009 Annual Meeting.

HECO: Effective April 24, 2007, HEI, HECO’s sole common shareholder, elected by written consent in lieu of an annual meeting (1) all eleven incumbent HECO directors and (2) KPMG LLP as independent registered public accounting firm of HECO for 2007.

Item 5.

Other Information

A.	Ratio of earnings to fixed charges.


	Six months ended June 30,		Years ended December 31,
	2007	2006	2006	2005	2004	2003	2002
HEI and Subsidiaries
Excluding interest on ASB deposits	1.44	2.21	2.08	2.31	2.32	2.11	2.03
Including interest on ASB deposits	1.29	1.85	1.73	1.98	2.00	1.84	1.72
HECO and Subsidiaries	1.58	3.16	3.14	3.23	3.49	3.36	3.71

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B.	News release.

On August 6, 2007, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports Second Quarter 2007 Earnings.” See HEI Exhibit 99.1.

C.	New PUC Commissioner

Leslie Kondo, most recently the director of the State of Hawaii Office of Information Practices, has been appointed to the PUC by Governor Linda Lingle, effective July 2007, for a term to expire in June 2008. Mr. Kondo is an attorney and was in private practice prior to serving as the director of the Office of Information Practices. Continuing to serve on the PUC are Chairman Carlito Caliboso and Commissioner John Cole.

D.	HELCO PPA for renewable energy

In July 2007, HELCO signed a PPA, subject to PUC approval, to purchase renewable energy produced by a biomass-powered generation facility under development by Tradewinds Forest Products LLC and Rockland Capital Energy Investments. The biomass-based energy source will utilize the portions of wood not suitable for veneer. Under the terms of the PPA, HELCO will purchase between 2 MW and 3.6 MW of electricity on a scheduled basis. The project will also generate additional electricity to power the veneer operations, which energy could be made available to HELCO if needed to cover a generation shortfall. The project is expected to be a net consumer of carbon dioxide, reducing the amount of greenhouse gases released into the atmosphere.

Item 6.

Exhibits


HEI Exhibit 10		HEI 1990 Nonemployee Director Stock Plan, As Amended and Restated: June 12, 2007

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 2007 and 2006 and years ended December 31, 2006, 2005, 2004, 2003 and 2002

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 Eric K. Yeaman (HEI Chief Financial Officer)

HEI Exhibit 32.1		Written Statement of Constance H. Lau (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HEI Exhibit 32.2		Written Statement of Eric K. Yeaman (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HEI Exhibit 99.1		News release, dated August 6, 2007, “Hawaiian Electric Industries, Inc. Reports Second Quarter 2007 Earnings”

HEI Exhibit 99.2		Twelfth Amendment, dated August 1, 2007, to Trust Agreement between HEI and Fidelity Management Trust Company for the HEI Retirement Savings Plan

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 2007 and 2006 and years ended December 31, 2006, 2005, 2004, 2003 and 2002

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/ Eric K. Yeaman	By	/s/ Tayne S. Y. Sekimura
	Eric K. Yeaman		Tayne S. Y. Sekimura
	Financial Vice President, Treasurer		Financial Vice President
	and Chief Financial Officer		(Principal Financial Officer of HECO)
	(Principal Financial Officer of HEI)



By	/s/ Curtis Y. Harada	By	/s/ Patsy H. Nanbu
	Curtis Y. Harada		Patsy H. Nanbu
	Controller		Controller
	(Chief Accounting Officer of HEI)		(Chief Accounting Officer of HECO)

Date: August 6, 2007		Date: August 6, 2007