Edgar Filing: HAWAIIAN ELECTRIC CO INC

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2006

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


Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-8503	HAWAIIAN ELECTRIC INDUSTRIES, INC., a Hawaii corporation 900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-5662	99-0208097
1-4955	HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation 900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-7771	99-0040500

Securities registered pursuant to Section 12(b) of the Act:


Registrant	Title of each class	Name of each exchange on which registered
Hawaiian Electric Industries, Inc.	Common Stock, Without Par Value	New York Stock Exchange
Hawaiian Electric Industries, Inc.	Preferred Stock Purchase Rights	New York Stock Exchange
Hawaiian Electric Company, Inc.	Guarantee with respect to 6.50% Cumulative Quarterly Income Preferred Securities Series 2004 (QUIPS^SM)	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:


Registrant		Title of each class
Hawaiian Electric Industries, Inc.		None
Hawaiian Electric Company, Inc.		Cumulative Preferred Stock

Indicate by check mark if Registrant Hawaiian Electric Industries, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if Registrant Hawaiian Electric Industries, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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


	Aggregate market value of the voting and non- voting common equity held by non-affiliates of the registrants as of	Number of shares of common stock outstanding of the registrants as of
	June 30, 2006	June 30, 2006	February 21, 2007
Hawaiian Electric Industries, Inc. (HEI)	$2,268,395,604.61	81,275,371	81,471,220
		(Without par value)	(Without par value)

Hawaiian Electric Company, Inc. (HECO)	None	12,805,843 ($6 2/3 par value)	12,805,843 ($6 2/3 par value)

DOCUMENTS INCORPORATED BY REFERENCE

HECO Consolidated 2006 Financial Statements—Parts I, II, III and IV

HECO Consolidated Selected Financial Data—Part II

Portions of Proxy Statement of Hawaiian Electric Industries, Inc. for the 2007 Annual Meeting of Shareholders to be filed—Part III

This combined Form 10-K represents separate filings by Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc. Information contained herein relating to any individual registrant is filed by each registrant on its own behalf. Neither registrant makes any representations as to the information relating to the other registrant.

TABLE OF CONTENTS


		Page
Glossary of Terms		ii

Forward-Looking Statements		v

	PART I

Item 1.	Business	1

Item 1A.	Risk Factors	33

Item 1B.	Unresolved Staff Comments	42

Item 2.	Properties	42

Item 3.	Legal Proceedings	44

Item 4.	Submission of Matters to a Vote of Security Holders	44

Executive Officers of the Registrant (HEI)		44

	PART II

Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Securities	45

Item 6.	Selected Financial Data	46

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48

	HEI Consolidated	48

	Electric Utility	57

	Bank	76

	Certain Factors that May Affect Future Results and Financial Condition	82

	Material Estimates and Critical Accounting Policies	90

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	94

Item 8.	Financial Statements and Supplementary Data	97

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	147

Item 9A.	Controls and Procedures	147

Item 9B.	Other Information	151

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	151

Item 11.	Executive Compensation	157

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	184

Item 13.	Certain Relationships and Related Transactions, and Director Independence	186

Item 14.	Principal Accountant Fees and Services	187

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	188

Report of Independent Registered Public Accounting Firm - HEI		189

Report of Independent Registered Public Accounting Firm - HECO		190

Index to Exhibits		195

Signatures		195

GLOSSARY OF TERMS

Defined below are certain terms used in this report:


Terms		Definitions
1935 Act		Public Utility Holding Company Act of 1935
2005 Act		Public Utility Holding Company Act of 2005
AES Hawaii		AES Hawaii, Inc., formerly known as AES Barbers Point, Inc.
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 since March 15, 2001, Bishop Insurance Agency of Hawaii, Inc.) and AdCommunications, Inc. Former subsidiaries include American Savings Mortgage Co., Inc. (dissolved in July 2003), ASB Service Corporation (dissolved in January 2004) and ASB Realty Corporation (dissolved in May 2005).
BIF		Bank Insurance Fund
BLNR		Board of Land and Natural Resources of the State of Hawaii
Btu		British thermal unit
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
Chevron		Chevron Products Company, a fuel oil supplier
Company		When used in Hawaiian Electric Industries, Inc. sections, the “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries, Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, Renewable Hawaii, Inc. and HECO Capital Trust III; HEI Diversified, Inc. and its subsidiary, American Savings Bank, F.S.B. and its subsidiaries (listed under ASB); Pacific Energy Conservation Services, Inc.; HEI Properties, Inc.; HEI Investments, Inc.; Hycap Management, Inc. (in dissolution); Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries include HECO Capital Trust I (dissolved and terminated in 2004), HECO Capital Trust II (dissolved and terminated in 2004), HEI District Cooling, Inc. (dissolved in October 2003), ProVision Technologies, Inc. (sold in July 2003), HEI Leasing, Inc. (dissolved in October 2003), Hawaiian Electric Industries Capital Trust I (dissolved and terminated in 2004), HEI Preferred Funding, LP (dissolved and terminated in 2004), Malama Pacific Corp. (discontinued operations, dissolved in June 2004), ASB Service Corporation (dissolved in January 2004) and HEIPC (discontinued operations, dissolved in 2006) and its dissolved subsidiaries. (unconsolidated subsidiaries as of January 1, 2004) When used in Hawaiian Electric Company, Inc. sections, the “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries, including, without limitation, Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, Renewable Hawaii, Inc. and HECO Capital Trust III. Former subsidiaries include HECO Capital Trust I (dissolved and terminated in 2004) and HECO Capital Trust II (dissolved and terminated in 2004). (unconsolidated subsidiaries as of January 1, 2004)
Consumer Advocate		Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
CT		Combustion turbine
D&O		Decision and order
DG		Distributed generation
DOD		Department of Defense – federal
DOH		Department of Health of the State of Hawaii
DRIP		HEI Dividend Reinvestment and Stock Purchase Plan
DSM		Demand-side management
ECAC		Energy cost adjustment clause
EITF		Emerging Issues Task Force
EOTP		East Oahu Transmission Project
EPA		U.S. Environmental Protection Agency
ERL		Environmental Response Law of the State of Hawaii
FDIC		Federal Deposit Insurance Corporation
FDICIA		Federal Deposit Insurance Corporation Improvement Act of 1991
federal		U.S. Government
FERC		Federal Energy Regulatory Commission
FHLB		Federal Home Loan Bank
FICO		Financing Corporation

GLOSSARY OF TERMS (continued)


Terms		Definitions
GAAP		U. S. generally accepted accounting principles
HCPC		Hilo Coast Power Company, formerly Hilo Coast Processing Company
HC&S		Hawaiian Commercial & Sugar Company, a division of A&B-Hawaii, Inc.
HECO		Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, Renewable Hawaii, Inc. and HECO Capital Trust III. Former subsidiaries include HECO Capital Trust I (dissolved and terminated in 2004)* and HECO Capital Trust II (dissolved and terminated in 2004). (unconsolidated subsidiaries as of January 1, 2004)
HECO’s Consolidated Financial Statements		Hawaiian Electric Company, Inc.’s Consolidated Financial Statements, incorporated by reference into Parts I, II, III and IV of this Form 10-K, which is filed as HECO Exhibit 99.4
HECO’s MD&A		Hawaiian Electric Company, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 herein
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., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries include HEI District Cooling, Inc. (dissolved in October 2003), ProVision Technologies, Inc. (sold in July 2003), HEI Leasing, Inc. (dissolved in October 2003), Hawaiian Electric Industries Capital Trust I (dissolved and terminated in 2004)* and Malama Pacific Corp. (discontinued operations, dissolved in June 2004) and HEI Power Corp. (discontinued operations, dissolved in 2006). (*unconsolidated subsidiaries as of January 1, 2004)
HEI’s Consolidated Financial Statements		Hawaiian Electric Industries, Inc.’s Consolidated Financial Statements in Item 8 herein
HEI’s MD&A		Hawaiian Electric Industries, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 herein
HEI’s 2007 Proxy Statement		Portions of Hawaiian Electric Industries, Inc.’s 2007 Proxy Statement to be filed, which portions are incorporated into this Form 10-K by reference
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 direct subsidiary of Hawaiian Electric Industries, Inc. since January 2007 and formerly a wholly-owned subsidiary of HEI Power Corp.
HEIPC		HEI Power Corp., formerly a wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the parent company of numerous subsidiaries, several 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.
HEIPC Group		HEI Power Corp. and its subsidiaries
HEIPI		HEI Properties, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
HEIRSP		Hawaiian Electric Industries Retirement Savings Plan
HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HEP		Hamakua Energy Partners, L.P., formerly known as Encogen Hawaii, L.P.
HITI		Hawaiian Interisland Towing, Inc.
HRD		Hawi Renewable Development, LLC
HTB		Hawaiian Tug & Barge Corp. On November 10, 1999, HTB sold substantially all of its operating assets and the stock of Young Brothers, Limited, and changed its name to The Old Oahu Tug Services, Inc.
IPP		Independent power producer
IRP		Integrated resource plan
Kalaeloa		Kalaeloa Partners, L.P.

iii

GLOSSARY OF TERMS (continued)


Terms		Definitions
kV		kilovolt
KWH		Kilowatthour
KWP		Kaheawa Wind Power, LLC
LSFO		Low sulfur fuel oil
MBtu		Million British thermal unit
MECO		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
MSFO		Medium sulfur fuel oil
MW		Megawatt/s (as applicable)
NA		Not applicable
NM		Not meaningful
O&M		operation and maintenance
OPA		Federal Oil Pollution Act of 1990
OTS		Office of Thrift Supervision, Department of Treasury
PCB		Polychlorinated biphenyls
PECS		Pacific Energy Conservation Services, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
PGV		Puna Geothermal Venture
PPA		Power purchase agreement
PUC		Public Utilities Commission of the State of Hawaii
PURPA		Public Utility Regulatory Policies Act of 1978
QF		Qualifying Facility under the Public Utility Regulatory Policies Act of 1978
QTL		Qualified Thrift Lender
RCRA		Resource Conservation and Recovery Act of 1976
Registrant		Each of Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc.
ROACE		Return on average common equity
ROR		Return on rate base
SAIF		Savings Association Insurance Fund
SARs		Stock appreciation rights
SEC		Securities and Exchange Commission
See		Means the referenced material is incorporated by reference
ST		Steam turbine
state		State of Hawaii
Tesoro		Tesoro Hawaii Corporation dba BHP Petroleum Americas Refining Inc., a fuel oil supplier
TOOTS		The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. On November 10, 1999, HTB sold the stock of YB and substantially all of HTB’s operating assets and changed its name.
UST		Underground storage tank
VIE		Variable interest entity
YB		Young Brothers, Limited, which was sold on November 10, 1999, was formerly a wholly-owned subsidiary of Hawaiian Tug & Barge Corp.

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, North Korea’s and 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 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 operations and maintenance expenses for the electric utilities and the possibility of more frequent rate cases;

•

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

•

the effects of changes in accounting principles applicable to HEI, HECO and their subsidiaries, including the adoption of new accounting principles (such as the effects of Statement of Financial Accounting Standards (SFAS) No. 158 regarding employers’ accounting for defined benefit pension and other postretirement plans and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48 regarding uncertainty in income taxes), continued regulatory accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying FIN 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” to PPAs with independent power producers;

•

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

•

faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicing 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 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 (e.g., Item 1A. Risk Factors) and in other periodic reports 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 and its 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

ITEM 1.

BUSINESS

HEI

HEI was incorporated in 1981 under the laws of the State of Hawaii and is a holding company with its principal subsidiaries engaged in electric utility, banking and other businesses operating primarily in the State of Hawaii. HEI’s predecessor, HECO, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a result of a 1983 corporate reorganization, HECO became an HEI subsidiary and common shareholders of HECO became common shareholders of HEI.

HECO and its operating subsidiaries, Maui Electric Company, Limited (MECO) and Hawaii Electric Light Company, Inc. (HELCO), are regulated electric public utilities providing the only electric public utility service on the islands of Oahu, Maui, Lanai, Molokai and Hawaii, which islands collectively include approximately 95% of Hawaii’s population. HECO also owns all the common securities of HECO Capital Trust III (Delaware statutory trust), which was formed to effect the issuance of $50 million of cumulative quarterly income preferred securities in 2004, for the benefit of HECO, HELCO and MECO. In December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects.

Besides HECO and its subsidiaries, HEI also owns directly or indirectly the following subsidiaries: HEI Diversified, Inc. (HEIDI) (a holding company) and its subsidiary, ASB, and the subsidiaries of ASB; Pacific Energy Conservation Services, Inc. (PECS); HEI Properties, Inc. (HEIPI); HEI Investments, Inc.; Hycap Management, Inc. (in dissolution); Hawaiian Electric Industries Capital Trusts II and III (formed in 1997 to be available for trust securities financings); The Old Oahu Tug Service, Inc. (TOOTS); and HEI Power Corp. (HEIPC) (discontinued operations, dissolved in December 2006).

ASB, acquired in 1988, is the third largest financial institution in the State of Hawaii based on total assets as of December 31, 2006. ASB has subsidiaries involved in the sale and distribution of insurance products and an inactive advertising agency for ASB and its subsidiaries. Former ASB subsidiary, ASB Realty Corporation, which had elected to be taxed as a real estate investment trust, was dissolved in May 2005 (see Note 10 to HEI’s Consolidated Financial Statements under “ASB state franchise tax dispute and settlement”).

HEIPI, whose predecessor company was formed in February 1998, holds venture capital investments (in companies based in Hawaii and the U.S. mainland) with a carrying value of $2.8 million as of December 31, 2006.

HEI Investment Corp. (HEIIC), incorporated in May 1984 primarily to make passive investments in corporate securities and other long-term investments, changed its name to HEI Investments, Inc. (HEIII) in January 2000. HEIII is not an “investment company” regulated under the Investment Company Act of 1940. In February 2000, HEIII became a subsidiary of HEIPC, but, in connection with the dissolution of HEIPC and related transactions, it again is a direct subsidiary of HEI. HEIII’s long-term investments currently consist primarily of investments in leveraged leases accounted for in the Company’s continuing operations. In 2005, HEIII sold its approximate 25% interest in a trust that is the owner/lessor of a 60% undivided interest in a coal-fired electric generating plant in Georgia for a pretax gain of $14 million.

PECS was formed in 1994 and currently is a contract services company providing limited support services in Hawaii.

Hycap Management, Inc., HEI Preferred Funding, LP (a limited partnership in which Hycap Management, Inc. was the sole general partner) and Hawaiian Electric Industries Capital Trust I (a Delaware statutory trust in which HEI owned all the common securities) were formed to effect the issuance of $100 million of 8.36% HEI-obligated trust preferred securities in 1997, which securities were redeemed in April 2004. Hawaiian Electric Industries Capital Trust I and HEI Preferred Funding, LP were dissolved and terminated in 2004, and Hycap Management, Inc. began dissolution in 2004 and will terminate in 2007.

In November 1999, Hawaiian Tug & Barge Corp. (HTB) sold substantially all of its operating assets and the stock of YB for a nominal gain, changed its name to TOOTS and ceased maritime freight transportation operations. TOOTS currently administers certain employee and retiree-related benefits programs and monitors matters related to its former operations and the operations of its former subsidiary.

For information about the Company’s discontinued international power operations formerly conducted by HEIPC and its subsidiaries, see Note 14 to HEI’s Consolidated Financial Statements.

For additional information about the Company, see HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and HEI’s Consolidated Financial Statements.

The Company’s website address is www.hei.com. The information on the Company’s website is not incorporated by reference in this annual report on Form 10-K unless specifically incorporated herein by reference. HEI and HECO currently make available free of charge through this website their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports (since 1994) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC.

Electric utility

HECO and subsidiaries and service areas

HECO, HELCO and MECO are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, respectively. HECO was incorporated under the laws of the Kingdom of Hawaii (now State of Hawaii) in 1891. HECO acquired MECO in 1968 and HELCO in 1970. MECO acquired the Lanai City power plant on the island of Lanai in 1988 and all the outstanding common stock of Molokai Electric Company, Limited (currently a division of MECO) in 1989. In 2006, the electric utilities’ revenues and net income amounted to approximately 84% and 69%, respectively, of HEI’s consolidated revenues and income from continuing operations, compared to approximately 82% and 57% in 2005 and approximately 81% and 75% in 2004, respectively.

The islands of Oahu, Maui, Lanai, Molokai and Hawaii have a combined population estimated at 1.2 million, or approximately 95% of the Hawaii population, and comprise a service area of 5,766 square miles. The principal communities served include Honolulu (on Oahu), Wailuku and Kahului (on Maui) and Hilo and Kona (on Hawaii). The service areas also include numerous suburban communities, resorts, U.S. Armed Forces installations and agricultural operations. The state has granted HECO, MECO and HELCO nonexclusive franchises, which authorize the utilities to construct, operate and maintain facilities over and under public streets and sidewalks. HECO’s franchise covers the City & County of Honolulu, MECO’s franchises cover the County of Maui and the County of Kalawao, and HELCO’s franchise covers the County of Hawaii. Each of these franchises will continue in effect for an indefinite period of time until forfeited, altered, amended or repealed.

For additional information about HECO, see HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures about Market Risk” and HECO’s Consolidated Financial Statements.

Sales of electricity

The following table sets forth the number of electric customer accounts as of December 31, 2006, 2005 and 2004 and electric sales revenues by company for each of the years then ended:


Years ended December 31	2006			2005			2004
(dollars in thousands)	Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues
HECO	292,988	$	1,361,566	291,580	$	1,201,156	288,456	$	1,050,388
HELCO	76,417		338,786	73,835		293,739	71,594		240,947
MECO	64,937		343,916	63,901		301,755	61,996		250,750

	434,342	$	2,044,268	429,316	$	1,796,650	422,046	$	1,542,085

*	As of December 31.

Revenues from the sale of electricity in 2006 were from the following types of customers in the proportions shown:


	HECO		HELCO		MECO		Total
Residential	31	%	41	%	36	%	34	%
Commercial	32		40		34		34
Large light and power	36		19		29		32
Other	1		—		1		—

	100	%	100	%	100	%	100	%

Seasonality. Kilowatthour (KWH) sales of HECO and its subsidiaries follow a seasonal pattern, but they do not experience the extreme seasonal variation due to extreme weather variations like some electric utilities on the U.S. mainland. KWH sales in Hawaii tend to increase in the warmer summer months, probably as a result of increased demand for air conditioning.

Significant customers. HECO and its subsidiaries derived approximately 10% of their operating revenues from the sale of electricity to various federal government agencies in each of 2006, 2005 and 2004.

In 1995, HECO and the U.S. General Services Administration entered into a Basic Ordering Agreement under which HECO would arrange for the financing and installation of energy conservation projects at federal facilities in Hawaii. In 1996, HECO signed an umbrella Basic Ordering Agreement with the Department of Defense (DOD-BOA). In 2001, HECO signed a new DOD-BOA, which expired in 2006. In January 2007, HECO signed another new DOD-BOA, which expires in 2012. Under these and other agreements, HECO has completed energy conservation and other projects for federal agencies over the years, although the number of projects completed has decreased through the years.

Executive Order 13123, adopted in 1994, mandated that each federal agency develop and implement a program to reduce energy consumption by 35% by the year 2010 to the extent that these measures are cost effective. The 35% reduction was measured relative to the agency’s 1985 energy use. The Energy Policy Act of 2005 further mandated that federal buildings reduce energy consumption by up to 20% in fiscal year 2015 relative to base fiscal year 2003 consumption to the extent that these measures are cost effective. The Act also establishes energy conservation goals at the state level for federally funded programs; stricter conservation measures for a variety of large energy consuming products; tax credits for energy efficient homes, solar energy, fuel cells and microturbine power plants; and includes other energy-related provisions. HECO continues to work with various federal agencies to implement DSM programs that will help them achieve their energy reduction objectives. Neither HEI nor HECO management can predict with certainty the impact of federal mandates on HEI’s or HECO’s future financial condition, results of operations or liquidity.

Selected consolidated electric utility operating statistics


Years ended December 31,	2006		2005		2004		2003		2002
KWH sales (millions)
Residential		3,022.2		3,008.0		3,000.6		2,875.9		2,778.5
Commercial		3,313.3		3,288.5		3,247.3		3,168.3		3,073.6
Large light and power		3,728.8		3,742.0		3,762.6		3,676.5		3,639.2
Other		51.5		51.4		52.8		54.4		53.0

		10,115.8		10,089.9		10,063.3		9,775.1		9,544.3

KWH net generated and purchased (millions)
Net generated		6,610.8		6,485.3		6,572.5		6,280.2		6,249.7
Purchased		4,094.4		4,167.5		4,066.5		4,054.3		3,829.6

		10,705.2		10,652.8		10,639.0		10,334.5		10,079.3

Losses and system uses (%)		5.3		5.1		5.2		5.2		5.1

Energy supply (December 31)
Net generating capability—MW		1,669		1,644		1,642		1,606		1,606
Firm purchased capability—MW		535		540		529		531		510

		2,204		2,184		2,171		2,137		2,116

Net peak demand—MW ¹		1,685		1,641		1,694		1,638		1,583
Btu per net KWH generated		10,848		10,873		10,767		10,663		10,673
Average fuel oil cost per Mbtu (cents)		1,094.1		908.6		684.3		580.5		466.4

Customer accounts (December 31)
Residential		376,783		372,638		366,217		362,400		356,244
Commercial		55,493		54,647		53,854		52,659		51,386
Large light and power		567		559		555		549		551
Other		1,499		1,472		1,420		1,385		1,374

		434,342		429,316		422,046		416,993		409,555

Electric revenues (thousands)
Residential	$	690,425	$	607,031	$	527,970	$	471,697	$	426,291
Commercial		695,247		611,403		522,230		474,017		425,595
Large light and power		648,066		569,016		483,737		434,319		389,312
Other		10,530		9,200		8,148		7,758		7,028

	$	2,044,268	$	1,796,650	$	1,542,085	$	1,387,791	$	1,248,226

Average revenue per KWH sold (cents)		20.21		17.81		15.32		14.20		13.08
Residential		22.85		20.18		17.60		16.40		15.34
Commercial		20.98		18.59		16.08		14.96		13.85
Large light and power		17.38		15.21		12.86		11.81		10.70
Other		20.44		17.92		15.44		14.26		13.26

Residential statistics
Average annual use per customer account (KWH)		8,056		8,141		8,239		8,004		7,840
Average annual revenue per customer account	$	1,840	$	1,643	$	1,450	$	1,313	$	1,203
Average number of customer accounts		375,143		369,495		364,225		359,288		354,419

¹	Sum of the net peak demands on all islands served, noncoincident and nonintegrated.

Generation statistics

The following table contains certain generation statistics as of, and for the year ended, December 31, 2006. The net generating and firm purchased capability available for operation at any given time may be more or less than shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.


	Island of Oahu- HECO		Island of Hawaii- HELCO		Island of Maui- MECO		Island of Lanai- MECO		Island of Molokai- MECO		Total
Net generating and firm purchased capability (MW) as of December 31, 2006¹
Conventional oil-fired steam units	1,106.8		62.2		35.9		—		—		1,204.9
Diesel	24.6		30.8		82.5		10.3		9.6		157.8
Combustion turbines (peaking units)	101.8		—		—		—		—		101.8
Combustion turbines	—		88.9		—		—		2.2		91.1
Combined-cycle unit	—		—		113.6		—		—		113.6
Firm contract power²	434.0		84.7		16.0		—		—		534.7

	1,667.2		266.6		248.0		10.3		11.8		2,203.9

Net peak demand (MW)	1,266.0		201.3		206.4		5.5		6.2		1,685.4	³
Reserve margin	33.8	%	32.4	%	20.2	%	87.1	%	91.0	%	32.3	%
Annual load factor	73.1	%	71.1	%	70.6	%	62.6	%	71.2	%	72.5	%³
KWH net generated and purchased (millions)	8,104.9		1,254.5		1,276.9		30.2		38.7		10,705.2

¹	HECO units at normal ratings; MECO and HELCO units at reserve ratings.

Nonutility generators—HECO: 208 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired) and 46 MW (HPower, refuse-fired); HELCO: 25 MW (Puna Geothermal Venture, geothermal) and 60 MW (Hamakua Energy Partners, L.P., oil-fired); MECO: 16 MW (Hawaiian Commercial & Sugar Company, primarily bagasse-fired).

³	Noncoincident and nonintegrated.

Generating reliability and reserve margin

HECO serves the island of Oahu and HELCO serves the island of Hawaii. MECO has three separate electrical systems—one each on the islands of Maui, Molokai and Lanai. HECO, HELCO and MECO have isolated electrical systems that are not interconnected to each other or to any other electrical grid and thus, each maintain a higher level of reserve generation than is typically carried by interconnected mainland U.S. utilities, which are able to share reserve capacity. These higher levels of reserve margins are required to meet peak electric demands, to provide for scheduled maintenance of generating units (including the units operated by IPPs relied upon for firm capacity) and to allow for the forced outage of the largest generating unit in the system. Although the planning for, and installation of, adequate levels of reserve generation have contributed to the achievement of generally high levels of system reliability, HECO is below preferred levels of reserve margin and has made several public calls for energy conservation when reserves were especially narrow. See “Integrated resource planning, requirements for additional generating capacity and adequacy of supply” in HEI’s MD&A under “Electric utility.”

Integrated resource planning and requirements for additional generating capacity

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. See “Integrated resource planning, requirements for additional generating capacity and adequacy of supply” in HEI’s MD&A.

New capital projects

The capital projects of the electric utilities may be subject to various approval and permitting processes, including obtaining PUC approval of the project, air permits from the Department of Health of the State of Hawaii (DOH) and/or the U.S. Environmental Protection Agency (EPA), land use permits from the Hawaii Board of Land and Natural Resources (BLNR) and land use entitlements from the applicable county. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits could result in project delays, increased project costs and/or project abandonment. Extensive project delays and significantly increased project costs could result in a portion of

the project costs being excluded from rates. If a project is abandoned, the project costs are generally written-off to expense, unless the PUC determines that all or part of the costs may be deferred for later recovery in rates.

Significant capital projects include HECO’s East Oahu Transmission Project (see discussion in Note 11 to HECO’s Consolidated Financial Statements) and HELCO’s ST-7, currently under construction, HELCO’s West Hawaii Transmission projects and MECO’s Waena power plant expansion. HECO’s New Dispatch Center project houses a modernized Energy Management System and will be integrated with new Outage Management and Customer Information systems. The New Dispatch Center building and associated equipment and the Energy Management System became operational in 2006, with the remainder of the project expected to be completed in 2007. HECO has also requested approval from the PUC to install a new generating unit in Campbell Industrial Park (an approximately 110 MW combustion turbine scheduled for commercial operation in 2009) and a two-mile-long 138 kilovolt (kV) overhead transmission line to provide additional transmission capacity for the new generating unit as well as for existing units at Campbell Industrial Park. See discussion in “Integrated resource planning and requirements for additional generating capacity” in HEI’s MD&A under “Electric utility.”

Nonutility generation

The Company has supported state and federal energy policies which encourage the development of renewable energy sources that reduce the use of fuel oil. The Company’s renewable energy sources range from wind, geothermal and hydroelectric power, to energy produced by the burning of bagasse (sugarcane waste) and municipal waste.

HECO PPAs. HECO currently has three major PPAs. In March 1988, HECO entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended, provides that, for a period of 30 years beginning September 1992, HECO will purchase 180 MW of firm capacity. The AES Hawaii 180 MW coal-fired cogeneration plant utilizes a “clean coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). In 2003, HECO consented to AES Hawaii’s proposed refinancing and received consideration for its consent, primarily in the form of a PPA amendment that reduced the cost of firm capacity retroactive to June 1, 2003, which benefit is being passed on to ratepayers through a reduction in rates. AES Hawaii also granted HECO an option, subject to certain conditions, to acquire an interest in portions of the AES Hawaii facility site that are not needed for the existing plant operations, and which potentially could be used for the development of another coal-fired facility.

In October 1988, HECO entered into an agreement with Kalaeloa Partners, L.P. (Kalaeloa), a limited partnership whose sole general partner was an indirect, wholly-owned subsidiary of ASEA Brown Boveri, Inc. (ABB), which, through affiliates, contracted to design, build, operate and maintain the facility. The ownership of Kalaeloa was subsequently restructured and its current owners are PSEG Kalaeloa Inc., a Delaware corporation and 1% general partner, and Kalaeloa Investment Partners, L.P., a Delaware limited partnership and 99% limited partner. The agreement with Kalaeloa, as amended, provides that HECO will purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. The Kalaeloa facility is a combined-cycle operation, consisting of two oil-fired combustion turbines burning low sulfur fuel oil (LSFO) and a steam turbine that utilizes waste heat from the combustion turbines, and is designed to sell sufficient steam to be a QF. On October 12, 2004, HECO and Kalaeloa executed two amendments to the PPA: 1) Confirmation Agreement Concerning Section 5.2B(2) Of PPA and Amendment No. 5 To PPA (Amendment No. 5) and 2) Agreement For Increment Two Capacity and Amendment No. 6 To PPA (Amendment No. 6). Amendment No. 5 confirms that Kalaeloa’s facility is able to deliver 189 MW of capacity and sets the capacity payment rate for capacity above 180 MW at $112 per kilowatt per year. Amendment No. 6 provides for the purchase of up to 20 MW of additional capacity, beyond the 189 MW capacity confirmed in Amendment No. 5, at $112 per kilowatt per year. Amendment Nos. 5 and 6 became effective on September 28, 2005, when HECO received an interim decision and order (D&O) allowing the recovery of the costs of the additional 29 MW (subsequently revised to 28 MW) of additional capacity (see FIN 46R discussion in Note 3 to HECO’s Consolidated Financial Statements). Kalaeloa currently supplies HECO with 208 MW of firm capacity.

HECO also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired plant (HPower). The HPower facility currently supplies HECO with 46 MW of firm capacity. Under the amendment, HECO will purchase firm capacity until mid-2015.

HECO purchases energy on an as-available basis from two nonutility generators, which are qualifying cogeneration facilities at two oil refineries, Chevron USA, Inc. (10 MW) and Tesoro Hawaii Corporation (19 MW). These generators burn a variety of fuels available from within their refinery. HECO’s contract with Chevron USA, Inc. began in 1990 and the contract with Tesoro Hawaii Corporation began in 1984. Both contracts continue unless either party wants to terminate with 90 days notice.

The PUC has allowed rate recovery for the firm capacity and purchased energy costs related to HECO’s three major PPAs that provide a total of 434 MW of firm capacity, representing 26% of HECO’s total net generating and firm purchased capacity on Oahu as of December 31, 2006. The PUC also has allowed rate recovery for the purchased energy costs related to HECO’s as-available energy PPAs.

HELCO and MECO PPAs. As of December 31, 2006, HELCO has PPAs for 90 MW and MECO has 16 MW (includes 4 MW of system protection) of firm capacity, which PPAs have been approved by the PUC.

HELCO has a 35-year PPA with Puna Geothermal Venture (PGV) for 30 MW of firm capacity from its geothermal steam facility expiring on December 31, 2027. Since April 2002, PGV’s output has been reduced. If PGV does not provide the contracted 30 MW of capacity, the PPA provides for annual availability sanctions, which amounted to $0.7 million, $0.2 million, $0.1 million, $0.1 million and $0.1 million for 2002, 2003, 2004, 2005 and 2006, respectively. In 2005, PGV re-drilled an existing well, and drilled for a new production and a new injection well. As a result, from July 2005 through June 2006, PGV exported 30 MW to HELCO with all of its wells and converters in service. In July 2006, PGV experienced well problems, which required it to be derated to approximately 20 MW. PGV cleaned out two production wells, converted an injection well to a production well, and worked on sealing an existing injection well. As a result, PGV output steadily increased to an average 25 MW by December 2006. With the completion of the injection well repairs and permanent piping for the converted well, PGV estimates that it will restore to its full 30 MW capacity level by April 2007. PGV has indicated its intent to pursue improvements to the plant to increase its capacity by 8 MW, and to pursue negotiations with HELCO for a new or amended PPA. In November 2006, HELCO delineated to PGV the desired ancillary characteristics of an expanded PGV facility.

On October 4, 1999, HELCO entered into a PPA with Hilo Coast Power Company (HCPC) effective January 1, 2000 through December 31, 2004, whereby HELCO purchased 22 MW of firm capacity from HCPC’s coal-fired facility. HELCO terminated the PPA as of January 1, 2005.

In October 1997, HELCO entered into an agreement with Encogen, which has been succeeded by Hamakua Energy Partners, L. P. (HEP). The agreement provides that HELCO will purchase up to 60 MW (net) of firm capacity for a period of 30 years. The dual-train combined-cycle DTCC facility, which primarily burns naphtha, consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines. In December 2000, HEP began providing HELCO with firm capacity. In June 2001, HEP demonstrated 60 MW of output from the facility. Subsequently, the output deteriorated due to technical problems, but HEP returned to providing 60 MW in 2003 and has been consistently maintained since that time.

HELCO purchases energy on an as-available basis from a number of nonutility generators. Wailuku River Hydroelectric L.P., the owner of a 12.1 MW run-of-the-river hydroelectric facility, has an existing contract to provide HELCO with as-available power through May 2023.

Apollo Energy Corporation (Apollo), the owner of a 7 MW wind facility, had a contract to provide HELCO with as-available windpower through June 29, 2002 (and extending thereafter until terminated by HELCO or Apollo). HELCO and Apollo reached agreement on a PPA on October 13, 2004. The PPA enables Apollo to repower its existing facility, and install an additional 13.5 MW of capacity, for a total windfarm capacity of 20.5 MW. The PUC approved the PPA on March 10, 2005 and it became effective in April 2005. The existing 7 MW wind facility was shut down in August 2006, prior to construction of the new 20.5 MW windfarm, which will be operated by Tawhiri Power LLC, a subsidiary of Apollo. Apollo has informed HELCO that it can meet the April 2007 target for commercial operation.

On December 30, 2003, HELCO and Hawi Renewable Development, LLC (HRD) entered into a PPA under which HRD would sell energy from an expanded wind farm (approximately 10.6 MW) at HRD’s 5 MW wind farm site. It is anticipated that the output of the 10.6 MW wind farm may be limited on occasion. The PUC approved the PPA on May 14, 2004. HELCO began purchasing as-available energy from the HRD wind farm during its test period,

which began in February 2006, and the 15-year contract term started in May 2006 after HRD completed its control system acceptance test.

MECO has a PPA with Hawaiian Commercial & Sugar Company (HC&S) for 16 MW of firm capacity. The HC&S generating units primarily burn bagasse (sugar cane waste) along with secondary fuels of oil or coal. HC&S has had some difficulties in meeting its contractual obligations to MECO over the years through 2003 due to operational constraints. On June 28, 2005, MECO and HC&S agreed to extend the PPA through December 31, 2011, and from year to year thereafter, subject to termination on or after December 31, 2011 on not less than two years prior written notice by either party. MECO informed the PUC of the PPA extension by letter dated July 27, 2005.

Beginning in June 2006, MECO began purchasing as-available energy from a 30 MW windfarm at Ukumehame, Maui owned by Kaheawa Wind Power, LLC (KWP) under a PPA between MECO and KWP dated December 3, 2004. The PUC had approved the PPA on March 18, 2005.

On May 10, 2005, MECO entered into a PPA with Makila Hydro, LLC (Makila) for the purchase of as-available energy from an existing 0.5 MW hydro electric plant, which Makila has refurbished. The PPA was approved by the PUC on May 10, 2006.

The PUC has allowed rate recovery for the firm capacity and purchased energy costs for HELCO’s and MECO’s approved firm capacity and as-available energy PPAs.

Fuel oil usage and supply

The rate schedules of the Company’s electric utility subsidiaries include energy cost adjustment clauses (ECACs) under which electric rates (and consequently the revenues of the electric utility subsidiaries generally) are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. See discussion of rates and issues relating to the ECAC below under “Rates,” and “Certain factors that may affect future results and financial condition–Electric utility–Regulation of electric utility rates” and “Material estimates and critical accounting policies–Electric utility–Electric utility revenues” in HEI’s MD&A.

HECO’s steam power plants burn LSFO. HECO’s combustion turbine peaking units burn No. 2 diesel fuel (diesel). MECO’s and HELCO’s steam power plants burn medium sulfur fuel oil (MSFO) and their combustion turbine and diesel engine generating units burn diesel. The LSFO supplied to HECO is primarily derived from Chinese, Vietnamese and other Far East crude oils processed in Hawaii refineries. The MSFO supplied to MECO and HELCO is derived from U.S. domestic crude oil and various foreign crude oil grades processed in Hawaii refineries. Diesel supplies to HECO, HELCO and MECO are derived from all of the various grades of crude oil processed at the Hawaii refineries.

In March and April of 2004, HECO executed 10-year extensions of the existing contracts, commencing January 1, 2005, for the purchase of LSFO with Chevron Products Company (Chevron) and Tesoro Hawaii Corporation (Tesoro) with no material changes in the primary commercial arrangements including volumes and pricing formulas. The PUC approved these contract extensions in December 2004. The PUC currently permits the inclusion of costs incurred under these contracts in HECO’s ECAC. HECO pays market-related prices for fuel supplies purchased under these agreements. In December 2004, HECO executed long-term contracts with Chevron for the continued use of certain Chevron fuel distribution facilities and for the operation and maintenance of certain HECO fuel distribution facilities.

In March and April of 2004, HECO, HELCO and MECO executed 10-year extensions of existing contracts with Chevron and Tesoro, commencing January 1, 2005, for the purchase of diesel and MSFO, including the use of certain petroleum storage and distribution facilities, with no material changes in the primary commercial arrangements including volumes and pricing formulas. The PUC approved these contract extensions in December 2004. The electric utilities pay market-related prices for diesel and MSFO supplied under these agreements.

The diesel supplies acquired by the Lanai Division of MECO are purchased under a contract with a local petroleum wholesaler, Lanai Oil Co., Inc. An amendment extending the current supply arrangement was executed December 1, 2006 and will become effective upon the approval of the PUC for the recovery of costs incurred under the contract. Under the amendment, the term of the contract would continue through December 31, 2008.

See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 11 to HECO’s Consolidated Financial Statements.

The following table sets forth the average cost of fuel oil used by HECO, HELCO and MECO to generate electricity in the years 2006, 2005 and 2004:


	HECO		HELCO		MECO		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
2006	63.33	1,004.9	70.21	1,138.7	85.46	1,431.9	68.13	1,094.1
2005	52.61	833.1	57.44	935.4	70.88	1,188.3	56.61	908.6
2004	40.53	641.8	42.32	688.3	51.02	855.1	42.67	684.3

The average per-unit cost of fuel oil consumed to generate electricity for HECO, HELCO and MECO reflects a different volume mix of fuel types and grades. In 2006, over 99% of HECO’s generation fuel consumption consisted of LSFO. The balance of HECO’s fuel consumption was diesel. Diesel made up approximately 30% of HELCO’s and 75% of MECO’s fuel consumption. MSFO made up the remainder of the fuel consumption of HELCO and MECO. In general, MSFO is the least costly fuel, diesel is the most expensive fuel and the price of LSFO falls between the two on a per-barrel basis. During 2006, the prices of LSFO, MSFO and diesel rose with crude oil prices during the first half of the year, peaked in the May-June period and gradually fell in the year’s second half to end relatively close to the January 2006 level. The average prices paid by the utilities in 2006 for LSFO, MSFO and diesel averaged approximately 18%, 25% and 18%, respectively, above the average price paid for that grade of fuel in 2005. During 2006, the prices of LSFO, MSFO and diesel rose slightly above the levels reached in the fall of 2005 when hurricanes Katrina and Rita seriously damaged U.S. Gulf crude oil and natural gas production facilities, but declined during the late summer and fall of 2006 reflecting moderate weather and stagnating end-user demand, rising U.S. crude oil inventory levels and weakened natural gas prices, among other factors. During 2005, the prices of LSFO, MSFO and diesel rose above the levels reached at the end of 2004, reflecting demand supported by continued strong economic growth in the U.S. and China, and continued geopolitical uncertainty. Elevated price levels continued into the later part after hurricanes Katrina and Rita caused a significant, if temporary, loss in regional refinery processing capability. Thus, the average prices paid by the utilities in 2005 for LSFO, MSFO and diesel averaged approximately 30%, 33% and 37%, respectively, above the average price paid for that grade of fuel in 2004.

In December 2000, HELCO and MECO executed contracts of private carriage with Hawaiian Interisland Towing, Inc. (HITI) for the shipment of MSFO and diesel supplies from their fuel suppliers’ facilities on Oahu to storage locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. On December 10, 2001, the PUC approved these contracts and issued a final order that permits HELCO and MECO to include the fuel transportation and related costs incurred under the provisions of these agreements in their respective ECACs. The contracts provided for the employment of a new-building double-hull bulk petroleum barge (which has been in service since March 2002). The contracts were extended for a second 5-year term commencing January 1, 2007 and contain options for two additional 5-year extensions.

HITI never takes title to the fuel oil or diesel fuel, but does have custody and control while the fuel is in transit from Oahu. If there were an oil spill in transit, HITI is generally contractually obligated to indemnify HELCO and/or MECO for resulting clean-up costs, fines and damages. HITI has liability insurance coverage for oil spill related damage of $1 billion. State law provides a cap of $700 million on liability for releases of heavy fuel oil transported interisland by tank barge. In the event of a release, HELCO and/or MECO may be responsible for any clean-up, damages, and/or fines that HITI or its insurance carrier does not cover.

The prices that HECO, HELCO and MECO pay for purchased energy from nonutility generators are generally linked to the price of oil. The AES Hawaii energy prices vary primarily with an inflation indicator. The energy prices for Kalaeloa, which purchases LSFO from Tesoro, vary primarily with world LSFO prices. The HPower, HC&S and PGV energy prices are based on the electric utilities’ respective PUC-filed short-run avoided energy cost rates (which vary with their respective composite fuel costs), subject to minimum floor rates specified in their approved PPAs. HEP energy prices vary primarily with HELCO’s diesel costs.

The Company estimates that 77.2% of the net energy generated and purchased by HECO and its subsidiaries in 2007 will be generated from the burning of oil. Increases in fuel oil prices are passed on to customers through the electric utility subsidiaries’ ECACs. Any changes in the ECACs by the PUC, and/or the failure by the Company’s oil suppliers to provide fuel pursuant to the supply contracts, and/or substantial increases in fuel prices, could

adversely affect consolidated HECO’s and the Company’s financial condition, results of operations and/or liquidity. HECO generally maintains an average system fuel inventory level equivalent to 35 days of forward consumption. HELCO and MECO generally maintain an average system fuel inventory level equivalent to approximately one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and HEP require that they maintain certain minimum fuel inventory levels.

Transmission systems

HECO has 138 kV transmission and 46 kV sub-transmission lines. HELCO has 69 kV transmission and 34.5 kV transmission and sub-transmission lines. MECO has 69 kV transmission and 23 kV sub-transmission lines on Maui and 34.5 kV transmission lines on Molokai. Lanai has no transmission lines and uses 12 kV lines to distribute electricity. The electric utilities’ overhead and underground transmission and sub-transmission lines, as well as their distribution lines, are uninsured because the amount of insurance available is limited and the premiums are extremely high.

Lines are added when needed to serve increased loads and/or for reliability reasons. In some design districts on Oahu, lines must be placed underground. Under Hawaii law, the PUC generally must determine whether new 46 kV, 69 kV or 138 kV lines can be constructed overhead or must be placed underground. The process of acquiring permits and regulatory approvals for new lines can be contentious, time consuming (leading to project delays) and costly.

HECO system. HECO serves Oahu’s electricity requirements with firm capacity (net) generating units (as of December 31, 2006) located in West Oahu (1,055 MW); Waiau, adjacent to Pearl Harbor (481 MW); and Honolulu (107 MW). HECO also leases fifteen 1.64 MW generating units that provide a total of 24.6 MW (net) of firm power and are located at three substation sites, at HECO’s Kalaeloa pole yard and at HECO’s Iwilei tank farm. HECO transmits power to its service areas on Oahu through approximately 220 miles of overhead and underground 138 kV transmission lines (of which approximately 8 miles are underground) and approximately 521 miles of overhead and underground 46 kV sub-transmission lines (of which approximately 41 miles are underground). See “East Oahu Transmission Project (EOTP)” in Note 11 to HECO’s Consolidated Financial Statements for a further discussion of the transmission system and the EOTP.

HELCO system. HELCO serves the island of Hawaii’s electricity requirements with firm capacity (net) generating units (as of December 31, 2006) located in West Hawaii (78 MW) and East Hawaii (189 MW). HELCO transmits power to its service area on the island of Hawaii through approximately 468 miles of 69 kV overhead lines and approximately 173 miles of 34.5 kV overhead lines.

MECO system. MECO serves its electricity requirements with firm capacity (net) generating units (as of December 31, 2006) located on the island of Maui (232 MW), Molokai (12 MW) and Lanai (10 MW). MECO transmits power to its service area through approximately 143 miles of 69 kV overhead lines, approximately 15 miles of 34.5 kV overhead lines, and approximately 90 miles of 23 kV overhead lines.

Rates

HECO, HELCO and MECO are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation and other matters—Electric utility regulation.”

All rate schedules of HECO and its subsidiaries contain ECACs as described previously. Under current law and practices, specific and separate PUC approval is not required for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. Rate increases, other than pursuant to such automatic adjustment clauses, require the prior approval of the PUC after public and contested case hearings. PURPA requires the PUC to periodically review the ECACs of electric and gas utilities in the state, and such clauses, as well as the rates charged by the utilities generally, are subject to change. Further, Act 162 may impact the ECACs. See Act 162 discussion in “Energy cost adjustment clauses” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

See “Electric utility–Results of operations–Most recent rate requests,” “Certain factors that may affect future results and financial condition–Electric utility–Regulation of electric utility rates” and “Material estimates and critical accounting policies–Electric utility–Electric utility revenues” in HEI’s MD&A and “Energy cost adjustment clauses” in Note 11 of HECO’s “Notes to Consolidated Financial Statements.”

Public Utilities Commission and Division of Consumer Advocacy of the State of Hawaii

Carlito P. Caliboso (an attorney previously in private practice) continues to serve as Chairman of the PUC (term expiring June 30, 2010). Also serving as commissioner is John E. Cole (whose term expires June 30, 2012), who previously served as the Executive Director of the Division of Consumer Advocacy and, prior to holding that position, served as a member of the Governor of the State of Hawaii’s Policy Team, which served as advisor to the Governor on state-wide policy matters.

Commissioner Wayne H. Kimura resigned effective August 1, 2006. A replacement has not yet been announced.

Catherine P. Awakuni, an attorney formerly with the PUC staff, was named Executive Director of the Division of Consumer Advocacy effective September 18, 2006.

Competition

See “Certain factors that may affect future results and financial condition–Consolidated–Competition–Electric utility” in HEI’s MD&A.

Electric and magnetic fields

Research on potential adverse health effects from exposure to electric and magnetic fields (EMF) continues. To date, no definite relationship between EMF and health risks has been clearly demonstrated. In 1996, the National Academy of Sciences examined more than 500 studies and stated that “the current body of evidence does not show that exposure to EMFs presents a human-health hazard.” An extensive study released in 1997 by the National Cancer Institute and the Children’s Cancer Group found no evidence of increased risk for childhood leukemia from EMF. In 1999, the National Institute of Environmental Health Sciences (NIEHS) Director’s Report concluded that while EMF could not be found to be “entirely safe,” the evidence of a health risk was “weak” and did not warrant “aggressive” regulatory actions. In 2002, the NIEHS further stated that for “most health outcomes,” there is “no evidence that EMF exposures have adverse effects,” and also that there “is some evidence from epidemiology studies that exposure to power-frequency EMF is associated with an increased risk for childhood leukemia.” In the same brochure, the NIEHS further concluded that this association is “difficult to interpret in the absence of reproducible laboratory evidence or a scientific explanation that links magnetic fields with childhood leukemia.”

While EMF has not been established as a cause of any health condition by any national or international agency, EMF remains the subject of ongoing studies and evaluations. EMF has been classified as a possible human carcinogen by more than one public health organization. In 2004, the U.K. National Radiological Protection Board (NRPB) published a report that supported a precautionary approach and recommended adoption of guidelines for limiting exposure to EMF. In the U.S., there are no federal standards limiting occupational or residential exposure to 60-Hz EMF.

The implications of the foregoing reports have not yet been determined. However, these reports may raise the profile of the EMF issue for electric utilities.

HECO and its subsidiaries are monitoring the research and continue to participate in utility industry-funded studies on EMF and, where technically feasible and economically reasonable, continue to pursue a policy of prudent avoidance in the design and installation of new transmission and distribution facilities. Management cannot predict the impact, if any, the EMF issue may have on HECO, HELCO and MECO in the future.

Global warming

The Company shares the concerns of many regarding the potential effects of global warming and the human contributions to the phenomenon, including burning of fossil fuels for electricity production, transportation, manufacturing, agricultural activities and deforestation. Recognizing that effectively addressing global warming requires commitment by the private sector, all levels of government, and the public, the Company is committed to taking direct action to mitigate greenhouse gas emissions from its operations.

Currently, there are no regulatory requirements for HECO and its subsidiaries to track or reduce greenhouse gas emissions. Nonetheless, consistent with the Company’s position on global warming, HECO and its subsidiaries have been tracking carbon dioxide emissions, the primary greenhouse gas emitted by fossil fuel combustion for electricity production, since 1996 and reporting them to the federal Department of Energy. Consistent with their commitment to reduce greenhouse gas emissions, HECO and its subsidiaries have taken and continue to identify

opportunities to take direct action to reduce such emissions from their operations, including, but not limited to, creating a DSM program that fosters energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, committing to burn biofuels in HECO’s next unit, and using biodiesel for startup and shutdown of selected MECO generation units. Through its subsidiary, RHI, HECO seeks to identify and support viable technology for electricity production that will increase energy efficiency and reduce or eliminate greenhouse gas emissions.

Legislation

See “Electric utility–Results of operations–Legislation and regulation” in HEI’s MD&A.

Commitments and contingencies

See “Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” in HEI’s MD&A, Item 1A. Risk Factors, and Note 11 to HECO’s Consolidated Financial Statements for a discussion of important commitments and contingencies, including (but not limited to) HELCO’s Keahole power plant units; HECO’s East Oahu Transmission Project; and the Honolulu Harbor environmental investigation.

Bank—American Savings Bank, F.S.B.

General

ASB was granted a federal savings bank charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & Loan Association of Salt Lake City, Utah. As of December 31, 2006, ASB was the third largest financial institution in the State of Hawaii based on total assets of $6.8 billion and deposits of $4.6 billion. In 2006, ASB’s revenues and net income amounted to approximately 17% and 52%, respectively, of HEI’s consolidated revenues and income from continuing operations, compared to approximately 18% and 51% in 2005 and approximately 19% and 38% in 2004, respectively.

At the time of HEI’s acquisition of ASB in 1988, HEI agreed with the Office of Thrift Supervision’s (OTS’) predecessor regulatory agency that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital to insure that ASB would have a capital level required by the OTS was limited to a maximum aggregate amount of approximately $65.1 million. As of December 31, 2006, as a result of certain HEI contributions to ASB, HEI’s maximum obligation to contribute additional capital has been reduced to approximately $28.3 million. ASB is subject to OTS regulations on dividends and other distributions applicable to financial institutions and ASB must receive a letter of non-objection from the OTS before it can declare and pay a dividend to HEI.

ASB’s earnings depend primarily on its net interest income—the difference between the interest income earned on earning assets (loans receivable and investment and mortgage-related securities) and the interest expense incurred on costing liabilities (deposit liabilities and other borrowings, including advances from the Federal Home Loan Bank (FHLB) of Seattle and securities sold under agreements to repurchase). Other factors affecting ASB’s operating results include fee income, provision for (or reversal of) allowance for loan losses, gains or losses on sales of securities available-for-sale, and noninterest expense.

For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 4 to HEI’s Consolidated Financial Statements.

The following table sets forth selected data for ASB for the years indicated (average balances calculated using the average daily balances, except for common equity, which is calculated using the average month-end balances):


Years ended December 31	2006		2005		2004
Common equity to assets ratio
Average common equity divided by average total assets	8.25	%	8.15	%	7.10	%
Return on assets
Net income for common stock divided by average total assets	0.82		0.95		0.62
Return on common equity
Net income for common stock divided by average common equity	9.9		11.7		8.7
Tangible efficiency ratio
Total noninterest expense divided by net interest income and noninterest income	64		61		61

ASB’s tangible efficiency ratio – the cost of earning $1 of revenue – increased from 61% in 2004 to 64% in 2006 due to higher noninterest expense as a result of continued investment in employees and technology necessary to adapt and remain competitive in the banking industry and higher legal and litigation-related expenses. ASB’s ongoing challenge is to increase revenues faster than expenses.

Consolidated average balance sheet

The following table sets forth average balances of ASB’s major balance sheet categories for the years indicated (average balances have been calculated using the daily average balances, except for common equity, which is calculated using the average month-end balances):


Years ended December 31	2006		2005		2004
(in thousands)

Assets
Investment and mortgage-related securities	$	2,679,754	$	2,962,994	$	3,039,769
Loans receivable, net		3,687,673		3,411,389		3,121,878
Other		433,421		442,368		424,464

	$	6,800,848	$	6,816,751	$	6,586,111

Liabilities and stockholder’s equity
Deposit liabilities	$	4,540,292	$	4,453,762	$	4,114,070
Other borrowings		1,613,667		1,703,353		1,819,598
Other		85,920		104,009		109,544
Stockholder’s equity		560,969		555,627		542,899

	$	6,800,848	$	6,816,751	$	6,586,111

In 2006, average loans receivable increased by $276.3 million, or 8.1% over 2005 average loans receivable. Continued strength in the Hawaii economy and real estate market enabled the average residential mortgage portfolio balance to grow by $113.8 million, or 4.3% over the 2005 average residential mortgage portfolio. The average commercial loan portfolio balance increased by $95.0 million, or 27.2% due to higher commercial loan originations. The average commercial real estate loan portfolio balance was $48.1 million, or 18.4% higher than the 2005 average commercial real estate loan portfolio balance primarily due to higher construction fundings. Average consumer loan balances also grew by $21.5 million, or 8.9% over 2005 average consumer loan portfolio balances. Average deposit balances increased by $86.5 million, enabling ASB to replace other, more costly borrowings.

In 2005, the average loans receivable increased by $289.5 million, or 9.3%, over 2004 average loans receivable due to the continued strength in the Hawaii economy and real estate market. The average residential mortgage portfolio for 2005 grew by $139.8 million, or 5.6%, over the 2004 average residential mortgage portfolio. Average commercial real estate loans, net of undisbursed loan funds, increased $51.1 million, or 24.2%, over 2004 primarily due to commercial construction real estate loans originated in 2005 of $39.8 million. ASB’s average commercial portfolio increased by $65.6 million, or 23.1%, during 2005 primarily due to higher commercial loan originations. The average consumer loan portfolio increased $22.5 million, or 10.3%, from 2004. ASB’s average deposit balances increased by $339.7 million, or 8.3%, during 2005, enabling ASB to replace other borrowings and to help fund loan growth.

Asset/liability management

See HEI’s “Quantitative and Qualitative Disclosures about Market Risk.”

Interest income and interest expense

See “Results of operations—Bank” in HEI’s MD&A for a table of 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 years ended December 31, 2006, 2005 and 2004.

The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average balance) and (2) changes in volume (change in average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a pro rata basis.


(in thousands)	2006 vs. 2005									2005 vs. 2004
Increase (decrease) due to	Rate			Volume			Total			Rate			Volume			Total
Income from earning assets
Loans receivable, net	$	9,464		$	17,062		$	26,526		$	2,861		$	17,450		$	20,311
Investment and mortgage-related securities		3,781			(12,545	)		(8,764	)		6,158			(2,581	)		3,577

		13,245			4,517			17,762			9,019			14,869			23,888

Expense from costing liabilities
Deposit liabilities		13,576			7,974			21,550			(15	)		4,895			4,880
Other borrowings		6,900			(3,780	)		3,120			8,091			(4,332	)		3,759

		20,476			4,194			24,670			8,076			563			8,639

Net interest income	$	(7,231	)	$	323		$	(6,908	)	$	943		$	14,306		$	15,249

Noninterest income

In addition to net interest income, ASB has various sources of noninterest income, including fee income from credit and debit cards and fee income from deposit liabilities and other financial products and services. Noninterest income totaled approximately $59.6 million in 2006, $56.9 million in 2005 and $57.2 million in 2004. The increase in noninterest income for 2006 was due to higher fee income on deposit liabilities and gain on sale of securities, partially offset by lower income from the sale of investment and insurance products.

Lending activities

General. Loans and mortgage-related securities of $6.0 billion represented 88.1% of total assets as of December 31, 2006, compared to $6.2 billion, or 90.3%, and $6.2 billion, or 91.3%, as of December 31, 2005 and 2004, respectively. ASB’s loan portfolio consists primarily of conventional residential mortgage loans.

The following table sets forth the composition of ASB’s loan and mortgage-related securities portfolio as of the dates indicated:


December 31	2006					2005					2004					2003					2002
(dollars in thousands)	Balance			% of total		Balance			% of total		Balance			% of total		Balance			% of total		Balance			% of total
Real estate loans ¹
Conventional (1-4 unit residential)	$	2,697,422		45.0		$	2,617,194		42.4		$	2,464,133		39.9		$	2,438,573		42.1		$	2,347,446		40.9
Commercial		264,458		4.4			229,430		3.7			226,699		3.6			208,683		3.6			193,627		3.4
Construction and development		268,672		4.5			241,311		3.9			202,466		3.3			100,986		1.8			46,150		0.8

		3,230,552		53.9			3,087,935		50.0			2,893,298		46.8			2,748,242		47.5			2,587,223		45.1
Less: Deferred fees and discounts		(21,153	)	(0.4	)		(21,484	)	(0.3	)		(20,701	)	(0.3	)		(20,268	)	(0.4	)		(18,937	)	(0.3	)
Undisbursed loan funds		(124,895	)	(2.1	)		(140,271	)	(2.3	)		(132,208	)	(2.1	)		(69,884	)	(1.2	)		(21,412	)	(0.4	)
Allowance for loan losses		(13,693	)	(0.2	)		(16,212	)	(0.3	)		(15,663	)	(0.3	)		(14,734	)	(0.3	)		(23,708	)	(0.4	)

Total real estate loans, net		3,070,811		51.2			2,909,968		47.1			2,724,726		44.1			2,643,356		45.6			2,523,166		44.0

Other loans
Consumer and other		275,046		4.5			259,048		4.2			232,189		3.8			222,743		3.9			245,853		4.3
Commercial		453,151		7.6			412,816		6.7			310,999		5.0			286,068		4.9			247,114		4.3

		728,197		12.1			671,864		10.9			543,188		8.8			508,811		8.8			492,967		8.6
Less: Deferred fees and discounts		(880	)	—			(613	)	—			(526	)	—			(606	)	—			(416	)	—
Undisbursed loan funds		(132	)	—			(2	)	—			(3	)	—			(31	)	—			(1	)	—
Allowance for loan losses		(17,535	)	(0.3	)		(14,383	)	(0.2	)		(18,194	)	(0.3	)		(29,551	)	(0.5	)		(21,727	)	(0.4	)

Total other loans, net		709,650		11.8			656,866		10.7			524,465		8.5			478,623		8.3			470,823		8.2

Mortgage-related securities, net		2,218,103		37.0			2,604,920		42.2			2,928,507		47.4			2,666,619		46.1			2,736,679		47.8

Total loans and mortgage-related securities, net	$	5,998,564		100.0		$	6,171,754		100.0		$	6,177,698		100.0		$	5,788,598		100.0		$	5,730,668		100.0

¹	Includes renegotiated loans.

The following table summarizes ASB’s loan portfolio as of December 31, 2006 and 2005, excluding loans held for sale and undisbursed commercial real estate construction and development loan funds, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:


December 31	2006								2005
Due	In 1 year or less		After 1 year through 5 years		After 5 years		Total		In 1 year or less		After 1 year through 5 years		After 5 years		Total
(in millions)
Residential loans - Fixed	$	456	$	1,002	$	1,129	$	2,587	$	361	$	920	$	1,120	$	2,401
Residential loans - Adjustable		110		86		6		202		82		142		82		306

		566		1,088		1,135		2,789		443		1,062		1,202		2,707

Commercial real estate loans - Fixed		27		36		73		136		4		19		42		65
Commercial real estate loans - Adjustable		127		31		56		214		107		38		65		210

		154		67		129		350		111		57		107		275

Consumer loans – Fixed		11		18		5		34		11		19		14		44
Consumer loans – Adjustable		51		117		63		231		52		106		47		205

		62		135		68		265		63		125		61		249

Commercial loans – Fixed		69		122		54		245		109		104		51		264
Commercial loans – Adjustable		154		54		–		208		107		38		4		149

		223		176		54		453		216		142		55		413

Total loans - Fixed		563		1,178		1,261		3,002		485		1,062		1,227		2,774
Total loans - Adjustable		442		288		125		855		348		324		198		870

	$	1,005	$	1,466	$	1,386	$	3,857	$	833	$	1,386	$	1,425	$	3,644

Origination, purchase and sale of loans. Generally, residential and commercial real estate loans originated by ASB are secured by real estate located in Hawaii. As of December 31, 2006, approximately $6.2 million of loans purchased from other lenders were secured by properties located in the continental United States. For additional information, including information concerning the geographic distribution of ASB’s mortgage-related securities portfolio and the geographic concentration of credit risk, see Note 13 to HEI’s Consolidated Financial Statements.

The amount of loans originated during 2006, 2005, 2004, 2003 and 2002 were $1.3 billion, $1.4 billion, $1.4 billion, $1.6 billion and $1.2 billion, respectively. The demand for loans is primarily dependent on the Hawaii real estate market, business conditions, interest rates and loan refinancing activity. The decrease in loan originations in 2006 compared to 2005 was due to lower residential loan originations as a result of a slowdown in real estate transaction volumes and lower refinancing activity. Loan originations in 2005 approximated 2004 as higher commercial loan originations were offset by lower commercial real estate originations. The decrease in loan originations in 2004 compared to 2003 was due to a slowdown in residential refinancing activity. The increase in loan originations in 2003 was due to the strength in the Hawaii real estate market and low interest rates which had resulted in increased affordability of housing for consumers and higher loan refinancings.

Residential mortgage lending. ASB’s general policy is to require private mortgage insurance when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For nonowner-occupied residential properties, the loan-to-value ratio may not exceed 90% of the lower of the appraised value or purchase price at origination.

Construction and development lending. ASB provides both fixed- and adjustable-rate loans for the construction of one-to-four unit residential and commercial properties. Construction and development financing generally involves a higher degree of credit risk than long-term financing on improved, occupied real estate. Accordingly, construction and development loans are generally priced higher than loans secured by completed structures. ASB’s underwriting, monitoring and disbursement practices with respect to construction and development financing are designed to ensure sufficient funds are available to complete construction projects. As of December 31, 2006, 2005 and 2004, ASB had commercial real estate construction and development loans of $170 million, $149 million and $108 million and residential construction and development loans of $91 million, $93 million and $94 million, respectively. See “Loan portfolio risk elements” and “Multifamily residential and commercial real estate lending.”

Multifamily residential and commercial real estate lending. ASB provides permanent financing and construction and development financing secured by multifamily residential properties (including apartment buildings) and secured by commercial and industrial properties (including office buildings, shopping centers and warehouses) for its own portfolio as well as for participation with other lenders. In 2006, 2005 and 2004, ASB originated $102 million, $77 million and $153 million, respectively, of loans secured by multifamily or commercial and industrial properties. ASB enhanced its commercial real estate lending capabilities and plans to continue to increase commercial real estate lending in the future. One of the objectives of commercial real estate lending is to diversify ASB’s loan portfolio as commercial real estate loans tend to have higher yields and shorter durations than residential mortgage loans.

Consumer lending. ASB offers a variety of secured and unsecured consumer loans. Loans secured by deposits are limited to 90% of the available account balance. ASB offers home equity lines of credit, secured and unsecured VISA cards, checking account overdraft protection and other general purpose consumer loans. In 2006, 2005 and 2004, ASB originated $174 million, $189 million and $156 million, respectively, of consumer loans.

Commercial lending. ASB provides both secured and unsecured commercial loans to business entities. This lending activity is part of ASB’s strategic transformation to a full-service community bank and is designed to diversify ASB’s asset structure, shorten maturities, improve rate sensitivity of the loan portfolio and attract commercial checking deposits. In 2006, 2005 and 2004, ASB had gross commercial loan originations of $477 million, $436 million and $351 million, respectively.

Loan origination fee and servicing income. In addition to interest earned on loans, ASB receives income from servicing loans, for late payments and from other related services. Servicing fees are received on loans originated and subsequently sold by ASB where ASB acts as collection agent on behalf of third-party purchasers.

ASB generally charges the borrower at loan settlement a loan origination fee of 1% of the amount borrowed. See “Loans receivable” in Note 1 to HEI’s Consolidated Financial Statements.

Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of secured loans. In a foreclosure action, the property securing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold. ASB’s real estate acquired in settlement of loans represented nil, less than 0.01% and 0.01% of total assets as of December 31, 2006, 2005 and 2004, respectively.

In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (renegotiated loans). ASB had no loans that were 90 days or more past due on which interest was being accrued as of the dates presented in the table below. The following table sets forth certain information with respect to nonaccrual and renegotiated loans as of the dates indicated:


December 31	2006			2005			2004			2003			2002
(dollars in thousands)

Nonaccrual loans—
Real estate
One-to-four unit residential	$	907		$	1,394		$	2,240		$	2,784		$	9,783
Commercial		—			—			235			—			983

Total real estate		907			1,394			2,475			2,784			10,766
Consumer		346			377			411			341			1,382
Commercial		1,144			598			3,510			2,236			3,633

Total nonaccrual loans	$	2,397		$	2,369		$	6,396		$	5,361		$	15,781

Nonaccrual loans to total net loans		0.1	%		0.1	%		0.2	%		0.2	%		0.5	%

Renegotiated loans not included above—
Real estate
One-to-four unit residential	$	2,540		$	731		$	1,243		$	2,148		$	—
Commercial		3,274			3,446			3,653			3,877			7,582
Commercial		467			790			427			1,919			2,175

Total renegotiated loans	$	6,281		$	4,967		$	5,323		$	7,944		$	9,757

Nonaccrual and renegotiated loans to total net loans		0.2	%		0.2	%		0.4	%		0.4	%		0.9	%

ASB’s policy generally is to place loans on a nonaccrual status (i.e., interest accrual is suspended) when the loan becomes 90 days or more past due or on an earlier basis when there is a reasonable doubt as to its collectibility.

In 2003, the decrease in nonaccrual loans of $10.4 million was primarily due to $7.0 million lower delinquencies in residential loans as a result of improved credit quality of ASB’s loan portfolio due to the strong real estate market in Hawaii. In 2004, the increase in nonaccrual loans of $1.0 million was primarily due to an increase in commercial loans on nonaccrual status. In 2005, the decrease in nonaccrual loans of $4.0 million was primarily due to a $2.9 million payoff of a commercial loan and lower delinquencies in residential loans. In 2006, nonaccrual loans of $2.4 million approximated 2005 nonaccrual loans. A reduction in nonaccrual residential loans due to lower delinquencies was offset by higher amount of commercial loans on nonaccrual status.

Allowance for loan losses. See “Allowance for loan losses” in Note 1 to HEI’s Consolidated Financial Statements.

The following table presents the changes in the allowance for loan losses for the years indicated:


(dollars in thousands)	2006			2005			2004			2003			2002
Allowance for loan losses, January 1	$	30,595		$	33,857		$	44,285		$	45,435		$	42,224

Provision (reversal of allowance) for loan losses		1,400			(3,100	)		(8,400	)		3,075			9,750

Charge-offs
Residential real estate loans		—			—			40			892			2,345
Commercial real estate loans		—			—			—			174			441
Consumer loans		1,119			1,558			1,790			3,027			3,479
Commercial loans		766			456			2,479			2,601			1,479

Total charge-offs		1,885			2,014			4,309			6,694			7,744

Recoveries
Residential real estate loans		200			459			346			1,244			858
Commercial real estate loans		—			—			562			426			52
Consumer loans		436			525			549			586			257
Commercial loans		482			868			824			213			38

Total recoveries		1,118			1,852			2,281			2,469			1,205

Allowance for loan losses, December 31	$	31,228		$	30,595		$	33,857		$	44,285		$	45,435

Ratio of allowance for loan losses, December 31, to average loans outstanding		0.85	%		0.90	%		1.08	%		1.44	%		1.60	%

Ratio of provision for loan losses during the year to average loans outstanding		0.04	%		NM			NM			0.10	%		0.34	%

Ratio of net charge-offs during the year to average loans outstanding		0.02	%		<0.01	%		0.06	%		0.14	%		0.23	%

NM	Not meaningful.

The following table sets forth the allocation of ASB’s allowance for loan losses and the percentage of loans in each category to total loans as of the dates indicated:


December 31	2006				2005				2004				2003				2002
(dollars in thousands)	Balance		% of total		Balance		% of total		Balance		% of total		Balance		% of total		Balance		% of total
Residential real estate	$	5,682	70.6	%	$	8,613	72.1	%	$	10,137	74.4	%	$	4,031	76.9	%	$	6,246	77.6	%
Commercial real estate		7,922	11.0			7,450	10.0			5,355	9.7			6,008	7.5			6,343	6.4
Consumer		3,623	6.9			3,111	6.9			4,008	6.8			6,540	6.8			8,489	8.0
Commercial		13,801	11.5			11,139	11.0			13,986	9.1			14,758	8.8			12,118	8.0
Unallocated		200	NA			282	NA			371	NA			12,948	NA			12,239	NA

	$	31,228	100.0	%	$	30,595	100.0	%	$	33,857	100.0	%	$	44,285	100.0	%	$	45,435	100.0	%

NA	Not applicable.

In 2006, ASB’s allowance for loan losses increased by $0.6 million, compared to a decrease of $3.3 million in 2005. Continued strength in real estate and business conditions in 2006 resulted in low net charge-offs and lower historical loss ratios, which enabled ASB to largely offset the provision for loan losses as a result of loan growth with the release of reserves on existing loans. However, ASB recorded a provision for loan losses of $1.4 million in 2006, which was primarily due to a single commercial loan and is not reflective of a change in the overall credit quality of the loan portfolio.

In 2005, ASB’s allowance for loan losses decreased by $3.3 million compared to a decrease of $10.4 million in 2004. Continued strength in real estate and business conditions in 2005 resulted in lower historical loss ratios and lower net charge-offs as a result of lower delinquencies which enabled ASB to record a reversal of allowance for loan losses of $3.1 million.

In 2004, ASB’s allowance for loan losses decreased by $10.4 million compared to a decrease of $1.2 million in 2003. Considerable strength in real estate and business conditions in 2004 resulted in lower historical loss

ratios and lower net charge-offs enabled ASB to record a reversal of allowance for loan losses of $8.4 million. The allowance for loan losses for each category was also impacted by external factors affecting the national and Hawaii economy, specific industries and sectors and interest rates. In prior years, the impact of these external factors was reflected in the unallocated category of the allowance for loan losses; however, beginning in 2004 these factors are largely reflected in the allowance for loan losses allocated to each specific loan portfolio.

In 2003, ASB’s allowance for loan losses decreased by $1.2 million compared to an increase of $3.2 million in 2002. The decrease in 2003 was due to lower net charge-offs as a result of lower delinquencies. The increasing value of Hawaii real estate and continued low interest rates gave debtors the opportunity to sell their properties or refinance before defaulting. ASB also continued to improve its collection efforts. Residential, consumer and commercial real estate loan delinquencies continued to decrease during 2003 and lower loan loss reserves were required for those lines of business. The growth in the commercial loan portfolio as a result of ASB’s strategic focus of diversifying its loan portfolio from single-family home mortgages to commercial loans has required additional loan loss reserves. The unallocated component of the allowance for loan losses, which takes into consideration economic trends and differences in the estimation process that are not necessarily captured in determining the allowance for loan losses for each category, increased slightly.

Investment activities

Currently, ASB’s investment portfolio consists primarily of mortgage-related securities, stock of the FHLB of Seattle and federal agency obligations. ASB owns private-issue mortgage-related securities as well as mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA). As of December 31, 2006, the various securities rating agencies rated all of the private-issue mortgage-related securities as investment grade. ASB did not maintain a portfolio of securities held for trading during 2006, 2005 or 2004.

As of December 31, 2006, 2005 and 2004, ASB’s investment in stock of FHLB of Seattle amounted to $97.8 million, $97.8 million and $97.4 million, respectively. The weighted-average yield on investments during 2006, 2005 and 2004 was 3.16%, 1.13% and 3.29%, respectively. The amount that ASB is required to invest in FHLB stock is determined by regulatory requirements and ASB’s investment is in excess of that requirement. See “FHLB of Seattle business and capital plan” in HEI’s MD&A for a discussion of dividends on ASB’s investment in FHLB of Seattle Stock and recent events that have adversely affected those dividends. Also, see “Regulation and other matters—Bank regulation—Federal Home Loan Bank System.”

As of December 31, 2006, ASB owned private-issue mortgage related securities issued by Countrywide Financial with an aggregate book and market value of $148 million.

The following table summarizes ASB’s investment portfolio (excluding stock of the FHLB of Seattle, which has no contractual maturity), as of December 31, 2006, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:


Due	In 1 year or less			After 1 year through 5 years			After 5 years through 10 years			After 10 years			Total
(dollars in millions)

Federal agency obligations	$	100		$	49		$	—		$	—		$	149
FNMA, FHLMC and GNMA		353			990			292			68			1,703
Private issue		177			294			43			1			515

	$	630		$	1,333		$	335		$	69		$	2,367

Weighted average yield		4.45	%		4.25	%		5.06	%		5.30	%

Note: ASB does not currently invest in tax exempt obligations.

Deposits and other sources of funds

General. Deposits traditionally have been the principal source of ASB’s funds for use in lending, meeting liquidity requirements and making investments. ASB also derives funds from the receipt of interest and principal on outstanding loans receivable and mortgage-related securities, borrowings from the FHLB of Seattle, securities sold under agreements to repurchase and other sources. ASB borrows on a short-term basis to compensate for seasonal or other reductions in deposit flows. ASB also may borrow on a longer-term basis to support expanded lending or investment activities. Advances from the FHLB and securities sold under agreements to repurchase continue to be a significant source of funds, but they are a higher cost of funds than deposits.

Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow in 2006, 2005 and 2004, measured as the year-over-year difference in year-end deposits, was $18.1 million, $261 million and $270 million, respectively.

The following table illustrates the distribution of ASB’s average deposits and average daily rates by type of deposit for the years indicated. Average balances have been calculated using the average daily balances.


Years ended December 31	2006								2005						2004
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %
Savings	$	1,609,070	35.4	%	0.83	%	$	1,721,988	38.7	%	0.51	%	$	1,613,856	39.2	%	0.40	%
Checking		1,155,687	25.5		0.09			1,151,345	25.8		0.05			1,019,464	24.8		0.03
Money market		226,837	5.0		1.69			288,731	6.5		0.89			322,806	7.8		0.45
Certificate		1,548,698	34.1		3.58			1,291,698	29.0		3.10			1,157,944	28.2		3.36

Total deposits	$	4,540,292	100.0	%	1.62	%	$	4,453,762	100.0	%	1.17	%	$	4,114,070	100.0	%	1.15	%

As of December 31, 2006, ASB had $529.7 million in certificate accounts of $100,000 or more, maturing as follows:


(in thousands)	Amount
Three months or less	$	230,258
Greater than three months through six months		141,775
Greater than six months through twelve months		85,148
Greater than twelve months		72,552

	$	529,733

Deposit-insurance premiums and regulatory developments. On February 8, 2006, the Federal Deposit Insurance Reform Act of 2005 (the Reform Act) became law. One of the provisions of the Reform Act was to merge the Savings Association Insurance Fund (SAIF) and the Bank Insurance Fund (BIF) into a new fund, the Deposit Insurance Fund. This change was made effective March 31, 2006. The Financing Corporation (FICO) will continue to impose an assessment on deposits.

For a discussion of recent changes to the deposit insurance system, premiums and FICO assessments, see “Bank regulation—Deposit insurance coverage.”

Other borrowings. ASB may obtain advances from the FHLB of Seattle provided certain standards related to creditworthiness have been met. Advances are secured by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral pledged to the FHLB of Seattle, the excess must be covered by qualified marketable securities held under the control of and at the FHLB of Seattle or at an approved third party custodian. FHLB advances generally are available to meet seasonal and other withdrawals of deposit accounts, to expand lending and to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to time by the FHLB of Seattle.

As of December 31, 2006, 2005 and 2004, advances from the FHLB amounted to $0.7 billion, $0.9 billion and $1.0 billion, respectively. The weighted-average rates on the advances from the FHLB outstanding as of December 31, 2006, 2005 and 2004 were 4.92%, 4.53% and 4.48%, respectively. The maximum amount outstanding at any month-end during 2006, 2005 and 2004 was $0.9 billion, $1.1 billion and $1.0 billion,

respectively. Advances from the FHLB averaged $0.8 billion during 2006 and $1.0 billion during each of 2005 and 2004 and the approximate weighted-average rate on the advances was 4.75%, 4.48% and 4.43%, respectively.

See “Securities sold under agreements to repurchase” in Note 4 of HEI’s Consolidated Financial Statements.

The following table sets forth information concerning ASB’s advances from the FHLB and securities sold under agreements to repurchase as of the dates indicated:


December 31	2006			2005			2004
(dollars in thousands)

Advances from the FHLB	$	730,000		$	935,500		$	988,231
Securities sold under agreements to repurchase		838,585			686,794			811,438

Total other borrowings	$	1,568,585		$	1,622,294		$	1,799,669

Weighted-average rate		4.55	%		4.23	%		4.01	%

Competition

The banking industry in Hawaii is highly competitive. ASB is the third largest financial institution in Hawaii based on total assets and is in direct competition for deposits and loans, not only with the two larger institutions, but also with smaller institutions that are heavily promoting their services in certain niche areas, such as providing financial services to small and medium-sized businesses. ASB’s main competitors are banks, savings associations, credit unions, mortgage bankers, mortgage brokers, finance companies and brokerage firms. These competitors offer a variety of financial products to retail and business customers.

The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation and perceptions of the institution’s financial soundness and safety. Competition for deposits comes primarily from other savings institutions, commercial banks, credit unions, money market and mutual funds and other investment alternatives. In Hawaii, there were 9 Federal Deposit Insurance Corporation (FDIC)-insured financial institutions, of which 2 were thrifts and 7 were commercial banks, and approximately 100 credit unions as of December 31, 2006. Additional competition for deposits comes from various types of corporate and government borrowers, including insurance companies. To meet competition, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch and convenient automated teller machines. ASB also conducts advertising and promotional campaigns.

The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending products and services offered. Competition for origination of first mortgage loans comes primarily from mortgage banking and brokerage firms, commercial banks, other savings institutions, insurance companies and real estate investment trusts. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the types of mortgage loan programs it offers and the efficiency and quality of the services it provides its borrowers and the real estate business community.

In 2002, ASB began implementing a strategic plan to move from its traditional position as a thrift institution, focused on retail banking and residential mortgages, to a full-service community bank. To make the shift, ASB has continued to build its commercial and commercial real estate lines of business. The origination of commercial and commercial real estate loans involves risks different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for mortgage loans. These different risk factors are considered in the underwriting and pricing standards established by ASB for its commercial and commercial real estate loans.

As a result of the transformation, ASB is now a full service community bank serving both consumer and commercial customers. ASB will continue to invest in projects and opportunities that will build core franchise value and add to earnings growth and returns. Additionally, the banking industry is constantly changing and ASB is continuously making the changes and investments necessary to adapt and remain competitive.

See “Certain factors that may affect future results and financial condition—Bank—Regulation of ASB—Federal Thrift Charter” in HEI’s MD&A for a discussion of the Gramm-Leach-Bliley Act of 1998.

Regulation and other matters

Holding company regulation. HEI and HECO are each holding companies within the meaning of the Public Utility Holding Company Act of 2005 and implementing regulations (2005 Act) and filed a required notification of that status on February 21, 2006. The 2005 Act makes holding companies and certain of their subsidiaries subject to certain rights of the Federal Energy Regulatory Commission (FERC) to have access to books and records relating to FERC’s jurisdictional rates, and also imposes certain record retention, accounting and reporting requirements. HEI and HECO filed a FERC Form 65B seeking a waiver of these record retention, accounting and reporting requirements. A written notice dated May 26, 2006 was received from FERC confirming the effectiveness of the HEI and HECO waivers.

HEI is subject to an agreement entered into with the PUC (the PUC Agreement) when HECO became a subsidiary of HEI. The PUC Agreement, among other things, requires HEI to provide the PUC with periodic financial information and other reports concerning intercompany transactions and other matters. It prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common stock of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the electric utility subsidiaries to pay dividends on their common stock. See “Restrictions on dividends and other distributions” and “Electric utility regulation” (regarding the PUC review of the relationship between HEI and HECO).

As a result of the acquisition of ASB, HEI and HEIDI are subject to OTS registration, supervision and reporting requirements as savings and loan holding companies. In the event the OTS has reasonable cause to believe that the continuation by HEI or HEIDI of any activity constitutes a serious risk to the financial safety, soundness, or stability of ASB, the OTS is authorized under the Home Owners’ Loan Act of 1933, as amended, to impose certain restrictions in the form of a directive to HEI and any of its subsidiaries, or HEIDI and any of its subsidiaries. Such possible restrictions include limiting (i) the payment of dividends by ASB; (ii) transactions between ASB, HEI or HEIDI, and the subsidiaries or affiliates of ASB, HEI or HEIDI; and (iii) the activities of ASB that might create a serious risk that the liabilities of HEI and its other affiliates, or HEIDI and its other affiliates, may be imposed on ASB. See “Restrictions on dividends and other distributions.”

OTS regulations also generally prohibit savings and loan holding companies and their nonthrift subsidiaries from engaging in activities other than those which are specifically enumerated in the regulations. However, the OTS regulations provide for an exemption which is available to HEI and HEIDI if ASB satisfies the qualified thrift lender (QTL) test discussed below. See “Bank regulation—Qualified thrift lender test.” ASB met the QTL test at all times during 2006, but the failure of ASB to satisfy the QTL test in the future could result in a need to divest ASB. If such divestiture were to be required, federal law limits the entities that might be eligible to acquire ASB.

HEI and HEIDI are prohibited, directly or indirectly, or through one or more subsidiaries, from (i) acquiring control of, or acquiring by merger or purchase of assets, another insured institution or holding company thereof, without prior written OTS approval; (ii) acquiring more than 5% of the voting shares of another savings association or savings and loan holding company which is not a subsidiary; or (iii) acquiring or retaining control of a savings association not insured by the FDIC.

Restrictions on dividends and other distributions. HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, the principal sources of its funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The rights of HEI and, consequently, its creditors and shareholders, to participate in any distribution of the assets of any of its subsidiaries is subject to the prior claims of the creditors and preferred stockholders of such subsidiary, except to the extent that claims of HEI in its capacity as a creditor are recognized.

The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of total electric utility capitalization (including in capitalization the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would be restricted, unless they obtained PUC approval, in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also provides that the foregoing dividend restriction shall not be construed to relinquish any right the PUC may have to review the dividend policies of the electric utility

subsidiaries. As of December 31, 2006, the consolidated common stock equity of HEI’s electric utility subsidiaries was 54% of their total capitalization (as calculated for purposes of the PUC Agreement). As of December 31, 2006, HECO and its subsidiaries had common stock equity of $958 million (which was reduced to that level as a result of an accumulated other comprehensive income (AOCI) charge of $127 million related to retirement benefit plans) of which approximately $431 million was not available for transfer to HEI without regulatory approval.

The ability of ASB to make capital distributions to HEI and other affiliates is restricted under federal law. Subject to a limited exception for stock redemptions that do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohibited from declaring any dividends, making any other capital distributions, or paying a management fee to a controlling person if, following the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. See “Bank regulation—Prompt corrective action.” All capital distributions are subject to a prior indication of no objection by the OTS. Also see Note 12 to HEI’s Consolidated Financial Statements.

HEI and its subsidiaries are also subject to debt covenants, preferred stock resolutions and the terms of guarantees that could limit their respective abilities to pay dividends. The Company does not expect that the regulatory and contractual restrictions applicable to HEI or its direct and indirect subsidiaries will significantly affect the operations of HEI or its ability to pay dividends on its common stock.

Electric utility regulation. The PUC regulates the rates, issuance of securities, accounting and certain other aspects of the operations of HECO and its electric utility subsidiaries. See the previous discussion under “Electric utility—Rates” and the discussions under “Electric utility–Results of operations–Most recent rate requests” and “Certain factors that may affect future results and financial condition–Electric utility–Regulation of electric utility rates” in HEI’s MD&A.

Any adverse decision or policy made or adopted by the PUC, or any prolonged delay in rendering a decision, could have a material adverse effect on consolidated HECO’s and the Company’s financial condition, results of operations or liquidity.

The PUC has ordered the electric utility subsidiaries to develop plans for the integration of demand- and supply-side resources available to meet consumer energy needs efficiently, reliably and at the lowest reasonable cost. See the previous discussion under “Electric utility—Integrated resource planning and requirements for additional generating capacity.”

In 1996, the PUC issued an order instituting a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. In October 2003, the PUC closed the competition proceeding and opened investigative proceedings on two specific issues (competitive bidding and distributed generation (DG)) to move toward a more competitive electric industry environment under cost-based regulation. For a discussion of the D&Os issued by the PUC in the competitive bidding and DG proceedings, see “Certain factors that may affect future results and financial condition–Consolidated–Competition–Electric utility” in HEI’s MD&A.

Certain transactions between HEI’s electric public utility subsidiaries (HECO, HELCO and MECO) and HEI and affiliated interests are subject to regulation by the PUC. All contracts (including summaries of unwritten agreements) made on or after July 1, 1988 of $300,000 or more in a calendar year for management, supervisory, construction, engineering, accounting, legal, financial and similar services and for the sale, lease or transfer of property between a public utility and affiliated interests must be filed with the PUC to be effective, and the PUC may issue cease and desist orders if such contracts are not filed. All such affiliated contracts for capital expenditures (except for real property) must be accompanied by comparative price quotations from two nonaffiliates, unless the quotations cannot be obtained without substantial expense. Moreover, all transfers of $300,000 or more of real property between a public utility and affiliated interests require the prior approval of the PUC and proof that the transfer is in the best interest of the public utility and its customers. If the PUC, in its discretion, determines that an affiliated contract is unreasonable or otherwise contrary to the public interest, the utility must either revise the contract or risk disallowance of the payments for ratemaking purposes. In ratemaking proceedings, a utility must also prove the reasonableness of payments made to affiliated interests under any affiliated contract of $300,000 or more by clear and convincing evidence. An “affiliated interest” is defined by statute and includes officers and directors of a public utility, every person owning or holding, directly or indirectly, 10% or more of the voting securities of a public utility, and corporations which have in common with a public utility more than one-third of the directors of that public utility.

In January 1993, to address community concerns expressed at the time, HECO proposed that the PUC initiate a review of the relationship between HEI and HECO and the effects of that relationship on the operations of HECO. The PUC opened a docket and initiated such a review and in May 1994, the PUC selected a consultant. The consultant’s 1995 report concluded that “on balance, diversification has not hurt electric ratepayers.” Other major findings were that (1) no utility assets have been used to fund HEI’s nonutility investments or operations, (2) management processes within the electric utilities operate without interference from HEI and (3) HECO’s access to capital did not suffer as a result of HEI’s involvement in nonutility activities and that diversification did not permanently raise or lower the cost of capital incorporated into the rates paid by HECO’s utility customers. In December 1996, the PUC issued an order that adopted the report in its entirety, ordered HECO to continue to provide the PUC with status reports on its compliance with the PUC agreement (pursuant to which HEI became the holding company of HECO) and closed the investigation and proceeding. In the order, the PUC also stated that it adopted the recommendation of the federal Department of Defense (DOD) that HECO, HELCO and MECO present a comprehensive analysis of the impact that the holding company structure and investments in nonutility subsidiaries have on a case-by-case basis on the cost of capital to each utility in future rate cases and remove such effects from the cost of capital. The PUC has accepted, in subsequent HELCO and MECO rate cases, the presentations made by HELCO and MECO that there was no such impact in those cases. HECO made a similar presentation in its current 2005 test-year rate case, which was accepted by the PUC pending the final D&O. See also “Holding company regulation” above.

HECO and its electric utility subsidiaries are not subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act, except under Sections 210 through 212 (added by Title II of PURPA and amended by the Energy Policy Act of 1992), which permit the Federal Energy Regulatory Commission to order electric utilities to interconnect with qualifying cogenerators and small power producers, and to wheel power to other electric utilities. Title I of PURPA, which relates to retail regulatory policies for electric utilities, and Title VII of the Energy Policy Act of 1992, which addresses transmission access, also apply to HECO and its electric utility subsidiaries. HECO and its electric utility subsidiaries are also required to file various financial and operational reports with the Federal Energy Regulatory Commission. The Company cannot predict the extent to which cogeneration or transmission access will reduce its electrical loads, reduce its current and future generating and transmission capability requirements or affect its financial condition, results of operations or liquidity.

Because they are located in the State of Hawaii, HECO and its subsidiaries are exempt by statute from limitations set forth in the Powerplant and Industrial Fuel Act of 1978 on the use of petroleum as a primary energy source.

Bank regulation. ASB, a federally chartered savings bank, and its holding companies are subject to the regulatory supervision of the OTS and, in certain respects, the FDIC. See “Holding company regulation” above. In addition, ASB must comply with Federal Reserve Board (FRB) reserve requirements.

Deposit insurance coverage. The Federal Deposit Insurance Act, as amended by the Federal Deposit Insurance Corporation Insurance Act of 1991 (FDICIA) and the federal deposit insurance reform which became law on February 8, 2006, and regulations promulgated by the FDIC, govern insurance coverage of deposit amounts. Generally, the deposits maintained by a depositor in an insured institution are insured to $100,000, with the amount of all deposits held by a depositor in the same capacity (even if held in separate accounts) aggregated for purposes of applying the $100,000 limit.

Among other things, the major reform of 2006: merges the BIF and the SAIF; indexes the $100,000 deposit insurance to inflation beginning in 2010 and every five years thereafter; gives the FDIC and the National Credit Union Administration authority to determine whether raising the standard $100,000 deposit insurance limit is warranted; increases to $250,000 the deposit insurance limit for certain retirement accounts; and authorizes the FDIC to assess risk-based premiums. Under the new FDIC rules assessing risk-based premiums, which became effective on January 1, 2007, ASB is classified in Risk Category I, the lowest risk group. For 2007, financial institutions in Risk Category I will have an assessment rate within the range of 5 to 7 basis points. Based upon its component ratings under the Uniform Financial Institutions Ratings System (i.e., the CAMELS rating system) and five financial ratios specified in the new FDIC rules, ASB anticipates that its assessment rate for 2007 will be approximately 5 basis points, which would result in an assessment amount of approximately $2.4 million. This

compares to no assessment amount for 2006 and 2005. FICO will continue to impose an assessment on deposits to service the interest on FICO bond obligations. ASB’s annual FICO assessment is 1.24 cents per $100 of deposits as of September 30, 2006. Also as a result of the federal deposit insurance reform, certain financial institutions will be entitled to a one-time assessment credit, which may be used to offset up to 90% of annual deposit insurance assessments (not including FICO assessments). The FDIC has calculated ASB’s one-time assessment credit at approximately $3 million. This one-time credit will offset 90% of ASB’s 2007 assessment with the balance available to offset a portion of ASB’s 2008 assessment.

Federal thrift charter. See “Certain factors that may affect future results and financial condition—Bank—Regulation of ASB—Federal Thrift Charter” in HEI’s MD&A.

Legislation. The Gramm-Leach-Bliley Act of 1998 (the Gramm Act) and implementing regulations imposed on financial institutions an obligation to protect the security and confidentiality of its customers’ nonpublic personal information. The Gramm Act also requires public disclosure of certain agreements entered into by insured depository institutions and their affiliates in fulfillment of the Community Reinvestment Act of 1977, and the filing of an annual report with the appropriate regulatory agencies.

On December 26, 2006, the SEC and the Federal Reserve Board, following consultation with the other federal financial regulatory agencies, issued for public comment a set of proposed final rules to implement the Gramm Act’s exemptions for financial institutions from the definition of “broker” in the Securities and Exchange Act of 1934, which rules would address issues arising out of “networking” arrangements whereby a financial institution refers its customers to a broker-dealer for securities services and employees of the financial institution are permitted to receive from the broker-dealer a “nominal fee” for such referrals. ASB does have a networking arrangement with UVEST Financial Services, but has not yet had an opportunity to evaluate the impact of the proposed rules on that arrangement. ASB will continue to monitor regulatory developments.

The International Money Laundering Abatement and Financial Anti-Terrorism Act of 2001 (the 2001 Act), which is part of the USA Patriot Act, imposes on financial institutions a wide variety of additional obligations with respect to such matters as collecting information, monitoring relationships and reporting suspicious activities. The 2001 Act also requires financial institutions to establish anti-money laundering programs and, with respect to correspondent and private banking accounts of non-U.S. persons, to implement appropriate due diligence policies to detect money laundering activities carried out through such accounts.

The Fair and Accurate Credit Transactions Act of 2003 (the FACT Act) amended the Fair Credit Reporting Act of 1978 to enhance the ability of consumers to combat identity theft, to increase the accuracy of consumer reports, to allow consumers to exercise greater control of the type and number of solicitations they receive, and to restrict the use and distribution of sensitive medical information.

The agencies have implemented provisions of the FACT Act to, among other things, require each financial institution, including thrifts, to develop, implement and maintain, as part of its existing information security program, appropriate measures to properly dispose of consumer information such as that derived from consumer reports.

Capital requirements. The OTS has set three capital standards for thrifts, each of which must be no less stringent than those applicable to national banks. As of December 31, 2006, ASB was in compliance with all of the minimum standards with a core capital ratio of 7.6% (compared to a 4.0% requirement), a tangible capital ratio of 7.6% (compared to a 1.5% requirement) and total risk-based capital ratio of 14.7% (based on risk-based capital of $541.5 million, $246.7 million in excess of the 8.0% requirement).

The OTS requires that thrifts with a composite rating of “1” under the Uniform Financial Institution Rating System (i.e., CAMELS rating system) must maintain core capital in an amount equal to at least 3% of adjusted total assets. All other institutions must maintain a minimum core capital of 4% of adjusted total assets, and higher capital ratios may be required if warranted by particular circumstances. As of December 31, 2006, ASB met the applicable minimum core capital requirement.

On January 1, 2002, new OTS regulations went into effect with respect to the regulatory capital treatment of recourse obligations, residual interests, direct credit substitutes and asset- and mortgage-backed securities. These regulations have had a slight positive impact on ASB’s risk-based capital.

Current OTS risk-based capital requirements are based on an internationally agreed-upon framework for capital measurement (the 1988 Accord) that was developed by the Basel Committee on Banking Supervision (BCBS). In

April 2003, BCBS released for comment proposed revisions to the 1988 Accord. A set of further proposed revisions was released by BCBS in June 2004. (These two sets of revisions are collectively referred to as “Basel II”.) On September 25, 2006, following more than three years of consultation with U.S. financial institutions on the implementation of Basel II, the federal financial institution regulatory agencies, including the OTS, issued two notices of proposed rulemaking to change U.S. risk-based capital requirements in light of Basel II. The first such notice (referred to by the agencies as the “Basel II NPR”) dealt with proposed changes to capital requirements for credit and operational risks. These changes are proposed to be mandatory for financial institutions with consolidated total assets of $250 billion or more or consolidated total on-balance-sheet foreign exposure of $10 billion or more. The second notice of proposed rulemaking concerned changes to capital requirements for market risk. Unlike the currently existing market risk rules, the proposed new rules would apply to thrifts. The new market risk rules would be mandatory for financial institutions with consolidated trading activity (in, for example, foreign exchange and commodity positions, as well as traded credit products such as credit default swaps and transfer of collateralized debt obligations) equal to at least 10% of total assets or $1 billion.

The review of U.S. risk-based capital requirements given impetus by Basel II resulted in the agencies’ issuance on December 26, 2006 of a notice of proposed rulemaking (referred to by the agencies as the “Basel IA NPR”) addressing the risk-based capital requirements for credit and operational risk of those financial institutions that will not come within the scope of the Basel II NPR. The Basel IA NPR gives financial institutions not subject to Basel II the option of using existing risk-based capital rules for credit and operational risk or applying the rules proposed in the Basel IA NPR. The changes proposed in the Basel IA NPR would attempt to improve the risk sensitivity of the capital rules by: increasing the number of risk weight categories for credit exposures; expanding the use of external credit ratings to weigh the risk of certain exposures; expanding the range of eligible collateral and guarantors used to mitigate credit risk; using loan-to-value ratios to risk weight most residential mortgages; increasing the credit conversion factor for certain commitments with an original maturity of one year or less; assessing a risk-based capital charge to reflect the early amortization risk in securitizations of revolving exposures; and removing the 50% limit on the risk weight for certain derivative transactions. ASB believes that the Basel IA NPR proposals would, if adopted by OTS in their current form and implemented by ASB, result in some improvement in its risk-based capital ratios. The agencies’ announced intention is to adopt final rules based on the Basel II NPR and the Basel IA NPR within the same timeframe in order to allow the comparative evaluation of the two sets of risk-based capital standards. The agencies have indicated that they anticipate that full transition to Basel II will not be completed until 2011 at the earliest. ASB will continue to monitor these regulatory developments.

Affiliate transactions. Significant restrictions apply to certain transactions between ASB and its affiliates, including HEI and its direct and indirect subsidiaries. The Financial Institutions Reform, Recovery, and Enforcement Act of 1989 significantly altered both the scope and substance of such limitations on transactions with affiliates and provided for thrift affiliate rules similar to, but more restrictive than, those applicable to banks. On December 12, 2002, the OTS issued an interim final rule which applies Regulation W of the FRB to thrifts with modifications appropriate to the greater restrictions under which thrifts operate. Most of these greater restrictions were carried over into the OTS’ final rule, which became effective November 6, 2003. For example, ASB is prohibited from making any loan or other extension of credit to an entity affiliated with ASB unless the affiliate is engaged exclusively in activities which the FRB has determined to be permissible for bank holding companies. There are also various other restrictions which apply to certain transactions between ASB and certain executive officers, directors and insiders of ASB. ASB is also barred from making a purchase of or any investment in securities issued by an affiliate, other than with respect to shares of a subsidiary of ASB.

Financial Derivatives and Interest Rate Risk. ASB is subject to OTS rules relating to derivatives activities, such as interest rate swaps. Currently ASB does not use interest rate swaps to manage interest rate risk, but may do so in the future. Generally speaking, the OTS rules permit thrifts to engage in transactions involving financial derivatives to the extent these transactions are otherwise authorized under applicable law and are safe and sound. The rules require ASB to have certain internal procedures for handling financial derivative transactions, including involvement of the ASB Board of Directors.

OTS Thrift Bulletin 13a (TB 13a) provides guidance on the management of interest rate risks, investment securities and derivatives activities. TB 13a also describes the guidelines OTS examiners use in assigning the

“Sensitivity to Market Risk” component rating under the Uniform Financial Institutions Rating System (i.e., the CAMELS rating system). TB 13a updated the OTS’ minimum standards for thrift institutions’ interest rate risk management practices and also contains guidance on thrifts’ investment and derivatives activities by describing the types of analysis institutions should perform prior to purchasing securities or financial derivatives.

Liquidity. OTS regulations require ASB to maintain sufficient liquidity to ensure safe and sound operations. ASB’s principal sources of liquidity are customer deposits, borrowings, the maturity and repayment of portfolio loans and securities and the sale of loans into secondary market channels. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. ASB is approved by the FHLB to borrow up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. As of December 31, 2006, ASB’s unused FHLB borrowing capacity was approximately $1.7 billion. ASB utilizes growth in deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. As of December 31, 2006, ASB had loan commitments, undisbursed loan funds 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.

Supervision. FDICIA made a number of reforms addressing the safety and soundness of the deposit insurance system, supervision of domestic and foreign depository institutions and improvement of accounting standards. FDICIA also limited deposit insurance coverage, implemented changes in consumer protection laws and called for least-cost resolution and prompt corrective action with regard to troubled institutions.

Pursuant to FDICIA, the federal banking agencies promulgated regulations which apply to the operations of ASB and its holding companies. Such regulations address, for example, standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates, and loans to insiders.

Prompt corrective action. FDICIA establishes a statutory framework that is triggered by the capital level of a savings association and subjects it to progressively more stringent restrictions and supervision as capital levels decline. The OTS rules implement the system of prompt corrective action. In particular, the rules define the relevant capital measures for the categories of “well capitalized”, “adequately capitalized”, “undercapitalized”, “significantly undercapitalized” and “critically undercapitalized.”

A savings association that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OTS determines that any of the actions is necessary to resolve the problems of the association at the least possible long-term cost to the SAIF. A savings association that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless the OTS and the FDIC concur that other action would be more appropriate. As of December 31, 2006, ASB was “well-capitalized.”

Interest rates. FDIC regulations restrict the ability of financial institutions that are undercapitalized to offer interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2006, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

Qualified thrift lender test. In order to satisfy the QTL test, a thrift must maintain 65% of its assets in “qualified thrift investments” on a monthly average basis in 9 out of the previous 12 months. Failure to satisfy the QTL test would subject ASB to various penalties, including limitations on its activities, and would also bring into operation restrictions on the activities that may be engaged in by HEI, HEIDI and their other subsidiaries, which could effectively result in the required divestiture of ASB. At all times during 2006, ASB was in compliance with the QTL test. As of December 31, 2006, 88% of ASB’s portfolio assets was “qualified thrift investments.” See “Holding company regulation.”

Federal Home Loan Bank System. ASB is a member of the FHLB System which consists of 12 regional FHLBs, and ASB’s regional bank is the FHLB of Seattle. The FHLB System provides a central credit facility for member institutions. Historically, the FHLBs have served as the central liquidity facilities for savings associations and sources of long-term funds for financing housing. The FHLB may only make long-term advances to ASB for the purpose of providing funds for financing residential housing. At such time as an advance is made to ASB or renewed, it must be secured by collateral from one of the following categories: (1) fully disbursed, whole first

mortgages on improved residential property, or securities representing a whole interest in such mortgages; (2) securities issued, insured or guaranteed by the U.S. Government or any agency thereof; (3) FHLB deposits; and (4) other real estate-related collateral that has a readily ascertainable value and with respect to which a security interest can be perfected. The aggregate amount of outstanding advances secured by such other real estate-related collateral may not exceed 30% of ASB’s capital.

As mandated by the Gramm Act, the Federal Housing Finance Board (Board) regulations require each FHLB to maintain a minimum total capital leverage ratio of 5% of total assets and include risk-based capital standards requiring each FHLB to maintain permanent capital in an amount sufficient to meet credit risk and market risk. In June 2001, the FHLB of Seattle formulated a capital plan to meet these new minimum capital standards, which plan was approved by the Board. The capital plan requires ASB to own capital stock in the FHLB of Seattle in an amount equal to the total of 4% of the FHLB of Seattle’s advances to ASB plus the greater of (i) 5% of the outstanding balance of loans sold to the FHLB of Seattle by ASB or (ii) 0.5% of ASB’s mortgage loans and pass through securities. As of December 31, 2006, ASB was required under the capital plan to own capital stock in the FHLB of Seattle in the amount of $47 million and owned capital stock in the amount of $98 million, or $51 million in excess of the requirement. Under the capital plan, stock in the FHLB of Seattle is subject to a 5-year notice of redemption. This 5-year notice period has an adverse but immaterial effect on ASB’s liquidity.

Community Reinvestment. The Community Reinvestment Act (CRA) requires banks and thrifts help meet the credit needs of their communities, including low- and moderate-income areas, consistent with safe and sound lending practices. The OTS will consider ASB’s CRA record in evaluating an application for a new deposit facility, including the establishment of a branch, the relocation of a branch or office, or the acquisition of an interest in another bank or thrift. ASB currently holds an “outstanding” CRA rating.

Other laws. ASB is subject to federal and state consumer protection laws which affect lending activities, such as the Truth-in-Lending Law, the Truth-in-Savings Act, the Equal Credit Opportunity Act, the Real Estate Settlement Procedures Act and several federal and state financial privacy acts. These laws may provide for substantial penalties in the event of noncompliance. ASB believes that its lending activities are in compliance with these laws and regulations.

Environmental regulation. HEI and its subsidiaries are subject to federal and state statutes and governmental regulations pertaining to water quality, air quality and other environmental factors.

HECO, HELCO and MECO, like other utilities, are subject to periodic inspections by federal, state, and in some cases, local environmental regulatory agencies, including, but not limited to, agencies responsible for regulation of water quality, air quality, hazardous and other waste, and hazardous materials. These inspections may result in the identification of items needing corrective or other action. When the corrective or other necessary action is taken, no further regulatory action is expected. Except as otherwise disclosed in this report (see “Certain factors that may affect future results and financial condition—Consolidated—Environmental matters” in HEI’s MD&A and Note 11 to HECO’s Consolidated Financial Statements, which are incorporated herein by reference), the Company believes that each subsidiary has appropriately responded to environmental conditions requiring action and, as a result of such actions, such environmental conditions will not have a material adverse effect on consolidated HECO or the Company.

Water quality controls. The generating stations, substations and other utility subsidiaries facilities operate under federal and state water quality regulations and permits, including but not limited to the Clean Water Act National Pollution Discharge Elimination System (governing point source discharges, including wastewater and storm water discharges), Underground Injection Control (regulating disposal of wastewater into the subsurface), the Spill Prevention, Control and Countermeasure (SPCC) program and other regulations associated with discharges of oil and other substances to surface water.

For a discussion of section 316(b) of the federal Clean Water Act, related EPA rules and their possible application to the electric utilities, including a recent adverse development concerning these regulations, see “Environmental regulation” in Note 11 to HECO’s Consolidated Financial Statements.

The Federal Oil Pollution Act of 1990 (OPA) governs actual or threatened oil releases in navigable U.S. waters (inland waters and up to three miles offshore) and waters of the U.S. exclusive economic zone (up to 200 miles to sea from the shoreline). In the event of an oil release into navigable U.S. waters, OPA establishes strict and joint

and several liability for responsible parties for 1) oil removal costs incurred by the federal government or the state, and 2) damages to natural resources and real or personal property. Responsible parties include vessel owners and operators of on-shore facilities. OPA imposes fines and jail terms ranging in severity depending on how the release was caused. OPA also requires that responsible parties submit certificates of financial responsibility sufficient to meet the responsible party’s maximum limited liability.

During 2006 and up through February 28, 2007, HECO, HELCO and MECO did not experience any significant petroleum releases. Except as otherwise disclosed herein, the Company believes that each subsidiary’s costs of responding to petroleum releases to date will not have a material adverse effect on the respective subsidiary or the Company.

EPA regulations under OPA also require certain facilities that store petroleum to prepare and implement Spill Prevention, Containment and Countermeasure (SPCC) Plans in order to prevent releases of petroleum to navigable waters of the U.S. HECO, HELCO and MECO facilities subject to the SPCC program are in compliance with these requirements. In July 2002, the EPA amended the SPCC regulations to include facilities, such as substations, that use (as opposed to store) petroleum products. HECO, HELCO and MECO have determined that the amended SPCC program applies to a number of their substations. Since 2002, the EPA issued four extensions of the compliance dates for the amended regulations. The most recent extension, issued on February 17, 2006, requires that existing facilities that started operation prior to August 16, 2002, must maintain or amend, and implement SPCC plans by October 31, 2007. Regulated facilities that started operations after August 16, 2002, also must prepare and implement an SPCC Plan by October 31, 2007. HECO, HELCO and MECO are developing and implementing SPCC plans for all facilities that are subject to the amended SPCC requirements.

Air quality controls. The generating stations of the utility subsidiaries operate under air pollution control permits issued by the DOH and, in a limited number of cases, by the EPA. The entire electric utility industry has been affected by the 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter. Further significant impacts may occur if currently proposed legislation, rules and standards are adopted. If the Clear Skies Bill or the Clean Air Planning Act of 2006 is adopted as proposed, HECO, and to a lesser extent, HELCO and MECO will likely incur significant capital and operations and maintenance costs beginning one to two years after enactment.

Effective March 29, 2005, the EPA delisted coal-fired and oil-fired utility boilers from regulation under Title III of the CAA (the Delisting Rule). On the same date, the EPA issued a rule designed to control mercury emissions from coal-fired utility units. The preamble to the mercury control rule stated that the EPA would not require control of nickel emissions from oil-fired utility boilers. Subsequently, on October 21, 2005, the EPA issued a notice that it would reconsider the Delisting Rule (the Notice of Reconsideration). On May 31, 2006, the EPA confirmed the Delisting Rule, thereby confirming that the EPA is not requiring control of nickel emissions from the electric utilities’ oil-fired utility boilers.

For a discussion of the July 1999 Regional Haze Rule amendments, see “Environmental regulation” in Note 11 to HECO’s Consolidated Financial Statements.

CAA operating permits (Title V permits) have been issued for all affected generating units.

Hazardous waste and toxic substances controls. The operations of the electric utility and former freight transportation subsidiaries of HEI are subject to EPA regulations that implement provisions of the Resource Conservation and Recovery Act (RCRA), the Superfund Amendments and Reauthorization Act (SARA) and the Toxic Substances Control Act. In 2001, the DOH obtained primacy to operate state-authorized RCRA (hazardous waste) programs. The DOH’s state contingency plan and the State of Hawaii Environmental Response Law (ERL) rules were adopted in August 1995.

Both federal and state RCRA provisions identify certain wastes as hazardous and set forth measures that must be taken in the transportation, storage, treatment and disposal of these wastes. Some wastes generated at steam electric generating stations possess characteristics that subject them to RCRA regulations. Since October 1986, all HECO generating stations have operated RCRA-exempt wastewater treatment units to treat potentially regulated wastes from occasional boiler waterside and fireside cleaning operations. Steam generating stations at MECO and HELCO also operate similar RCRA-exempt wastewater management systems.

The EPA issued a final regulatory determination on May 22, 2000, concluding that fossil fuel combustion wastes do not warrant regulation as hazardous under RCRA. This determination allows for more flexibility in waste management strategies. The electric utilities’ waste characterization programs continue to demonstrate the adequacy of the existing treatment systems. Waste recharacterization studies indicate that treatment facility wastestreams are nonhazardous.

RCRA underground storage tank (UST) regulations require all facilities with USTs used for storing petroleum products to comply with costly leak detection, spill prevention and new tank standard retrofit requirements. All HECO, HELCO and MECO USTs currently meet these standards and continue in operation.

The Emergency Planning and Community Right-to-Know Act under SARA Title III requires HECO, HELCO and MECO to report potentially hazardous chemicals present in their facilities in order to provide the public with information so that emergency procedures can be established to protect the public in the event of hazardous chemical releases. All HECO, HELCO and MECO facilities are in compliance with applicable annual reporting requirements to the State Emergency Planning Commission, the Local Emergency Planning Committee and local fire departments. Since January 1, 1998, the steam electric industry category has been subject to Toxics Release Inventory (TRI) reporting requirements. All HECO, HELCO and MECO facilities are in compliance with TRI reporting requirements.

The Toxic Substances Control Act regulations specify procedures for the handling and disposal of polychlorinated biphenyls (PCB), a compound found in some transformer and capacitor dielectric fluids. HECO, HELCO and MECO have instituted procedures to monitor compliance with these regulations. In addition, HECO and its subsidiaries have implemented a program to identify and replace PCB transformers and capacitors in their systems. Management believes that all HECO, HELCO and MECO facilities are currently in compliance with PCB regulations.

The ERL, as amended, governs releases of hazardous substances, including oil, in areas within the state’s jurisdiction. Responsible parties under the ERL are jointly, severally and strictly liable for a release of a hazardous substance into the environment. Responsible parties include owners or operators of a facility where a hazardous substance comes to be located and any person who at the time of disposal of the hazardous substance owned or operated any facility at which such hazardous substance was disposed. The DOH issued final rules (or State Contingency Plan) implementing the ERL in August 1995.

HECO is currently one of many parties involved in an ongoing investigation regarding releases of petroleum to the subsurface in the Honolulu Harbor area. (See Note 11 to HECO’s Consolidated Financial Statements.) Under the terms of the agreement for the sale of YB, HEI and TOOTS had certain environmental obligations arising from conditions existing prior to the sale of YB, including obligations with respect to the Honolulu Harbor investigation. In 2003, TOOTS paid $250,000 to fund response activities related to the Honolulu Harbor area as a one-time cash-out payment in lieu of continuing with further response activities.

In July 2002, personnel at MECO’s Maalaea Generating Station discovered a leak in an underground diesel fuel line. MECO notified DOH, instituted temporary corrective measures, and constructed a new aboveground fuel line and concrete containment trough as a permanent replacement. MECO also notified the U.S. Fish & Wildlife Service (USFWS), which manages the Kealia Pond National Wildlife Refuge located south of the Maalaea facility. MECO constructed a sump to remove fuel from the subsurface, conducted soil borings and installed groundwater monitoring wells to assess impacts of the fuel release, and, with the guidance and consent of the USFWS and the DOH, installed an interception trench in the buffer zone and in a small part of the Wildlife Refuge. Based on the results of the subsurface investigation and the operation of the interception trench, it appears that the fuel release has not affected and will not affect wildlife, sensitive wildlife habitat or the ocean, which lies approximately one-quarter mile south of the Maalaea facility. Total costs incurred as of December 31, 2006 were approximately $1.0 million. An estimated $0.3 million is expected to be expended during 2007-2010 to address ongoing response efforts. In 2002 through 2006, MECO reserved adequate amounts to cover expenditures to date as well as costs projected for the future. Remediation efforts have significantly reduced the volume of the product plume and product recovery has reached asymptotic levels. Based on this data, MECO developed a Monitoring and Closure Plan, which DOH approved in December 2004. Continued monitoring occasionally reveals a groundwater sample that exceeds DOH groundwater action levels. Once modeling information shows that product has been removed to the

extent practicable and MECO obtains two years of groundwater monitoring data that meets DOH action levels, MECO anticipates the project can be terminated.

HECO, HELCO and MECO, like other utilities, periodically identify leaking petroleum-containing equipment such as USTs, piping and transformers. In a few instances, small amounts of PCBs have been identified in the leaking equipment. Each subsidiary reports releases from such equipment when and as required by applicable law and addresses impacts due to the releases in compliance with applicable regulatory requirements.

ASB may be subject to the provisions of Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and regulations promulgated thereunder. CERCLA imposes liability for environmental cleanup costs on certain categories of responsible parties, including the current owner and operator of a facility and prior owners or operators who owned or operated the facility at the time the hazardous substances were released or disposed. CERCLA exempts persons whose ownership in a facility is held primarily to protect a security interest, provided that they do not participate in the management of the facility. Although there may be some risk of liability for ASB for environmental cleanup costs in the event ASB forecloses on, and becomes the owner of, property with environmental problems, the Company believes the risk is not as great for ASB as it may be for other depository institutions that have a larger portfolio of commercial loans.

Securities ratings

See the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI’s and HECO’s securities and discussion under “Liquidity and capital resources” (both “Consolidated” and “Electric utility”) in HEI’s MD&A. These ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. There is no assurance that any such credit rating will remain in effect for any given period of time or that such rating will not be lowered, suspended or withdrawn entirely by the applicable rating agency if, in such rating agency’s judgment, circumstances so warrant. Any such lowering, suspension or withdrawal of any rating may have an adverse effect on the market price or marketability of HEI’s and/or HECO’s securities, which could increase the cost of capital of HEI and HECO. Neither HEI nor HECO management can predict future rating agency actions or their effects on the future cost of capital of HEI or HECO.

Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii for the benefit of HECO and its subsidiaries, but the source of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on all revenue bonds currently outstanding are insured either by MBIA Insurance Corporation, Ambac Assurance Corporation, XL Capital Assurance, Inc. or Financial Guaranty Insurance Company and the ratings of those bonds are based on the ratings of the obligations of the bond insurer rather than HECO.

Research and development

HECO and its subsidiaries expensed approximately $1.8 million, $3.9 million and $3.3 million in 2006, 2005 and 2004, respectively, for research and development (R&D). In 2006, HELCO made contributions of $0.3 million to the Electric Power Research Institute (EPRI) and HECO and MECO did not make any contributions. In 2005 and 2004, the electric utilities’ contributions to EPRI accounted for more than half of the R&D expenses. There were also expenses in the areas of energy conservation, new technologies and environmental and emissions controls.

Employees

As of December 31, 2006 and 2005, the Company had full-time employees as follows:


December 31	2006	2005
HEI	41	42
HECO and its subsidiaries	2,085	2,066
ASB and its subsidiaries	1,318	1,272
Other subsidiaries	3	3

	3,447	3,383

The employees of HEI and its direct and indirect subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement. Of the 2,085 full time employees of HECO and its subsidiaries as of

December 31, 2006, 58% were covered by collective bargaining agreements. See the discussion of “Collective bargaining agreements” in Note 11 to HECO’s Consolidated Financial Statements.

ITEM 1A.

RISK FACTORS

For additional information for certain risk factors enumerated below and other risks of the Company and its operations, see “Forward-Looking Statements,” HEI’s MD&A, “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements, HECO’s MD&A and HECO’s Consolidated Financial Statements.

Holding Company and Company-Wide Risks

HEI is a holding company that derives its income from its operating subsidiaries and depends on the ability of those subsidiaries to pay dividends or make other distributions to HEI and on its own ability to raise capital.

HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, HEI’s cash flows and consequent ability to service its obligations and pay dividends on its common stock is dependent upon its receipt of dividends or other distributions from its operating subsidiaries and its ability to issue common stock or other equity securities and to incur additional debt. The ability of HEI’s subsidiaries to pay dividends or make other distributions to HEI is, in turn, subject to the risks associated with their operations and to contractual and regulatory restrictions, including:

•

the provisions of an HEI agreement with the PUC, which could limit the ability of HEI’s principal electric public utility subsidiary, HECO, to pay dividends to HEI in the event that the consolidated common stock equity of the electric public utility subsidiaries falls below 35% of total electric utility capitalization;

•

the provisions of an HEI agreement entered into with federal bank regulators in connection with its acquisition of its bank subsidiary, ASB, which require HEI to contribute additional capital to ASB (up to a maximum amount of additional capital of $28.3 million as of December 31, 2006) upon request of the regulators in order to maintain ASB’s regulatory capital at the level required by regulation;

•

the minimum capital and capital distribution regulations of the OTS that are applicable to ASB;

•

the receipt of a letter from the OTS stating it has no objection to the payment of any dividend ASB proposes to declare and pay to HEI; and

•

the provisions of preferred stock resolutions and debt instruments of HEI and its subsidiaries.

The Company is subject to risks associated with the Hawaii economy, volatile U.S. capital markets and changes in the interest rate environment that could result in higher retirement benefits expenses, declines in electric utility kilowatthour sales, declines in ASB’s interest rate margins, higher delinquencies and charge-offs in ASB’s loan portfolio and restrictions on the ability of HEI or its subsidiaries to borrow money.

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

A decline in the Hawaii economy, or the U.S. or Asian economies, could lead to a decline in KWH sales and an increase in uncollected billings of HECO and its subsidiaries, higher delinquencies in ASB’s loan portfolio and other adverse effects on HEI’s businesses. If S&P or Moody’s were to downgrade HEI’s or HECO’s long-term debt ratings because of these adverse effects, or if future events were to adversely affect the availability of capital to the Company, HEI’s and HECO’s ability to borrow could be constrained and their future borrowing costs would likely increase with resulting reductions in HEI’s consolidated net income in future periods. Further, if HEI’s or HECO’s ratings were to be downgraded, HEI and HECO might not be able to sell commercial paper under current market conditions and might be required to draw on more expensive bank lines of credit or to defer capital or other expenditures.

Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension expense is affected by the market performance of the assets in the master pension trust maintained for pension plans, and by the discount rate used to determine the service and interest cost components of net periodic pension cost.

Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. HEI and its electric utility subsidiaries are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine retirement benefits expenses and obligations and the possible effect of interest rates on the electric utilities’ rates of return. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.

HEI and HECO and their subsidiaries may incur higher retirement benefits expenses and have and will likely continue to recognize substantial liabilities for retirement benefits.

Retirement benefits expenses and cash funding requirements could increase in future years depending on numerous factors, including the performance of the U.S. equity markets, trends in interest rates and health care costs, plan amendments, new laws relating to pension funding and changes in accounting principles. Retirement benefits expenses based on net periodic pension and other postretirement benefit costs have been an allowable expense for rate-making, and higher retirement benefits expenses, along with other factors, may affect each electric utilities’ need to request a rate increase.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in stockholders’ equity (using the projected benefit obligation, rather than the accumulated benefit obligation, to calculate the funded status of pension plans). The amounts recorded in the future will be dependent on numerous factors, including the year-end discount rate assumption, asset returns experienced, any changes to actuarial assumptions or plan provisions, contributions made by the Company to the plans, and what action the PUC takes in rate cases.

By application filed on December 8, 2005 (AOCI Docket), the electric utilities had requested the PUC to permit them to record, as a regulatory asset the amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension liability as prescribed by SFAS No. 87. The electric utilities updated their application in the AOCI Docket in November 2006 to take into account SFAS No. 158. On January 26, 2007, the PUC issued a D&O in the updated AOCI docket, which denied the electric utilities’ request to record a regulatory asset. Although there was not an immediate impact on net income due to this D&O, the electric utilities (as well as HEI) were required to record substantial charges against stockholder’s equity, and the electric utilities’ reported returns on rate base and returns on average common equity will be higher than if there had been no charge against stockholder’s equity. Consolidated debt to capitalization and interest coverage ratios of the Company and the electric utilities were also adversely affected. These effects could adversely affect security ratings, and increase the difficulty or expense of obtaining future financing.

The Company is subject to the risks associated with the geographic concentration of its businesses and lack of interconnections that could result in service interruptions at the electric utilities or higher default rates on loans held by ASB.

The business of HECO and its electric utility subsidiaries is concentrated on the individual islands they serve in the State of Hawaii. The operations of HEI’s electric utility subsidiaries are more vulnerable to service interruptions than are many U.S. mainland utilities because none of the systems of HECO and its subsidiaries are interconnected with the systems on the other islands they serve. Because of this lack of interconnections, it is necessary to maintain higher generation reserve margins than are typical for U.S. mainland utilities to help ensure reliable service. The peak reserve margins on Oahu are currently below desirable levels and this condition will likely continue and be exacerbated by projected load growth until additional generation is brought on line, which is not expected until 2009. Service interruptions, including in particular extended interruptions that could result from a natural disaster or terrorist activity, could adversely impact the KWH sales of some or all of the electric utility

subsidiaries. For example, on October 15, 2006, two sequential earthquakes registering 6.7 and 6.0 on the Richter scale with an epicenter near the island of Hawaii triggered power outages throughout most of the state, and although power was restored to over 99% of Oahu customers over a period of time ranging from 4 1/2 to 18 hours, some areas were without power for more than 24 hours.

Substantially all of ASB’s consumer loan customers are Hawaii residents. A significant portion of the commercial loan customers are located in Hawaii. Substantially all of the real estate underlying ASB’s residential and commercial real estate loans are located in Hawaii. These assets may be subject to a greater risk of default than other comparable assets held by financial institutions with other geographic concentrations in the event of adverse economic, political or business developments or natural disasters affecting Hawaii and the ability of ASB’s customers to make payments of principal and interest on their loans.

Increasing competition and technological advances could cause HEI’s businesses to lose customers or render their operations obsolete.

The banking industry in Hawaii, and certain aspects of the electric utility industry, are competitive. The success of HEI’s subsidiaries in meeting competition will continue to have a direct impact on HEI’s consolidated financial performance. For example:

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ASB, which is the third largest financial institution in the state based on total assets, is in direct competition for deposits and loans not only with two larger institutions that have substantial capital, technology and marketing resources, but also with smaller Hawaii institutions and other U.S. institutions, including credit unions, mutual funds, mortgage brokers, finance companies and investment banking firms. Larger financial institutions may have greater access to capital at lower costs, which could impair ASB’s ability to compete effectively. Significant advances in technology could render the operations of ASB less competitive or obsolete.

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HECO and its subsidiaries face competition from IPPs, including alternate energy providers, and customer self-generation, with or without cogeneration. The PUC issued a decision in its investigative proceeding on competitive bidding as a mechanism for acquiring or building new electric generating capacity. With the exception of certain identified projects, the utilities are now required to use competitive bidding to acquire a future generation resource unless the PUC finds competitive bidding to be unsuitable. The PUC issued a decision in its distributed generation (DG) investigative proceeding, in which it set policies for DG interconnection agreements and standby rates, and established conditions under which electric utilities can provide DG services on customer-owned sites as a regulated service. The electric utilities cannot predict the ultimate effect of the PUC’s decisions in the competitive bidding and DG proceedings, the impact they will have on competition from IPPs and customer self-generation, or the rate at which technological developments facilitating non-utility generation of electricity will occur.

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New technological developments, such as the commercial development of fuel cells, may render the operations of HEI’s electric utility subsidiaries less competitive or outdated.

HEI’s businesses could suffer losses that are uninsured due to a lack of insurance coverage or limitations on the insurance coverage the Company does have.

In the ordinary course of business, HEI and its subsidiaries purchase insurance coverages (e.g., property and liability coverages) to protect against loss of, or damage to, their properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. Certain of the insurance has substantial deductibles or has limits on the maximum amounts that may be recovered. For example:

The electric utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have an estimated replacement cost of approximately $3.5 billion and are not insured against loss or damage because the amount of transmission and distribution system insurance available is limited and the premiums are cost prohibitive. Similarly, the electric utilities have no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the utilities are not interconnected to other systems. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the affected electric utilities to recover from ratepayers restoration costs and revenues lost from business interruption, the lost revenues and repair expenses could

result in a significant decrease in HEI’s consolidated net income or in significant net losses for the affected periods.

ASB generally does not obtain credit enhancements such as mortgagor bankruptcy insurance but does require standard hazard and hurricane insurance and may require flood insurance for certain properties. ASB is subject to the risks of borrower defaults and bankruptcies and special hazard losses not covered by the required insurance.

Increased federal and state environmental regulation will require an increasing commitment of resources and funds and could result in construction delays or penalties and fines for non-compliance.

HEI and its subsidiaries are subject to federal and state environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health and safety, which 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. Compliance with these legal requirements requires HEI’s utility subsidiaries to commit significant resources and funds toward environmental monitoring, installation of pollution control equipment and payment of emission fees. These laws and regulations, among other things, require that certain environmental permits be obtained in order to construct or operate certain facilities, and obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance. For example, emission and/or discharge limits may be tightened, more extensive permitting requirements may be imposed and additional substances may become regulated.

If HEI or its subsidiaries fail to comply with environmental laws and regulations, even if caused by factors beyond their control, that failure may result in civil or criminal penalties and fines. At the present time, HECO is a named party in an ongoing environmental investigation to determine the nature and extent of actual or potential release of hazardous substances, oil, pollutants or contaminants at or near Honolulu Harbor and management cannot predict the ultimate cost or outcome of that investigation.

Adverse tax rulings or developments could result in significant increases in tax payments and/or expense.

Governmental taxing authorities could challenge a tax return position taken by HEI or its subsidiaries and, if the taxing authorities prevail, HEI’s consolidated tax payments and/or expense, including applicable penalties and interest, could increase significantly. Further, the ability of HEI and its subsidiaries to generate capital gains and utilize capital loss carryforwards on future tax returns could impact future earnings.

The Company could be subject to the risk of uninsured losses in excess of its accruals for litigation matters.

HEI and its subsidiaries are involved in routine litigation in the ordinary course of their businesses, most of which is covered by insurance (subject to policy limits and deductibles). However, other litigation may arise that is not routine or involves claims that may not be covered by insurance. Because of the uncertainties associated with litigation, there is a risk that litigation against HEI or its subsidiaries, even if vigorously defended, could result in costs of defense and judgment or settlement amounts not covered by insurance and in excess of reserves established in HEI’s consolidated financial statements.

Changes in accounting principles and estimates could affect the reported amounts of the Company’s assets and liabilities or revenues and expenses.

HEI’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Changes in these principles, such as the changes related to the accounting for retirement benefits in SFAS No. 158, or the Company’s application of existing accounting principles could materially affect HEI’s or the electric utilities’ consolidated financial position and/or results of operations. Further, in preparing the consolidated 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. Material estimates that are particularly susceptible to significant change include the amounts reported for investment and mortgage-related securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; variable interest entities; and allowance for loan losses.

In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” HECO and its subsidiaries’ financial statements reflect assets and costs based on cost-based rate-making regulations. Continued

accounting in this manner requires that certain criteria relating to the recoverability of such costs through rates be met. If events or circumstances should change so that the criteria are no longer satisfied, the electric utilities’ regulatory assets (amounting to approximately $112 million as of December 31, 2006) may need to be charged to expense, which could result in significant reductions in the electric utilities’ net income, and the electric utilities’ regulatory liabilities (amounting to $241 million as of December 31, 2006) may need to be refunded to ratepayers.

Changes in accounting principles can also impact HEI’s consolidated financial statements. For example, if a PPA falls within the scope of FASB FIN No. 46 (FIN 46R), “Consolidation of Variable Interest Entities” and results in the consolidation of the IPP in HECO’s consolidated financial statements, the consolidation 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. Also, if a PPA falls within the scope of Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” and results in the classification of the agreement as a capital lease, a material effect on HEI’s consolidated balance sheet may result, including the recognition of significant capital assets and lease obligations.

Electric Utility Risks

Actions of the PUC are outside the control of the electric utility subsidiaries and could result in inadequate or untimely rate relief, in rate reductions or refunds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects.

The rates the electric utilities are allowed to charge for their services and the timeliness of permitted rate increases are among the most important items influencing the electric utilities’ financial condition, results of operations and liquidity. The PUC has broad discretion over the rates that the electric utilities charge their customers. HECO currently has a rate case based on a 2005 test year pending before the PUC. Near the end of September 2005, HECO received an interim D&O (granting $53 million in annual base revenues) and is awaiting a final D&O. In May 2006, HELCO filed a request for a rate increase based on a 2006 test year intended largely to recover the cost of improvements to its transmission and distribution lines and the two generating units at its Keahole generating plant (CT-4 and CT-5). In December 2006, HECO filed a request for general rate increases based on a 2007 test year intended largely to recover costs incurred to maintain and improve reliability. In February 2007, MECO filed a request for general rate increase also based on a 2007 test year intended largely to recover costs incurred for the installation of Maalaea Unit M18 as well as to maintain service quality, fulfill infrastructure needs, and maintain financial integrity. The trend of increased operation and maintenance (O&M) expenses (including increased retirement benefits expenses), which management expects will continue, increased plant-in-service and other factors are likely to result in the electric utilities seeking rate relief more often than in the past. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding, could have a material adverse effect on HECO’s consolidated financial condition, results of operations and liquidity.

The electric utilities could be required to refund to their customers, with interest, revenues received under interim rate orders if and to the extent they exceed the amounts allowed in final rate orders. As of December 31, 2006, the electric utilities had recognized an aggregate of $79 million of such revenues with respect to interim orders regarding certain IRP costs and the interim order in the HECO rate case based on a 2005 test year.

Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. For example, two major capital improvement projects — HECO’s East Oahu Transmission Project and the expansion of HELCO’s Keahole generating plant — have encountered substantial opposition and consequent delay and increased cost. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of the project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income.

Energy cost adjustment clauses (ECACs). The rate schedules of each of HEI’s electric utilities include ECACs under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 2004 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC affirmed the electric utilities’ right to include in their respective ECACs the stated costs incurred pursuant to their respective new fuel supply contracts, to the extent that these costs are not included in their respective base rates, and restated its intention to examine the need for continued use of ECACs in rate cases.

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 file frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already reviews the automatic fuel rate adjustment clause in rate cases, Act 162 requires 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.

On June 30, 2006, HECO and the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (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 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 Department of Defense (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 rate case based on a 2005 test year.

In December 2006, HECO (in its 2007 test year rate case) and HELCO (in its 2006 test year rate case) filed testimonies and a consultant report to address the ECAC provisions of Act 162. In February 2007, MECO filed its 2007 test year rate case application, which included testimony to address the ECAC provisions of Act 162. The testimonies and consultant report concluded that the utilities’ current ECACs comply with the requirements of Act 162.

Management cannot predict the ultimate outcome or the effect of these Act 162 issues on the operation of the ECAC as it relates to the electric utilities.

Electric utility operations are significantly influenced by weather conditions.

The electric utilities’ results of operations can be affected by changes in the weather. Weather conditions, particularly temperature and humidity, directly influence the demand for electricity. In addition, severe weather and natural disasters such as hurricanes, earthquakes and tsunamis, can be destructive, causing outages and property damage and requiring the utilities to incur significant additional expenses that may not be recoverable.

Electric utility operations depend heavily on third party suppliers of fuel oil and purchased power.

The electric utilities rely on fuel oil suppliers and shippers and independent power producers to deliver fuel oil and power, respectively, in accordance with contractual agreements. Approximately 78.9% of the net energy generated or purchased by the electric utilities in 2006 was generated from the burning of oil, and purchases of power by the electric utilities provided about 38.2% of their total net energy generated and purchased for the same period. Failure or delay by oil suppliers and shippers to provide fuel pursuant to existing contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could disrupt the ability of the electric utilities to deliver electricity and require the electric utilities to incur additional expenses to meet the needs of their customers that may not be recoverable. In addition, as these contractual agreements end, the electric utilities may not be able to purchase fuel and power on terms equivalent to the current contractual agreements.

Electric utility generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated and/or increased operation and maintenance expenses and increased power purchase costs.

Operation of electric generating facilities involves certain risks which can adversely affect energy output and efficiency levels. Included among these risks are facility shutdowns or power interruptions due to insufficient generation or a breakdown or failure of equipment or processes or interruptions in fuel supply, inability to negotiate satisfactory collective bargaining agreements when existing agreements expire or other labor disputes, inability to comply with regulatory or permit requirements, disruptions in delivery of electricity, operator error and catastrophic events such as earthquakes, tsunamis, hurricanes, fires, explosions, floods or other similar occurrences affecting the electric utilities’ generating facilities or transmission and distribution systems. For example, as a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability. Generation peak reserve margins are lower than considered desirable in light of circumstances. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. HECO has taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying energy to meet growing demand, however, are increasing because of the decreasing peak reserve margin situation, and the trend of cost increases is not likely to ease.

The electric utilities may be adversely affected by new legislation.

Congress and the Hawaii Legislature periodically consider legislation that could have positive or negative effects on the electric utilities and their customers. For example, Congress adopted the Energy Policy Act of 2005, which will provide $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. The incentives include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. The primary impact of these incentives on the electric utilities will 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. In addition to the ECAC provisions of Act 162 discussed above, the Hawaii Legislature adopted a number of measures in 2006, which may affect the electric utilities, as described below.

Renewable Portfolio Standards (RPS) law. The 2004 Hawaii Legislature amended an existing RPS law to require electric utilities to meet a RPS of 8% of KWH sales by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. These standards may be met by the electric utilities on an aggregated basis and were met in 2005 when 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).

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 demand-side management (DSM) surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC.

Non-fossil fuel purchased power contracts. In 2006, a law was passed that requires the PUC, in connection with its determination of just and reasonable rates in purchased power contracts, to 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.

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 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.

Bank Risks

Fluctuations in interest rates could result in lower net interest income, impair ASB’s ability to originate new loans or impair the ability of ASB’s adjustable-rate borrowers to make increased payments.

Interest rate risk is a significant risk of ASB’s operations. ASB’s net interest income consists primarily of interest income received on fixed-rate and adjustable-rate loans, mortgage-related securities and investments and interest expense consisting primarily of interest paid on deposits and other borrowings. Interest rate risk arises when earning assets mature or when their interest rates change in a time frame different from that of the costing liabilities. Changes in market interest rates, including changes in the relationship between short-term and long-term market interest rates or between different interest rate indices, can impact ASB’s net interest margin. Although ASB pursues an asset-liability management strategy designed to mitigate its risk from changes in market interest rates, unfavorable movements in interest rates could result in lower net interest income.

Increases in market interest rates could have an adverse impact on ASB’s cost of funds. Higher market interest rates could lead to higher interest rates paid on deposits and other borrowings.

Significant increases in market interest rates, or the perception that an increase may occur, could adversely affect ASB’s ability to originate new loans and grow. An increase in market interest rates, especially a sudden increase, could also adversely affect the ability of ASB’s adjustable-rate borrowers to meet their higher payment obligations. If this occurred, it could cause an increase in nonperforming assets and charge-offs. Conversely, a decrease in interest rates or a mismatching of maturities of interest sensitive financial instruments could result in an acceleration in the prepayment of loans and mortgage-related securities and impact ASB’s ability to reinvest its liquidity in similar yielding assets.

ASB’s operations are affected by many disparate factors, some of which are beyond its control, that could result in lower net interest income or decreased demand for its products and services.

ASB’s results of operations depend primarily on the level of net interest income generated by ASB’s earning assets and costing liabilities and the supply of and demand for its products and services (i.e., loans and deposits). ASB’s net income may also be adversely affected by various other factors, such as:

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local and other economic and political conditions that could result in declines in employment and real estate values, which in turn could adversely affect the ability of borrowers to make loan payments and the ability of ASB to recover the full amounts owing to it under defaulted loans;

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the ability of borrowers to obtain insurance and the ability of ASB to place insurance where borrowers fail to do so, particularly in the event of catastrophic damage to collateral securing loans made by ASB;

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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;

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

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increases in operating costs, due to its strategic transformation to a full-service community bank, inflation and other factors, that exceed increases in ASB’ s net interest, fee and other income;

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the ability of ASB to maintain or increase the level of deposits, ASB’s lowest cost funds; and

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the ability of ASB to execute its strategy to transform itself to a full-service community bank.

Banking and related regulations could result in significant restrictions being imposed on ASB’s business.

ASB is subject to examination and comprehensive regulation by the Department of Treasury, the OTS and the Federal Deposit Insurance Corporation, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. As ASB’s primary regulator, the OTS regularly conducts examinations to assess the “safety and soundness” of ASB’s operations and activities and ASB’s compliance with applicable banking laws and regulations. Because ASB is an indirect subsidiary of HEI, federal regulatory authorities have the right to examine HEI and its activities.

Under certain circumstances, including any determination that ASB’s relationship with HEI results in an unsafe and unsound banking practice, these regulatory authorities have the authority to restrict the ability of ASB to transfer assets and to make distributions to its stockholders (including payment of dividends to HEI), or they could seek to require HEI to sever its relationship with or divest its ownership of ASB. Payment by ASB of dividends to HEI may also be restricted by the OTS under its prompt corrective action regulations or its capital distribution regulations if ASB’s capital position deteriorates. In order to maintain its status as a QTL, ASB is required to maintain at least 65% of its assets in “qualified thrift investments.” Savings associations that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI and HEI’s other subsidiaries would also be subject to restrictions, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. In the event of a required divestiture, federal law substantially limits the entities that could acquire ASB.

ASB’s strategy to expand its commercial and commercial real estate lending activities may result in higher service costs and greater credit risk than residential lending activities due to the unique characteristics of these markets.

ASB has been aggressively pursuing a strategy that includes expanding its commercial and commercial real estate lines of business. These types of loans generally entail higher underwriting and other service costs and present greater credit risks than traditional residential mortgages.

Generally, both commercial and commercial real estate loans have shorter terms to maturity and earn higher rates than residential mortgage loans. Only the assets of the business typically secure commercial loans. In such cases, upon default, any collateral repossessed may not be sufficient to repay the outstanding loan balance. In addition, loan collections are dependent on the borrower’s continuing financial stability and, thus, are more likely to be affected by current economic conditions and adverse business developments.

Commercial real estate properties tend to be unique and are more difficult to value than residential real estate properties. Commercial real estate loans may not be fully amortizing, meaning that they may have a significant principal balance or “balloon” payment due at maturity. In addition, commercial real estate properties, particularly

industrial and warehouse properties, are generally subject to relatively greater environmental risks than noncommercial properties and to the corresponding burdens and costs of compliance with environmental laws and regulations. Also, there may be costs and delays involved in enforcing rights of a property owner against tenants in default under the terms of leases with respect to commercial properties. For example, tenants may seek the protection of bankruptcy laws, which could result in termination of such tenant’s lease.

In addition to the inherent risks of commercial and commercial real estate lending described above, the expansion of these new lines of business present execution risks including the ability of ASB to attract personnel experienced in underwriting such loans and the ability of ASB to appropriately evaluate credit risk associated with such loans in determining the adequacy of the allowance for loan losses.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

HEI has not received, prior to July 4, 2006, written comments from the SEC staff regarding its periodic or current reports under the Securities Exchange Act of 1934, which remain unresolved.

HECO has not received, prior to July 4, 2006, written comments from the SEC staff regarding its periodic or current reports under the Securities Exchange Act of 1934, which remain unresolved.

ITEM 2.

PROPERTIES

HEI leases office space from nonaffiliated lessors in downtown Honolulu under leases that expire in May 2011. HEI also subleases office space in a downtown Honolulu building leased by HECO under a lease that expires in November 2021, with an option to extend to November 2024. The properties of HEI’s subsidiaries are as follows:

Electric utility

See “Generation statistics” and “Transmission systems” in Item 1 and “Limited insurance” in HEI’s MD&A. Electric lines are located over or under public and nonpublic properties. See “HECO and subsidiaries and service areas” in Item 1 for a discussion of the nonexclusive franchises of HECO and subsidiaries. Most of the leases, easements and licenses for HECO’s, HELCO’s and MECO’s lines have been recorded.

HECO owns and operates three generating plants on the island of Oahu at Honolulu, Waiau and Kahe. These plants, along with distributed generators (at three substation sites, at HECO’s Kalaeloa pole yard and at HECO’s Iwilei tank farm), have an aggregate net generating capability of 1,233.2 MW as of December 31, 2006. The three plants are situated on HECO-owned land having a combined area of 535 acres and one 3-acre parcel of land under a lease expiring December 31, 2018. In addition, HECO owns a total of 124 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located.

HECO owns overhead transmission lines, overhead distribution lines, underground cables, poles (fully owned or jointly owned) and steel or aluminum high voltage transmission towers. The transmission system operates at 46,000 volts and 138,000 volts. The total capacity of HECO’s transmission and distribution substations was 6,726,800 kilovoltamperes as of December 31, 2006.

HECO owns buildings and approximately 11.5 acres of land located in Honolulu which houses its operating, engineering and information services departments and a warehousing center. It also leases an office building and certain office spaces in Honolulu. The lease for the office building expires in November 2021, with an option to extend through November 2024. The leases for certain office spaces expire on various dates through November 30, 2016 with options to extend to various dates through January 31, 2020.

HECO owns 19.2 acres of land at Barbers Point used to situate fuel oil storage facilities with a combined capacity of 970,700 barrels. HECO also owns fuel oil tanks at each of its plant sites with a total maximum usable capacity of 844,600 barrels and underground fuel pipelines that transport fuel from HECO’s tank farm at Campbell Industrial Park to HECO’s power plants at Waiau and Kahe. HECO also owns a fuel storage facility at its Iwilei site with a maximum usable capacity of 79,203 barrels, and an underground pipeline that transports fuel from that site to its Honolulu power plant.

HELCO owns and operates five generating plants on the island of Hawaii, two at Hilo and one at each of Waimea, Kona and Puna, along with distributed generators at substation sites. These plants have an aggregate net generating capability of 181.9 MW as of December 31, 2006 (excluding a small run-of-river hydro unit and a small windfarm). The plants are situated on HELCO-owned land having a combined area of approximately 44 acres. The distributed generators are located within HELCO-owned substation sites having a combined area of approximately 4 acres. HELCO also owns fuel storage facilities at these sites with a total maximum usable capacity of 76,041 barrels of bunker oil, and 48,812 barrels of diesel. HELCO also owns 6 acres of land in Kona, which is used for a baseyard, and one acre of land in Hilo, which houses its engineering and administrative offices. HELCO also leases 4 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addition, HELCO owns a total of approximately 99 acres of land, and leases a total of approximately 9 acres of land, on which hydro facilities, substations and switching stations, microwave facilities, and transmission lines are located. The deeds to the sites located in Hilo contain certain restrictions, but the restrictions do not materially interfere with the use of the sites for public utility purposes. HELCO occupies 78 acres of land (located in Kamuela on the island of Hawaii) for the Lalamilo windfarm (with an aggregate net capability of 2.3 MW as of December 31, 2006), pursuant to a long-term agreement with the Water Commission of the County of Hawaii expiring in 2010.

MECO owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 232.0 MW as of December 31, 2006. The plants are situated on MECO-owned land having a combined area of 28.6 acres. MECO also owns fuel oil storage facilities at these sites with a total maximum usable capacity of 176,355 barrels. MECO owns two 1 MW stand-by diesel generators and a 6,000 gallon fuel storage tank located in Hana. MECO owns 65.7 acres of undeveloped land at Waena. The Waena land is currently being used for agricultural purposes by the former landowner under a license agreement dated November 19, 1996. The license agreement was originally scheduled to expire on December 31, 2004, but has been extended on a month-to-month basis until the area is required for development by MECO for utility purposes or September 30, 2007, whichever comes first.

MECO’s administrative offices and engineering and distribution departments are located on 9.1 acres of MECO-owned land in Kahului.

MECO also owns and operates smaller distribution systems, generation systems (with an aggregate net capability of 22.1 MW as of December 31, 2006) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by MECO.

Bank

ASB owns or leases several office buildings in downtown Honolulu and owns land and an operations center in the Mililani Technology Park on the island of Oahu.

The following table sets forth the number of bank branches owned and leased by ASB by island:


	Number of branches
December 31, 2006	Owned	Leased	Total
Oahu	8	36	44
Maui	3	5	8
Kauai	3	2	5
Hawaii	2	4	6
Molokai	—	1	1

	16	48	64

As of December 31, 2006, the net book value of branches and office facilities is approximately $48 million. Of this amount, $33 million represents the net book value of the land and improvements for the branches and office facilities owned by ASB and $15 million represents the net book value of ASB’s leasehold improvements. The leases expire on various dates through November 2036, but many of the leases have extension provisions.

ITEM 3.

LEGAL PROCEEDINGS

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in “Item 1. Business,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the notes to HEI’s Consolidated Financial Statements are incorporated by reference in this Item 3. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) are also involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

HEI and HECO:

During the fourth quarter of 2006, no matters were submitted to a vote of security holders of the Registrants.

EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)

The following persons are, or may be deemed to be, executive officers of HEI. Their ages are given as of February 28, 2007, their years of company service are given as of December 31, 2006 and their business experience is given for the past five years. Officers are appointed to serve until the meeting of the HEI Board of Directors (HEI Board) after the next Annual Meeting of Shareholders (which is scheduled for April 24, 2007) and/or until their successors have been appointed and qualified (or until their earlier resignation or removal). Company service includes service with an HEI subsidiary.


HEI Executive Officers
Constance H. Lau, age 54 (Company service: 22 years)
President and Chief Executive Officer		5/06 to date
Chairman of the Board, HECO		5/06 to date
Chairman of the Board, ASB		5/06 to date
President and Chief Executive Officer, ASB		6/01 to date
Director, HEI		6/01 to 12/04, 5/06 to date

Eric K. Yeaman, age 39 (Company service: 3 years)
Financial Vice President, Treasurer and Chief Financial Officer		01/03 to date
Eric K. Yeaman, prior to joining HEI, served as Chief Operating and Financial Officer of Kamehameha Schools from 4/02 to 1/03 and Chief Financial Officer of Kamehameha Schools from 7/00 to 4/02.

Patricia U. Wong, age 50 (Company service: 16 years)
Vice President – Administration and Corporate Secretary		4/05 to date
Vice President		1/05 to 4/05
Vice President – Corporate Excellence, HECO		3/98 to 12/04

Andrew I. T. Chang, age 67 (Company service: 21 years)
Vice President – Government Relations		4/91 to date

Curtis Y. Harada, age 51 (Company service: 17 years)
Controller		1/91 to date

T. Michael May, age 60 (Company service: 14 years)
President and Chief Executive Officer, HECO		9/95 to date
Director, HEI		9/95 to 12/04

Robert F. Clarke retired from HEI on May 31, 2006. Constance H. Lau was named to succeed Mr. Clarke and became President and Chief Executive Officer (CEO) of HEI effective May 2, 2006.

HEI’s executive officers, with the exception of Andrew I. T. Chang, are also officers and/or directors of one or more of HEI’s subsidiaries. Mr. May is not an officer of HEI, but he is deemed to be an executive officer of HEI for purposes of this Item under the definition of “executive officer” in Rule 3b-7 of the SEC’s General Rules and Regulations under the Securities Exchange Act of 1934.

There are no family relationships between any executive officer of HEI and any other executive officer or director of HEI, nor are there any arrangements or understandings between any executive officer of HEI and any person, pursuant to which such executive officer was selected.

PART II

ITEM 5.

MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF SECURITIES

HEI:

Certain of the information required by this item is incorporated herein by reference to Note 12, “Regulatory restrictions on net assets” and Note 16, “Quarterly information (unaudited)” of HEI’s Consolidated Financial Statements and “Item 6. Selected Financial Data” and “Item 12. Equity compensation plan information” of this Form 10-K. Certain restrictions on dividends and other distributions of HEI are described in this report under “Item 1. Business—Regulation and other matters—Restrictions on dividends and other distributions” and that description is incorporated herein by reference. HEI’s common stock is traded on the New York Stock Exchange and the total number of holders of record of HEI common stock as of February 21, 2007, was 11,902.

In 2006, HEI issued an aggregate of 27,600 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 2, 2006 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each nonemployee HEI director receives, in addition to an annual cash retainer, an annual stock grant of 1,400 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 a nonemployee HEI director receives an annual stock grant of 1,000 shares of HEI common stock (600 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 and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

In 2005, HEI issued an aggregate of 28,200 shares of unregistered common stock pursuant to the HEI Nonemployee Director Plan, as amended and restated effective March 8, 2005. In 2004, HEI issued an aggregate of 18,800 shares (split-adjusted) of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective April 20, 2004.

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.

Purchases of HEI common shares were made as follows:

ISSUER PURCHASES OF EQUITY SECURITIES


Period*	(a) Total Number of Shares Purchased **	(b) Average Price Paid per Share **	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs **	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to 31, 2006	66,809	27.6318	—	NA
November 1 to 30, 2006	32,400	26.9562	—	NA
December 1 to 31, 2006	221,518	27.4882	—	NA

	320,727	27.4644	—	NA

NA	Not applicable.

*	Trades (total number of shares purchased) are reflected in the month in which the order is placed.

The purchases were made to satisfy the requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) and Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the broker making the purchases for the DRIP and HEIRSP. Of the shares listed in column (a), all of the 66,809 shares, all of the 32,400 shares and 192,118 of the 221,518 shares were purchased for the DRIP and the remainder were purchased for the HEIRSP. All purchases were made through a broker on the open market.

HECO:

Since a corporate restructuring on July 1, 1983, all the common stock of HECO has been held solely by its parent, HEI, and is not publicly traded. Accordingly, information required with respect to “Market information” and “holders” is not applicable to HECO.

The dividends declared and paid on HECO’s common stock for the quarters ended March 31, 2006 and June 30, 2006 were $13,640,000 and $15,741,000, respectively. No dividends were declared or paid on HECO’s common stock for the quarters ended September 30, 2006 and December 31, 2006 because HECO was strengthening its capital structure by retaining earnings. The dividends declared and paid on HECO’s common stock for the quarters ended March 31, 2005, June 30, 2005, September 30, 2005 and December 31, 2005 were $9,933,000, $9,289,000, $14,733,000 and $16,940,000, respectively. Also, see “Liquidity and capital resources” in HEI’s MD&A.

See the discussion of regulatory restrictions on distributions in Note 12 to HECO’s Consolidated Financial Statements, which are incorporated herein by reference, and the discussion of “Restrictions on dividends and other distributions” under “Regulation and other matters” in Item 1. Business.

ITEM 6.

SELECTED FINANCIAL DATA

HEI:

Selected Financial Data


Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 31	2006			2005			2004			2003			2002
(dollars in thousands, except per share amounts)
Results of operations
Revenues	$	2,460,904		$	2,215,564		$	1,924,057		$	1,781,316		$	1,653,701
Net income (loss)
Continuing operations	$	108,001		$	127,444		$	107,739		$	118,048		$	118,217
Discontinued operations		—			(755	)		1,913			(3,870	)		—

	$	108,001		$	126,689		$	109,652		$	114,178		$	118,217

Basic earnings (loss) per common share
Continuing operations	$	1.33		$	1.58		$	1.36		$	1.58		$	1.63
Discontinued operations		—			(0.01	)		0.02			(0.05	)		—

	$	1.33		$	1.57		$	1.38		$	1.53		$	1.63

Diluted earnings per common share	$	1.33		$	1.56		$	1.38		$	1.52		$	1.62

Return on average common equity-continuing operations *		9.3	%		10.5	%		9.4	%		11.1	%		12.0	%

Return on average common equity		9.3	%		10.4	%		9.5	%		10.7	%		12.0	%

Financial position **
Total assets	$	9,891,209		$	9,951,577		$	9,719,257		$	9,307,700		$	9,039,121
Deposit liabilities		4,575,548			4,557,419			4,296,172			4,026,250			3,800,772
Other bank borrowings		1,568,585			1,622,294			1,799,669			1,848,388			1,843,499
Long-term debt, net		1,133,185			1,142,993			1,166,735			1,064,420			1,106,270
HEI- and HECO-obligated preferred securities of trust subsidiaries		—			—			—			200,000			200,000
Preferred stock of subsidiaries – not subject to mandatory redemption		34,293			34,293			34,405			34,406			34,406
Stockholders’ equity		1,095,240			1,216,630			1,210,945			1,089,031			1,046,300

Common stock
Book value per common share **	$	13.44		$	15.02		$	15.01		$	14.36		$	14.21
Market price per common share
High		28.94			29.79			29.55			24.00			24.50
Low		25.69			24.60			22.96			19.10			17.28
December 31		27.15			25.90			29.15			23.69			21.99
Dividends per common share		1.24			1.24			1.24			1.24			1.24

Dividend payout ratio		93	%		79	%		90	%		81	%		76	%
Dividend payout ratio-continuing operations		93	%		78	%		91	%		78	%		76	%
Market price to book value per common share **		202	%		172	%		194	%		165	%		155	%
Price earnings ratio ***		20.4x			16.4x			21.4x			15.0x			13.5x
Common shares outstanding (thousands) **		81,461			80,983			80,687			75,838			73,618
Weighted-average		81,145			80,828			79,562			74,696			72,556
Shareholders ****		35,021			35,645			35,292			34,439			34,901

Employees **		3,447			3,383			3,354			3,197			3,220

*	Net income from continuing operations divided by average common equity.

**	At December 31. (Note: Stockholders’ equity and book value per common share as of December 31, 2006 includes a charge to AOCI pursuant to SFAS No. 158. See Note 8, “Retirement benefits,” of HEI’s “Notes to Consolidated Financial Statements.”)

***	Calculated using December 31 market price per common share divided by basic earnings per common share from continuing operations. The principal trading market for HEI’s common stock is the New York Stock Exchange (NYSE).

****	At December 31. Registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan who are not registered shareholders. As of February 21, 2007, HEI had 34,908 registered shareholders and participants.

The Company discontinued its international power operations in 2001. See Note 14, “Discontinued operations,” of HEI’s “Notes to Consolidated Financial Statements.” Also see “Commitments and contingencies” in Note 3 of HEI’s “Notes to Consolidated Financial Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions of certain contingencies that could adversely affect future results of operations and factors that affected reported results of operations (e.g., bank franchise taxes).

On April 20, 2004, the HEI Board of Directors approved a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information has been adjusted to reflect the stock split for all periods presented.

HECO:

The information required by this item is incorporated herein by reference to “Selected Financial Data” on page 1 of HECO Exhibit 99.4.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with HEI’s consolidated financial statements and accompanying notes. The general discussion of HEI’s consolidated results should be read in conjunction with the segment discussions of the electric utilities and the bank that follow.

HEI Consolidated

Executive overview and strategy

The Company’s three strategic objectives, currently, are to operate the electric utility and bank subsidiaries for long-term growth, maintain the annual dividend and increase the Company’s financial flexibility by strengthening the balance sheet and maintaining credit ratings.

HEI, through HECO and its electric utility 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 asset size.

In 2006, income from continuing operations was $108 million, compared to $127 million in 2005. Basic earnings per share from continuing operations were $1.33 per share in 2006, down 16% from $1.58 per share in 2005 due to lower earnings at the bank and “other” segments, partly offset by slightly higher earnings at the electric utilities. The electric utilities’ earnings benefited from interim rate relief and slightly higher kilowatthour (KWH) sales, but were also impacted by higher expenses, which were expected and are expected to continue. The bank’s earnings were hurt by the challenging interest rate environment—a flat or inverted yield curve throughout 2006—and higher legal and litigation-related expenses, but the core business performed well as loans grew and deposits stabilized. The “other” segment’s $23 million loss in 2006 was larger than the $10 million loss in 2005 primarily due to a one-time net gain of $9 million on the sale of a leveraged lease investment in 2005.

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. Per the State of Hawaii Department of Business, Economic Development and Tourism (DBEDT), Hawaii real gross state product grew by an estimated 2.7% in 2006 and is expected to grow by a forecasted 2.6% in 2007.

Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, HECO, have paid dividends continuously since 1901. The dividend has been stable at $1.24 per share annually since 1998 (split-adjusted). The indicated dividend yield as of December 31, 2006 was 4.6%. HEI’s Board believes that HEI should have a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level. The dividend payout ratios based on net income for 2006, 2005 and 2004 were 93%, 79% and 90% (payout ratios of 93%, 78% and 91% based on income from continuing operations), respectively. The payout ratio for 2006 was higher due to the lower net income. The payout ratio for 2004 was impacted by a charge to net income of $20 million due to a June 2004 adverse tax ruling and subsequent settlement and an increased number of shares outstanding from the sale of 2 million shares (pre-split) of common stock in March 2004. Without the bank franchise tax charge, the payout ratio for 2004 would have been 76% (77% based on income from continuing operations).

In the first half of 2004, HEI strengthened its balance sheet through a common stock sale and repayment and refinancing of debt.

HEI’s subsidiaries from time to time consider various strategies designed to enhance their competitive positions and to maximize shareholder value. These strategies may include the formation of new subsidiaries or the acquisition or disposition of businesses. The Company may from time to time be engaged in preliminary

discussions, either internally or with third parties, regarding potential transactions. Management cannot predict whether any of these strategies or transactions will be carried out or, if so, whether they will be successfully implemented.

See the Electric Utility and Bank sections for their respective executive overviews and strategies.

Economic conditions

Note: The statistical data in this section is from public third party sources (e.g., DBEDT, U.S. Census Bureau and Bloomberg).

Because its 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 – is estimated by the DBEDT to have been 2.7% in 2006. DBEDT expects that growth will further moderate to 2.6% in 2007 and 2.5% in 2008.

Following two exceptional years of growth, tourism in Hawaii remained strong with visitor expenditures reaching a record $12 billion in 2006, a 2.9% increase over 2005. 2006 visitor days were slightly lower by 0.3% compared to the 2005 record-high level. State economists expect continued growth in 2007 with projected increases of 1.5% in visitor days and 4.8% in visitor expenditures.

Hawaii was the fifth ranking state in federal government expenditures per capita in the latest available data. 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.

The real estate and construction industries in Hawaii also influence HEI’s core businesses. The Oahu housing market continued to stabilize in 2006 with home sales volume down by 12.5% compared to 2005. Total dollar sales volume for 2006 was $5.5 billion, down 8.8%, compared to the same period of 2005. However, Oahu home sales prices continued to increase with the average median price for a single-family home of $630,000 for 2006, compared to $590,000 for 2005.

The construction industry continues to remain strong as indicated by an 8% increase in 2006 building permits compared to 2005. Local economists expect a gradual slowing in residential construction as rising costs meet flattening demand. However, it is expected that increased military and commercial construction will be stabilizing factors.

Overall, the outlook for the Hawaii 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.

Management also monitors (1) oil prices because of their impact on the rates the utilities charge for electricity and the potential effect of increased electricity prices on usage and (2) interest rates because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital and pension costs, and HEI’s stock price. Crude oil prices hovered around $70 per barrel in the first half of 2006 due to geopolitical fallout from Iran’s renewed nuclear program and risks of supply disruption. Prices remained high during the third quarter of 2006 and came off their high levels toward year-end due to a slowing U.S. economy and lessening concerns about Iran’s continuing its nuclear program. The average fuel oil cost per barrel for the electric utilities increased 20% in 2006 compared to 2005. On February 21, 2007, crude oil futures closed at $58.02 per barrel.

For most of 2006, long-term interest rates fluctuated in the 4.0% to 5.25% trading range and the short-end of the yield curve continued to increase. This resulted in an inverted yield curve for most of 2006 which is indicative of a difficult earning environment for ASB. As of December 31, 2006, the yield curve was inverted with a spread between the 10-year and 2-year Treasuries of (0.11)%, compared to the yield curve as of December 31, 2005, with a spread of (0.02)%.

Results of Operations


(dollars in millions, except per share amounts)	2006			% change		2005			% change		2004
Revenues	$	2,461		11		$	2,216		15		$	1,924
Operating income		239		(12	)		271		—			271

Income from continuing operations	$	108		(15	)	$	128		18		$	108
Loss from discontinued operations		—		NM			(1	)	NM			2

Net income	$	108		(15	)	$	127		16		$	110

Electric utility	$	75		3		$	73		(10	)	$	81
Bank		56		(14	)		65		58			41
Other		(23	)	NM			(10	)	NM			(14	)

Income from continuing operations	$	108		(15	)	$	128		18		$	108

Basic earnings (loss) per share
Continuing operations	$	1.33		(16	)	$	1.58		16		$	1.36
Discontinued operations		—		NM			(0.01	)	NM			0.02

	$	1.33		(15	)	$	1.57		14		$	1.38

Dividends per share	$	1.24		—		$	1.24		—		$	1.24

Weighted-average number of common shares outstanding (millions)		81.1		—			80.8		2			79.6
Dividend payout ratio		93	%				79	%				90	%
Dividend payout ratio – continuing operations		93	%				78	%				91	%

NM	Not meaningful.

Stock split

On April 20, 2004, HEI announced a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information above, in the accompanying financial statements and notes and elsewhere in this report have been adjusted to reflect the stock split (unless otherwise noted). See Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

Bank franchise taxes (consolidated HEI)

The 2004 results of operations include an after-tax charge of $20 million, or $0.25 per share, due to a June 2004 tax ruling and subsequent settlement as discussed in Note 10 of HEI’s “Notes to Consolidated Financial Statements” under “ASB state franchise tax dispute and settlement.” The following table presents a reconciliation of HEI’s consolidated income from continuing operations to income from continuing operations excluding this $20 million charge in 2004. The Company believes the adjusted information below presents results from continuing operations on a more comparable basis for the periods shown. However, net income, or earnings per share, including these adjustments is not a presentation defined under U.S. generally accepted accounting principles (GAAP) and may not be comparable to presentations used by other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.


Years ended December 31	2006			2005			2004
(dollars in thousands, except per share amounts)

Income from continuing operations	$	108,001		$	127,444		$	107,739
Basic earnings per share - continuing operations	$	1.33		$	1.58		$	1.36

Cumulative bank franchise taxes, net of taxes, through December 31, 2003	$	—		$	—		$	20,340

As adjusted
Income from continuing operations	$	108,001		$	127,444		$	128,079
Basic earnings per share - continuing operations	$	1.33		$	1.58		$	1.61
Return on average common equity ¹		9.3	%		10.5	%		11.2	%

¹	Calculated using adjusted income from continuing operations divided by the simple average adjusted common equity.

Taking into account the adjustments in the table above, HEI’s 2005 consolidated income from continuing operations would have been flat compared to 2004.

Retirement benefits

The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions about future experience. For example, retirement benefits costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans, earnings and realized and unrealized gains and losses on plan assets and changes made to the provisions of the plans. (No changes were made to the retirement benefit plans’ provisions in 2006, 2005 and 2004 that have had a significant impact on costs.) Costs may also be significantly affected by changes in key actuarial assumptions, including the expected return on plan assets and the discount rate. The Company accounts for retirement benefit costs in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” and thus, changes in obligations associated with the factors noted above may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.

The assumptions used by management in making benefit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefits costs on a prospective basis. In selecting an assumed discount rate, the Company considered the Moody’s Daily Long-Term Corporate Bond Aa Yield Average (which was 5.72% as of December 31, 2006 compared to 5.41% as of December 31, 2005) and changes in this rate from period to period. In addition, the Company also considered the plans’ actuarial consultant’s cashflow matching analysis based upon bond information provided by Standard & Poors for all high quality bonds (i.e., rated AA- or better) as of December 31, 2006. In selecting an assumed rate of return on plan assets, the Company considers economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the plans’ asset allocations and the past performance of the plans’ assets.

For 2006, the Company’s retirement benefit plans’ assets generated a total return, net of investment management fees, of 13.5%, resulting in earnings and realized and unrealized gains of $122 million, compared to $65 million for 2005 and $82 million for 2004. The market value of the retirement benefit plans’ assets as of December 31, 2006 was $1 billion. See “Liquidity and Capital Resources” below for the Company’s cash contributions to the retirement benefit plans.

Based on various assumptions in Note 8 of HEI’s “Notes to Consolidated Financial Statements” and assuming no further changes in retirement benefit plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s accumulated other comprehensive income (AOCI) balance, net of tax benefits, related to the liability for retirement benefits; retirement benefits expense, net of income taxes; and retirement benefits paid and plan expenses were, or are estimated to be, as follows as of the dates or for the periods indicated:


	AOCI balance, net of tax benefits,						Retirement benefits expense, net of income tax benefits								Retirement benefits paid and expenses
	December 31						Years ended December 31								Years ended December 31
	2006			2005			(Estimated) 2007 ¹		2006		2005 ²		2004 ²		2006		2005		2004
(dollars in millions)

Consolidated HEI	$	(140	)	$	(1	)	$	20	$	17	$	11	$	7	$	55	$	51	$	49
Consolidated HECO		(127	)		—			16		13		8		4		51		50		47
ASB		(8	)		—			2		3		2		2		2		1		1

¹	Forward-looking statements subject to risks and uncertainties, including the impact of plan changes during the year, if any, and the impact of actual information when received (e.g., actual participant demographics as of January 1, 2007).

²	Does not include impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

See Note 8 of HEI’s “Notes to Consolidated Financial Statements” for further retirement benefits information.

The following tables reflect the sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2006, and the sensitivity of 2007 net income, associated with a change in certain actuarial assumptions by the indicated basis points and constitute “forward-looking statements.” Each sensitivity below reflects the impact of a change in that assumption.


Actuarial assumption	Change in assumption in basis points	Impact on PBO or APBO			Impact on 2007 net income
(dollars in millions)

Pension benefits
Discount rate	+/–50	$	(63	)/$70	$	3/$	(3)
Rate of return on plan assets	+/–50		NA			2/	(2)
Other benefits
Discount rate	+/–50		(11	)/12		– /	(1)
Health care cost trend rate	+/–100		4/	(4)		–/–
Rate of return on plan assets	+/– 50		NA			–/–

NA	Not applicable.

Baseline assumptions: 6.0% discount rate; 8.5% asset return rate; 10% medical trend rate for 2007, grading down to 5% for 2012 and thereafter; 5% dental trend rate; and 4% vision trend rate.

“Other” segment


(dollars in millions)	2006		% change	2005			% change	2004
Revenues ¹	(2	)	NM	$	21		134	$	9
Operating income (loss)	(16	)	NM		5		NM		(8	)
Net loss	(23	)	NM		(10	)	NM		(14	)

¹	Including writedowns of and net gains and losses from investments.

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. (TOOTS), a maritime freight transportation company that ceased operations in 1999; HEI and HEI Diversified, Inc. (HEIDI), holding companies; and eliminations of intercompany transactions.

· HEIII recorded net income of $3.5 million in 2006, including intercompany interest income and income from leveraged leases. HEIII recorded net income of $16.2 million in 2005, including a gain of $14 million on the sale of its approximate 25% interest in a trust that is the owner/lessor of a 60% undivided interest in a coal-fired electric generating plant in Georgia. Most of the approximately $5 million of income taxes on the sale were recorded at HEI in accordance with the Company’s “stand-alone” tax allocation policy. HEIII recorded net income of $1.8 million in 2004, primarily from leveraged leases.

· HEIPI recorded net losses of $1.8 million in 2006, net income of $3.5 million in 2005 and net losses of $0.9 million in 2004, which amounts include income and losses from and/or writedowns of venture capital investments. In 2006, HEIPI recognized $2.6 million in unrealized and realized losses ($1.6 million after-tax) on its investment in Hoku Scientific, Inc. (Hoku), a materials science company focused on clean energy technologies that completed its initial public offering and became a public company in August 2005. In 2005, HEIPI recognized a $4.6 million unrealized gain ($2.9 million after-tax) on its investment in Hoku and recorded lower writedowns of another venture capital investment in a nonpublic company. HEIPI began trading Hoku stock in February 2006 when its lock-up agreement expired. As of December 31, 2006, HEIPI’s venture capital investments (including its remaining investment in Hoku) amounted to $2.8 million. In January 2007, HEIPI sold its remaining investment in Hoku with a fair value at December 31, 2006 of $1.2 million for a net after-tax gain of $0.9 million.

· HEI Corporate and the other subsidiaries’ revenues in 2004 include a $5.6 million pretax gain ($3.6 million after-tax) on the sale of the income notes that HEI purchased in May and July 2001 in connection with the termination of ASB’s investments in trust certificates.

HEI Corporate operating, general and administrative expenses (including labor, employee benefits, incentive compensation, charitable contributions, legal fees, consulting, rent, supplies and insurance) were $12.1 million in 2006, down from $14.8 million in 2005 and $14.9 million in 2004. In 2006, incentive compensation was lower and share-based compensation was lower (as the restricted stock granted in 2006 had no acceleration feature for retirement). HEI Corporate and the other subsidiaries’ net loss was $24.5 million in 2006, $30.0 million in 2005 and $15.4 million in 2004, the majority of which is comprised of financing costs. The results for 2006 and 2005 did not

include $5.4 million of dividends on ASB preferred stock held by HEIDI, as it had in 2004, due to the redemption of ASB’s preferred stock in December 2004, which was followed by a $75 million infusion into ASB of common equity by HEIDI. The results for 2005 include most of the $5 million of income taxes on the $14 million gain on sale by HEIII of the trust interest described above and results for 2004 include a $3.6 million after-tax gain on the sale of the income notes, which amounts are not expected to be recurring.

• The “other” segment’s interest expenses were $23.1 million in 2006, $25.9 million in 2005 and $27.6 million in 2004. In 2006, financing costs decreased due to the use of lower-costing short-term commercial paper borrowings to replace or temporarily refinance maturing medium-term notes. In 2005, financing costs decreased due to lower interest rates and lower average borrowing balances.

Discontinued operations

In 2001, the HEI Board of Directors adopted a plan to exit the international power business. In 2004, HEI Power Corp. (HEIPC) and its subsidiaries (HEIPC Group) sold the company that holds its interest in Cagayan Electric Power & Light Co., Inc. (CEPALCO) for a nominal gain. Also in 2004, the HEIPC Group transferred its interest in a China joint venture to its partner and another entity and recorded an after-tax gain on disposal of $2 million. In 2005, HEIPC increased its reserve for future expenses by $1 million primarily due to higher than expected arbitration costs in connection with HEI and HEIPC claims under a political risk insurance policy; the arbitration concluded unsuccessfully in 2005. See Note 14 of HEI’s “Notes to Consolidated Financial Statements.”

Prior to July 1, 2006, all of HEIPC’s subsidiaries, except for HEIII, were dissolved. In December 2006, HEIPC’s stock in HEIII was transferred to HEI and HEIDI and HEIPC filed articles of dissolution in Hawaii on December 20, 2006. HEI is currently the sole shareholder of HEIII.

Effects of inflation

U.S. inflation, as measured by the U.S. Consumer Price Index (CPI), averaged 2.5% in 2006, 3.4% in 2005, and 3.3% in 2004. Hawaii inflation, as measured by the Honolulu CPI, was 5.9% in 2006, 3.8% in 2005 and 3.3% in 2004. DBEDT forecasts average Honolulu CPI to be 4.0% for 2007. The rate of inflation over the last few years has been trending upward and inflation continues to have an impact on HEI’s operations.

Inflation increases operating costs and the replacement cost of assets. Subsidiaries with significant physical assets, such as the electric utilities, replace assets at much higher costs and must request and obtain rate increases to maintain adequate earnings. In the past, the Public Utilities Commission of the State of Hawaii (PUC) has generally approved rate increases to cover the effects of inflation. The PUC granted an interim rate increase in 2005 for HECO and final rate increases in 2001 and 2000 for HELCO and in 1999 for MECO, in part to cover increases in construction costs and operating expenses due to inflation.

Recent accounting pronouncements

See “Recent accounting pronouncements and interpretations” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

Liquidity and capital resources

Selected contractual obligations and commitments

The following tables present Company-aggregated information about total payments due during the indicated periods under the specified contractual obligations and commercial commitments:


December 31, 2006	Payment due by period
(in millions)	1 year or less		2-3 years		4-5 years		More than 5 years		Total
Contractual obligations
Deposit liabilities
Commercial checking	$	319	$	—	$	—	$	—	$	319
Other checking		853		—		—		—		853
Savings		1,570		—		—		—		1,570
Money market		202		–—		—		—		202
Term certificates		1,212		213		198		9		1,632

Total deposit liabilities		4,156		213		198		9		4,576

Other bank borrowings		787		482		100		200		1,569
Long-term debt, net		10		50		150		923		1,133
Operating leases, service bureau contract and maintenance agreements		29		44		26		32		131
Open purchase order obligations		54		11		3		—		68
Fuel oil purchase obligations (estimate based on January 1, 2007 fuel oil prices)		539		1,078		1,077		1,617		4,311
Power purchase obligations– minimum fixed capacity charges		118		234		237		1,130		1,719

Total (estimated)	$	5,693	$	2,112	$	1,791	$	3,911	$	13,507


December 31, 2006
(in millions)

Other commercial commitments to ASB customers
Loan commitments (primarily expiring in 2007)	$	24
Loans in process		117
Unused lines and letters of credit		1,000

	$	1,141

The tables above do not include other categories of obligations and commitments, such as interest (on deposit liabilities, other bank borrowings and long-term debt), trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, obligations that may arise under indemnities provided to purchasers of discontinued operations and potential refunds of amounts collected under interim D&Os of the PUC. As of December 31, 2006, the fair value of the assets held in trusts to satisfy the obligations of the qualified pension plans exceeded the pension plans’ accumulated benefit obligation. Thus, no minimum funding requirements for retirement benefit plans have been included in the tables above.

See Note 3 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of fuel and power purchase commitments.

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

The Company’s total assets were $9.9 billion as of December 31, 2006 and $10.0 billion as of December 31, 2005.

The consolidated capital structure of HEI (excluding ASB’s deposit liabilities, securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle) was as follows:


December 31	2006				2005
(dollars in millions)			`

Short-term borrowings	$	177	7	%	$	142	6	%
Long-term debt, net		1,133	47			1,143	45
Preferred stock of subsidiaries		34	1			34	1
Common stock equity ¹		1,095	45			1,217	48

	$	2,439	100	%	$	2,536	100	%

¹	Includes AOCI charge for retirement benefit plans in accordance with SFAS No. 158 as of December 31, 2006.

As of February 28, 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/Negative/A-2.

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities. In November 2006, S&P affirmed its corporate credit ratings of HEI and maintained its negative outlook. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P indicated:

Failure to strengthen key financial parameters, especially cash flow coverage of debt, a slump in the Hawaiian economy, a punitive final rate order, and, although not expected, a major erosion in American Savings Bank’s creditworthiness could lead to lower ratings. Conversely, credit-supportive actions by the company as well as responsive rate treatment would lead to ratings stability.

In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). In November 2006, S&P did not change HEI’s business profile rank of “6”.

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.”

On August 8, 2006, HEI completed the sale of $100 million of 6.141% Medium-Term Notes, Series D due August 15, 2011, under its registered medium-term note program. The proceeds from the sale were ultimately used to reduce HEI’s outstanding commercial paper as it matured. As of December 31, 2006, $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 2006 of $68.5 million and had $63.2 million outstanding as of December 31, 2006. Management believes that if HEI’s commercial paper ratings were to be downgraded, it might not be able to sell commercial paper under current market conditions.

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight

financial institutions. See Note 6 of HEI’s “Notes to Consolidated Financial Statements” for a description of the $100 million credit facility. As of December 31, 2006, 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.

Operating activities provided net cash of $286 million in 2006, $218 million in 2005 and $244 million in 2004. Investing activities used net cash of $141 million in 2006, $202 million in 2005 and $540 million in 2004. In 2006, net cash was used in investing activities primarily for HECO’s consolidated capital expenditures, net of contributions in aid of construction, and net increases in loans held for investment, partly offset by repayments of investment and mortgage-related securities and sales of mortgage-related securities, net of purchases. Financing activities used net cash of $105 million in 2006 and provided net cash of $22 million in 2005 and $187 million in 2004. In 2006, net cash used in financing activities was affected by several factors, including payment of common stock dividends and net decreases in other bank borrowings and long-term debt, partly offset by net increases in short-term borrowings and deposits and proceeds from the issuance of common stock.

A portion of the net assets of HECO and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval. One of the conditions of the merger and corporate restructuring of HECO and HEI requires that HECO maintain a consolidated common equity to total capitalization ratio of not less than 35%, and restricts HECO from making distributions to HEI to the extent it would result in that ratio being less than 35%. In the absence of an unexpected material adverse change in the financial condition of the electric utilities or ASB, such restrictions are not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or its ability to meet its debt or other cash obligations. See Note 12 of HEI’s “Notes to Consolidated Financial Statements.”

Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2007 through 2009 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction program (see “Electric utility—Liquidity and capital resources”), approximately $60 million will be required during 2007 through 2009 to repay maturing HEI medium-term notes, which are expected to be repaid with the issuance of common stock under Company plans and dividends from subsidiaries. On December 15, 2006, the HEI Board of Directors determined that the common stock requirements for the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) and Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) will be satisfied by issuance of new HEI shares (rather than open market purchases), and this change is expected to be implemented commencing in March 2007. Additional debt and/or equity financing may be required to fund unanticipated expenditures not included in the 2007 through 2009 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the utilities, utility capital expenditures that may be required by new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if tax positions taken by the Company do not prevail. In addition, existing debt may be refinanced prior to maturity (potentially at more favorable rates) with additional debt or equity financing (or both).

As further explained in Note 8 of HEI’s “Notes to Consolidated Financial Statements,” the Company maintains pension and other postretirement benefit plans. Funding for the qualified pension plans is based upon actuarially determined contributions that consider the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended (ERISA). The Company was not required to make any contributions to the qualified pension plans to meet minimum funding requirements pursuant to ERISA for 2006, 2005 and 2004, but the Company’s Pension Investment Committee chose to make tax deductible contributions in those years. The electric utilities’ policy is to comply with directives from the PUC to fund the costs of the postretirement benefit plan. These costs are ultimately collected in rates billed to customers. The Company reserves the right to change, modify or terminate the plans and, historically, benefits have been changed from time to time. From time to time in the past, benefits have changed.

Contributions to the retirement benefit plans totaled $13 million in 2006 (comprised of $10 million made by the utilities and $3 million by ASB), $25 million in 2005 and $37 million in 2004 (includes Company payments for nonqualified plans in 2005 and 2004, but not 2006). Contributions to the retirement benefits plans are expected to total $14 million in 2007 ($11 million by the utilities and $3 million by ASB ). Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to

meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate access to capital resources to support any necessary funding requirements.

Off-balance sheet arrangements

Although the Company has off-balance sheet arrangements, management has determined that it has no off-balance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors, including the following types of off-balance sheet arrangements:

(1)

obligations under guarantee contracts,

(2)

retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serves as credit, liquidity or market risk support to that entity for such assets,

(3)

obligations under derivative instruments, and

(4)

obligations under a material variable interest held by the Company in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.

Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments. Additional segment information is shown in Note 2 of HEI’s “Notes to Consolidated Financial Statements.”

Electric utility

Executive overview and strategy

The electric utilities are vertically integrated and regulated by the PUC. The island utility systems are not interconnected, which requires that additional reliability be built into the systems, but also means that the utilities are not exposed to the risks of inter-ties. The electric utilities’ strategic focus has been to meet Hawaii’s growing energy needs through a combination of diverse activities—modernizing and adding needed infrastructure through capital investment, placing emphasis on energy efficiency and conservation, pursuing renewable energy options and technology opportunities (such as combined heat and power and distributed generation (DG)) and taking the necessary steps to secure regulatory support for their plans.

Reliability projects, including projects to increase generation reserves to meet growing peak demand, remain a priority for HECO and its subsidiaries. On Oahu, HECO is in the early permitting stages for a new generating unit, which is projected to be placed in service in 2009, and is making progress with plans to build the East Oahu Transmission Project (EOTP), a needed alternative route to move power from the west side of the island. HECO installed a new Energy Management System in 2006 and is scheduled to complete a new Dispatch Center on Oahu in 2007. PUC approvals have been obtained for the new Outage Management and Customer Information Systems, which will also be integrated. On the island of Hawaii, after years of delay, the two 20 megawatt (MW) combustion turbines at Keahole are operating. On the island of Maui, an 18 MW steam turbine at the Maalaea power plant site was installed in 2006. Further, the utilities have demand-side management (DSM) rebate programs and are considering additional DG at utility-owned sites (e.g., substations) as another measure to potentially help meet growing peak demand.

Major infrastructure projects can have a pronounced impact on the communities in which they are located. The electric utilities continue to expand their community outreach and consultation process so they can better understand and evaluate community concerns early in the process.

With large power users in the electric utilities’ service territories, such as the U.S. military, hotels and state and local government, management believes that retaining customers by maintaining customer satisfaction is a critical component in achieving kilowatthour (KWH) sales and revenue growth over time. The electric utilities have established programs that offer these customers specialized services and energy efficiency audits to help them save on energy costs.

In November 2004, HECO filed a request with the PUC to increase base rates, primarily for (1) costs relating to existing and proposed energy conservation and efficiency programs (DSM programs), (2) costs of capital improvement projects, (3) the proposed purchase of additional firm capacity and energy, (4) costs of other measures taken to address peak load increases, and (5) increased operation and maintenance expenses. Interim rate relief was granted in late September 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 DSM programs, with certain modifications, were approved in February 2007. See “Most recent rate requests—HECO” and “Other regulatory matters—Demand-side management programs.”

In May 2006, December 2006 and February 2007, HELCO, HECO and MECO filed requests with the PUC to increase base rates by $29.9 million, $99.6 million and $19.0 million, respectively. See “Most recent rate requests.”

The electric utilities’ long-term plan to meet Hawaii’s future energy needs includes their support of a range of energy choices, including renewable energy and new power supply technologies such as DG. The PUC has issued a decision and framework in a competitive bidding proceeding and a decision in a DG proceeding (see “Certain factors that may affect future results and financial condition—Consolidated—Competition—Electric utility”). HECO’s subsidiary, Renewable Hawaii, Inc. (RHI), has initial approval from the HECO Board of Directors to fund investments by RHI of up to $10 million in selected renewable energy projects to help bring online commercially feasible renewable energy sources in Hawaii.

Net income for HECO and its subsidiaries was $75 million in 2006 compared to $73 million in 2005 and $81 million in 2004. The increase in 2006 was primarily due to the impact of HECO’s interim rate increase granted by the PUC in late September 2005, largely offset by increased operation and maintenance expenses (including more extensive maintenance on generating units, which are getting older and are being run harder to meet the higher peak demand for electricity, and higher retirement benefits expense) and higher depreciation expense due to investments in capital projects.

Results of Operations


(dollars in millions, except per barrel amounts)	2006			% change		2005			% change		2004
Revenues ¹	$	2,055		14		$	1,806		16		$	1,551
Expenses
Fuel oil		782		22			640		32			483
Purchased power		507		11			458		15			399
Other		599		10			546		11			495
Operating income		167		3			162		(7	)		174
Allowance for funds used during construction		9		30			7		(15	)		8
Net income		75		3			73		(10	)		81
Return on average common equity		7.5	%				7.1	%				8.3	%
Average price per barrel of fuel oil ¹	$	68.13		20		$	56.61		33		$	42.67
Kilowatthour sales (millions)		10,116		—			10,090		—			10,063
Cooling degree days (Oahu)		4,520		(9	)		4,971		(3	)		5,107
Number of employees (at December 31)		2,085		1			2,066		3			2,013

¹	The rate schedules of the electric utilities currently contain ECACs through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.

• In 2006, the electric utilities’ revenues increased by 14%, or $249 million, from 2005 primarily due to higher fuel prices ($200 million), interim rate relief granted by the PUC in late September 2005 ($30 million), slightly higher KWH sales ($13 million), and higher DSM program recovery revenues ($6 million), partly offset by lower shareholder incentives and lost margins ($4 million), including the surcharge transferred to base rates in the interim rate relief granted in September 2005. Since May 26, 2006, HECO and, since September 26, 2006, HELCO and MECO, have discontinued their recovery of lost margins and shareholder incentives for their DSM programs until further order by the PUC, which has resulted in reduced revenues. KWH sales increased 0.3% from 2005 primarily due to new load growth (i.e., increase in number of customers), largely offset by the impacts of cooler and less humid weather and customer conservation. Cooling degree days for Oahu were 9% lower in 2006 compared to 2005. The electric utilities are currently estimating KWH sales for 2007 and 2008 to increase over the prior year by 0.6% and 1.6%, respectively. The higher fuel prices are also reflected in the higher amount of customer accounts receivable and accrued unbilled revenues.

Operating income in 2006 was $5 million higher than in 2005 due primarily to the impact of HECO’s interim rate increase in late September 2005, partly offset by higher other expenses, including higher maintenance and retirement benefit expenses, and the discontinuation of the recovery of DSM lost margins and shareholder incentives.

Fuel oil and purchased power expenses in 2006 increased by 22% and 11%, respectively, due primarily to higher fuel prices, which are generally passed on to customers.

Other expenses increased 10% in 2006 due to an 8% (or $13 million) increase in “other operation” expense; a 10% (or $8 million) increase in maintenance expense; a 6% (or $7 million) increase in depreciation expense; and a 14% (or $23 million) increase in taxes, other than income taxes, primarily due to the increase in revenues. “Other operation” expenses increased 8% in 2006 when compared to 2005 due primarily to $5 million higher expenses for production operations (including expenses incurred to sustain or increase generating unit availability and lease rent and operating expenses for distributed generation units on Oahu), higher DSM expenses which are generally passed on to customers through a surcharge, and higher retirement benefits expenses. Pension and other postretirement benefit expenses for the electric utilities increased $9 million over 2005 due in part to the adoption of a 25 basis points lower discount rate as of December 31, 2005. Maintenance expenses increased 10% due to $7 million higher production maintenance expense (primarily due to generating plant maintenance and an increase in the number and greater scope of generating unit overhauls) and $1 million higher transmission and distribution maintenance expense (including higher substation maintenance, vegetation management and distribution line maintenance expenses). Higher depreciation expense was attributable to additions to plant in service in 2005 (including HECO’s New Kuahua Substation, Mokuone Substation 46 kilovolt (kV) and 12 kV line extensions, an office building air conditioning replacement and HELCO’s Keahole power plant noise mitigation measures).

The trend of increased operation and maintenance (O&M) expenses is expected to continue 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 decision and order (D&O) in an EE DSM Docket), (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to support the increased level of peak demand that has occurred over the past five years.

As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability. 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 and Maui during peak periods continued to be strained. The electric utilities on Oahu and Maui have taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying energy to meet growing demand, however, are increasing because of the decreasing peak reserve margin situation, and the trend of cost increases is not likely to ease.

• In 2005, the electric utilities’ revenues increased by 16%, or $256 million, from 2004 primarily due to higher fuel prices ($235 million), interim rate relief granted by the PUC in late September 2005 ($10 million) and increased shareholder incentives and lost margins ($6 million), including the surcharge transferred to base rates in the interim rate relief granted in September 2005. KWH sales increased 0.3% from 2004 primarily due to new load growth (i.e., increase in number of customers), largely offset by the impacts of cooler and less humid weather and major commercial repair and renovation projects. Cooling degree days for Oahu were 2.7% lower in 2005 compared to 2004. In addition, customers may have been moderating their energy usage in response to the electric utilities’ campaign to promote conservation and efficiency and possibly reacting to higher fuel prices reflected in electric bills. The higher fuel prices are also reflected in the higher amount of customer accounts receivable and accrued unbilled revenues.

Operating income in 2005 was $12 million lower than in 2004 mainly due to higher other expenses, including higher maintenance and retirement benefit expenses.

Fuel oil and purchased power expenses in 2005 increased by 32% and 15%, respectively, due primarily to higher fuel prices, which are generally passed on to customers.

Other expenses increased 11% in 2005 due to a 10% (or $16 million) increase in “other operation” expense; a 6% (or $5 million) increase in maintenance expense; a 7% (or $8 million) increase in depreciation expense;

and a 16% (or $23 million) increase in taxes, other than income taxes, primarily due to the increase in revenues. “Other operation” expenses increased 10% in 2005 when compared to 2004 due primarily to higher expenses for production operations (including higher environmental expenses as there was a Department of Health of the State of Hawaii (DOH) emission fee waiver in 2004, which was not repeated in 2005), transmission and distribution operations and retirement benefits. Pension and other postretirement benefit expenses for the electric utilities increased $6.7 million over the same period in 2004 due in part to the HEI Pension Investment Committee’s adoption of a 25 basis points lower discount rate as of December 31, 2004. Maintenance expenses increased 6% due to higher production maintenance expense (primarily due to generating plant maintenance and generating unit overhauls) and higher transmission and distribution maintenance expense. Higher depreciation expense was attributable to additions to plant in service in 2004 (including HELCO’s CT-4 and CT-5 and HECO’s Waiau fuel oil pipeline), offset in part by lower depreciation expense resulting from the PUC’s approval in September 2004 of rates and accounting methodology applicable to HECO’s depreciable assets on Oahu.

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, however, there is no guarantee of such an interim increase. Similarly, the timing and amount of any final increase is up to the discretion of the PUC. As of February 21, 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 ROACE used for purposes of the interim rate increase in HECO’s rate case based on a 2005 test year was 10.70%.

For 2006, the simple average ROACEs (calculated under the rate-making method and reported to the PUC), which calculations included the AOCI charges due to the application of SFAS No. 158, for HECO, HELCO and MECO were 8.19%, 3.88% and 9.86%, respectively; if the AOCI charges due to SFAS No. 158 were excluded, these ROACEs would have been 7.61%, 3.70% and 9.51%, respectively. HECO’s actual ROACE continues to be significantly lower than its allowed ROACE primarily because of increased 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 will continue to be negatively impacted by CT-4 and CT-5 as electric rates will not change for the unit additions unless and until the PUC grants rate relief in the HELCO rate case based on a 2006 test year (see below).

As of February 21, 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 ROR used for purposes of the interim D&O in the HECO rate case based on a 2005 test year was 8.66%. For 2006, the simple average RORs (calculated under the rate-making method and reported to the PUC) for HECO, HELCO and MECO were 6.78%, 4.50% and 7.21%, respectively.

The utilities have 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, the resulting increase in the electric utilities’ RORs and ROACEs could impact the rates the electric utilities are allowed to charge, which may ultimately result in reduced revenues and lower earnings. See Note 10 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 include (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. The parties/participants for all issues include HECO, the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate), the federal Department of Defense (DOD), the County of Maui, two renewable energy organizations, an energy efficiency organization, and an environmental organization. HELCO, MECO, Kauai Island Utility Cooperative, The Gas Company and the County of Kauai are parties/participants solely for issues dealing with statewide energy policies. The U.S. Environmental Protection Agency (EPA) and its consultants also have been involved in an advisory capacity to the PUC, and have submitted comments on the proposed DSM programs and the issues in this proceeding. See “Other regulatory matters—Demand-side management programs” below for additional information on this docket and a discussion of the PUC’s Interim D&O issued on April 26, 2006.

In September 2005, HECO, the Consumer Advocate and the DOD reached agreement (subject to PUC approval) among themselves 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 effective September 28, 2005 and amounts collected refundable, with interest, to ratepayers to the extent they exceed the amount approved in the final D&O). 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	Effective 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.

The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and ROR) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

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. Act 162, which was effective in June 2006, requires the PUC to consider certain specific factors in evaluating fuel adjustment clauses. See “Energy cost adjustment clauses” in Note 3 of HECO’s “Notes to Consolidated Financial Statements.” 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 Consumer Advocate, and the 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 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, 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 rate case based on a 2005 test year.

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, based on a 2007 test year, an 8.92% rate of ROR, an 11.25% ROACE and a $1.214 billion average rate base. HECO’s electric rates currently in effect include the interim rate increase discussed above of $53 million ($41 million net additional revenues) granted by the PUC in September 2005, which is subject to a final D&O from the PUC, and is subject to refund with interest if and to the extent that the final D&O provides for a lesser increase. If the additional revenues from the interim increase were ultimately not included in rates, 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, are 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 a 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 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) was filed with the PUC. The ECAC Report was prepared by the electric utilities’ consultant who was retained to determine whether their existing ECACs are in compliance with Act 162. 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 proceeding, the electric utilities requested the 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’s application, filed before that decision was issued, assumed that the amounts that would otherwise be charged to AOCI in stockholder’s equity would be recorded as a regulatory asset for financial reporting purposes (and used for ratemaking purposes). HECO’s book equity (financial reporting equity) will be lower than that assumed in the rate increase application because of the charges to AOCI as a result of recording a pension and other postretirement benefits liability after implementing SFAS No. 158 on December 31, 2006. HECO will propose in its rebuttal testimony to restore the book equity (financial reporting equity) for the amounts that were charged against equity (i.e., AOCI) in determining the equity balance for ratemaking purposes. 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 and rate increase in a rate case. If the equity balance is not restored for ratemaking purposes, the utility’s position is that a higher ROE will be required.

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. HELCO has filed testimonies and a consultant report to address the ECAC provisions of Act 162.

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 certain costs relating to the CT-4 and CT-5 generating units at Keahole (primarily a portion of 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 (which as a participant in the proceeding is limited to responding to discovery requests, filing a statement of position and responding to questions at any evidentiary hearing) 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.

Among the actions the Consumer Advocate or Keahole Defense Coalition claim to have been imprudent were the decision to site the generation at Keahole and HELCO’s attempts to expedite the addition of generation, even though the PUC, in its 1994 decision approving the commitment of expenditures for CT-4, found that HELCO had an urgent need for generation in the 1994-1995 time frame, recognized that permitting problems might delay CT-4, and concluded that, in light of present and foreseeable circumstances, the location of CT-4 at Keahole was reasonable.

HELCO plans to submit its rebuttal to the Consumer Advocate’s testimony and the Keahole Defense Coalition’s statement of position in March 2007. The rebuttal testimony will also propose to restore book equity (financial reporting equity) for the amounts that were charged against equity as of December 31, 2006 (i.e., AOCI) in determining the equity balance for ratemaking purposes. The procedural schedule also includes settlement discussions and discovery of HELCO’s rebuttal testimony prior to the evidentiary hearings scheduled in May 2007. The earliest that any increase, if granted, may go into effect is expected to be in the second quarter of 2007.

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. MECO has filed testimonies to address the ECAC provisions of Act 162. 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.

Depreciation rates and accounting

In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates based on a study of depreciation expense for 2000 and to change to vintage amortization accounting for selected plant accounts. In March 2004, HECO and the Consumer Advocate reached an agreement, which the PUC approved in September 2004. In accordance with the agreement, HECO changed its depreciation rates and changed to vintage amortization accounting for selected plant accounts effective September 1, 2004, resulting in slightly lower depreciation in the remainder of 2004 and for future years than would have been recorded under the previous rates and method.

Other regulatory matters

Demand-side management programs. In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, for the continuation of HECO’s three commercial and industrial DSM programs and two residential DSM programs until HECO’s next rate case. These agreements were in lieu of HECO continuing to seek approval of new 5-year DSM programs and provided that DSM programs to be in place after HECO’s next rate case would be determined as part of the case. Under the agreements, HECO agreed to cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current “authorized return on rate base” (i.e. the rate of return on rate base found by the PUC to be reasonable in the most recent rate case for HECO). HECO also agreed it would not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases. At the time of the agreement, HECO indicated to the Consumer Advocate that it planned to seek alternative incentive mechanisms for DSM programs in its rate case. In November 2001, the PUC issued orders that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case.

In November 2004, HECO filed a request for a rate increase based on a 2005 test year and approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. 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 based on a 2005 test year into a new EE DSM docket. The bifurcation order allowed HECO to temporarily continue, in the manner currently employed, its existing three commercial and industrial DSM programs and two residential DSM programs, until further order by the PUC. As a result of the bifurcation order in HECO’s rate case, HECO has been continuing its existing DSM programs and cost recovery mechanisms, including the recovery of incremental program costs for its energy efficiency DSM programs through a surcharge mechanism, pending the resolution of the EE DSM Docket.

Following the bifurcation order, HECO also continued to accrue shareholder incentives and lost margins. In December 2005 in the EE DSM Docket, HECO requested PUC approval, on an interim basis, for certain modifications to its existing energy efficiency DSM programs and a new interim DSM program (Interim DSM Proposals). HECO did not request shareholder incentives and lost margins for its proposed new interim DSM program, but did so for the modifications to its existing energy efficiency programs. In January 2006, the Consumer Advocate filed comments on HECO’s Interim DSM Proposals, which generally supported the proposals, but objected to the continued recovery of shareholder incentives and lost margins for the existing energy efficiency DSM programs, as well as for the modifications.

In April 2006, the PUC issued an Interim Decision and Order (Interim D&O) approving HECO’s requests to modify its existing DSM programs and implement its proposed interim DSM program. However, the PUC also ordered that HECO’s recovery of lost margins and shareholder incentives for its DSM programs be discontinued within 30 days of the Interim D&O (i.e., by May 26, 2006), until further order by the PUC. Lost margins and shareholder incentives are estimated and recorded in the year earned, and collected from ratepayers in the current year (lost margins) or the following year (shareholder incentives). Revenues that HECO had previously expected to accrue for lost margins and shareholder incentives from May 26, 2006 through the end of 2006 were estimated at $2.1 million, or $1.2 million in after-tax net income.

In October 2001, HELCO and MECO had reached similar agreements with the Consumer Advocate regarding the continuation of their DSM programs and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO were allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but were permitted in the orders to request to extend the time of such accrual and recovery for up to one additional year.

Based on the Interim D&O in the EE DSM docket, on May 25, 2006, HELCO and MECO filed a request for a one-year extension for the recovery of HELCO and MECO’s lost margins and shareholder incentives or until final resolution of the EE DSM Docket. On September 19, 2006, the Consumer Advocate opposed an extension beyond September 26, 2006 (i.e., one year beyond the interim rate increase in the HECO rate case). On October 4 and 5, 2006, the PUC issued orders that allowed HELCO and MECO to accrue lost margins and shareholder incentives only up to September 26, 2006. Revenues that HELCO and MECO had previously expected to accrue for lost margins and shareholder incentives from September 27, 2006 through the end of 2006 were estimated at $1.6 million, or $0.9 million in after-tax net income.

One of the conditions to the interim continuation of the DSM programs requires the utilities and the Consumer Advocate to review, every six months, the economic and rate impacts resulting from implementing the agreement. In 2003, 2005 and 2006, none of the electric utilities exceeded their respective authorized RORs. In 2004, only MECO exceeded its authorized ROR, resulting in a reduction of revenues from shareholders incentives and lost margins for MECO for 2004 by $1.0 million (recorded in December 2004). In reviewing HELCO’s ROR for 2003, the Consumer Advocate raised an issue regarding Keahole settlement expenses and HELCO agreed to refund, with interest, all of the lost margins and shareholder incentives it had earned in 2003. In June 2004, HELCO recorded reduced revenues of $1.1 million to reflect the lost margins and shareholder incentives for 2003 that were refunded to ratepayers in August 2004.

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. On November 22 and December 29, 2006, HECO filed proposed modifications to its Residential Direct Load Control (RDLC) and Commercial and Industrial Direct Load Control (CIDLC) programs. On December 29, 2006, the PUC approved the RDLC program modifications.

On February 13, 2007, the PUC issued its D&O in the EE DSM Docket. In the D&O, the PUC authorized HECO to implement its seven proposed EE DSM programs (which include enhancements to its five existing programs), with certain modifications, as well as a proposed Residential Customer Energy Awareness (RCEA) Program. 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 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.

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 will be determined using a computer production simulation model except for Lanai and Molokai, 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 it subsidiaries, the Consumer Advocate and 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.

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

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities 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.

In December 2006, the PUC issued a D&O allowing recovery of all but $46,000 of the $2.7 million of IRP costs the utilities incurred in 1995 and, in February 2007, issued a D&O allowing recovery of all but $1,000 of the $1.8 million of IRP costs the utilities incurred in 1996. However, 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. As

of December 31, 2006, the amount of revenues, including interest and revenue taxes, that the electric utilities recorded in 1997 through 2006 for IRP cost recoveries, subject to refund with interest, amounted to $14 million.

See “Demand-side management programs” above, which includes a discussion of the agreements between the utilities and the Consumer Advocate concerning prior caps on the recovery of lost margins and shareholders incentives.

HECO’s IRP. In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation (including a combustion turbine generating unit in 2009 described under “HECO’s 2009 Campbell Industrial Park generating unit” and a possible 180 MW coal unit in 2022). 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). In June 2006, the PUC granted an environmental group’s motion to intervene in the proceeding and ordered the parties to determine the issues, procedures and schedule for the docket and to file a stipulated procedural order. In September 2006, the parties to the IRP-3 docket filed for PUC approval a stipulation for the parties to meet informally to address IRP-3 process issues and to attempt to reach a follow-up stipulation that will allow for the disposition of the IRP-3 docket without a final D&O approving the IRP-3 plan and action plan. If the parties are unable to reach a follow-up stipulation, then the parties will file a stipulated procedural order setting forth the issues, procedures and schedule for the docket, or if the parties are unable to reach agreement on a stipulated procedural order, then the parties will submit separate proposed procedural orders for PUC consideration.

HELCO’s IRP. In September 1998, HELCO filed its second IRP with the PUC, and updated it in 1999 and 2004. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. The near-term additions included installing two 20 MW CTs at its Keahole power plant site (which were put into limited commercial operation in May and June 2004) and a power purchase agreement (PPA) with Hamakua Energy Partners, L.P. (HEP) for a 60 MW (net) facility (which was completed in December 2000). HELCO has deferred the retirements of some of its older generating units until the 2030 timeframe, and periodically assesses the cost-effectiveness of the continued operation of those units. HELCO’s current plans are to install an 18 MW heat recovery steam generator (ST-7) in 2009 or earlier. After the installation of ST-7, the target date in HELCO’s updated second IRP for the next firm capacity addition is the 2020 timeframe.

HELCO was to have filed its third IRP with the PUC by December 29, 2006, but requested an extension of the filing date to no later than May 31, 2007 and is awaiting a ruling on this request.

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000, and updated it in 2004 and 2005. On the supply side, MECO’s second IRP focused on the planning for the installation of approximately 150 MW of additional generation through the year 2020 on the island of Maui, including 38 MW of generation at its Maalaea power plant site in increments from 2000-2005, 100 MW at its new Waena site in increments from 2007-2018, beginning with a 20 MW combustion turbine in 2007 (currently not planned to be added until 2011), and 10 MW from the acquisition of a wind resource in 2003 (MECO actually first began to purchase wind energy in 2006 from Kaheawa Wind Power, LLC of 30 MW, not 10 MW). Approximately 4 MW of additional generation through the year 2020 were included for each of the islands of Lanai and Molokai. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000, and the final increment of 18 MW, which was originally expected to be installed in 2005, went into commercial operation in October 2006.

MECO’s third IRP is required to be filed with the PUC by April 30, 2007.

HECO’s 2009 Campbell Industrial Park 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 Campbell Industrial Park and an additional 138 kilovolt transmission line to transmit power from generating units at Campbell Industrial Park (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). Plans are for the combustion turbine 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 combustion turbine unit. The contract allows HECO to terminate the contract at a specified payment amount if necessary CT project approvals are not obtained.

The PUC granted an environmental group’s motion to intervene. In July 2006, the Honolulu City Council adopted a resolution to amend the Public Infrastructure Map to include the new generating facility at Campbell Industrial Park. HECO’s Final Environmental Impact Statement for the Project was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and the steps necessary for HECO to reach that goal. After agreeing to use 100% biofuels in its new plant, there were no remaining differences between HECO and the Consumer Advocate regarding the issues in the docket. The environmental group agreed that there is a need for additional generation on Oahu, but disagreed on the use of the proposed CT unit and the use of biofuels. Hearings were held in December 2006. Opening and Reply Briefs are due in March 2007 and a PUC decision is expected to follow.

Preliminary costs for the Project are estimated at $138 million. As of December 31, 2006, accumulated Project costs for planning, engineering, permitting and AFUDC amounted to $4.2 million.

In conjunction with the Project, in December 2006, HECO issued a Request for Proposals for suppliers of ethanol or biodiesel meeting HECO’s specifications 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 for part of the package of community benefit measures, which is currently estimated at $13.8 million (through the first 10 years of implementation), to mitigate the impact of the new generating unit on communities near the proposed generating unit site. These measures include a base electric rate discount for HECO’s residential customers who live near the proposed generation site, additional air quality monitoring stations, a fish monitoring program and the use of recycled instead of potable water for industrial water consumption at the Kahe power plant. For the community benefits application, the only party to the proceeding is the Consumer Advocate, and a hearing was held in November 2006. The primary issue during the hearing was whether rate recovery of foregone revenues from the proposed electric rate discount program is just and reasonable. The Consumer Advocate did not object to the remainder of the community benefit package. Briefs were filed in January 2007 and a PUC decision is pending.

Adequacy of supply.

HECO. HECO’s 2007 Adequacy of Supply (AOS) letter, filed in February 2007, indicates that HECO’s analysis estimates the reserve capacity shortfall to be approximately 70 MW in the 2007 to 2008 period (before the addition of the Campbell Industrial Park combustion turbine estimated to be installed in 2009), which is significantly smaller than the 170 to 180 MW shortfall in the 2007 to 2008 period projected in the 2006 AOS letter. While the decrease in the projected reserve capacity shortfall is due to a combination of factors, the primary factor is the significantly lower sales and peak forecast issued in August 2006 resulting in a reduction in peak demand used in AOS analyses of approximately 90 MW in the 2007 to 2008 period. Among other factors contributing to the reduction is a small improvement in the expectation of overall availability for existing generating units in future years. The small improvement projected in overall generating unit availability is based on the most recent operating experience in 2006 during which there was some improvement over 2005 in unit availability. However, 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, which could range between 20 MW to 110 MW in the 2009 to 2012 period. 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 and 1,315 MW in 2006. The gross peak demand of 1,327 MW in 2004 was 20 MW higher than the projected peak for 2004. Although the gross peak demand in 2005 and 2006 was lower than in 2004, demand for electricity on Oahu is projected to increase. In October 2004, November 2005, January 2006, June 2006 and February 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 November 2005, January 2006, June 2006 and February 2007, HECO remotely turned off water heaters for a number of residential customers who participate in its Energy Scout load-control program.

Also, see “Recent outages” below.

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.

Also, see “Recent outages” below.

MECO. In December 2005, MECO’s Maalaea Unit 13, a diesel generator, suffered an equipment failure and the unit is not expected to be available for service until approximately July 2007. 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. However, in the event of an unexpected outage of the largest unit, the Maui island system may not have sufficient capacity until Maalaea Unit 13, with a 12.34 MW capacity, returns to service. To overcome insufficient reserve capacity situations, MECO has been implementing appropriate mitigation measures, such as optimizing its unit overhaul schedule to minimize load capability shortfalls, coordinating the delivery of supplemental power, as needed, from an IPP and modifying its combined-cycle unit overhaul procedure to allow for the possible operation of the combustion turbine in simple-cycle mode. In October 2006, MECO placed into commercial operation an additional 18 MW of capacity at its Maalaea power plant site.

In April and August 2006, MECO experienced lower than normal generation capacity due to the unexpected temporary loss of several of its generating units, and issued a public request that its customers voluntarily conserve electricity.

Also, see “Recent outages” below.

Recent outages. HECO’s system peak loads generally occur in the fourth quarter of the year, but generation shortfall events may occur at any time during the year.

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 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 over 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, 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 on October 15 and 16, 2006. The preliminary 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 must be filed by March 30, 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.” The consultants also made a number of recommendations, mostly of a technical nature, regarding the operation of the electric system during such an incident. Management cannot predict the outcome of the investigation or its impacts on the utilities. Management is currently evaluating additional impacts the earthquakes and outages had and may have on the utilities (e.g., property damage and claims).

Collective bargaining agreements

Each of the electric utilities entered into a four-year collective bargaining agreement in 2003 with the union which represents approximately 58% of electric utility employees. See “Collective bargaining agreements” in Note 3 of HEI’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.

Public Utility Holding Company Act of 1935 (1935 Act) and Public Utility Holding Company Act of 2005 (2005 Act). The repeal of the 1935 Act, effective February 8, 2006, eliminates significant federal restrictions on the scope, structure and ownership of electric utilities. Some believe that the repeal will result in increased institutional ownership of and private equity and hedge fund investments in public utilities, increased consolidation in the industry, more Federal Energy Regulatory Commission (FERC) oversight, and additional diversification by electric utilities. The increased oversight by FERC results in part from the adoption of the 2005 Act, which provides for FERC access to the books and records of utility holding companies and, absent exemptions or waivers, imposes

certain record retention and accounting requirements on public utility holding companies. HEI and HECO filed a notification claiming a waiver of such requirements as single-state public utility holding companies. A written notice dated May 26, 2006 was received from FERC confirming the effectiveness of the HEI and HECO waivers. Regulation and oversight of HECO and its subsidiaries by the PUC, however, remains unchanged.

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. Management cannot predict the outcome of this process.

See “Renewable energy strategy” below.

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.

a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. If the fund is established, the PUC is required to appoint a fund administrator (other than an electric utility or utility affiliate) to operate and manage the programs established under the fund.

Non-fossil fuel purchased power contracts. In connection with the PUC’s determination of just and reasonable rates in purchased power contracts, the PUC will be required to 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.

Other legislation. A number of bills were introduced in the 2007 Hawaii State legislative session. The majority of the measures contained in these bills do not negatively affect the electric utilities, and the electric utilities support many of the measures that would encourage the more efficient use of energy and the use of Hawaii's renewable resources. Various bills also propose different approaches to addressing the issue of global warming. At this time, it is not possible to predict the outcome of the deliberations on any proposed legislation.

For a discussion of environmental legislation and regulations, see “Certain factors that may affect future results and financial condition—Consolidated—Environmental matters” below.

Other developments

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

HECO is currently partnering with Sensus Metering Systems to field test an Advanced Metering Infrastructure system that delivers hourly meter reads, which can enable time-of-use pricing options for HECO customers. This pilot is expected to include more than 3,000 residential, commercial and industrial customers. Other utility applications being evaluated include distribution system line monitoring, residential direct load control and monitoring of distribution substation equipment.

EarthLink, an internet service-provider, has partnered with the City and County of Honolulu in a pilot agreement to test providing free, wireless, broadband access in Chinatown in downtown Honolulu. As part of that Chinatown Pilot project, HECO hopes to negotiate a separate non-binding collaborative agreement with Earthlink to develop and demonstrate a variety of utility applications using WiFi technology, including advanced electric metering and energy conservation initiatives.

In October 2004, the Federal Communications Commission (FCC) released a Report and Order that amended and adopted new rules for Access Broadband over Power Line systems (Access BPL) and stated that an FCC goal in developing the rules for Access BPL “are therefore to provide a framework that will both facilitate the rapid introduction and development of BPL systems and protect licensed radio services from harmful interference.” Currently, there are no PUC regulations for electric utility applications of BPL systems. HECO completed a small-scale trial of the “Broadband over Power Line” (BPL) technology in 2005. Based on the favorable results of the trial, HECO proceeded with a small-scale pilot in an expanded residential/commercial area in Honolulu, which ended in late 2006. That effort was primarily focused on automatic meter reading, which is aimed at enabling time-of-use rates for residential and commercial customers. No further BPL pilots are anticipated at this time.

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. 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. However, the impact of the loss on the electric utilities’ financial statements is immaterial. In addition, 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. 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 periodically solicited competitive proposals for investment opportunities in qualified projects. To date, RHI has signed a Conditional Investment Agreement for a small-scale landfill gas-to-energy project on Oahu, a Framework Agreement for evaluation of three wind projects and two pumped storage hydroelectric projects and two Project Agreements providing the option to invest in wind projects. Project investments by RHI will generally be made only after developers secure the necessary approvals and permits and independently execute a PPA with HECO, HELCO or MECO, approved by the PUC.

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.

Liquidity and capital resources

HECO’s consolidated capital structure was as follows:


December 31	2006				2005
(dollars in millions)

Short-term borrowings	$	113	6	%	$	136	7	%
Long-term debt, net		766	41			766	38
Preferred stock		34	2			34	2
Common stock equity ¹		959	51			1,039	53

	$	1,872	100	%	$	1,975	100	%

¹	Includes AOCI charge for retirement benefit plans in accordance with SFAS No. 158 as of December 31, 2006.

As of February 28, 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 November 2006, S&P confirmed its corporate credit ratings of HECO and maintained its negative outlook. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P indicated:

Failure to strengthen key financial parameters, especially cash flow coverage of debt, a slump in the Hawaiian economy, a punitive final rate order, . . . could lead to lower ratings. Conversely, credit-supportive actions by the company as well as responsive rate treatment would lead to ratings stability.

In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). In November 2006, S&P 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. At December 31, 2006, HELCO and MECO had $49 million and $5 million, respectively, of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for 2006 of $136 million and had $113 million of commercial paper outstanding as of December 31, 2006. 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.

Operating activities provided $228 million in net cash during 2006. Investing activities used net cash of $175 million, primarily for capital expenditures, net of contributions in aid of construction. Financing activities used net cash of $49 million, including a $23 million net decrease in short-term borrowings and $30 million for the payment of common and preferred stock dividends. In order to strengthen HECO’s balance sheet and support its investment in its reliability program, HECO did not pay any dividends to HEI in the second half of 2006.

In May 2005, the Hawaii legislature authorized the issuance, prior to June 30, 2010, of up to $160 million of Special Purpose Revenue Bonds (SPRBs) ($100 million for HECO, $40 million for HELCO and $20 million for MECO), subject to PUC approval of the projects to be financed, 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.

In December 2005, an application was filed with the PUC requesting approval to issue up to a total of $165 million in taxable unsecured notes for HECO, MECO and HELCO (up to $100 million for HECO, up to $50 million for HELCO and up to $15 million for MECO). On January 20, 2006, a Registration Statement on Form S-3 was filed with the SEC for unsecured taxable notes to be issued by each of the electric utilities. However, on October 27, 2006, the electric utilities amended the PUC application, in accordance with a stipulation between the utilities and the Consumer Advocate, to seek approval for the issuance of up to $160 million of SPRBs (allocated as indicated above) instead of issuing the taxable unsecured notes. Accordingly, the electric utilities have withdrawn the Registration Statement on Form S-3 and currently contemplate issuing up to $160 million of SPRBs in March 2007.

In September 2006, the electric utilities filed an application with the PUC seeking authority to participate with the Department of Budget and Finance of the State of Hawaii in the issuance of refunding SPRBs, with the proceeds of such bonds, if issued, to be used to redeem the 6.20% Series 1996A SPRBs and/or the 5-7/8% Series 1996B SPRBs, which are currently callable. In December 2006, the PUC granted the approvals necessary to issue the refunding bonds. The decision whether and, if so, when to issue refunding SPRBs and/or to call the Series

1996A and/or the Series 1996B SPRBs will depend on future market conditions and contractual and other considerations.

For the five-year period 2007 through 2011, the utility forecasts $1.2 billion of gross capital expenditures, approximately 51% of which is for transmission and distribution projects and 41% for generation projects, with the remaining 8% for general plant and other projects. These estimates do not include expenditures, which could be material, that would be required to comply with cooling water intake structure regulations adopted by the EPA in 2004 or the July 1999 Regional Haze Rule amendments. See “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” The electric utilities’ net capital expenditures (which exclude AFUDC and capital expenditures funded by third-party contributions in aid of construction) for 2007 through 2011 are currently estimated to total approximately $1.0 billion. HECO’s consolidated cash flows from operating activities (net income, adjusted for non-cash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and preferred stock dividends, are currently not expected to provide sufficient cash to cover the forecast net capital expenditures and to reduce the level of short-term borrowings, which level is expected to fluctuate during this forecast period. Long-term debt financing is expected to be required to fund this estimated shortfall as well as any unanticipated expenditures not included in the 2007 through 2011 forecast, such as increases in the costs of, or acceleration of, the construction of capital projects, capital expenditures that may be required by new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if tax positions taken by the utilities do not prevail.

Proceeds from the anticipated issuance of revenue bonds, cash flows from operating activities and temporary increases in short-term borrowings are expected to provide the forecast $199 million needed for the net capital expenditures in 2007. For 2007, gross capital expenditures are estimated to be $232 million, including approximately $130 million for transmission and distribution projects, approximately $77 million for generation projects and approximately $25 million for general plant and other projects. Consolidated net capital expenditures for HECO and subsidiaries for 2006, 2005 and 2004 were $171 million, $194 million and $187 million, respectively.

Funding for the electric utilities’ qualified pension plans is based upon actuarially determined contributions that consider the amount deductible for income tax purposes and the funding requirements under the Employee Retirement Income Security Act of 1974, as amended (ERISA). Although the electric utilities were not required to make any contributions to the qualified pension plans to meet minimum funding requirements pursuant to ERISA for 2006, 2005 and 2004, they made voluntary contributions in 2005 and 2004. With respect to the postretirement benefit plans, the electric utilities policy is to comply with directives from the PUC to fund the costs. Contributions by the electric utilities to the retirement benefit plans for 2006, 2005 and 2004 totaled $10 million, $18 million and $34 million, respectively, and are expected to total $11 million in 2007. Additional contributions to the retirement benefit plans may be required, or may be made even if not required, and such contributions could be in amounts substantially in excess of the amounts currently included in the electric utilities forecast of their consolidated financing requirements for the period 2007 through 2011. SFAS No. 158, which was adopted on December 31, 2006, does not impact the calculations of retirement benefit costs.

Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generating units, the availability of generating sites and transmission and distribution corridors, the ability to obtain adequate and timely rate increases, escalation in construction costs, the impacts of DSM programs and combined heat and power installations, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

Bank

Executive overview and strategy

When ASB was acquired by HEI in 1988, it was a traditional thrift with assets of $1 billion and net income of about $13 million. ASB has grown by both acquisition and internal growth since 1988 and ended 2006 with assets of $6.8 billion and net income of $56 million, compared to assets of $6.8 billion as of December 31, 2005 and net income of $65 million in 2005.

The interest rate environment, the quality of ASB’s assets, and the strategic transformation of ASB from a traditional thrift to a community bank have impacted and will continue to impact its financial results.

ASB has been facing a challenging interest rate environment that has pressured its net interest margin. The Federal Reserve Bank’s rate increases since mid-2004 have led to higher short-term interest rates, while, during the same period, long-term interest rates have remained low, resulting in an inverted yield curve throughout the second half of 2006. The higher short-term interest rates have put upward pressure on deposit rates, while the low long-term interest rates have held down asset yields, putting downward pressure on net interest margin. If the current interest rate environment persists, the potential for compression of ASB’s margin will continue to be a concern. As part of its interest rate risk management process, ASB uses simulation analysis to measure net interest income sensitivity to changes in interest rates (see “Quantitative and Qualitative Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in interest rates on net interest income. ASB’s key strategies include:

(1)

attracting and retaining low cost deposits, which enables ASB to replace other borrowings and reduce funding costs;

(2)

diversifying its loan portfolio with higher-yielding, shorter-maturity loans or variable rate loans such as commercial, commercial real estate and consumer loans, which also creates a more diversified income stream for the bank;

(3)

investing in mortgage-related securities with short average lives; and

(4)

managing costing liabilities to optimize cost of funds and manage interest rate sensitivity.

ASB’s asset quality remained strong in 2006 as a result of continued strength in the Hawaii economy and the real estate market. However, ASB recorded a provision for loan losses of $0.8 million after-tax during 2006, primarily due to a single commercial loan, compared to a $1.9 million after-tax reversal of allowance for loan losses during 2005. ASB’s allowance as a percentage of average loans was 0.85% at the end of 2006, compared to 0.90% and 1.08% at the end of 2005 and 2004, respectively. This ratio falls between the benchmark ratios for national banks and thrifts, which is as expected because ASB’s large residential mortgage portfolio is typical of a thrift and ASB has added commercial and commercial real estate loans typical of commercial banks. The allowance is adjusted continuously through the provision for loan losses to reflect factors such as charge-offs; outstanding loan balances; loan grading; external factors affecting the national and Hawaii economy, specific industries and sectors and interest rates; and historical and estimated loan losses.

ASB is a full-service community bank serving both consumer and commercial customers. In order to remain competitive and continue building core franchise value, the bank continues to develop and introduce new products and services in order to meet the needs of those markets. Additionally, the banking industry is constantly changing and ASB is making the investments in people and technology necessary to adapt and remain competitive. ASB’s ongoing challenge is to increase revenues faster than expenses.

Results of Operations


(dollars in millions)	2006			% change		2005			% change	2004
Revenues	$	408		5		$	388		6	$	364
Net interest income		203		(3	)		210		8		194
Operating income		89		(16	)		105		–		105
Net income		56		(14	)		65		58		41
Return on average common equity ¹		10.0	%				11.7	%			8.0	%
Earning assets
Average balance ²	$	6,367		—		$	6,374		3	$	6,162
Weighted-average yield		5.48	%	6			5.19	%	4		4.98	%
Costing liabilities
Average balance ²	$	6,154		—		$	6,157		4	$	5,934
Weighted-average rate		2.37	%	3			1.97	%	4		1.90	%
Interest rate spread		3.11	%	(3	)		3.22	%	5		3.08	%
Net interest margin ³		3.18	%	(3	)		3.29	%	4		3.15	%

In late December 2004, ASB’s capital structure changed when ASB redeemed its preferred stock held by HEIDI ($75 million) and HEIDI infused common equity into ASB ($75 million). If ASB’s reported common equity as of December 31, 2004 was reduced by $75 million for the calculation, ASB’s ROACE would have been 8.7% for 2004.

²	Calculated using the average daily balances.

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

Bank franchise taxes (ASB)

The results of operations for 2004 include a net charge of $20 million due to a June 2004 tax ruling and subsequent settlement as discussed in Note 10 of HEI’s “Notes to Consolidated Financial Statements” under “ASB state franchise tax dispute and settlement.” The following table presents a reconciliation of ASB’s net income to net income excluding the $20 million charge in 2004. Management believes the adjusted information below presents ASB’s net income on a more comparable basis for the periods shown. However, the 2004 adjusted net income is not a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.


Years ended December 31	2006			2005			2004
(dollars in thousands)

Net income	$	55,782		$	64,883		$	41,062
Cumulative bank franchise taxes, net of taxes, through December 31, 2003		—			—			20,340


Net income – as adjusted	$	55,782		$	64,883		$	61,402

ROACE – as adjusted ¹		10.0	%		11.7	%		13.3	%

¹	Calculated using adjusted net income divided by the simple average adjusted common equity (excluding the $75 million common equity infusion in December 2004 from equity as of December 31, 2004).

Taking into account the adjustments in the table above, ASB’s 2005 net income would have increased 6% compared to 2004.

Bank operations

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. As discussed above, if the current interest rate environment persists, compression of ASB’s net interest margin will continue to be a concern. 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 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. As of December 31, 2005, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 11% commercial loans, 8% 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 December 31, 2006, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings, comparable to December 31, 2005. However, in 2006, higher short-term interest rates and the inverted yield curve made it challenging to retain deposits and control funding costs. ASB experienced net deposit outflows in the middle of 2006, and management acted in response with a combination of tactical repricings of deposits, promotions and the introduction of new products and services. 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. Deposits as of December 31, 2006 were essentially flat compared to deposits as of December 31, 2005. Deposit retention and growth, however, will remain a challenge in the current environment.

Other factors primarily affecting ASB’s operating results include fee income, provision (or reversal of allowance) for loan losses, gains or losses on sales of securities available-for-sale and expenses from operations.

Although higher long-term interest rates could reduce the market value of mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of mortgage-related securities would not result in a charge to net income in the absence of an “other-than-temporary” impairment in the value of the securities. As of December 31, 2006 and 2005, the unrealized losses, net of tax benefits, on available-for-sale investment and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $35 million and $36 million, respectively. See “Quantitative and qualitative disclosures about market risk.”

The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for certain categories of earning assets and costing liabilities for the years indicated. Average balances for each year have been calculated using the daily average balances during the year.


Years ended December 31	2006			2005			2004
(dollars in thousands)

Loans receivable
Average balances ¹	$	3,687,673		$	3,411,389		$	3,121,878
Interest income ²		231,610			205,084			184,773
Weighted-average yield		6.28	%		6.01	%		5.92	%

Investment and mortgage-related securities
Average balances	$	2,507,608		$	2,780,408		$	2,845,730
Interest income		113,403			122,828			118,424
Weighted-average yield		4.52	%		4.42	%		4.16	%

Other investments ³
Average balances	$	172,146		$	182,586		$	194,039
Interest and dividend income		3,757			3,096			3,923
Weighted-average yield		2.18	%		1.70	%		2.02	%

Total earning assets
Average balances	$	6,367,427		$	6,374,383		$	6,161,647
Interest and dividend income		348,770			331,008			307,120
Weighted-average yield		5.48	%		5.19	%		4.98	%

Deposit liabilities
Average balances	$	4,540,292		$	4,453,762		$	4,114,070
Interest expense		73,614			52,064			47,184
Weighted-average rate		1.62	%		1.17	%		1.15	%

Borrowings
Average balances	$	1,613,667		$	1,703,353		$	1,819,598
Interest expense		72,482			69,362			65,603
Weighted-average rate		4.49	%		4.07	%		3.61	%

Total costing liabilities
Average balances	$	6,153,959		$	6,157,115		$	5,933,668
Interest expense		146,096			121,426			112,787
Weighted-average rate		2.37	%		1.97	%		1.90	%

Net average balance	$	213,468		$	217,268		$	227,979
Net interest income		202,674			209,582			194,333
Interest rate spread		3.11	%		3.22	%		3.08	%
Net interest margin ⁴		3.18	%		3.29	%		3.15	%

¹	Includes nonaccrual loans.

²	Includes loan fees of $5.3 million, $6.4 million and $6.1 million for 2006, 2005 and 2004, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

³	Includes stock in the FHLB of Seattle ($98 million as of December 31, 2006). ASB received dividends of $98,000 in 2006, $0.4 million in 2005 and $2.7 million in 2004. See “FHLB of Seattle business and capital plan” below.

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

• Net interest income before provision for loan losses for 2006 decreased by $7 million, or 3.3%, when compared to 2005 as the challenging interest rate environment pressured ASB’s net interest margin. Continued growth in average loans and deposits partially offset margin compression pressure from a flattening yield curve, which was inverted throughout the second half of 2006. Net interest margin decreased from 3.29% in 2005 to 3.18% in 2006 as the impact of growth in the loan portfolio and higher yields in the loan and mortgage-related securities portfolios was more than offset by increased funding costs. The increase in the average loan portfolio balance was helped by 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 the proceeds from repayments in the portfolios to fund loans. Increased average deposit balances enabled ASB to replace other borrowings.

ASB’s asset quality remained strong due to continued strength in real estate and business conditions, which resulted in low historical loss ratios and low net charge-offs for ASB. However, a provision for loan losses of $1.4 million ($0.8 million, net of tax) was recorded in 2006, primarily due to a single commercial loan, but management does not believe that the adverse development of this loan is reflective of a trend in the overall credit quality of the loan portfolio. This compares with a reversal of allowance for loan losses of $3 million ($2 million, net of tax) in 2005.

Noninterest income for 2006 increased by $2.7 million over 2005 due to higher fee income on deposit liabilities and gains on sales of securities, partially offset by lower income from the sale of investment and insurance products.

Noninterest expense for 2006 increased by $7.6 million over 2005 primarily due to higher legal and litigation-related expenses and occupancy expenses.

• Net interest income before reversal of allowance for loan losses for 2005 increased by $15 million, or 7.8%, when compared to 2004. Strong organic growth in loans and deposits and the ability to keep deposit cost low enabled ASB to offset margin compression pressure from a flattening yield curve, which inverted near year-end. Net interest margin increased from 3.15% in 2004 to 3.29% in 2005 due to growth in the loan portfolio and higher yields in the loan and mortgage-related securities portfolios funded by strong deposit growth. 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 reinvestment of excess liquidity into loans. Average deposit balances grew by $340 million, enabling ASB to replace other borrowings and helping fund loan growth. The shift in liability mix enabled ASB to keep down its weighted average rate on costing liabilities.

Due to considerable strength in real estate and business conditions, which resulted in lower historical loss ratios and lower net charge-offs for ASB, and other factors discussed above, ASB recorded a reversal of allowance for loan losses of $3 million ($2 million, net of tax) in 2005, which was less than the reversal of allowance for loan losses of $8 million ($5 million, net of tax) in 2004.

Noninterest income remained stable for 2005 when compared to 2004.

Noninterest expense for 2005 increased by $10 million, or 6.3%, over 2004, primarily due to higher compensation and employee benefits expense related to strategic initiatives, increased pension costs, Sarbanes-Oxley Act of 2002 (SOX) compliance costs and the charge for prepayment of a high cost Federal Home Loan Bank advance.

• During 2006, ASB’s allowance for loan losses increased by $0.6 million, compared to decreases in its allowance for loan losses during 2005 and 2004 of $3 million and $10 million, respectively.

ASB’s nonaccrual and renegotiated loans represented 0.2%, 0.2% and 0.4% of total loans outstanding as of December 31, 2006, 2005 and 2004, respectively. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

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. In April 2005, the FHLB of Seattle delivered a proposed three-year business plan and capital management plan to the Finance Board, and issued a press release stating that it anticipates minimal to no dividends in the next few years while it implements its new business model. 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. In December 2006, the Board of Directors of the FHLB of Seattle declared, and ASB received, a cash dividend of $98,000 in December 2006. 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.

Legislation and regulation

ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (OTS) and the Federal Deposit Insurance Corporation (FDIC). Depending on its level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholders. See the discussions below under “Liquidity and capital resources” and “Certain factors that may affect future results and financial condition—Bank.”

Liquidity and capital resources


December 31	2006		% change		2005		% change
(dollars in millions)

Assets	$	6,808	—		$	6,835	1
Available-for-sale investment and mortgage-related securities		2,367	(10	)		2,629	(11	)
Investment in stock of Federal Home Loan Bank of Seattle		98	—			98	—
Loans receivable, net		3,780	6			3,567	10
Deposit liabilities		4,576	—			4,557	6
Other bank borrowings		1,569	(3	)		1,622	(10	)

As of December 31, 2006, ASB was the third largest financial institution in Hawaii based on assets of $6.8 billion and deposits of $4.6 billion.

ASB’s principal sources of liquidity are customer deposits, borrowings, the maturity and repayment of portfolio loans and securities and the sale of loans into secondary market channels. ASB’s deposits as of December 31, 2006 were $18 million higher than December 31, 2005. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. As of December 31, 2006, FHLB borrowings totaled approximately $0.7 billion, representing 11% of assets. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. As of December 31, 2006, ASB’s unused FHLB borrowing capacity was approximately $1.7 billion. As of December 31, 2006, securities sold under agreements to repurchase totaled $0.8 billion, representing 12% of assets. ASB utilizes deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. As of December 31, 2006, 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 commitments and obligations while maintaining liquidity at satisfactory levels.

As of December 31, 2006 and 2005, ASB had $2.4 million of loans on nonaccrual status, or 0.1% of net loans outstanding. As of December 31, 2006 and 2005, ASB’s real estate acquired in settlement of loans was nil and $0.2 million, respectively.

In 2006, net cash of $34 million was provided by investing activities primarily due to repayments of investment and mortgage-related securities and sales of mortgage-related securities, net of purchases, partly offset by net increases in loans held for investment and capital expenditures. Financing activities used net cash of $84 million due to net decreases in other borrowings and the payment of common stock dividends, partly offset by net increases in deposits. Operating activities provided cash of $94 million.

ASB believes that a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2006, ASB was well-capitalized (see “Regulation of ASB” for ASB’s capital ratios).

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 its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors. See also “Forward-Looking Statements” above and “Item 1A. Risk Factors.”

Consolidated

Economic conditions. Because its core businesses are providing local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism. See “Economic conditions” above.

Competition. The electric utility and banking industries are competitive and the Company’s success in meeting competition will continue to have a direct impact on the Company’s financial performance.

Electric utility. 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.

Competitive bidding proceeding. The stated purpose of this proceeding is 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. The decision required the parties to submit comments on the proposed framework. On September 11, 2006, HECO, HELCO and MECO, the Consumer Advocate and HREA each submitted comments on the proposed framework and responded to the PURPA issues in the decision. KIUC had no 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 from the issuance of the decision. The 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 on 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 as 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. The decision also ordered the utilities to file proposed tariffs containing procedures for interconnection and transmission upgrades within 90 days from the issuance of the framework, and proposed Codes of Conduct within 180 days from the issuance of the framework, or prior to commencement of any competitive bidding process, whichever comes first.

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.

Distributed generation 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), requesting that the PUC clarify how the three conditions under which electric utilities are allowed to provide regulated DG services at customer-owned sites will be administered, in order to better determine the impacts the conditions may have on the electric utilities’ DG plans. On April 6, 2006, the PUC issued its decision on the electric utilities’ 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. If a decision is made to pursue a specific project, an application requesting project approval will be

filed with the PUC. In July 2006, MECO filed an application for approval of an agreement for the installation of a CHP system 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 filed its statement of position in January 2007 and MECO filed its response to the Consumer Advocate’s statement of position in February 2007.

Prior to opening of the investigative DG proceeding, in October 2003 the electric utilities filed an application for approval of CHP tariffs, under which they would own, operate and maintain customer-sited, packaged CHP systems (and certain ancillary equipment) pursuant to standard form contracts with eligible commercial customers. This CHP tariff application and a HELCO application for approval of an agreement with a customer for a utility CHP project were suspended by the PUC until, at a minimum, the matters in the DG proceeding were adequately addressed.

By letters dated November 2, 2006, the PUC requested that the utilities state their intentions with regard to pursuing the CHP tariff application and that HELCO state its intentions with regard to its CHP project application, given the PUC criteria for allowing regulated utility-owned DG stated in the DG proceeding D&O. On December 29, 2006, the utilities withdrew their CHP tariff application, based on the determination that it would be difficult to implement CHP projects on a programmatic basis given the criteria of the D&O. The utilities will continue to consider CHP projects on a case-by-case basis, and if a decision is made to pursue the implementation of a CHP project, then an application will be filed requesting PUC approval of such CHP project. On December 29, 2006, HELCO withdrew its CHP project application for a particular customer on the basis that the D&O would require substantial modifications to the application and existing CHP agreement. HELCO is continuing to work with its customer with respect to CHP and/or other energy cost savings alternatives, and if a decision is made to pursue the implementation of a CHP system, then an application will be filed requesting PUC approval of a new CHP agreement.

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. 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.

Bank. The banking industry in Hawaii is highly competitive. ASB is the third largest financial institution in Hawaii, based on assets, and is in direct competition for deposits and loans, not only with the two larger institutions, but also with smaller institutions that are heavily promoting their services in certain niche areas, such as providing financial services to small- and medium-sized businesses, and national organizations offering financial services. ASB’s main competitors are banks, savings associations, credit unions, mortgage brokers, finance companies and securities brokerage firms. These competitors offer a variety of lending, deposit and investment products to retail and business customers.

The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.

ASB is a full-service community bank serving both consumer and commercial customers and has been diversifying its loan portfolio from single-family home mortgages to higher-yielding, shorter-duration consumer, commercial and commercial real estate loans. The origination of consumer, commercial and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate

loans. For example, the sources and level of competition may be different and credit risk is generally higher than for mortgage loans. These different risk factors are considered in the underwriting and pricing standards and in the allowance for loan losses established by ASB for its consumer, commercial and commercial real estate loans.

U.S. capital markets and interest rate environment. Changes in the U.S. capital markets can have significant effects on the Company. For example:

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Volatility in U.S. capital markets can affect the fair values of assets available to satisfy retirement benefits obligations. The Company estimates that consolidated retirement benefits expense, net of amounts capitalized and income taxes, will be $20 million in 2007 as compared to $17 million in 2006, partly as a result of changing the expected long-term rate of return assumption in recognition of lower expected future returns in the capital markets.

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Volatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB. As of December 31, 2006, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $2.4 billion.

Interest rate risk is a significant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. The Federal Reserve began increasing rates in 2004, while longer-term interest rates have not increased significantly, causing a flattening of the yield curve. The yield curve was inverted throughout the second half of 2006. This type of interest rate environment typically puts downward pressure on ASB’s net interest margin. As of December 31, 2006, the Company had no floating-rate long-term debt outstanding. As of December 31, 2006, consolidated HEI had $176 million of commercial paper outstanding with a weighted-average interest rate of 5.44% and maturities ranging from 2 to 38 days. See “Quantitative and Qualitative Disclosures about Market Risk.”

Technological developments. New technological developments (e.g., the commercial development of fuel cells or distributed generation or significant advances in internet banking) may impact the Company’s future competitive position, results of operations and financial condition.

Limited insurance. In the ordinary course of business, the Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. For electric utility examples, see “Limited insurance” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” ASB also has no insurance coverage for business interruption or credit card fraud. Certain of the Company’s insurance has substantial “deductibles” or has limits on the maximum amounts that may be recovered. Insurers also have exclusions or limitations of coverage for claims related to certain perils including, but not limited to, mold and terrorism. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the Company could incur uninsured losses in amounts that would have a material adverse effect on the Company’s results of operations and financial condition.

Environmental matters. 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. These laws and regulations, among other things, require that certain environmental permits be obtained as a condition to constructing or operating certain facilities. Obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance. Management believes that the recovery through rates of most, if not all, of any costs incurred by HECO and its subsidiaries in complying with environmental requirements would be allowed by the PUC.

The HECO, HELCO and MECO generating stations operate under air pollution control permits issued by the DOH and, in a limited number of cases, by the EPA. The 2004 legislature passed legislation that clarifies that the accepting agency or authority for an environmental impact statement is not required to be the approving agency for the permit or approval and also requires an environmental assessment for proposed waste-to-energy facilities, landfills, oil refineries, power-generating facilities greater than 5 MW and wastewater facilities, except individual wastewater systems. This legislation could result in an increase in project costs.

The entire electric utility industry has been affected by the 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone, and adoption of a NAAQS for fine particulate matter. Further significant impacts may occur if currently proposed legislation, rules and standards are adopted (e.g., greenhouse gas emission reduction rules) or are deemed applicable to company facilities (e.g., Regional Haze Rule amendments).

Pending environmental matters that may adversely affect the Company’s future operating results and financial condition include the ongoing Honolulu Harbor environmental investigation, the July 1999 Regional Haze Rule amendments and section 316(b) of the federal Clean Water Act, which are discussed under “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” There can be no assurance that a significant environmental liability will not be incurred by the electric utilities or that the related costs will be recoverable through rates.

Prior to extending a loan secured by real property, ASB conducts due diligence to assess whether or not the property may present environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.

Electric utility

Regulation of electric utility rates. The rates the electric utilities are allowed to charge for their services, and the timeliness of permitted rate increases, are among the most important items influencing their financial condition, results of operations and liquidity. The PUC has broad discretion over the rates the electric utilities charge and other matters. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse affect on the Company’s and HECO’s consolidated results of operations, financial condition and liquidity. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O. Interim rate increases are subject to refund with interest, pending the final outcome of the case. Through December 31, 2006, HECO and its subsidiaries had recognized $79 million of revenues with respect to interim orders regarding certain integrated resource planning costs and HECO’s general rate increase, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders. 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 this matter. In addition, MECO incurred approximately $0.7 million of incremental integrated resource planning costs for 2006, for which the Consumer Advocate has not yet stated its position. See “Most recent rate requests—HECO” above for a discussion of the status of the current HECO rate case.

Management cannot predict with certainty when the final D&Os in the pending two HECO rate cases, the HELCO rate case or the MECO rate case, or in future rate cases, will be rendered or the amount of any interim or final rate increase that may be granted. Further, the increasing levels of O&M expenses (including increased retirement benefit costs), increased plant-in-service, or other factors have and are likely to continue to result in the electric utilities seeking rate relief more often than in the past.

The rate schedules of each of HEI’s electric utilities include energy cost adjustment clauses (ECACs) under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 2004 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC affirmed the electric utilities’ right to include in their respective ECACs the stated costs incurred pursuant to their respective new fuel supply contracts, to the extent that these costs are not included in their respective base rates, and restated its intention to examine the need for continued use of ECACs in rate cases. Act 162 of the 2006 Hawaii legislature requires such examination and specifies certain factors that must be considered. See “Energy cost adjustment clauses” in Note 3 of HEI’s “Notes to consolidated financial statements.”

Fuel oil and purchased power. The electric utilities rely on fuel oil suppliers and IPPs to deliver fuel oil and power, respectively. See “Fuel contracts” and “Power purchase agreements (PPAs)” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” The Company estimates that 77.2% of the net energy generated and purchased by HECO and its subsidiaries in 2007 will be generated from the burning of oil. Purchased KWHs provided approximately 38.2% of the total net energy generated and purchased in 2006 compared to 39.1% in 2005 and 38.2% in 2004.

Failure or delay by the electric utilities’ oil suppliers and shippers to provide fuel pursuant to existing supply contracts, or failure by a major independent power producer to deliver the firm capacity anticipated in its PPA, could interrupt the ability of the electric utilities to deliver electricity, thereby materially adversely affecting the Company’s results of operations and financial condition. HECO generally maintains an average system fuel inventory level equivalent to 35 days of forward consumption. HELCO and MECO generally maintain an inventory level equivalent to one month’s supply of both medium sulfur fuel oil and diesel fuel. The electric utilities’ major sources of oil, through their suppliers, are in China, Vietnam and the Far East. Some, but not all, of the electric utilities’ PPAs require that the IPPs maintain minimum fuel inventory levels and all of the firm capacity PPAs include provisions imposing substantial penalties for failure to produce the firm capacity anticipated by those agreements.

Other operation and maintenance expenses. Other operation and maintenance expenses increased 8%, 9% and 7% for 2006, 2005 and 2004, respectively, when compared to the prior year. This trend of increased operation and maintenance expenses is expected to continue in 2007 as the electric utilities anticipate: (1) higher DSM expenses (that are passed on to customers through a surcharge and therefore do not impact net income) and integrated resource planning expenses, (2) higher employee benefits expenses, primarily for retirement benefits and (3) higher production expenses, primarily to meet higher demand levels and load growth set in 2004 and sustained in 2005 and 2006. The timing and amount of these expenses can vary as circumstances change. For example, recent overhauls have been more expensive than in the past due to the larger scope of work necessary to maintain the aging equipment, which has experienced heavier usage as demand has increased to current levels. Until an overhaul is fully underway, it is possible that the maintenance costs for a generating unit may be significantly higher than originally planned. Increased operation and maintenance expenses were among the reasons HECO (in November 2004 and December 2006), HELCO (in May 2006) and MECO (in February 2007) filed requests with the PUC to increase base rates. In September 2005, HECO received interim rate relief for its request filed in November 2004 (see “Most recent rate requests”).

Other regulatory and permitting contingencies. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company. Two major capital improvement utility projects, the Keahole project and the East Oahu Transmission Project, have encountered opposition and have been seriously delayed (although CT-4 and CT-5 at Keahole are now operating). See Note 3 of HEI’s “Notes to Consolidated Financial Statements.” HELCO is seeking to recover Keahole costs in its current rate case.

Bank

Regulation of ASB. ASB is subject to examination and comprehensive regulation by the Department of Treasury, OTS and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OTS. ASB’s insurance product sales activities, including those conducted by ASB’s insurance agency subsidiary, Bishop Insurance Agency of Hawaii, Inc., are subject to regulation by the Hawaii Insurance Commissioner.

Capital requirements. The OTS, which is ASB’s principal regulator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. As of December 31, 2006, ASB was in compliance with OTS minimum regulatory capital requirements and was “well-capitalized” within the meaning of OTS prompt corrective action regulations and FDIC capital regulations, as follows:

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ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2006 with a tangible capital ratio of 7.6% (1.5%), a core capital ratio of 7.6% (4.0%) and a total risk-based capital ratio of 14.7% (8.0%).

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ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2006 with a leverage ratio of 7.6% (5.0%), a Tier-1 risk-based capital ratio of 13.9% (6.0%) and a total risk-based capital ratio of 14.7% (10.0%).

The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (such as by foreclosure). The regulators have substantial discretion in the corrective actions they might direct and could include restrictions on dividends and other distributions that ASB may make to HEI (through HEIDI) and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI could be required to contribute to ASB up to an additional $28.3 million of capital, if necessary to maintain ASB’s capital position.

Examinations. ASB is subject to periodic “safety and soundness” examinations and other examinations by the OTS. In conducting its examinations, the OTS utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OTS examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OTS’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as an officer, director, employee, attorney, or auditor, except as provided by regulation. The OTS also regularly examines ASB’s information technology practices, and its performance as related to the Community Reinvestment Act measurement criteria.

The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2006, ASB was “well-capitalized” and thus not subject to these restrictions.

Qualified Thrift Lender status. ASB is a “qualified thrift lender” (QTL) under its federal thrift charter and, in order to maintain this status, ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (including mortgage-related securities) as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Savings associations that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI, HEIDI and HEI’s other subsidiaries would also be subject to restrictions if ASB failed to maintain its QTL status, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. As of December 31, 2006, approximately 88% of its assets were qualified thrift investments.

Federal Thrift Charter. The Gramm-Leach-Bliley Act of 1998 (the Gramm Act) permitted banks, insurance companies and investment firms to compete directly against each other, thereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricted the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, HEIDI and ASB is “grandfathered” under the Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB maintains its QTL status. Under the Gramm Act, any proposed sale of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the newly authorized financial holding companies permitted under the Gramm Act.

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.

Material estimates that are particularly susceptible to significant change include the amounts reported for investment and mortgage-related securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; variable interest entities (VIEs); and allowance for loan losses. Management considers an accounting estimate to be material if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the assumptions selected could have a material impact on the estimate and on the Company’s results of operations or financial condition. For example, in 2004, a significant change in estimated income taxes occurred as a result of a Tax Appeal Court decision (see “ASB state franchise tax dispute and settlement” in Note 10 of HEI’s “Notes to Consolidated Financial Statements”).

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the following accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that the policies below 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. These policies are identified according to whether they affect both of the Company’s two principal segments, or just one of these segments. Management has reviewed the material estimates and critical accounting policies with the HEI Audit Committee and, as applicable, the HECO Audit Committee.

For additional discussion of the Company’s accounting policies, see Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

Consolidated

Investment and mortgage-related securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and temporary losses excluded from earnings and reported in AOCI.

For securities that are not trading securities, declines in value determined to be other than temporary are included in earnings and result in a new cost basis for the investment. The specific identification method is used in determining realized gains and losses on the sales of securities.

ASB owns federal agency obligations, private-issue mortgage-related securities and mortgage-related securities issued by the Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and Federal National Mortgage Association (FNMA), all of which are classified as available-for-sale. ASB obtains market prices for investment and mortgage-related securities from a third party financial services provider. The prices of these securities may be influenced by factors such as market liquidity, corporate credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector concerns, and overall market psychology. Adverse changes in any of these factors may result in additional losses. As of December 31, 2006, ASB had mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $1.7 billion and private-issue mortgage-related securities valued at $0.5 billion.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or

loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

HECO and its subsidiaries evaluate the impact of applying Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” to their new PPAs, PPA amendments and other arrangements they enter into. A possible outcome of the evaluation is that an arrangement falls within the scope of EITF 01-8 and results in its classification as a capital lease, which could have a material effect on HECO’s consolidated balance sheet if a significant amount of capital assets and lease obligations needed to be recorded.

Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would be required to write off the disallowed costs at that time. See the discussion in Note 3 of HEI’s “Notes to Consolidated Financial Statements” concerning costs recorded for CT-4 and CT-5 at Keahole and the East Oahu Transmission Project.

Pension and other postretirement benefits obligations. Pension and other postretirement benefits (collectively, retirement benefits) costs are material estimates accounted for in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” For a discussion of retirement benefits (including costs, major assumptions, plan assets, other factors affecting costs, AOCI charges and sensitivity analyses), see “Retirement benefits (pension and other postretirement benefits)” in “Consolidated—Results of Operations” above and Note 8 of HEI’s “Notes to Consolidated Financial Statements.”

Contingencies and litigation. The Company is subject to proceedings, lawsuits and other claims, including proceedings under laws and government regulations related to environmental matters. Management assesses the likelihood of any adverse judgments in or outcomes to these matters as well as potential ranges of probable losses, including costs of investigation. A determination of the amount of reserves required, if any, for these contingencies is based on a careful analysis of each individual case or proceeding often with the assistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy.

In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered through future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. See “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements” for a description of the Honolulu Harbor investigation.

Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities at enacted tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from tax experts. Management believes that the Company’s provision for tax contingencies is reasonable. However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts. See disclosure in Note 1 of HEI’s “Notes to Consolidated Financial Statements” regarding the impact of changes made to estimating the impact of uncertain tax positions under FIN No. 48, which was adopted on January 1, 2007. Also, see Note 10, “Income taxes,” of HEI’s “Notes to Consolidated Financial Statements.”

Electric utility

Regulatory assets and liabilities. The electric utilities are regulated by the PUC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the Company’s financial statements reflect assets, liabilities, revenues and costs of HECO and its subsidiaries based on current cost-based rate-making regulations. The actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities.

Regulatory liabilities represent amounts collected from customers for costs that are expected to be incurred in the future. Regulatory assets represent incurred costs that have been deferred because their recovery in future customer rates is probable. As of December 31, 2006, regulatory liabilities and regulatory assets amounted to $241 million and $112 million, respectively. Regulatory liabilities and regulatory assets are itemized in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment. Because current rates include the recovery of regulatory assets existing as of the last rate case and rates in effect allow the utilities to earn a reasonable rate of return, management believes that the recovery of the regulatory assets as of December 31, 2006 is probable. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.

Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the electric utilities expect that the regulatory assets would be charged to income and the regulatory liabilities would be credited to income or refunded to ratepayers. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to customers. As of December 31, 2006, revenues applicable to energy consumed, but not yet billed to customers, amounted to $92 million.

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. As of December 31, 2006, HECO and its subsidiaries had recognized $79 million of such revenues with respect to interim orders. Also, the rate schedules of the electric utilities include ECACs under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. See “Regulation of electric utility rates” above.

Consolidation of VIEs. In December 2003, the FASB issued revised FIN No. 46 (FIN 46R), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. The Company evaluates the impact of applying FIN 46R to its relationships with IPPs with whom the electric utilities execute new PPAs or execute amendments of existing PPAs. A possible outcome of the analysis is that HECO (or its subsidiaries, as applicable) may be found to meet the definition of a primary beneficiary of a VIE (the IPP) which finding may result in the consolidation of the IPP in HECO’s consolidated financial statements. The consolidation of IPPs 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. The electric utilities do not know how the consolidation of IPPs would be treated for regulatory or credit ratings purposes. See “General—Consolidation—Consolidation of VIEs” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

Bank

Allowance for loan losses. See Note 1 of HEI’s “Notes to Consolidated Financial Statements.” As of December 31, 2006, ASB’s allowance for loan losses was $31.2 million and ASB had $2.4 million of loans on nonaccrual status. In 2006, ASB recorded a provision for loan losses of $1.4 million. Although management believes the allowance for loan losses is adequate, the actual loan losses, provision for loan losses and allowance for loan losses may be materially different if conditions change (e.g., if there is a significant change in the Hawaii economy), and material increases in those amounts could have a material adverse affect on the Company’s results of operations and financial position.

HECO:

Management’s Discussion and Analysis of Financial Condition and Results of Operations

HECO incorporates by reference all of the foregoing “electric utility” sections and all information related to HECO and its subsidiaries in HEI’s MD&A, except for HEI’s Selected contractual obligations and commitments table.

Selected contractual obligations and commitments

The following table presents HECO and subsidiaries-aggregated information as of December 31, 2006 about total payments due during the indicated periods under the specified contractual obligations and commercial commitments:


December 31, 2006 (in millions)	Payment due by period
December 31, 2006 (in millions)	1 year or less		2-3 years		4-5 years		More than 5 years		Total
Long-term debt, net	$	—	$	—	$	—	$	766	$	766
Operating leases		5		5		4		14		28
Open purchase order obligations		54		11		3		—		68
Fuel oil purchase obligations (estimate based on January 1, 2007 fuel oil prices)		539		1,078		1,077		1,617		4,311
Purchase power obligations–minimum fixed capacity charges		118		234		237		1,130		1,719

Total (estimated)	$	716	$	1,328	$	1,321	$	3,527	$	6,892

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI:

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk. The Company believes the electric utility and other segments’ exposures to these two risks are not material as of December 31, 2006.

Credit risk for ASB is the risk that borrowers or issuers of securities will not be able to repay their obligations to the bank. Credit risk associated with the lending portfolios is controlled through ASB’s underwriting standards, loan rating of commercial and commercial real estate loans, on-going monitoring by loan officers, credit review and quality control functions in these lending areas and adequate allowance for loan losses. Credit risk associated with the securities portfolio is mitigated by ASB’s asset/liability management process, experienced staff working with analytical tools, monthly fair value analysis and on-going monitoring and reporting such as investment watch reports and loss sensitivity analysis. See “Allowance for loan losses” above.

Liquidity risk for ASB is the risk that the bank will not meet its obligations when they become due. Liquidity risk is mitigated by ASB’s asset/liability management process, on-going analytical analysis, monitoring and reporting information such as weekly cash-flow analyses and maintenance of liquidity contingency plans.

The Company is exposed to some commodity price risk primarily related to its fuel supply and IPP contracts. The Company’s commodity price risk is substantially mitigated so long as the electric utilities have their current ECACs in their rate schedules. See discussion of the ECACs in “Certain factors that may affect future results and financial condition—Electric utility—Regulation of electric utility rates.” The Company currently has no hedges against its commodity price risk. Because the Company does not have a large portfolio of trading assets, the Company is not exposed to significant market risk from trading activities. The Company’s currently has no exposure to foreign currency exchange rate risk.

The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations and financial condition, especially as it relates to ASB, but also as it may affect the discount rate used to determine pension liabilities, the market value of pension plans’ assets and the electric utilities’ allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.

Bank interest rate risk

The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk. ASB’s interest-rate risk profile is strongly influenced by its primary business of making fixed-rate residential mortgage loans and taking in retail deposits. Large mismatches in the amounts or timing between the maturity or repricing of interest sensitive assets or liabilities could adversely affect ASB’s earnings and the market value of its interest-sensitive assets and liabilities in the event of significant changes in the level of interest rates. Many other factors also affect ASB’s exposure to changes in interest rates, such as general economic and financial conditions, customer preferences, and competition for loans or deposits.

ASB’s Asset/Liability Management Committee (ALCO), whose voting members are officers and employees of ASB, is responsible for managing interest rate risk and carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies under which management monitors and coordinates ASB’s assets and liabilities.

See Note 4 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential loan sale program.

Management measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income (NII) and the market value of interest-sensitive assets and liabilities in different interest-rate environments. The simulation analysis is performed using a dedicated asset/liability management software system enhanced with a mortgage prepayment model and a collateralized mortgage obligation (CMO) database. The simulation software is capable of generating scenario-specific cash flows for all instruments using the specified contractual information for each instrument and product specific prepayment assumptions for mortgage loans and mortgage-related securities.

NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in the alternate interest-rate scenarios as a percentage of the base case NII. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next twelve months. The alternate scenarios were created by assuming “rate ramps” or gradual interest changes and accomplished by moving the yield curve in a parallel fashion, over the next twelve month period, in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest cash flows for the interest-bearing assets and liabilities, and the NII is calculated for each scenario. Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptions are made about the prepayment behavior of mortgage-related assets, future pricing spreads for new assets and liabilities, and the speed and magnitude with which deposit rates change in response to changes in the overall level of interest rates.

ASB’s net portfolio value (NPV) ratio is a measure of the economic capitalization of ASB. The NPV ratio is the ratio of the net portfolio value of ASB to the present value of expected net cash flows from existing assets. Net portfolio value represents the theoretical market value of ASB’s net worth and is defined as the present value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet contracts. The NPV ratio is calculated by ASB pursuant to guidelines established by the OTS in Thrift Bulletin 13a. Key assumptions used in the calculation of ASB’s NPV ratio include the prepayment behavior of loans and investments, the possible distribution of future interest rates, pricing spreads for assets and liabilities in the alternate scenarios and the rate and balance behavior of deposit accounts with indeterminate maturities. Typically, if the value of ASB’s assets grows relative to the value of its liabilities, the NPV ratio will increase. Conversely, if the value of ASB’s liabilities grows relative to the value of its assets, the NPV ratio will decrease. The NPV ratio is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the current yield curve. Alternate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points.

The NPV ratio sensitivity measure is the change from the NPV ratio calculated in the base case to the NPV ratio calculated in the alternate rate scenarios. The sensitivity measure alone is not necessarily indicative of the interest-rate risk of an institution, as institutions with high levels of capital may be able to support a high sensitivity measure. This measure is evaluated in conjunction with the NPV ratio calculated in each scenario.

ASB’s interest-rate risk sensitivity measures as of December 31, 2006 and 2005 constitute “forward-looking statements” and were as follows:


December 31	2006						2005
	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	(3.8	)%	7.83	%	(341	)	(2.7	)%	8.12	%	(332	)
+200	(2.6	)	9.09		(215	)	(1.8	)	9.34		(210	)
+100	(1.3	)	10.29		(95	)	(0.9	)	10.49		(95	)
Base	—		11.24		—		—		11.44		—
-100	2.0		11.64		40		1.5		11.91		47
-200	1.8		11.27		3		1.0		11.62		17
-300	0.3		10.60		(64	)	*		*		*

*	Change from base case in basis points.

Management believes that ASB’s interest rate risk position as of December 31, 2006 represents a reasonable level of risk. Under the gradual interest rate change scenarios, the December 31, 2006 NII profile is slightly more sensitive to changes in interest rates compared to the NII profile on December 31, 2005. Shifts in ASB’s funding mix contributed to the slight increase in sensitivity.

ASB’s base NPV ratio as of December 31, 2006 was slightly lower than on December 31, 2005, primarily as a result of changes in the level and shape of the yield curve.

ASB’s NPV ratio sensitivity measures as of December 31, 2006 were comparable to the measures as of December 31, 2005.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. 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 the ASB’s balance sheet, and management’s responses to the changes in interest rates.

Other than bank interest rate risk

The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt (primarily fixed-rate debt) and preferred securities. As of December 31, 2006, management believes the Company is exposed to “other than bank” interest rate risk because of their periodic borrowing requirements, the impact of interest rates on the discount rate and the market value of plan assets used to determine retirement benefits expenses and obligations (see “Retirement benefits (pension and other postretirement benefits)” in “Management’s discussion and analysis of financial condition and results of operations” and Note 8 of HEI’s “Notes to Consolidated Financial Statements”) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Regulation of electric utility rates”). Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material. Based upon commercial paper outstanding as of December 31, 2006 of $177 million and a hypothetical 10% increase/decrease in interest rates, annual interest expense would have increased/decreased on that commercial paper by $1 million.

HECO:

HECO and its subsidiaries manage various market risks in the ordinary course of business, including credit risk and liquidity risk, but management believes their exposures to these two risks are not material as of December 31, 2006.

HECO and its subsidiaries are exposed to some commodity price risk primarily related to its fuel supply and IPP contracts. HECO and its subsidiaries’ commodity price risk is substantially mitigated so long as they have their current ECACs in their rate schedules. See discussion of the ECACs in Item 1A. Risk factors (Electric Utility Risks) and “Certain factors that may affect future results and financial condition—Electric utility—Regulation of electric utility rates.” HECO and its subsidiaries currently have no hedges against their commodity price risk.

Because HECO and its subsidiaries do not have a portfolio of trading assets, they are not exposed to market risk from trading activities.

See “Other than bank interest rate risk” above and Note 10 of HECO’s “Notes to Consolidated Financial Statements.” Based upon short-term borrowings outstanding as of December 31, 2006 of $113 million and a hypothetical 10% increase/decrease in interest rates, annual interest expense would have increased/decreased on those short-term borrowings by $0.6 million.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI:

Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries


Years ended December 31	2006			2005			2004
(in thousands, except per share amounts)
Revenues
Electric utility	$	2,054,890		$	1,806,384		$	1,550,671
Bank		408,365			387,910			364,284
Other		(2,351	)		21,270			9,102

		2,460,904			2,215,564			1,924,057

Expenses
Electric utility		1,888,172			1,644,681			1,376,768
Bank		319,807			283,009			259,310
Other		13,529			16,452			17,019

		2,221,508			1,944,142			1,653,097

Operating income (loss)
Electric utility		166,718			161,703			173,903
Bank		88,558			104,901			104,974
Other		(15,880	)		4,818			(7,917	)

		239,396			271,422			270,960

Interest expense – other than bank		(75,678	)		(75,309	)		(77,176	)
Allowance for borrowed funds used during construction		2,879			2,020			2,542
Preferred stock dividends of subsidiaries		(1,890	)		(1,894	)		(1,901	)
Allowance for equity funds used during construction		6,348			5,105			5,794

Income from continuing operations before income taxes		171,055			201,344			200,219
Income taxes		63,054			73,900			92,480

Income from continuing operations		108,001			127,444			107,739
Discontinued operations – gain (loss) on disposal, net of income taxes		—			(755	)		1,913

Net income	$	108,001		$	126,689		$	109,652

Basic earnings (loss) per common share
Continuing operations	$	1.33		$	1.58		$	1.36
Discontinued operations		—			(0.01	)		0.02

	$	1.33		$	1.57		$	1.38

Diluted earnings (loss) per common share
Continuing operations	$	1.33		$	1.57		$	1.36
Discontinued operations		—			(0.01	)		0.02

	$	1.33		$	1.56		$	1.38

Dividends per common share	$	1.24		$	1.24		$	1.24

Weighted-average number of common shares outstanding		81,145			80,828			79,562
Dilutive effect of stock-based compensation		228			372			157

Adjusted weighted-average shares		81,373			81,200			79,719

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries


December 31				2006						2005
(dollars in thousands)

ASSETS
Cash and equivalents				$	177,630					$	151,513
Federal funds sold					79,671						57,434
Accounts receivable and unbilled revenues, net					248,639						249,473
Available-for-sale investment and mortgage-related securities					2,367,427						2,629,351
Investment in stock of Federal Home Loan Bank of Seattle (estimated fair value $97,764)					97,764						97,764
Loans receivable, net					3,780,461						3,566,834
Property, plant and equipment, net
Land	$	48,558					$	46,350
Plant and equipment		4,148,707						3,884,886
Construction in progress		101,313						150,376

		4,298,578						4,081,612
Less – accumulated depreciation		(1,651,088	)		2,647,490			(1,538,836	)		2,542,776

Regulatory assets					112,349						110,718
Other					292,638						456,134
Goodwill and other intangibles, net					87,140						89,580

				$	9,891,209					$	9,951,577

LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Accounts payable				$	165,505					$	183,336
Deposit liabilities					4,575,548						4,557,419
Short-term borrowings—other than bank					176,272						141,758
Other bank borrowings					1,568,585						1,622,294
Long-term debt, net—other than bank					1,133,185						1,142,993
Deferred income taxes					106,780						207,997
Regulatory liabilities					240,619						219,204
Contributions in aid of construction					276,728						256,263
Other					518,454						369,390

					8,761,676						8,700,654

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: 81,461,409 shares and 80,983,326 shares					1,028,101						1,018,966
Retained earnings					242,667						235,394
Accumulated other comprehensive loss, net of income tax benefits
Net unrealized losses on securities	$	(35,462	)				$	(36,476	)
Minimum pension liability		—						(1,254	)
Defined benefit pension and postretirement benefit plans		(140,066	)		(175,528	)		—			(37,730	)

					1,095,240						1,216,630

				$	9,891,209					$	9,951,577

See accompanying “Notes to Consolidated Financial Statements.”


Consolidated Statements of Changes in Stockholders’ Equity Hawaiian Electric Industries, Inc. and Subsidiaries
	Common stock				Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount			earnings			income (loss)			Total
Balance, December 31, 2003	75,838	$	888,431		$	197,774		$	2,826		$	1,089,031
Comprehensive income:
Net income	—		—			109,652			—			109,652
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of tax benefits of $4,366	—		—			—			(7,775	)		(7,775	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $2,002	—		—			—			(3,535	)		(3,535	)
Minimum pension liability adjustment, net of taxes of $197	—		—			—			341			341

Comprehensive income (loss)	—		—			109,652			(10,969	)		98,683

Issuance of common stock:
Common stock offering	4,000		103,720									103,720
Dividend reinvestment and stock purchase plan	307		7,999			—			—			7,999
Retirement savings and other plans	542		10,128			—			—			10,128
Expenses and other, net	—		(188	)		—			—			(188	)
Common stock dividends ($1.24 per share)	—		—			(98,428	)		—			(98,428	)

Balance, December 31, 2004	80,687		1,010,090			208,998			(8,143	)		1,210,945
Comprehensive income:
Net income	—		—			126,689			—			126,689
Net unrealized losses on securities:
Net unrealized losses arising during the period, net of tax benefits of $21,933	—		—			—			(29,335	)		(29,335	)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $70	—		—			—			(105	)		(105	)
Minimum pension liability adjustment, net of tax benefits of $95	—		—			—			(147	)		(147	)

Comprehensive income (loss)	—		—			126,689			(29,587	)		97,102

Issuance of common stock:
Stock Option and Incentive Plan and other plans	296		6,095			—			—			6,095
Expenses and other, net	—		2,781			—			—			2,781
Common stock dividends ($1.24 per share)	—		—			(100,293	)		—			(100,293	)

Balance, December 31, 2005	80,983	$	1,018,966		$	235,394		$	(37,730	)	$	1,216,630
Comprehensive income:
Net income	—		—			108,001			—			108,001
Net unrealized gains on securities:
Net unrealized gains arising during the period, net of taxes of $1,361	—		—			—			2,059			2,059
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $690	—		—			—			(1,045	)		(1,045	)
Minimum pension liability adjustment, net of taxes of $804	—		—			—			1,254			1,254

Comprehensive income (loss)	—		—			108,001			2,268			110,269

Adjustment to initially apply SFAS No. 158, net of tax benefits of $89,394 (includes pension liability adjustment of $145, net of tax benefits of $91, which would have also been recorded under SFAS No. 87)	—		—			—			(140,066	)		(140,066	)
Issuance of common stock:
Stock Option and Incentive Plan and other plans	478		10,270			—			—			10,270
Expenses and other, net	—		(1,135	)		—			—			(1,135	)
Common stock dividends ($1.24 per share)	—		—			(100,728	)		—			(100,728	)

Balance, December 31, 2006	81,461	$	1,028,101		$	242,667		$	(175,528	)	$	1,095,240

As of December 31, 2006, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 16,810,697 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan, the Hawaiian Electric Industries Retirement Savings Plan, the 1987 Stock Option and Incentive Plan and the HEI 1990 Nonemployee Director Stock Plan.

In 1997, the HEI Board of Directors adopted a resolution designating 500,000 shares of Series A Junior Participating Preferred Stock in connection with HEI’s Shareholders Rights Plan, but no shares have been issued.

See accompanying “Notes to Consolidated Financial Statements.”


Consolidated Statements of Cash Flows Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 31	2006			2005			2004
(in thousands)

Cash flows from operating activities
Net income	$	108,001		$	126,689		$	109,652
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment		141,184			133,892			125,560
Other amortization		10,778			8,269			15,965
Provision (reversal of allowance) for loan losses		1,400			(3,100	)		(8,400	)
Gain on sale of income notes		—			—			(5,607	)
Deferred income taxes		(12,946	)		43			12,349
Allowance for equity funds used during construction		(6,348	)		(5,105	)		(5,794	)
Excess tax benefits from share-based payment arrangements		(1,052	)		—			—
Changes in assets and liabilities, net of effects from the disposal of businesses
Decrease (increase) in accounts receivable and unbilled revenues, net		834			(40,940	)		(20,823	)
Decrease (increase) in fuel oil stock		21,138			(26,880	)		(14,958	)
Decrease (increase) in federal tax deposit		30,000			(30,000	)		—
Increase (decrease) in accounts payable		(17,831	)		36,282			17,913
Increase (decrease) in taxes accrued		(2,273	)		37,631			46,675
Changes in other assets and liabilities		13,167			(18,343	)		(28,380	)

Net cash provided by operating activities		286,052			218,438			244,152

Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased		(343,927	)		(486,432	)		(1,105,133	)
Principal repayments on available-for-sale investment and mortgage-related securities		542,702			727,901			803,517
Proceeds from sale of available-for-sale mortgage-related securities		61,131			28,039			45,207
Net increase in loans held for investment		(211,872	)		(304,212	)		(113,991	)
Net proceeds from sale of investments		—			33,809			9,981
Proceeds from sale of real estate acquired in settlement of loans		403			624			1,617
Capital expenditures		(210,529	)		(223,675	)		(214,654	)
Contributions in aid of construction		19,707			21,083			8,522
Distributions from unconsolidated subsidiaries		—			—			24,379
Other		1,708			909			180

Net cash used in investing activities		(140,677	)		(201,954	)		(540,375	)

Cash flows from financing activities
Net increase in deposit liabilities		18,129			261,247			269,922
Net increase in short-term borrowings with original maturities of three months or less		35,213			65,147			76,611
Proceeds from short-term borrowings with original maturities of greater than three months		44,891			—			—
Repayment of short-term borrowings with original maturities of greater than three months		(45,590	)		—			—
Net increase in retail repurchase agreements		60,596			18,519			25,050
Proceeds from other bank borrowings		1,331,559			1,068,256			882,808
Repayments of other bank borrowings		(1,446,995	)		(1,265,376	)		(957,272	)
Proceeds from issuance of long-term debt		100,000			59,462			103,097
Repayment of long-term debt		(110,000	)		(84,000	)		(224,166	)
Excess tax benefits from share-based payment arrangements		1,052			—			—
Net proceeds from issuance of common stock		5,481			3,689			110,017
Common stock dividends		(100,673	)		(100,238	)		(93,864	)
Other		1,786			(5,015	)		(4,768	)

Net cash provided by (used in) financing activities		(104,551	)		21,691			187,435

Cash flows from discontinued operations (revised – see Note 11)
Cash flows provided by (used in) operating activities		7,530			(2,857	)		(3,571	)
Cash flows provided by investing activities		—			—			6,000

Net cash provided by (used in) discontinued operations		7,530			(2,857	)		2,429

Net increase (decrease) in cash and equivalents and federal funds sold		48,354			35,318			(106,359	)
Cash and equivalents and federal funds sold, January 1		208,947			173,629			279,988

Cash and equivalents and federal funds sold, December 31	$	257,301		$	208,947		$	173,629

See accompanying “Notes to Consolidated Financial Statements.”

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Notes to Consolidated Financial Statements

1 • Summary of significant accounting policies

General

HEI is a holding company with direct and indirect subsidiaries engaged in electric utility, banking and other businesses, primarily in the State of Hawaii. HEI’s common stock is traded on the New York Stock Exchange.

Basis of presentation. In preparing the consolidated 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.

Material estimates that are particularly susceptible to significant change include the amounts reported for investment securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; variable interest entities (VIEs); and allowance for loan losses.

Consolidation. The consolidated financial statements include the accounts of HEI and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable-interest entities of which the Company is not the primary beneficiary. Investments in companies over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method. All material intercompany accounts and transactions have been eliminated in consolidation.

See Note 5 for information regarding the application of FASB Interpretation No. 46(R).

Cash and equivalents and federal funds sold. The Company considers cash on hand, deposits in banks, deposits with the Federal Home Loan Bank (FHLB) of Seattle, money market accounts, certificates of deposit, short-term commercial paper of non-affiliates and reverse repurchase agreements and liquid investments (with original maturities of three months or less) to be cash and equivalents. Federal funds sold are excess funds that ASB loans to other banks overnight at the federal funds rate.

Investment and mortgage-related securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and temporary losses excluded from earnings and reported on a net basis in accumulated other comprehensive income (AOCI).

For securities that are not trading securities, declines in value determined to be other-than-temporary are included in earnings and result in a new cost basis for the investment. The specific identification method is used in determining realized gains and losses on the sales of securities. To determine whether an impairment is other-than-temporary, the Company considers whether it has the ability and intent to hold the investment until a market price recovery and considers whether evidence indicating the cost of the investment is recoverable outweighs evidence to the contrary. Evidence considered in this assessment includes the magnitude of the impairment, the severity and duration of the impairment, changes in value subsequent to year-end and forecasted performance of the investment.

Discounts and premiums on investment and mortgage-related securities are accreted or amortized over the remaining lives of the securities, adjusted for actual portfolio prepayments, using the interest method.

Equity method. Investments in up to 50%-owned affiliates over which the Company has the ability to exercise significant influence over the operating and financing policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the Company’s equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses are reflected in operating revenues.

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Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make property, plant or equipment more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

If a PPA falls within the scope of Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” and results in the classification of the agreement as a capital lease, the electric utility would recognize a capital asset and a lease obligation.

Depreciation. Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Electric utility plant additions in the current year are depreciated beginning January 1 of the following year. Electric utility plant has lives ranging from 20 to 45 years for production plant, from 25 to 60 years for transmission and distribution plant and from 7 to 45 years for general plant. The electric utilities’ composite annual depreciation rate, which includes a component for cost of removal, was 3.9% in 2006, 2005 and 2004.

Retirement benefits. Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant. The Public Utilities Commission of the State of Hawaii (PUC) requires the electric utilities to fund their pension and postretirement benefit costs. The Company’s policy is to fund qualified pension plan costs in amounts that will not be less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974 and will not exceed the maximum tax-deductible amounts. The Company generally funds at least the net periodic pension cost as calculated using Statement of Financial Accounting Standards (SFAS) No. 87 during the fiscal year, subject to limits and targeted funded status as determined with the consulting actuary. Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions as calculated using SFAS No. 106 and the amortization of the regulatory asset for postretirement benefits other than pensions, while maximizing the use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary.

Effective December 31, 2006, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” and recognized on its balance sheet the funded status of its defined benefit pension and other postretirement benefit plans. See Note 8 for the impacts of adoption.

Environmental expenditures. The Company is subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Financing costs. HEI uses the effective interest method to amortize the financing costs of the holding company over the term of the related long-term debt.

HECO and its subsidiaries use the straight-line method to amortize financing costs and premiums or discounts over the term of the related long-term debt. Unamortized financing costs and premiums or discounts on HECO and its subsidiaries’ long-term debt retired prior to maturity are classified as regulatory assets or liabilities and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

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HEI and HECO and its subsidiaries use the straight-line method to amortize the fees and related costs paid to secure a firm commitment under their line-of-credit arrangements.

Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities at enacted tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset might be impaired and written down or written off.

Effective January 1, 2007, the Company adopted FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” and uses a “more-likely-than-not” recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

Earnings per share. Basic earnings per share (EPS) is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that common shares for dilutive stock compensation are added to the denominator.

As of December 31, 2006 and 2004, the dilutive effect of all options, stock appreciation rights (SARs) and restricted stock were included in the computation of diluted EPS. As of December 31, 2005, the antidilutive effect of SARs on 879,000 shares of common stock (for which the SARs’ exercise prices were greater than the closing market price of HEI’s common stock) were not included in the computation of diluted EPS.

Share-based compensation. For 2005 and 2004, the Company applied the fair value based method of accounting prescribed by SFAS No. 123, “Accounting for Stock-Based Compensation,” to account for its stock compensation. Since January 1, 2006, the Company applied the fair value based method of accounting prescribed by SFAS No. 123 (Revised 2004), “Share-Based Payment,” to account for its stock compensation, including the use of a forfeiture assumption. See Note 9 for the impacts of adoption.

Impairment of long-lived assets and long-lived assets to be disposed of. The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

Recent accounting pronouncements and interpretations

Accounting for certain hybrid financial instruments. In March 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. The Company adopted SFAS No. 155 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

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Accounting for servicing of financial assets. In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 156 requires an entity to recognize, in certain situations, a servicing asset or servicing liability when it undertakes an obligation to service a financial asset, requires all separately recognized servicing assets and liabilities to be initially measured at fair value (if practicable), permits alternative subsequent measurement methods for each class of servicing assets and liabilities, permits a limited one-time reclassification of available-for-sale securities to trading securities at adoption, requires separate presentation of servicing assets and liabilities subsequently measured at fair value in the balance sheet and requires additional disclosures. SFAS No. 156 must be adopted by the beginning of the first fiscal year that begins after September 15, 2006. The Company adopted SFAS No. 156 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

Accounting for uncertainty in income taxes. In June 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation 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 a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN No. 48 in the first quarter of 2007. The Company anticipates reclassifying certain deferred tax liabilities to a liability for tax uncertainties. Further, although management’s analysis of the impact of adoption of FIN No. 48 is ongoing, management does not expect the adjustment to retained earnings as of January 1, 2007 for the cumulative effect of adoption of FIN No. 48 to be material.

Cash flows relating to income taxes generated by a leveraged lease transaction. In July 2006, the FASB issued FASB Staff Position (FSP) No. 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” which requires a recalculation of the rate of return and the allocation of income to positive investment years from the inception of the lease if there is a change or projected change in the timing of cash flows relating to income taxes generated by the leveraged lease. The amounts comprising the net leveraged lease investment would be adjusted to the recalculated amounts, and the change in the net investment would be recognized as a gain or loss in the year in which the projected cash flows and/or assumptions change. FSP No. 13-2 is effective for fiscal years beginning after December 15, 2006. The Company adopted FSP No. 13-2 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

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.

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Effects of prior year misstatements. In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” which provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. In order to evaluate whether an error is material based on all relevant quantitative and qualitative factors, SAB No. 108 requires the quantification of misstatements using both the income-statement (rollover) and balance sheet (iron curtain) approaches. If the Company does not elect to restate its financial statements for the material misstatements that arise in connection with application of the guidance in SAB No. 108, then for fiscal years ending after November 15, 2006, it must recognize the cumulative effect of applying SAB No. 108 in the current year beginning balances of the affected assets and liabilities with a corresponding adjustment to the current year opening balance in retained earnings. The Company adopted SAB No. 108 in the fourth quarter of 2006 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

Planned major maintenance activities. In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which eliminates the accrue-in-advance method of accounting for planned major maintenance activities. As a result of the elimination, three methods are currently permitted: (1) direct expensing, (2) built-in overhaul, and (3) deferral. FSP AUG AIR-1 must be adopted by the first fiscal year beginning after December 15, 2006. The Company adopted FSP AUG AIR-1 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity because the Company has used and continues to use the direct expensing method.

Defined benefit pension and other postretirement plans. In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans. Employers must recognize actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS Nos. 87 and 106 when recognizing a plan’s funded status, with the offset to AOCI in stockholders’ equity. SFAS No. 158 was required to be adopted in fiscal years ending after December 15, 2006. Accordingly, the Company adopted SFAS No. 158 on December 31, 2006. The electric utilities updated their application in the AOCI Docket to take into account SFAS No. 158 in seeking PUC approval to record as a regulatory asset the amount that would otherwise be charged against stockholders’ equity, but the application was denied. See Note 8 for the impacts of adoption.

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. Management has not yet determined when it will adopt SFAS No. 159 or what impact, if any, the adoption of SFAS No. 159 will have on the Company’s financial statements.

Common stock split. On April 20, 2004, the HEI Board of Directors approved a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information in the accompanying financial statements and notes has been adjusted to reflect the stock split for all periods presented (unless otherwise noted).

Reclassifications. Certain reclassifications have been made to prior years’ financial statements to conform to the 2006 presentation.

Electric utility

Regulation by the PUC. The electric utilities are regulated by the PUC and account for the effects of regulation under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes

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HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the electric utilities expect that the regulatory assets would be charged to income and the regulatory liabilities would be credited to income or refunded to ratepayers. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers.

Accounts receivable. Accounts receivable are recorded at the invoiced amount. The electric utilities assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company adjusts its allowance on a monthly basis, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Contributions in aid of construction. The electric utilities receive contributions from customers for special construction requirements. As directed by the PUC, contributions are amortized on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the meter readings in the beginning of the following month, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. As of December 31, 2006, customer accounts receivable include unbilled energy revenues of $92 million on a base of annual revenue of $2.1 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

The rate schedules of the electric utilities include energy cost adjustment clauses (ECACs) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The ECACs also include a provision requiring a quarterly reconciliation of the amounts collected through the ECACs. In 2004 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC affirmed the electric utilities’ right to include in their respective ECACs the stated costs incurred pursuant to their respective new fuel supply contracts, to the extent that these costs are not included in their respective base rates, and restated its intention to examine the need for continued use of ECACs in rate cases. See “Energy cost adjustment clauses” in Note 3.

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. HECO and its subsidiaries’ payments to the taxing authorities are based on the prior years’ revenues. For 2006, 2005 and 2004, HECO and its subsidiaries included approximately $182 million, $159 million and $136 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Repairs and maintenance costs. Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.

Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC may be stopped.

The weighted-average AFUDC rate was 8.4%, 8.5% and 8.6% in 2006, 2005 and 2004, respectively, and reflected quarterly compounding.

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Bank

Loans receivable. American Savings Bank, F.S.B. and subsidiaries (ASB) state loans receivable at amortized cost less the allowance for loan losses, loan origination fees (net of direct loan origination costs), commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Discounts and premiums are accreted or amortized over the life of the loans using the interest method.

Loan origination fees (net of direct loan origination costs) are deferred and recognized as an adjustment in yield over the life of the loan using the interest method or taken into income when the related loans are paid off or sold. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised are recognized as income upon expiration of the commitment.

Loans held for sale, gain on sale of loans, and mortgage servicing rights. Mortgage and educational loans held for sale are stated at the lower of cost or estimated market value on an aggregate basis. Generally, the determination of market value is based on the fair value of the loans. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold.

ASB capitalizes mortgage servicing rights (MSRs) when the related loans are sold with servicing rights retained. The total cost of the mortgage loans sold is allocated to the MSRs and the mortgage loans without the MSRs based on their relative fair values at the date of sale. The MSRs are included as a component of gain on sale of loans. The MSRs are amortized in proportion to and over the estimated period of net servicing income. Such amortization is reflected as a component of revenues on the consolidated statements of income.

The MSRs are periodically reviewed for impairment based on their fair value. The fair value of the MSRs, for the purposes of impairment, is measured using a discounted cash flow analysis based on market-adjusted discount rates and anticipated prepayment speeds. Market sources are used to determine prepayment speeds and net cost of servicing per loan.

ASB measures MSR impairment on a disaggregated basis based on certain risk characteristics including loan type and note rate. Impairment losses are recognized through a valuation allowance for each impaired stratum, with any associated provision recorded as a component of loan servicing fees included in ASB’s noninterest income.

Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb losses inherent in the loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and interest rate environment). Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.

For commercial and commercial real estate loans, a risk rating system is used. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. ASB’s credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the contractual terms of the loan agreement. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral. For all loans secured by real estate, ASB measures impairment by utilizing the fair value of the collateral; for other loans, discounted cash flows are used to measure impairment. Losses from impairment are charged to the provision for loan losses and included in the allowance for loan losses.

For the residential, consumer and homogeneous commercial loans receivable portfolios, the allowance for loan loss allocations are based on historical loss ratio analyses.

ASB generally ceases the accrual of interest on loans when they become contractually 90 days past due or when there is reasonable doubt as to collectibility. Subsequent recognition of interest income for such loans is generally on the cash method. When, in management’s judgment, the borrower’s ability to make periodic principal and interest payments resumes, a loan not accruing interest (nonaccrual loan) is returned to accrual status. ASB

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uses either the cash or cost-recovery method to record cash receipts on impaired loans that are not accruing interest. While the majority of consumer loans are subject to ASB’s policies regarding nonaccrual loans, certain past due consumer loans may be charged off upon reaching a predetermined delinquency status varying from 120 to 180 days.

Management believes the allowance for loan losses is adequate. While management utilizes available information to recognize losses on loans, future adjustments may be required from time to time to the allowance for loan losses (e.g. due to changes in economic conditions, particularly in the State of Hawaii) and actual results could differ from management’s estimates, and these adjustments and differences could be material.

Real estate acquired in settlement of loans. ASB records real estate acquired in settlement of loans at the lower of cost or fair value less estimated selling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fair value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expense through a valuation allowance. Costs related to holding real estate are charged to operations as incurred.

Goodwill and other intangibles. Goodwill and intangible assets with indefinite useful lives are tested for impairment at least annually. Intangible assets with definite useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144.

Goodwill. ASB’s $83.1 million of goodwill, which is the Company’s only intangible asset with an indefinite useful life, is tested for impairment annually in the fourth quarter using data as of September 30. For 2006, 2005 and 2004, there has been no impairment of goodwill. The fair value of ASB is estimated by an unrelated third party using a valuation method based on a market approach, which takes into consideration market values of comparable companies, which are publicly traded, and recent transactions of companies in the industry.

Amortized intangible assets.


December 31	2006				2005
(in thousands)	Gross carrying amount		Accumulated amortization		Gross carrying amount		Accumulated amortization
Core deposit intangibles	$	20,276	$	18,662	$	20,276	$	16,932
Mortgage servicing rights		11,695		9,130		11,662		8,650

	$	31,971	$	27,792	$	31,938	$	25,582

Changes in the valuation allowance for MSRs were as follows:


(in thousands)	2006			2005			2004
Valuation allowance, January 1	$	207		$	701		$	2,316
Provision (reversal of allowance)		(74	)		(359	)		4
Other than temporary impairment		(14	)		(135	)		(1,619	)

Valuation allowance, December 31	$	119		$	207		$	701

In 2006, 2005 and 2004, aggregate amortization expenses were $2.2 million, $2.4 million and $3.2 million, respectively.

The estimated aggregate amortization expense for ASB’s core deposit intangibles and MSRs for 2007, 2008, 2009, 2010 and 2011 is $2.0 million, $0.4 million, $0.3 million, $0.3 million and $0.2 million, respectively.

Core deposit intangibles are amortized each year based on the greater of the actual attrition rate of such deposit base or the applicable rate on the 10-year amortization table. Core deposit intangibles are reviewed for impairment based on their estimated fair value.

ASB capitalizes MSRs acquired through either the purchase or origination of mortgage loans for sale or securitization with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s MSRs. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others which increases the value of MSRs, whereas declining interest rates typically result in faster prepayment speeds which decreases the value of MSRs and increases the amortization of the MSRs. In 2006, 2005 and 2004, MSRs acquired

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through the sale or securitization of loans held for sale totaled $0.1 million, $0.1 million, and $0.4 million, respectively. Amortization expense for ASB’s MSRs amounted to $0.5 million, $0.7 million, and $1.5 million for 2006, 2005 and 2004, respectively, and are recorded as a reduction in revenues on the consolidated statements of income.

2 • Segment financial information

The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies, except that income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on income from continuing operations. The Company accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market prices. Intersegment revenues consist primarily of interest and preferred dividends.

Electric utility

HECO and its wholly-owned operating subsidiaries, HELCO and MECO, are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the PUC. HECO also owns non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which will invest in renewable energy projects, and HECO Capital Trust III, which is an unconsolidated financing entity.

Bank

ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Department of Treasury, Office of Thrift Supervision (OTS) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. ASB’s insurance product sales activities, including those conducted by ASB’s insurance agency subsidiary, Bishop Insurance Agency of Hawaii, Inc., are subject to regulation by the Hawaii Insurance Commissioner.

Other

“Other” includes amounts for the holding companies and other subsidiaries not qualifying as reportable segments and intercompany eliminations.

As of December 31, 2006, HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a materials science company focused on clean energy technologies. Prior to August 5, 2005, the investment had been accounted for under the cost method. Hoku initiated a public equity offering and shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005. Since August 5, 2005, Hoku shares have been considered marketable and HEIPI has classified the shares as trading securities, carried at fair value with changes in fair value recorded in earnings. HEIPI began trading Hoku stock in February 2006 when its lock-up agreement expired. In 2006 and 2005, HEIPI recognized a $1.6 million loss (unrealized and realized, net of taxes) and a $2.9 million gain (unrealized, net of taxes), respectively, on the Hoku shares. As of December 31, 2006, HEIPI had sold 33% of its Hoku shares and carried its remaining investment in Hoku shares at $1.2 million. In January 2007, HEIPI sold its remaining investment in Hoku for a net after-tax gain of $0.9 million.

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Segment financial information was as follows:


(in thousands)	Electric Utility		Bank		Other			Total
2006
Revenues from external customers	$	2,054,616	$	408,365	$	(2,077	)	$	2,460,904
Intersegment revenues (eliminations)		274		—		(274	)		—

Revenues		2,054,890		408,365		(2,351	)		2,460,904

Depreciation and amortization		138,096		13,175		691			151,962

Interest expense		52,563		146,096		23,115			221,774

Profit (loss)*		121,387		88,558		(38,890	)		171,055
Income taxes (benefit)		46,440		32,776		(16,162	)		63,054

Income (loss) from continuing operations		74,947		55,782		(22,728	)		108,001

Capital expenditures		195,072		14,927		530			210,529

Assets (at December 31, 2006 **)		3,063,134		6,808,499		19,576			9,891,209

2005
Revenues from external customers	$	1,806,198	$	387,910	$	21,456		$	2,215,564
Intersegment revenues (eliminations)		186		—		(186	)		—

Revenues		1,806,384		387,910		21,270			2,215,564

Depreciation and amortization		131,350		10,065		746			142,161

Interest expense		49,408		121,426		25,901			196,735

Profit (loss)*		117,425		104,852		(20,933	)		201,344
Income taxes (benefit)		44,623		39,969		(10,692	)		73,900

Income (loss) from continuing operations		72,802		64,883		(10,241	)		127,444

Capital expenditures		217,609		5,731		335			223,675

Assets (at December 31, 2005 **)		3,081,460		6,835,335		34,782			9,951,577

2004
Revenues from external customers	$	1,550,671	$	364,284	$	9,102		$	1,924,057

Depreciation and amortization		123,700		17,044		781			141,525

Interest expense		49,588		112,787		27,588			189,963

Profit (loss)*		130,656		99,466		(29,903	)		200,219
Income taxes (benefit)		49,479		58,404		(15,403	)		92,480

Income (loss) from continuing operations		81,177		41,062		(14,500	)		107,739

Capital expenditures		201,236		13,085		333			214,654

Assets (at December 31, 2004 **)		2,879,615		6,766,505		73,137			9,719,257

*	Income (loss) from continuing operations before income taxes.

**	Includes net assets of discontinued operations.

Intercompany electric sales of the electric utilities 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.

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3 • Electric utility subsidiary

Selected financial information

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income Data


Years ended December 31	2006			2005			2004
(in thousands)
Revenues
Operating revenues	$	2,050,412		$	1,801,710		$	1,546,875
Other—nonregulated		4,478			4,674			3,796

		2,054,890			1,806,384			1,550,671

Expenses
Fuel oil		781,740			639,650			483,423
Purchased power		506,893			458,120			398,836
Other operation		186,449			172,962			157,198
Maintenance		90,217			82,242			77,313
Depreciation		130,164			122,870			114,920
Taxes, other than income taxes		190,413			167,295			143,834
Other – nonregulated		2,296			1,542			1,244

		1,888,172			1,644,681			1,376,768

Operating income from regulated and nonregulated activities		166,718			161,703			173,903
Allowance for equity funds used during construction		6,348			5,105			5,794
Interest and other charges		(53,478	)		(50,323	)		(50,503	)
Allowance for borrowed funds used during construction		2,879			2,020			2,542

Income before income taxes and preferred stock dividends of HECO		122,467			118,505			131,736
Income taxes		46,440			44,623			49,479

Income before preferred stock dividends of HECO		76,027			73,882			82,257
Preferred stock dividends of HECO		1,080			1,080			1,080

Net income for common stock	$	74,947		$	72,802		$	81,177

Consolidated Balance Sheet Data


December 31	2006			2005
(in thousands)
Assets
Utility plant, at cost
Property, plant and equipment	$	4,038,264		$	3,782,565
Less accumulated depreciation		(1,558,913	)		(1,456,537	)
Construction in progress		95,619			147,756

Net utility plant		2,574,970			2,473,784
Regulatory assets		112,349			110,718
Other		375,815			496,958

	$	3,063,134		$	3,081,460

Capitalization and liabilities
Common stock ($6²/3 par value, authorized 50,000,000 shares. outstanding: 12,805,843 shares)	$	85,387		$	85,387
Premium on common stock		299,214			299,214
Retained earnings		700,252			654,686
Accumulated other comprehensive loss		(126,650	)		(28	)

Common stock equity		958,203			1,039,259
Cumulative preferred stock – not subject to mandatory redemption (authorized 5,000,000 shares, $20 par value (1,114,657 shares outstanding), and 7,000,000 shares,$100 par value (120,000 shares outstanding); dividend rates of 4.25-7.625%)		34,293			34,293
Long-term debt, net		766,185			765,993

Total capitalization		1,758,681			1,839,545
Short-term borrowings from nonaffiliates and affiliate		113,107			136,165
Deferred income taxes		118,055			208,374
Regulatory liabilities		240,619			219,204
Contributions in aid of construction		276,728			256,263
Other		555,944			421,909

	$	3,063,134		$	3,081,460

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Regulatory assets and liabilities. In accordance with SFAS No. 71, HECO and its subsidiaries’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under SFAS No. 71 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes HECO and its subsidiaries’ operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the electric utilities expect that the regulatory assets would be charged to income and the regulatory liabilities would be credited to income or refunded to ratepayers. In the event of unforeseen regulatory actions or other circumstances, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers.

Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC authorized periods. Generally, HECO and its subsidiaries do not earn a return on their regulatory assets, however, they have been allowed to accrue and recover interest on their regulatory assets for integrated resource planning costs. Noted in parenthesis are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2006, if different. Regulatory liabilities were as follows:


December 31	2006		2005
(in thousands)

Cost of removal in excess of salvage value (1 to 60 years)	$	239,049	$	217,493
Other (5 years; 1 to 5 years)		1,570		1,711

	$	240,619	$	219,204

Regulatory assets were as follows:


December 31	2006		2005
(in thousands)

Income taxes, net (1 to 36 years)	$	73,178	$	70,743
Postretirement benefits other than pensions (18 years; 6 years)		10,738		12,528
Unamortized expense and premiums on retired debt and equity issuances (13 to 30 years; 1 to 22 years)		14,909		16,081
Integrated resource planning costs, net (1 year)		4,521		2,395
Vacation earned, but not yet taken (1 year)		5,759		5,669
Other (1 to 20 years)		3,244		3,302

	$	112,349	$	110,718

Cumulative preferred stock. The cumulative preferred stock of HECO and its subsidiaries is redeemable at the option of the respective company at a premium or par, but none is subject to mandatory redemption.

Major customers. HECO and its subsidiaries received approximately 10%, or $197 million, $176 million and $148 million, of their operating revenues from the sale of electricity to various federal government agencies in 2006, 2005 and 2004, respectively.

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Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through December 31, 2014 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel as of January 1, 2007, the estimated cost of minimum purchases under the fuel supply contracts is $539 million for 2007, $540 million for 2008, $539 million each year for 2009, 2010 and 2011, and a total of $1.6 billion for the period 2012 through 2014. The actual cost of purchases in 2007 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $755 million, $662 million and $490 million of fuel under contractual agreements in 2006, 2005 and 2004, respectively.

Power purchase agreements (PPAs). As of December 31, 2006, HECO and its subsidiaries had six firm capacity PPAs for a total of 540 megawatt (MW) of firm capacity. Purchases from these six IPPs and all other IPPs totaled $507 million, $458 million and $399 million for 2006, 2005 and 2004, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $118 million in 2007, $119 million in 2008, $116 million in 2009, $118 million in 2010 and 2011 and a total of $1.1 billion in the period from 2012 through 2030.

In general, HECO and its subsidiaries base their payments under the PPAs upon available capacity and energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules (see “Energy cost adjustment clauses” below). HECO and its subsidiaries do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Interim increases. On September 27, 2005, the PUC issued an Interim Decision and Order (D&O) 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). The tariff changes implementing the interim rate increase were effective September 28, 2005.

As of December 31, 2006, HECO and its subsidiaries had recognized $79 million of revenues with respect to interim orders ($14 million related to interim orders regarding certain integrated resource planning costs and $65 million related to the interim order with respect to Oahu’s general rate increase request based on a 2005 test year), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

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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 reviews the automatic fuel rate adjustment clause in rate cases, Act 162 requires 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 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 rate case based on a 2005 test year.

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

Management cannot predict the ultimate outcome or the effect of these Act 162 issues on the operation of the ECAC as it relates to the electric utilities.

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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 the proceedings described below, CT-4 and CT-5 are now operational, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. In May 2006, HELCO filed a rate increase application based on a 2006 test year seeking to recover, among other things, CT-4 and CT-5 costs.

Historical context. Installation of CT-4 and CT-5 was significantly delayed as a result of land use and environmental permitting delays and related administrative proceedings and lawsuits. However, 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). Subsequently, HELCO installed CT-4 and CT-5 and put them into limited commercial operation in May and June 2004, respectively. HELCO met the Board of Land and Natural Resources’ (BLNR’s) construction deadline of July 31, 2005. 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.

Waimana filed four appeals to the Hawaii Supreme Court from judgments of the Third Circuit Court involving (i) vacating a November 2002 Final Judgment which had halted construction, (ii) upholding the BLNR 2003 construction period extension, (iii) upholding the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the primary source of water for operating the Keahole plant and (iv) upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water.

The Hawaii Supreme Court has either dismissed or issued favorable decisions on all four of these appeals.

In addition to the Supreme Court appeals, one Circuit Court matter had remained open, but it was inactive after the mediation that resulted in the Settlement Agreement. With all appeals resolved, the stipulation to dismiss this case was filed on October 5, 2006 and the case was dismissed with prejudice on October 6, 2006. Full implementation of the Settlement Agreement was conditioned on obtaining final dispositions, which have now been obtained, of all litigation pending at the time of the 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). Many of these actions had commenced well before all of the litigation was resolved.

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 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 $0.8 million has been incurred through December 31, 2006.

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CT-4 and CT-5 costs incurred; management’s evaluation. As of December 31, 2006, 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, including $43 million for equipment and material purchases, $47 million for planning, engineering, permitting, site development and other costs and $20 million for allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date HELCO has not accrued AFUDC. 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 of the year following the reclassification.

HELCO’s electric rates will not change as a result of including CT-4 and CT-5 in plant and equipment unless and until the PUC grants rate relief in the HELCO rate case filed in May 2006 based on a 2006 test year, in part to recover CT-4 and CT-5 costs. At this time, management continues to believe that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2006. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of these costs.

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 continues to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $62 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. 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 2008 or 2009, subject to the timing of the PUC approval, and the completion date of the second phase is being evaluated.

As of December 31, 2006, the accumulated costs recorded for the EOTP amounted to $30 million, including (i) $12 million of planning and permitting costs incurred prior to the denial in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $13 million for AFUDC. 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 before 2003, and the related 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. Management believes no adjustment to project costs is required as of December 31, 2006. 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.

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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 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 and of which $0.8 million has been expended through December 31, 2006). 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.

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 December 31, 2006, the remaining accrual (amounts expensed less amounts expended) related to the Honolulu Harbor investigation was $1.5 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.

117

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.

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 its 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 operations 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 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 has yet to announce whether it plans to request a rehearing by the court of appeals or appeal the decision to the U.S. Supreme Court. If it stands, the court’s decision reduces the compliance options available to HECO. The EPA has not issued a schedule for rulemaking, which would be necessary to comply with the court’s decision. Due to the uncertainties raised by the court’s decision as well as the need for further rulemaking by the EPA, HECO management is unable to predict which compliance options, some of which could entail significant capital expenditures to implement, will be applicable to the electric utilities’ facilities.

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Collective bargaining agreements. As of December 31, 2006, 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 provide 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.

Limited insurance. HECO and its subsidiaries purchase insurance coverages to protect themselves against loss of or damage to their properties and against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $3.5 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster should occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations and financial condition could be materially adversely impacted. Also, certain insurance has substantial “deductibles”, limits on the maximum amounts that may be recovered and exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business, each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, HECO, HELCO and MECO could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

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4 • Bank subsidiary

Selected financial information

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

Consolidated Statements of Income Data


Years ended December 31	2006		2005			2004
(in thousands)

Interest and dividend income
Interest and fees on loans	$	231,610	$	205,084		$	184,773
Interest and dividends on investment and mortgage-related securities		117,160		125,924			122,347

		348,770		331,008			307,120

Interest expense
Interest on deposit liabilities		73,614		52,064			47,184
Interest on other borrowings		72,482		69,362			65,603

		146,096		121,426			112,787

Net interest income		202,674		209,582			194,333
Provision (reversal of allowance) for loan losses		1,400		(3,100	)		(8,400	)

Net interest income after provision (reversal of allowance) for loan losses		201,274		212,682			202,733

Noninterest income
Fees from other financial services		26,385		25,790			23,560
Fee income on deposit liabilities		18,779		16,989			17,820
Fee income on other financial products		8,025		9,058			10,184
Gain (loss) on sale of securities		1,735		175			(70	)
Other income		4,671		4,890			5,670

		59,595		56,902			57,164

Noninterest expense
Compensation and employee benefits		68,478		69,082			65,052
Occupancy		18,829		17,055			16,996
Equipment		14,700		13,722			13,756
Services		21,484		15,466			12,863
Data processing		10,164		10,598			11,794
Marketing		5,199		3,816			3,987
Office supplies, printing and postage		4,055		4,440			4,699
Communication		3,335		3,475			2,879
Other expense		26,067		27,029			22,897

		172,311		164,683			154,923

Income before minority interests and income taxes		88,558		104,901			104,974
Minority interests		—		45			97
Income taxes		32,776		39,969			58,404

Income before preferred stock dividends		55,782		64,887			46,473
Preferred stock dividends		—		4			5,411

Net income for common stock	$	55,782	$	64,883		$	41,062

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Consolidated Balance Sheet Data


December 31	2006			2005
(in thousands)

Assets
Cash and equivalents	$	172,370		$	150,130
Federal funds sold		79,671			57,434
Available-for-sale investment and mortgage-related securities		2,367,427			2,629,351
Investment in stock of Federal Home Loan Bank of Seattle		97,764			97,764
Loans receivable, net		3,780,461			3,566,834
Other		223,666			244,443
Goodwill and other intangibles, net		87,140			89,379

	$	6,808,499		$	6,835,335

Liabilities and stockholder’s equity
Deposit liabilities–noninterest-bearing	$	648,915		$	624,497
Deposit liabilities–interest-bearing		3,926,633			3,932,922
Other borrowings		1,568,585			1,622,294
Other		104,470			98,189

		6,248,603			6,277,902

Common stock		323,154			321,538
Retained earnings		280,046			272,545
Accumulated other comprehensive loss, net of tax benefits		(43,304	)		(36,650	)

		559,896			557,433

	$	6,808,499		$	6,835,335

Investment and mortgage-related securities. ASB owns investment securities (federal agency obligations), private-issue mortgage-related securities and mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA). As of December 31, 2006, ASB’s available-for-sale federal agency obligations had contractual maturity dates in 2008. Mortgage-related securities have contractual terms to maturity, but require periodic payments to reduce principal. In addition, expected maturities will differ from contractual maturities because borrowers have the right to prepay the underlying mortgages.

ASB obtains market prices for the investment and mortgage-related securities from a third party financial services provider. The prices of these securities may be influenced by factors such as market liquidity, corporate credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector concerns and overall market psychology. Adverse changes in any of these factors may result in additional losses.

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December 31, 2006
										Gross unrealized losses
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Less than 12 months						12 months or longer
(dollars in thousands)	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Count	Fai r Value		Amount			Count	Fair Value		Amount
Available-for-sale

Investment securities-federal agency obligations	$	149,978	$	—	$	(654	)	$	149,324	5	$	124,842	$	(158	)	1	$	24,482	$	(496	)
Mortgage-related securities:
FNMA, FHLMC and GNMA		1,754,154		505		(51,854	)		1,702,805	4		4,534		(22	)	206		1,654,550		(51,832	)
Private issue		522,173		339		(7,214	)		515,298	8		102,155		(726	)	26		313,879		(6,488	)

	$	2,426,305	$	844	$	(59,722	)	$	2,367,427	17	$	231,531	$	(906	)	233	$	1,992,911	$	(58,816	)


December 31, 2005
										Gross unrealized losses
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Less than 12 months						12 months or longer
(dollars in thousands)	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Count	Fai r Value		Amount			Count	Fair Value		Amount
Available-for-sale

Investment securities-federal agency obligation	$	24,965	$	—	$	(534	)	$	24,431	—	$	—	$	—		1	$	24,431	$	(534	)
Mortgage-related securities:
FNMA, FHLMC and GNMA		2,230,279		3,482		(57,315	)		2,176,446	68		664,606		(9,774	)	147		1,385,218		(47,541	)
Private issue		434,671		145		(6,342	)		428,474	22		262,279		(3,175	)	10		125,332		(3,167	)

	$	2,689,915	$	3,627	$	(64,191	)	$	2,629,351	90	$	926,885	$	(12,949	)	158	$	1,534,981	$	(51,242	)


December 31, 2004
										Gross unrealized losses
	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Less than 12 months						12 months or longer
(dollars in thousands)	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value		Count	Fair Value		Amount			Count	Fair Value		Amount
Available-for-sale

Investment securities-federal agency obligation	$	24,953	$	—	$	(88	)	$	24,865	1	$	24,865	$	(88	)	—	$	—	$	—
Mortgage-related securities:
FNMA, FHLMC and GNMA		2,544,020		11,558		(19,538	)		2,536,040	97		1,345,961		(10,306	)	35		389,488		(9,232	)
Private issue		393,518		1,063		(2,114	)		392,467	9		169,374		(1,199	)	13		63,645		(915	)

	$	2,962,491	$	12,621	$	(21,740	)	$	2,953,372	107	$	1,540,200	$	(11,593	)	48	$	453,133	$	(10,147	)

As of December 31, 2006, 2005 and 2004, ASB’s investment in stock of the FHLB of Seattle was carried at cost because it can only be redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and/or borrowing levels.

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In 2006, 2005 and 2004, proceeds from sales of available-for-sale mortgage-related securities were $61 million, $28 million and $45 million resulting in gross realized gains of $1.8 million, $0.2 million and $0.2 million and gross realized losses of $0.1 million, nil and $0.3 million, respectively.

ASB pledged mortgage-related securities with a carrying value of approximately $195 million and $191 million as of December 31, 2006 and 2005, respectively, as collateral to secure public funds and deposits in ASB’s treasury, tax, and loan account with the Federal Reserve Bank of San Francisco. As of December 31, 2006 and 2005, mortgage-related securities with a carrying value of $1,035 million and $800 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

All securities in the ASB portfolio are investment grade bonds issued by FNMA, FHLMC, GNMA, or non-agency issuers. The non-agency bonds are collateralized by mortgage loan pools and utilize credit support structures that provide the securities with an investment grade rating. ASB has evaluated and determined that as of December 31, 2006 and 2005, all securities in the portfolio with unrealized losses are not other-than-temporarily impaired and these losses have not been included in earnings but instead have been included on a net basis in AOCI. Unrealized losses are primarily the result of changes in interest rates and market sentiment regarding specific issuers or sectors. Based on agency guarantees and credit support structures, management expects full payment of principal and interest on all bonds until maturity or call date. Management intends and believes it has the ability to hold all securities with unrealized losses until there is a recovery of fair value up to the amortized cost of its investment.

Loans receivable


December 31	2006			2005
(in thousands)

Real estate loans
One-to-four unit residential and commercial	$	2,961,880		$	2,844,347
Construction and development		260,870			241,311

		3,222,750			3,085,658
Consumer loans		264,537			248,635
Commercial loans		453,151			412,816

		3,940,438			3,747,109
Undisbursed portion of loans in process		(117,226	)		(140,273	)
Deferred fees and discounts, including net purchase accounting discounts		(22,033	)		(22,088	)
Allowance for loan losses		(31,228	)		(30,595	)

Loans held for investment		3,769,951			3,554,153
Loans held for sale		10,510			12,681

	$	3,780,461		$	3,566,834

As of December 31, 2006, ASB had impaired loans totaling $26.1 million, which consisted of $4.8 million of commercial real estate loans and $21.3 million of commercial loans. As of December 31, 2005, ASB had impaired loans totaling $20.5 million, which consisted of $4.3 million of commercial real estate loans and $16.2 million of commercial loans. As of December 31, 2006 and 2005, impaired loans totaling $0.3 million and $0.3 million, respectively, had related allowances for loan losses of $0.2 million and $0.1 million, respectively. As of December 31, 2006 and 2005, ASB had $25.8 million and $20.2 million of impaired loans, respectively, for which there were no related allowances for loan losses. ASB realized $1.9 million, $1.4 million and $1.3 million of interest income on impaired loans in 2006, 2005 and 2004, respectively. The average balances of impaired loans during 2006, 2005 and 2004 were $22.0 million, $20.8 million and $20.2 million, respectively.

As of December 31, 2006 and 2005, ASB had nonaccrual and renegotiated loans of $8.7 million and $7.3 million, respectively.

ASB realized $0.1 million, $0.1 million and $0.4 million of interest income on nonaccrual loans in 2006, 2005 and 2004, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $0.4 million, $0.5 million and $0.6 million in 2006, 2005 and 2004, respectively. ASB had no loans that were 90 days or more past due on which interest was being accrued as of December 31, 2006 and 2005.

As of December 31, 2006 and 2005, commitments not reflected in the consolidated balance sheets consisted of commitments to originate loans, other than the undisbursed portion of loans in process, of $24 million and $76 million, respectively. Commitments to extend credit are agreements to lend to a customer as long as there is no

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violation of any condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain of the commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. ASB minimizes its exposure to loss under these commitments by requiring that customers meet certain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may include residential real estate, accounts receivable, inventory, and property, plant, and equipment.

As of December 31, 2006 and 2005, ASB had commitments to sell residential loans of $0.2 million and $2.5 million, respectively. The loans are included in loans held for sale or represent commitments to make loans at an interest rate set prior to funding (rate lock commitments). Rate lock commitments guarantee a specified interest rate for a loan if ASB’s underwriting standards are met, but do not obligate the potential borrower. Rate lock commitments on loans intended to be sold in the secondary market are derivative instruments, but have not been designated as hedges. Rate lock commitments are carried at fair value and adjustments are recorded in “Other income,” with an offset on the balance sheet in “Other” liabilities. As of December 31, 2006 and 2005, rate lock commitments were made on loans totaling $0.2 million and $0.2 million, respectively. To offset the impact of changes in market interest rates on the rate lock commitments on loans held for sale, ASB utilizes short-term forward sale contracts. Forward sale contracts are also derivative instruments, but have not been designated as hedges, and thus any changes in fair value are also recorded in “Other income,” with an offset on the balance sheet in “Other” assets or liabilities. As of December 31, 2006 and 2005, the notional amounts for forward sales contracts were $0.2 million and $2.5 million, respectively. Valuation models are applied using current market information to estimate fair value. For 2006 and 2005, the net loss on derivatives was nil.

As of December 31, 2006 and 2005, ASB had commitments to sell education loans of $10 million.

As of December 31, 2006 and 2005, standby, commercial and banker’s acceptance letters of credit totaled $27 million and $25 million, respectively. Letters of credit are conditional commitments issued by ASB to guarantee payment and performance of a customer to a third party. The credit risk involved in issuing letters of credit is essentially the same as that involved in extending loan facilities to customers. ASB holds collateral supporting those commitments for which collateral is deemed necessary. As of December 31, 2006 and 2005, unused lines of credit totaled $973 million and $867 million, respectively.

ASB services real estate loans owned by third parties ($0.3 billion, $0.4 billion and $0.5 billion as of December 31, 2006, 2005 and 2004, respectively), which are not included in the accompanying consolidated financial statements. ASB reports fees earned for servicing loans as income when the related mortgage loan payments are collected and charges loan servicing costs to expense as incurred.

As of December 31, 2006 and 2005, ASB had pledged loans with an amortized cost of approximately $0.9 billion and $1.1 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

As of December 31, 2006 and 2005, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board Regulation O) of such individuals, was $90 million and $104 million, respectively. The $14 million decrease in such loans in 2006 was attributed to closed lines of credit and repayments of $18 million, partly offset by net new loans to new and existing directors and executive officers of $4 million. As of December 31, 2006 and 2005, $70 million and $87 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms except that residential real estate loans and consumer loans to directors and executive officers of ASB were made at preferred employee interest rates. Management believes these loans do not represent more than a normal risk of collection.

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Allowance for loan losses. Changes in the allowance for loan losses were as follows:


(dollars in thousands)	2006			2005			2004
Allowance for loan losses, January 1	$	30,595		$	33,857		$	44,285

Provision (reversal of allowance) for loan losses		1,400			(3,100	)		(8,400	)

Charge-offs, net of recoveries
Real estate loans		(200	)		(459	)		(868	)
Other loans		967			621			2,896

Net charge-offs		767			162			2,028

Allowance for loan losses, December 31	$	31,228		$	30,595		$	33,857

Ratio of net charge-offs to average loans outstanding		0.02	%		<0.01	%		0.06	%

NM Not meaningful.

Deposit liabilities


December 31 (dollars in thousands)	2006				2005
December 31 (dollars in thousands)	Weightedaverage stated rate		Amount		Weighted-average stated rate		Amount
Savings	1.03	%	$	1,569,514	0.63	%	$	1,723,949
Other checking
Interest-bearing	0.26			522,442	0.13			573,442
Noninterest-bearing	—			330,346	—			309,172
Commercial checking	—			318,569	—			315,325
Money market	2.07			202,328	1.18			257,144
Term certificates	3.97			1,632,349	3.18			1,378,387

	1.89	%	$	4,575,548	1.28	%	$	4,557,419

As of December 31, 2006 and 2005, certificate accounts of $100,000 or more totaled $530 million and $406 million, respectively.

The approximate amounts of term certificates outstanding as of December 31, 2006 with scheduled maturities for 2007 through 2011 were $1,213 million in 2007, $139 million in 2008, $73 million in 2009, $151 million in 2010 and $46 million in 2011.

Interest expense on deposit liabilities by type of deposit was as follows:


Years ended December 31	2006		2005		2004
(in thousands)

Term certificates	$	55,466	$	40,063	$	38,935
Savings		13,316		8,860		6,525
Money market		3,829		2,582		1,448
Interest-bearing checking		1,003		559		276

	$	73,614	$	52,064	$	47,184

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Other borrowings

Securities sold under agreements to repurchase.


December 31, 2006
Maturity	Repurchase liability		Weighted-average interest rate		Collateralized by mortgage- related securities– fair value plus accrued interest
(dollars in thousands)

Overnight	$	152,133	4.51	%	$	178,153
1 to 29 days		45,453	4.98			85,922
30 to 90 days		94,638	5.03			178,900
Over 90 days		546,361	3.93			596,510

	$	838,585	4.22	%	$	1,039,485

The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts at the Federal Reserve System. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.

The following table sets forth information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities:


Years ended December 31	2006			2005			2004
(dollars in millions)

Amount outstanding as of December 31	$	839		$	687		$	811
Average amount outstanding	$	771		$	705		$	842
Maximum amount outstanding as of any month-end	$	839		$	828		$	990
Weighted-average interest rate as of December 31		4.22	%		3.83	%		3.44	%
Weighted-average interest rate during the year		4.21	%		3.50	%		2.65	%
Weighted-average remaining days to maturity as of December 31		1,047			423			500

Advances from Federal Home Loan Bank.


December 31, 2006	Weighted-average stated rate		Amount
(dollars in thousands)

Due in
2007	4.44	%	$	299,000
2008	5.44			168,000
2009	4.60			163,000
2010	6.03			100,000
2011	—			—

	4.92	%	$	730,000

As of December 31, 2006, $65 million of fixed rate FHLB advances with a weighted average rate of 6.94% are callable quarterly at par until maturity in 2010.

ASB and the FHLB of Seattle are parties to an Advances, Security and Deposit Agreement (Advances Agreement), which applies to currently outstanding and future advances, and governs the terms and conditions under which ASB borrows and the FHLB of Seattle makes loans or advances from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB of Seattle’s credit policies, and makes certain warranties and representations to the FHLB of Seattle. Upon the occurrence of and during the continuation of an “Event of Default” (which term includes any event of nonpayment of interest or principal of any advance when due or failure to perform any promise or obligation under the Advances Agreement or other credit arrangements between the parties), the FHLB of Seattle may, at its option, declare all indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable. Advances from the FHLB of Seattle are secured by loans and stock in the FHLB of Seattle. ASB is required to obtain and hold a specific number of shares of capital

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stock of the FHLB of Seattle. ASB was in compliance with all Advances Agreement requirements as of December 31, 2006 and 2005.

Common stock equity. As of December 31, 2006, ASB was in compliance with the minimum capital requirements under OTS regulations. In 1988, HEI agreed with the OTS predecessor regulatory agency that it would contribute additional capital to ASB up to a maximum aggregate amount of approximately $65 million (Capital Maintenance Agreement). As of December 31, 2006, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the agreement had been reduced to approximately $28.3 million.

In December 2004, ASB’s capital structure changed when ASB redeemed its preferred stock held by HEIDI ($75 million) and HEIDI infused common equity into ASB ($75 million). This change did not affect HEI’s remaining maximum obligation to contribute additional capital under the Capital Maintenance Agreement.

The $7 million increase in accumulated other comprehensive loss from December 31, 2005 to December 31, 2006 was primarily due to the effect of applying SFAS No. 158, partly offset by the increase in the market value of the available-for-sale investment and mortgage-related securities. Changes in the market value of mortgage-related securities do not result in a charge to net income in the absence of an “other-than-temporary” impairment in the value of the securities.

5 · Unconsolidated variable interest entities

Trust financing entities. Hawaiian Electric Industries Capital Trust I (the Trust) was a Delaware statutory trust and financing entity, which issued, in 1997, $100 million of 8.36% Trust Originated Preferred Securities to the public. The Trust was a consolidated subsidiary of HEI through December 31, 2003. Since HEI, as the common security holder, did not absorb the majority of the variability of the Trust, HEI was not the primary beneficiary and, in accordance with FIN 46R, did not consolidate the Trust as of January 1, 2004. In March 2004, HEI completed the issuance and sale of 2 million shares of its common stock (pre-split) in a registered public offering. HEI used the net proceeds from the sale, along with other corporate funds, to effect the redemption of the 8.36% Trust Originated Preferred Securities in April 2004. The Trust was dissolved and terminated in 2004.

HECO Capital Trust I (Trust I) was a financing entity, which issued, in 1997, $50 million of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) to the public. In March 2004, HECO, HELCO and MECO borrowed the proceeds of the sale of HECO Capital Trust III’s 2004 Trust Preferred Securities and, in April 2004, applied the proceeds, along with other corporate funds, to redeem the 1997 Trust Preferred Securities. HECO Capital Trust II (Trust II) was a financing entity, which issued, in 1998, $50 million of 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 Trust Preferred Securities) to the public. In April 2004, the electric utilities used funds primarily from short-term borrowings from HEI and from the issuance of commercial paper by HECO to redeem the 1998 Trust Preferred Securities. Trust I and Trust II, each a Delaware statutory trust, were consolidated subsidiaries of HECO through December 31, 2003. Since HECO, as the common security holder, did not absorb the majority of the variability of the trusts, HECO was not the primary beneficiary and, in accordance with FIN 46R, did not consolidate the trusts as of January 1, 2004. Trust I and Trust II were dissolved and terminated in 2004.

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 MECO and HELCO 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. Trust III’s

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balance sheet as of December 31, 2006 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 statement for 2006 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 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 December 31, 2006, HECO and its subsidiaries had six purchase power agreements (PPAs) for a total of 540 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 2006 totaled $507 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $133 million, $181 million, $72 million and $44 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 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 has reviewed its significant PPAs and determined 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 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 and Kaheawa Wind Power, LLC (KWP) have now provided their information (see below).

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.”

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Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa Partners, L.P. (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 which affected 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.

Kaheawa Wind Power, LLC. In December 2004, MECO executed a new PPA with Kaheawa Wind Power, LLC (KWP), which completed the installation of a 30 MW windfarm on Maui and began selling power to MECO in June 2006. Management concluded that MECO does not have to consolidate KWP as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.

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 (targeted for commercial operation in April 2007). In December 2005, Apollo assigned the PPA to Tawhiri Power LLC (Tawhiri), a subsidiary of Apollo. In February 2007, Tawhiri 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. 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.

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6 • Short-term borrowings

Short-term borrowings as of December 31, 2006 and 2005 consisted of commercial paper issued by HEI and HECO and had weighted-average interest rates of 5.44% and 4.48%, respectively.

As of December 31, 2006, HEI and HECO maintained syndicated credit facilities which totaled $100 million and $175 million, respectively. As of December 31, 2005, HEI and HECO maintained bilateral bank lines of credit which totaled $80 million and $180 million, respectively. None of the facilities are secured. There were no borrowings under these facilities or lines of credit during 2006 or 2005.

Credit agreements. 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 its agreement, or meet other requirements will result in an event of default. For example, under its agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 28% as of December 31, 2006, as calculated under the agreement) and “Consolidated Net Worth” of $850 million (Net Worth of $1.3 billion as of December 31, 2006, 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.

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 has an initial term which expires on March 29, 2007. On August 30, 2006, HECO filed an application with the PUC requesting approval to maintain the $175 million credit facility for five years, which, if approved by the PUC, will automatically extend the termination date of the credit facility from March 29, 2007 to March 31, 2011. 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

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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 47% for HELCO and 43% for MECO as of December 31, 2006, 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 December 31, 2006, 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.

7 · Long-term debt


December 31	2006			2005
(dollars in thousands)

6.50% Junior Subordinated Deferrable Interest Debentures, Series 2004, due 2034 (see Note 5)	$	51,546		$	51,546

Obligations to the State of Hawaii for the repayment of special purpose revenue bonds (SPRB) issued on behalf of electric utility subsidiaries
4.75-4.95%, due 2012-2025		118,500			118,500
5.00-5.50%, due 2014-2032		203,400			203,400
5.65-5.88%, due 2018-2027		266,000			266,000
6.15-6.20%, due 2020-2029		130,000			130,000

		717,900			717,900
Less unamortized discount		(3,261	)		(3,453	)

		714,639			714,447

HEI medium-term notes 6.55-7.56%, paid in 2006		—			110,000
HEI medium-term notes 6.90-6.93%, due 2007		10,000			10,000
HEI medium-term note 4.00%, due 2008		50,000			50,000
HEI medium-term notes 4.23-6.141%, due 2011		150,000			50,000
HEI medium-term note 7.13%, due 2012		7,000			7,000
HEI medium-term note 5.25%, due 2013		50,000			50,000
HEI medium-term note 6.51%, due 2014		100,000			100,000

	$	1,133,185		$	1,142,993

As of December 31, 2006, the aggregate principal payments required on long-term debt for 2007 through 2011 are $10 million in 2007, $50 million in 2008, nil in 2009 and 2010 and $150 million in 2011.

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8 • Retirement benefits

Pensions. Substantially all of the employees of HEI and the electric utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (HEI/HECO Pension Plan) and substantially all of the employees of ASB and its subsidiaries participate in the American Savings Bank Retirement Plan (ASB Pension Plan and, collectively, Plans). The Plans are qualified, non-contributory defined benefit pension plans and include benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental/Excess/Directors Plans). In general, benefits are based on the employees’ years of service and compensation.

The Plans and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. The Directors’ Plan has been frozen since 1996, and no participants have accrued any benefits after that time. The plan will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their respective plans at any time. If a participating employer terminates its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue Code. The funding of the Plans is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary.

To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental/Excess/ Directors Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified below.

Postretirement benefits other than pensions. HEI and the electric utilities provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (HECO Benefits Plan). Health benefits are also provided to dependents of eligible retired employees. The contribution for health benefits paid by the participating employers is based on the retirees’ years of service and retirement dates. Generally, employees are eligible for these benefits if, upon retirement from active employment, they are eligible to receive benefits from the HEI/HECO Pension Plan.

Among other provisions, the HECO Benefits Plan provides prescription drug benefits for Medicare-eligible participants who retire after 1998. Retirees who are eligible for the drug benefits are required to pay a portion of the cost each month. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the 2003 Act) was signed into law on December 8, 2003. The 2003 Act expanded Medicare to include for the first time coverage for prescription drugs. The 2003 Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28 percent of a participant’s drug costs between $250 and $5,000 if the participant waives coverage under Medicare Part D.

The HECO Benefits Plan was adopted with the expectation that it will continue indefinitely, but the continuation of the plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the plan at any time.

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SFAS No. 158. In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in stockholders’ equity (using the projected benefit obligation, rather than the accumulated benefit obligation, to calculate the funded status of pension plans).

By application filed on December 8, 2005 (AOCI Docket), the electric utilities had requested the PUC to permit them to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension liability as prescribed by SFAS No. 87. The electric utilities updated their application in the AOCI Docket in November 2006 to take into account SFAS No. 158. On January 26, 2007, the PUC issued a D&O in the updated AOCI Docket, which denied the electric utilities’ request to record a regulatory asset on the grounds that the electric utilities had not met their burden of proof to show that recording a regulatory asset was warranted, or that there would be adverse consequences if a regulatory asset was not recorded. The PUC also required HECO to submit a pension study (determining whether ratepayers are better off with a well-funded pension plan, a minimally-funded pension plan, or something in between) by May 31, 2007 in its pending 2007 test year rate case, as proposed by the electric utilities in support of their request.

The incremental effect of applying SFAS No. 158 on individual line items in the Company’s balance sheet as of December 31, 2006 was as follows:


(in thousands)	Before SFAS No. 158 adoption			Pension benefits adjustments			Other benefits adjustments			After SFAS No. 158 adoption
Other assets	$	395,668		$	(103,030	)	$	—		$	292,638

Total assets		9,994,239			(103,030	)		—			9,891,209

Other liabilities		392,260			94,658			31,536			518,454
Deferred income taxes		196,083			(77,032	)		(12,271	)		106,780

Total liabilities		8,724,785			17,626			19,265			8,761,676

Accumulated other comprehensive loss		(35,607	)		(120,656	)		(19,265	)		(175,528	)

Total stockholders’ equity		1,235,161			(120,656	)		(19,265	)		1,095,240

Although there is not an immediate impact on net income due to the D&O in the updated AOCI Docket, the electric utilities (as well as HEI) were required by SFAS No. 158 to record substantial charges against stockholder’s equity, and the electric utilities’ reported returns on rate base and returns on average common equity will be higher than if there were no charge against stockholder’s equity. Consolidated debt to capitalization and interest coverage ratios of the Company and the electric utilities were also adversely affected. These effects could adversely affect security ratings, and increase the difficulty or expense of obtaining future financing. The electric utilities will continue to seek a return on their pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of related deferred income taxes) in rate base in their respective rate cases. The electric utilities will also propose to restore equity for all AOCI charges for rate making purposes in their respective rate cases.

Pension and other postretirement benefit plans information. The changes in the obligations and assets of the Company’s retirement benefit plans for 2005 and the funded status of these plans and the unrecognized and recognized amounts related to these plans and reflected in the Company’s balance sheet as of December 31, 2005 were as follows:

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(in thousands)	Pension benefits			Other benefits
Benefit obligation, January 1, 2005	$	893,638		$	200,182
Service cost		29,369			5,248
Interest cost		52,120			11,104
Amendments		123			—
Actuarial (gain) loss		28,422			(17,080	)
Benefits paid and expenses		(42,555	)		(8,540	)

Benefit obligation, December 31, 2005		961,117			190,914

Fair value of plan assets, January 1, 2005		781,758			109,484
Actual return on plan assets		56,621			7,965
Employer contribution (including company payments for nonqualified plans)		14,126			10,716
Benefits paid and expenses		(42,555	)		(8,540	)

Fair value of plan assets, December 31, 2005		809,950			119,625

Funded status		(151,167	)		(71,290	)
Unrecognized net actuarial loss		266,784			24,871
Unrecognized net transition obligation		18			21,966
Unrecognized prior service cost (gain)		(4,949	)		157

Net amount recognized, December 31, 2005	$	110,686		$	(24,296	)

Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	122,206		$	—
Accrued benefit liability		(13,929	)		(24,296	)
Intangible asset		351			—
Accumulated other comprehensive income		2,058			—

Net amount recognized, December 31, 2005	$	110,686		$	(24,296	)

The changes in the obligations and assets of the Company’s retirement benefit plans and the changes in AOCI (gross) for 2006 and the funded status of these plans and amounts related to these plans reflected in the Company’s balance sheet as of December 31, 2006 were as follows:


(in thousands)	Pension benefits			Other benefits
Benefit obligation, January 1, 2006	$	961,117		$	190,914
Service cost		32,486			5,099
Interest cost		54,200			10,620
Amendments		4,726			—
Actuarial gain		(21,832	)		(5,856	)
Benefits paid and expenses		(45,135	)		(9,555	)

Benefit obligation, December 31, 2006		985,562			191,222

Fair value of plan assets, January 1, 2006		809,950			119,625
Actual return on plan assets		106,702			15,957
Employer contribution		3,022			9,890
Benefits paid and expenses		(44,396	)		(9,106	)

Fair value of plan assets, December 31, 2006		875,278			136,366

Accrued benefit liability, December 31, 2006		(110,284	)		(54,856	)

AOCI, January 1, 2006		2,058			—
Recognized during year – net recognized transition obligation		(5	)		(3,138	)
Recognized during year – prior service (cost)/credit		205			(13	)
Recognized during year – net actuarial losses		(12,005	)		(412	)
Occurring during year – prior service cost		4,726			—
Occurring during year – net actuarial gains		(56,850	)		(11,895	)
Other adjustments		259,795			46,994

AOCI, December 31, 2006		197,924			31,536

Net actuarial loss		120,812			7,676
Prior service cost (gain)		(19	)		87
Net transition obligation		8			11,502

AOCI, net of taxes, December 31, 2006	$	120,801		$	19,265

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The Company does not expect any plan assets to be returned to the Company during calendar year 2007.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2006, 2005 and 2004.

The defined benefit pension plans’ accumulated benefit obligations, which do not consider projected pay increases, as of December 31, 2006 and 2005 were $854 million and $806 million, respectively.

The Company has determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years - 0% in the first year and 25% in years two to five, and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual net periodic benefit cost.

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for retirement defined benefit plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by: asset class, geographic region, market capitalization and investment style.

The expected long-term rate of return assumption of 8.5% was based on the Plan’s target asset allocation and projected asset class returns provided by the plans’ actuarial consultant.

The weighted-average asset allocation of retirement defined benefit plans was as follows:


	Pension benefits								Other benefits
					Investment policy								Investment policy
December 31	2006		2005		Target		Range		2006		2005		Target		Range
Asset category
Equity securities	72	%	69	%	70	%	65-75	%	71	%	68	%	70	%	65-75	%
Fixed income	27		29		30		25-35	%	29		31		30		25-35	%
Other ¹	1		2		—		—		—		1		—		—

	100	%	100	%	100	%			100	%	100	%	100	%

1	Other includes alternative investments, which are relatively illiquid in nature and will remain as plan assets until an appropriate liquidation opportunity occurs.

The Company’s current estimate of contributions to the retirement benefit plans in 2007 is $14 million.

As of December 31, 2006, the benefits expected to be paid under the retirement benefit plans in 2007, 2008, 2009, 2010, 2011 and 2012 through 2016 amounted to $57 million, $59 million, $62 million, $64 million, $67 million and $385 million, respectively.

The following weighted-average assumptions were used in the accounting for the plans:


	Pension benefits						Other benefits
December 31	2006		2005		2004		2006		2005		2004
Benefit obligation
Discount rate	6.00	%	5.75	%	6.00	%	6.00	%	5.75	%	6.00	%
Expected return on plan assets	8.5		9.0		9.0		8.5		9.0		9.0
Rate of compensation increase	4.2		4.6		4.6		4.2		4.6		4.6
Net periodic benefit cost (years ended)
Discount rate	5.75		6.00		6.25		5.75		6.00		6.25
Expected return on plan assets	9.0		9.0		9.0		9.0		9.0		9.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

As of December 31, 2006, the assumed health care trend rates for 2007 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2012 and thereafter; dental, 5.00%; and vision, 4.00%. As of December 31, 2005, the assumed health care trend rates for 2006 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2011 and thereafter; dental, 5.00%; and vision, 4.00%.

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The components of net periodic benefit cost were as follows:


	Pension benefits									Other benefits
Years ended December 31	2006			2005			2004			2006			2005			2004
(in thousands)

Service cost	$	32,486		$	29,369		$	26,454		$	5,099		$	5,248		$	4,530
Interest cost		54,200			52,120			50,654			10,620			11,104			10,770
Expected return on plan assets		(71,684	)		(73,971	)		(72,880	)		(9,918	)		(9,853	)		(9,690	)
Amortization of unrecognized net (2006) transition obligation		5			5			4			3,138			3,138			3,138
Amortization of net (2006) prior service cost (gain)		(205	)		(623	)		(587	)		13			13			13
Amortization of net actuarial loss		12,005			5,924			1,160			412			442			—

Net periodic benefit cost	$	26,807		$	12,824		$	4,805		$	9,364		$	10,092		$	8,761

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefits pension plans that will be amortized from AOCI into net periodic pension benefit cost over 2007 are $(0.2) million, $11.4 million and nil, respectively. The estimated prior service cost, net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI into net periodic other than pension benefit cost over 2007 are nil, nil and $3.1 million, respectively.

Of the net periodic pension benefit costs, the Company recorded expense of $21 million, $11 million, $5 million in 2006, 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant. Of the net periodic other than pension benefit costs, the Company expensed $7 million, $8 million and $6 million in 2006, 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with an accumulated benefit obligation in excess of plan assets were $19 million, $16 million and nil, respectively, as of December 31, 2006 and $16 million, $14 million and nil, respectively, as of December 31, 2005.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2006, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.6 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.1 million.

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9 • 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 (4,984,655 shares available for issuance under outstanding and future grants and awards as of December 31, 2006) 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, 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.

The Company recorded share-based compensation expense of $1.6 million in 2006, $3.6 million in 2005 and $1.8 million in 2004. The Company recorded related income tax benefit (including a valuation allowance due to limits on the deductibility of executive compensation) on share-based compensation expense of $0.7 million in 2006, $1.1 million in 2005 and $0.7 million in 2004. The Company has not capitalized any share-based compensation cost.

In place of a SARs grant for 2006, the Company instead awarded restricted stock, as described under “Restricted stock.” For all share-based compensation, the estimated forfeiture rate is 1.4%.

Nonqualified stock options

Information about HEI’s NQSOs is summarized as follows:


	2006				2005				2004
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	929,000		$	19.88	1,122,500		$	19.74	1,476,600		$	19.02
Granted	—			—	—			—	—			—
Exercised	(269,000	)	$	20.38	(193,500	)		19.07	(348,100	)		16.67
Forfeited	—			—	—			—	—			—
Expired	—			—	—			—	(6,000	)		19.86

Outstanding, December 31	660,000		$	19.68	929,000		$	19.88	1,122,500		$	19.74

Options exercisable, December 31	581,000		$	19.57	651,500		$	19.51	568,000		$	19.06

(1)	Weighted-average exercise price


December 31, 2006			Outstanding				Exercisable
Year of grant	Range of exercise prices		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price		Number of options	Weighted- average remaining contractual life	Weighted- average exercise price
1998	$	20.50	6,000	1.3	$	20.50	6,000	1.3	$	20.50
1999		17.61 - 17.63	65,000	2.5		17.62	65,000	2.5		17.62
2000		14.74	52,000	3.3		14.74	52,000	3.3		14.74
2001		17.96	89,000	4.2		17.96	89,000	4.2		17.96
2002		21.68	150,000	5.2		21.68	150,000	5.2		21.68
2003		20.49	298,000	6.2		20.49	219,000	6.1		20.49

	$	14.74 - 21.68	660,000	5.0	$	19.68	581,000	4.9	$	19.57

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As of December 31, 2006, NQSO shares outstanding and NQSO exercisable had an aggregate intrinsic value (including dividend equivalents) of $8.3 million and $7.4 million, respectively.

NQSO activity and statistics are summarized as follows:


($ in thousands, except prices)	2006		2005		2004
Shares vested		198,500		277,000		325,000
Aggregate fair value of vested shares	$	916	$	1,215	$	1,493
Cash received from exercise	$	5,481	$	3,689	$	5,802
Intrinsic value of shares exercised ¹	$	2,908	$	2,375	$	5,719
Tax benefit realized for the deduction of exercises	$	965	$	518	$	531
Dividend equivalent shares distributed under Section 409A		43,265		—		—
Weighted-average Section 409A distribution price	$	26.27		—		—
Intrinsic value of shares distributed under Section 409A	$	1,137		—		—
Tax benefit realized for Section 409A distributions	$	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 December 31, 2006, there was $0.1 million of total unrecognized compensation cost related to nonvested NQSOs and that cost is expected to be recognized over a weighted average period of four months.

Stock appreciation rights

Information about HEI’s SARs is summarized as follows:


	2006			2005				2004
	Shares	(1)		Shares		(1)		Shares	(1)
Outstanding, January 1	879,000	$	26.12	349,000		$	26.02	—	$	—
Granted	—		—	554,000			26.18	349,000		26.02
Exercised	—		—	(24,000	)		26.02	—		—
Forfeited	—		—	—			—	—		—
Expired	—		—	—			—	—		—

Outstanding, December 31	879,000	$	26.12	879,000		$	26.12	349,000	$	26.02

Options exercisable, December 31	399,000	$	26.09	81,250		$	26.02	—		—

(1)	Weighted-average exercise price


December 31, 2006			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	5.1	$	26.02	235,000	4.3	$	26.02
2005		26.18	554,000	6.5		26.18	164,000	2.4		26.18

		$26.02 –26.18	879,000	6.0	$	26.12	399,000	3.5	$	26.09

As of December 31, 2006, the SARs outstanding and the SARs exercisable had an aggregate intrinsic value (including dividend equivalents) of $2.2 million and $0.8 million, respectively.

SARs activity and statistics are summarized as follows:


($ in thousands, except prices)	2006		2005		2004
Shares vested		317,750		105,250	—
Aggregate fair value of vested shares	$	1,773	$	537	—
Cash received from exercise		—		—	—
Intrinsic value of shares exercised ¹		—	$	10	—
Tax benefit realized for the deduction of exercises		—	$	4	—
Dividend equivalent shares distributed under Section 409A		28,600		—	—
Weighted-average Section 409A distribution price	$	26.37		—	—
Intrinsic value of shares distributed under Section 409A	$	754		—	—
Tax benefit realized for Section 409A distributions	$	293		—	—

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.

138

As of December 31, 2006, there was $1.1 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 2.2 years.

No SARs were granted in 2006. The weighted-average fair value of each of the SARs granted during 2005 and 2004 was $5.82 and $5.11 (at grant date), respectively. For 2005 and 2004, the weighted-average assumptions used to estimate fair value include: risk-free interest rate of 4.1% and 3.4%, expected volatility of 18.1% and 16.7%, expected dividend yield of 5.9% and 5.8%, respectively, term of 10 years and expected life of 4.5 years for both years. The weighted-average fair value of the SARs grant is estimated on the date of grant using a Binomial Option Pricing Model. See below for discussion of 2005 grant modification. The expected volatility is based on historical price fluctuations. The Company believes that historical volatility is appropriate based upon the Company’s business model and strategies.

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 2006 a total of 71,865 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, including those that retired during 2006. 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 would be paid within 2¹/2 months after the end of the calendar year. However, upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement rather than at the end of the calendar year.

As noted above, in December 2005, to comply with Section 409A, HEI modified certain provisions pertaining to the dividend equivalent rights attributable to the outstanding grants of NQSOs and SARs held by 40 employees under the 1987 HEI Stock Option and Incentive Plan, as amended. The modifications apply to the NQSOs granted in 2001, 2002, and 2003 and the SARs granted in 2004 and 2005 and in general accelerate the distribution of dividend equivalent shares earned after 2004. When a share-based award is modified, the Company recognizes the incremental compensation cost, which is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before its terms are modified.

The assumptions used to estimate fair value at the time of the Section 409A modification for the 2005 and 2004 SARs include: risk-free interest rate of 4.4%, expected volatility of 14.9%, original term of 10 years and expected dividend yield of 4.6%. The expected life used at the time of modification was 4.2 and 3.8 years for 2005 and 2004, respectively. As of December 7, 2005, the fair value of modified 2005 SARs, the fair value of original 2005 SARs and the additional compensation cost to be recognized per grant was $5.07, $4.95 and $0.12, respectively. As of December 7, 2005, the fair value of modified 2004 SARs, the fair value of original 2004 SARs and the additional compensation cost to be recognized per grant was $4.34, $4.25 and $0.09, respectively. The additional compensation cost for the Section 409A modification was not material.

Restricted stock

Information about HEI’s restricted stock grants are summarized as follows:


	2006				2005				2004
	Shares		(1)		Shares		(1)		Shares	(1)
Outstanding, January 1	41,000		$	23.50	34,000		$	22.58	28,000	$	22.17
Granted	60,800		$	26.32	9,000			26.06	6,000		24.48
Restrictions ended	(10,000	)	$	20.65	(2,000	)		19.29	—		—
Forfeited	—			—	—			—	—		—

Outstanding, December 31	91,800		$	25.68	41,000		$	23.50	34,000	$	22.58

(1)	Weighted-average price per share at grant date

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.

In 2006, 2005 and 2004, restricted stock granted had a fair market value of $1.6 million, $0.2 million and $0.1 million, respectively. In 2006, 2005 and 2004, restricted stock vested had a fair market value of $0.2 million, nil and nil, respectively. The tax benefit realized for the tax deductions from restricted stock dividends were $0.1 million for 2006 and immaterial for 2005 and 2004.

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As of December 31, 2006, there was $1.5 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a period of 3.3 years

10 • Income taxes

The components of income taxes attributable to income from continuing operations were as follows:


Years ended December 31	2006			2005			2004
(in thousands)

Federal
Current	$	65,501		$	66,819		$	42,142
Deferred		(9,372	)		(1,226	)		15,670
Deferred tax credits, net		(1,259	)		(1,351	)		(1,446	)

		54,870			64,242			56,366

State
Current		5,848			3,586			32,809
Deferred		(1,468	)		2,619			(1,875	)
Deferred tax credits, net		3,804			3,453			5,180

		8,184			9,658			36,114

	$	63,054		$	73,900		$	92,480

A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the Company’s consolidated statements of income was as follows:


Years ended December 31	2006			2005			2004
(in thousands)

Amount at the federal statutory income tax rate	$	59,869		$	70,471		$	70,077
Increase (decrease) resulting from:
State income taxes, net of effect on federal income taxes and excluding cumulative bank franchise taxes through December 31, 2003		5,319			6,278			3,133
Cumulative bank franchise taxes through December 31, 2003		—			—			20,340
Other, net		(2,134	)		(2,849	)		(1,070	)

	$	63,054		$	73,900		$	92,480

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:


December 31	2006		2005
(in thousands)

Deferred tax assets
Cost of removal in excess of salvage value	$	93,014	$	85,292
Contributions in aid of construction and customer advances		38,582		38,406
Allowance for loan losses		12,202		11,886
Net unrealized losses on available-for-sale mortgage-related securities		23,416		24,087
Retirement Benefits in AOCI		89,394		804
Other		23,543		22,588

		280,151		183,063

Deferred tax liabilities
Property, plant and equipment		277,508		271,949
Leveraged leases		6,542		8,444
Retirement Benefits		27,886		38,545
Goodwill		12,531		10,652
Regulatory assets, excluding amounts attributable to property, plant and equipment		28,495		27,588
FHLB stock dividend		20,552		20,552
Other		13,417		13,330

		386,931		391,060

Net deferred income tax liability	$	106,780	$	207,997

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon historical taxable income,

140

projections for future taxable income and available tax planning strategies, management believes it is more likely than not the Company will realize substantially all of the benefits of the deferred tax assets.

In the first quarter of 2005, the Company recorded a $2 million reserve, net of taxes, for interest the Company might incur on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends. In the second quarter of 2005, the Company made a $30 million deposit primarily to stop the further accrual of interest on the potential taxes related to the disputed timing of dividend income recognition. Also in the second quarter of 2005, $1 million of income taxes and interest payable, net of taxes, were reversed due to the resolution of other audit issues with the IRS. In the fourth quarter of 2005, additional IRS audit issues were resolved, resulting in the reversal of $1 million of interest expense, net of taxes.

As of December 31, 2006, $1 million, net of tax effects, was accrued for potential tax issues and related interest. Although not probable, adverse developments on potential tax issues could result in additional charges to net income in the future. Based on information currently available, the Company believes it has adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

ASB state franchise tax dispute and settlement. In 1998, ASB formed a subsidiary, ASB Realty Corporation, which elected to be taxed as a real estate investment trust (REIT). This reorganization had reduced Hawaii bank franchise taxes as a result of ASB taking a dividends received deduction on dividends paid to it by ASB Realty Corporation. The State of Hawaii Department of Taxation (DOT) challenged ASB’s position on the dividends received deduction and issued notices of tax assessment for 1999 through 2001. ASB filed an appeal with the State Board of Review, First Taxation District (Board), which issued its decision in favor of the DOT. ASB filed a notice of appeal with the Hawaii Tax Appeal Court, which issued its decision in favor of the DOT in June 2004. As a result of the decision, ASB recorded a cumulative after-tax charge to net income in the second quarter of 2004 of $24 million ($21 million for the bank franchise taxes and $3 million for interest). ASB appealed the decision to the Hawaii Supreme Court, which appeal was dismissed as part of a settlement on December 31, 2004. ASB agreed to settle its dispute with the DOT and close the tax years 1999 through 2004 (relating to the financial performance of ASB for the years 1998 through 2003) for purposes of audit, examination, assessment, refund and judicial review. Under the terms of the settlement, ASB agreed to pay the DOT $12 million, in addition to $17 million previously paid under protest, dismiss its appeal to the Hawaii Supreme Court and not take the dividends received deduction in future years. As a result, ASB recognized $3 million in additional net income in the fourth quarter of 2004, representing a partial reversal of the $24 million previously charged against net income. ASB Realty Corporation was dissolved in the second quarter of 2005, with substantially all of its assets being distributed to ASB.

11 • Cash flows

Supplemental disclosures of cash flow information. In 2006, 2005 and 2004, the Company paid interest to non-affiliates amounting to $214 million, $192 million and $185 million, respectively.

In 2006, 2005 and 2004, the Company paid income taxes amounting to $69 million, $45 million and $42 million, respectively.

Supplemental disclosures of noncash activities. Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $5 million in 2004. Since March 2004, HEI has been satisfying 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 December 15, 2006, however, the HEI Board of Directors determined that the common stock requirements for the HEI DRIP and HEIRSP will be satisfied by issuance of new HEI shares, commencing in March 2007.

In 2006, 2005 and 2004, other noncash increases in common stock for director and officer compensatory plans were $3 million, $5 million and $3 million, respectively.

In 2006, 2005 and 2004, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $6 million, $5 million and $6 million, respectively.

141

In 2006, 2005 and 2004, the estimated fair value of noncash contributions in aid of construction amounted to $14 million, $12 million and $5 million, respectively.

In 2004, ASB financed $6 million of sales of real estate acquired in settlement of loans.

In 2006, the Company completed the settlement of net taxes and interest due to the IRS for tax years 1994 through 2002. In a non-cash transaction in 2006, a $30 million deposit made by the Company in 2005 with the IRS was applied to the net liabilities of $10 million for tax years 1994 through 2002 and $18 million for tax year 2005 with an immaterial net income impact. The remaining $2 million of the 2005 deposit was refunded to the Company.

Revised cash flows from discontinued operations. From December 31, 2005, the Company will separately disclose the operating, investing and financing portions of the cash flows attributable to its discontinued operations, which were previously reported on a combined basis as a single amount.

12 • Regulatory restrictions on net assets

As of December 31, 2006, HECO and its subsidiaries could not transfer approximately $431 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.

ASB is required to file a notice with the OTS 30 days prior to making any capital distribution to HEI. Generally, the OTS may disapprove or deny ASB’s notice of intention to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statute, regulation, or agreement between ASB and the OTS. As of December 31, 2006, ASB could transfer approximately $172 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.

HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

13 • Significant group concentrations of credit risk

Most of the Company’s business activity is with customers located in the State of Hawaii. Most of ASB’s financial instruments are based in the State of Hawaii, except for the investment and mortgage-related securities it owns. Substantially all real estate loans receivable are secured by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination. As of December 31, 2006, ASB’s private-issue mortgage-related securities represented whole or participating interests in pools of mortgage loans collateralized by real estate in the U.S. As of December 31, 2006, various securities rating agencies rated the private-issue mortgage-related securities held by ASB as investment grade.

14 • Discontinued operations

HEI Power Corp. (HEIPC). In 2001, the HEI Board of Directors adopted a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries, the HEIPC Group). HEIPC management has carried out a program to dispose of all of the HEIPC Group’s remaining projects and investments. Accordingly, the HEIPC Group (other than HEI Investment, Inc. (HEIII)) has been reported as a discontinued operation in the Company’s consolidated statements of income. HEIPC was dissolved in December 2006. Prior to the dissolution, HEIPC transferred its ownership interests in HEIII to HEI and HEI Diversified, Inc. (HEIDI).

China project. In 1998 and 1999, the HEIPC Group acquired what became a 75% interest in a joint venture, Baotou Tianjiao Power Co., Ltd., formed to construct, own and operate a 200 MW (net) coal-fired power plant to be located in Inner Mongolia. The project received approval from both the national and Inner Mongolia governments. However, the Inner Mongolia Power Company, which owns and operates the electricity grid in Inner Mongolia, caused a delay of the project by failing to enter into a satisfactory interconnection arrangement with the joint venture. The HEIPC Group determined that a satisfactory interconnection arrangement could not be obtained and did not proceed with the project. In the third quarter of 2001, the HEIPC Group wrote off its remaining investment of approximately $24 million in the project. In 2004, the HEIPC Group negotiated with various government agencies a partial recovery of its interest in the China joint venture in the amount of $3 million and recorded a gain, net of income taxes, of $2 million. The HEIPC Group pursued recovery of a significant portion of its losses through arbitration of its claims under a political risk insurance policy. In 2005, the arbitration panel issued its decision denying HEIPC’s claims for recovery of losses under the political risk insurance policy.

142

Philippines investment. In 1998 and 1999, the HEIPC Group invested $10 million to acquire shares in Cagayan Electric Power & Light Co., Inc. (CEPALCO), an electric distribution company in the Philippines. The HEIPC Group recognized impairment losses of approximately $3 million in 2001 and $5 million in 2003 to adjust this investment to its estimated net realizable value at the time of approximately $7 million and $2 million, respectively. In the first quarter of 2004, the HEIPC Group sold HEIPC Philippine Development, LLC, the HEIPC Group company that held an interest in CEPALCO, for a nominal gain.

Summary financial information for the discontinued operations of the HEIPC Group is as follows:


Years ended December 31	2006		2005			2004
(in thousands)

Disposal
Gain (loss), including a provision of $1 million for losses from operations during phase-out period in 2006, 2005 and 2004	$	—	$	(1,237	)	$	2,878
Income tax benefits (income taxes)		—		482			(965	)

Gain (loss) on disposal	$	—	$	(755	)	$	1,913

As of December 31, 2006, the remaining net assets of the discontinued international power operations amounted to $2 million (included in “Other” assets) and consisted primarily of deferred taxes receivable.

15 • Fair value of financial instruments

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

Cash and equivalents and federal funds sold. The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities. Fair value was based on market prices obtained from a third party financial services provider.

Loans receivable. For certain homogenous categories of loans, such as residential real estate loans, an asset/liability simulation model was used to estimate fair value. Whenever possible, observable market prices for securities backed by similar loans were used as benchmarks to calibrate the model. The fair value of other types of loans was estimated by discounting the future cash flows using the current rates at which similar loans would be made to borrowers with similar credit ratings and for the same remaining maturities.

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

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

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

Off-balance sheet financial instruments. The fair value of loans serviced for others was estimated as the net present value of expected net income streams generated from servicing residential mortgage loans for others. The fair value of commitments to originate loans and unused lines of credit was estimated based on the primary market prices of new commitments and new lines of credit. The change in current primary market prices provided the estimate of the fair value of these commitments and unused lines of credit. The fair values of other off-balance sheet financial instruments (letters of credit) were estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

143

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


December 31 (in thousands)	2006				2005
December 31 (in thousands)	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value
Financial assets
Cash and equivalents	$	177,630	$	177,630	$	151,513	$	151,513
Federal funds sold		79,671		79,671		57,434		57,434
Available-for-sale investment and mortgage-related securities		2,367,427		2,367,427		2,629,351		2,629,351
Investment in stock of Federal Home Loan Bank of Seattle		97,764		97,764		97,764		97,764
Loans receivable, net		3,780,461		3,739,223		3,566,834		3,534,583
Financial liabilities
Deposit liabilities		4,575,548		4,557,418		4,557,419		4,532,420
Other bank borrowings		1,568,585		1,566,571		1,622,294		1,617,198
Long-term debt		1,133,185		1,170,657		1,142,993		1,185,174
Off-balance sheet items
Loans serviced for others		323,631		4,218		358,565		4,611
HECO-obligated preferred securities of trust subsidiary		50,000		50,800		50,000		51,400

As of December 31, 2006 and 2005, loan commitments and unused lines and letters of credit had carrying amounts of $1.1 billion and $1.1 billion and the estimated fair value was $0.1 million and $0.6 million, respectively.

Limitations. The Company makes fair value estimates at a specific point in time, based on relevant market information and information about the financial instrument. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a significant portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

144

16 • Quarterly information (unaudited)

Selected quarterly information was as follows:


	Quarters ended									Years ended December 31
(in thousands, except per share amounts)	March 31		June 30			Sept. 30		Dec. 31		Years ended December 31
2006
Revenues ^{1, 2}	$	574,962	$	604,969		$	673,894	$	607,079	$	2,460,904
Operating income ^{1, 2}		69,151		60,729			66,356		43,160		239,396
Net income (loss) ^{1, 2}		32,337		27,224			32,323		16,117		108,001
Basic earnings (loss) per common share ³		0.40		0.34			0.40		0.20		1.33
Diluted earnings (loss) per common share ⁴		0.40		0.33			0.40		0.20		1.33
Dividends per common share		0.31		0.31			0.31		0.31		1.24
Market price per common share ⁵
High		27.26		27.92			28.94		28.18		28.94
Low		25.71		25.69			26.07		26.50		25.69

2005
Revenues	$	472,628	$	522,262		$	595,915	$	624,759	$	2,215,564
Operating income ⁶		56,671		61,449			77,239		76,063		271,422
Net income (loss) ⁶
Continuing operations		24,095		28,335			37,490		37,524		127,444
Discontinued operations		—		(755	)		—		—		(755	)

		24,095		27,580			37,490		37,524		126,689

Basic earnings (loss) per common share ³
Continuing operations		0.30		0.35			0.46		0.46		1.58
Discontinued operations		—		(0.01	)		—		—		(0.01	)

		0.30		0.34			0.46		0.46		1.57

Diluted earnings (loss) per common share ⁴
Continuing operations		0.30		0.35			0.46		0.46		1.57
Discontinued operations		—		(0.01	)		—		—		(0.01	)

		0.30		0.34			0.46		0.46		1.56

Dividends per common share		0.31		0.31			0.31		0.31		1.24
Market price per common share ⁵
High		29.79		27.45			28.76		28.50		29.79
Low		24.60		24.69			26.21		25.50		24.60

¹	For 2006, amounts include interim rate relief for HECO.

²	The fourth quarter of 2006 includes an electric utility adjustment for quarterly rate schedule tariff reconciliation that relates to prior quarters.

³	The quarterly basic earnings (loss) per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.

⁴	The quarterly diluted earnings (loss) per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter plus the dilutive incremental shares at quarter end.

⁵	Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape.

⁶	For 2005, amounts for the fourth quarter include interim rate relief for HECO and a $9 million net gain on the sale of an interest in a trust that is the owner/lessor of a 60% interest in a electric generating plant in Georgia.

145

[KPMG letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Hawaiian Electric Industries, Inc.:

We have audited the accompanying consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), Share-Based Payment, and, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Hawaiian Electric Industries, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Honolulu, Hawaii

February 28, 2007

146

HECO:

The information required by this item is incorporated herein by reference to pages 4 to 44 of HECO Exhibit 99.4.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

HEI and HECO:

None

ITEM 9A.

CONTROLS AND PROCEDURES

HEI:

Disclosure Controls and Procedures

The discussion below under “HECO – Disclosure Controls and Procedures” and “Remediation” is incorporated herein by reference. The incorporated material describes a material weakness in HECO’s design of its internal control over financial reporting that was also an HEI material weakness. The material weakness was remediated in the fourth quarter as described in the incorporated information.

Changes in Internal Control Over Financial Reporting

Except for changes subsequent to September 30, 2006, in connection with the remediation of the material weakness (identified above), during the fourth quarter of 2006, 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 December 31, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of December 31, 2006. Based on their evaluations, as of December 31, 2006, 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.

147

Annual Report of Management on Internal Control Over Financial Reporting

The Board of Directors and Shareholders

Hawaiian Electric Industries, Inc.:

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control system was designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of its consolidated financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2006.

KPMG LLP, an independent registered public accounting firm, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting as of December 31, 2006. This report appears on page 149.


/s/ Constance H. Lau	/s/ Eric K. Yeaman	/s/ Curtis Y. Harada
Constance H. Lau	Eric K. Yeaman	Curtis Y. Harada
President and Chief Executive Officer	Financial Vice President, Treasurer and Chief Financial Officer	Controller and Chief Accounting Officer

February 28, 2007

148

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors and Shareholders

Hawaiian Electric Industries, Inc.:

We have audited management’s assessment, included in the accompanying annual report of management on internal control over financial reporting, that Hawaiian Electric Industries, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Hawaiian Electric Industries, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Hawaiian Electric Industries, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also, in our opinion, Hawaiian Electric Industries, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Honolulu, Hawaii

February 28, 2007

149

HECO:

Disclosure Controls and Procedures

As of September 30, 2006 HECO’s management, including its Chief Executive Officer and Chief Financial Officer, reviewed and evaluated the effectiveness of HECO's disclosure controls and procedures pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934. Based on that review and evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the HECO's disclosure controls and procedures were effective as of September 30, 2006, as disclosed in its SEC Form 10-Q for the quarterly period ended September 30, 2006.

Subsequent to the filing of the Form 10-Q for the quarterly period ended September 30, 2006, management identified a material weakness as of September 30, 2006 in the design of its internal control over financial reporting relating to the assessment of the results of quarterly reconciliations required under the provisions of one of the rate schedules in HECO and its subsidiaries tariffs. The material weakness did not result in a material misstatement (quantitatively and qualitatively) of the financial statements as of and for the period ended September 30, 2006. However, the absence of a review of the quarterly reconciliation prior to the issuance of its September 30, 2006 financial statements resulted in an immaterial misstatement and created a more than remote likelihood that a material misstatement of the interim financial statements would not be prevented or detected on a timely basis.

HECO and its subsidiaries prepared the required quarterly reconciliations under their tariffs in the month following the end of the quarterly period ended September 30, 2006. However, the reconciliations were not reviewed prior to the issuance of HECO’s consolidated financial statements. An appropriate review of the reconciliations at the end of each quarterly period will serve to identify potential misstatements of HECO’s consolidated financial statements on a timely basis. Management determined that the absence of a timely and appropriate review of the reconciliation was a material weakness in internal control over financial reporting as of September 30, 2006.

Remediation

In order to address this material weakness, HECO and its subsidiaries instituted a control that requires the review of the quarterly reconciliations under their tariffs to occur prior to the issuance of its financial statements and the inclusion of any adjustments resulting from those reconciliations in the results of operations for the quarter, whether or not material. This control was implemented in the quarter ended December 31, 2006 and has been reviewed, tested and determined to be designed and operating effectively at December 31, 2006.

Changes in Internal Control over Financial Reporting

Except for the changes subsequent to September 30, 2006 in connection with the remediation described above, there have been no changes in HECO's internal control over financial reporting that occurred during the quarter ended December 31, 2006, that have materially affected or are reasonably likely to affect the company's internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

T. Michael May, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of December 31, 2006. Based on their evaluations, as of December 31, 2006, 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

The “Annual Report of Management on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting” required by this item are incorporated herein by reference to pages 2 and 3, respectively, of HECO Exhibit 99.4.

150

ITEM 9B.

OTHER INFORMATION

HEI: None

HECO:

The Board of Directors of HECO approved, at its meeting on February 26, 2007, an amendment to Article III (Board of Directors), Section 12 of the Bylaws of HECO, effective February 26, 2007, and the restatement of the Bylaws as thus amended. Prior to the amendment, Section 12 of the Bylaws provided that any action required or permitted to be taken at any meeting of the Board of Directors, or a committee of the Board of Directors, may be taken if all of the members of the Board of Directors or committee, as the case may be, sign a written consent setting forth the action taken and the effective date of that action. The revision to Section 12 allows the members of the Board of Directors or committee to provide their written consent via electronic transmission, provided the consent is submitted with information from which it may be determined that the electronic transmission was authorized by the proper director or committee member.

The Bylaws, amended and restated in their entirety to incorporate this amendment to Article III, Section 12, is included as HECO Exhibit 3(ii).

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

HEI:

Information for this item concerning the executive officers of HEI is set forth at the end of Item 4 of this report. Information on the current HEI directors and their business experience and directorships is incorporated herein by reference to the sections relating to director nominees and continuing directors in HEI’s 2007 Proxy Statement. The information on the HEI Audit Committee and the HEI Board’s determination of HEI’s Audit Committee financial experts and their names are incorporated herein by reference to the section relating to Committees of the Board and the relevant information in the section relating to the Audit Committee Report in HEI’s 2007 Proxy Statement. No other portion of the “Audit Committee Report” is incorporated by reference.

Family relationships; director arrangements

There are no family relationships between any director of HEI and any executive officer or director of HEI or any arrangement or understanding between any director of HEI and any person, pursuant to which such director was selected.

Code of Conduct

Information on HEI’s Code of Conduct is incorporated herein by reference to the section on corporate governance in HEI’s 2007 Proxy Statement. In connection with its periodic review of corporate governance trends and best practices, on January 30, 2007, the HEI Board adopted a Revised Code of Conduct, including the code of ethics for, among others, the CEO, senior financial officers and senior accounting officers of HEI, which may be viewed under “Corporate Governance” on HEI’s website at www.hei.com. HEI also elects to disclose the information required by Form 8-K, Item 5.05, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through this website and such information will remain available on this website for at least a 12-month period. A copy of the Revised Code of Conduct may be obtained free of charge upon written request from the HEI Vice President-Administration & Corporate Secretary, P.O. Box 730, Honolulu, Hawaii 96808-0730.

Section 16(a) beneficial ownership reporting compliance

Information required to be reported under this caption is incorporated herein by reference to the section relating to stock ownership in HEI’s 2007 Proxy Statement.

151

HECO:

Executive officers

The following persons are, or may be deemed to be, executive officers of HECO. Their ages are given as of February 28, 2007, their years of company service are given as of December 31, 2006 and their business experience is given for the past five years. Executive officers are appointed to serve until the meeting of the HECO Board of Directors (HECO Board) after the next HECO Annual Meeting (or written consent of sole shareholder, which is expected in April 2007) and/or until their respective successors have been appointed and qualified (or until their earlier resignation or removal). Company service includes service with HECO affiliates.


HECO Executive Officers
Constance H. Lau, age 54 (Company service: 22 years)
Chairman of the Board of HECO		5/06 to date
President and Chief Executive Officer of HEI		5/06 to date
Chairman of the Board of ASB		5/06 to date
President and Chief Executive Officer of ASB		6/01 to date

T. Michael May, age 60 (Company service: 14 years)
President, Chief Executive Officer and Director of HECO		9/95 to date
Chairman of the Board, MECO and HELCO		9/95 to date

Robert A. Alm, age 55 (Company service: 5 years)
Senior Vice President – Public Affairs		7/01 to date

Thomas L. Joaquin, age 63 (Company service: 33 years)
Senior Vice President – Operations		7/01 to date

Karl E. Stahlkopf, age 66 (Company service: 4 years)
Senior Vice President – Energy Solutions and Chief Technology Officer		5/02 to date
Karl E. Stahlkopf, prior to joining HECO, served as Vice President – Power Delivery and Utilization of the Electric Power Research Institute from 1/01 to 5/02.

William A. Bonnet, age 63 (Company service: 21 years)
Vice President – Government & Community Affairs		5/01 to date

Amy E. Ejercito, age 48 (Company service: 18 years)
Vice President – Corporate Excellence		1/05 to date
Manager, Customer Service		5/00 to 12/04

Jackie Mahi Erickson, age 66 (Company service: 25 years)
Vice President – General Counsel		3/03 to date
Vice President – Customer Operations & General Counsel		10/98 to 3/03

Harold K. Kageura, age 54 (Company service: 20 years)
Vice President – Energy Delivery		9/04 to date
Manager, Construction & Maintenance		2/02 to 09/04
Manager, Power Supply Operations & Maintenance		4/96 to 2/02

Tayne S.Y. Sekimura, age 44 (Company service: 15 years)
Financial Vice President		10/04 to date
Assistant Financial Vice President		8/04 to 10/04
Director, Corporate & Property Accounting		2/01 to 8/04

Thomas C. Simmons, age 58 (Company service: 35 years)
Vice President – Power Supply		2/02 to date
Manager, Power Supply		7/95 to 2/02

152


HECO Executive Officers		Business experience for past five years
(continued)

Lynne T. Unemori, age 47 (Company service: 21 years)
Vice President – Corporate Relations		07/06 to date
Director, Corporate Communications		12/00 to 07/06

David G. Waller, age 58 (Company service: 17 years)
Vice President – Customer Solutions		6/04 to date
Manager, Energy Services		4/99 to 6/04

Lorie Ann K. Nagata, age 48 (Company service: 24 years)
Treasurer		12/00 to date
Manager, Management Accounting		5/98 to date

Patsy H. Nanbu, age 47 (Company service: 20 years)
Controller		5/05 to date
Assistant Controller		2/05 to 5/05
Director, Regulatory Affairs		10/01 to 2/05

Molly M. Egged, age 56 (Company service: 26 years)
Secretary		10/89 to date

HECO executive officers T. Michael May, Karl E. Stahlkopf, William A. Bonnet, Tayne S.Y. Sekimura, Lorie Ann K. Nagata, Patsy H. Nanbu and Molly M. Egged are also officers and/or directors of MECO, HELCO and/or Renewable Hawaii, Inc. HECO executive officers Constance H. Lau and Molly M. Egged are also officers of one or more of the affiliated nonutility HEI companies, including HEI and ASB.

In February 2006, Constance H. Lau, President and CEO of ASB, was named to succeed Robert F. Clarke as Chairman of the HECO Board, effective May 2, 2006.

Board

The following serve on the HECO Board as of February 28, 2007.


Director	Age	Director since [2]
Constance H. Lau	54	2006
T. Michael May	60	1995
David C. Cole	54	2006
Thomas B. Fargo [1]	58	2005
Timothy E. Johns [1]	51	2005
Bert A. Kobayashi, Jr.	36	2006
David M. Nakada	55	2005
James K. Scott	55	1999
Anne M. Takabuki [1]	50	1997
Kelvin H. Taketa	52	2004
Barry K. Taniguchi [1]	59	2001

[1]	Audit committee member.

[2]	Year indicates first year elected or appointed. All directors are elected for one year terms.

David C. Cole, Timothy E. Johns, Bert A. Kobayashi, Jr., David M. Nakada, and Anne M. Takabuki are the only nonemployee directors of HECO who are not also directors of HEI. Constance H. Lau, Thomas B. Fargo, James K. Scott, Kelvin H. Taketa, and Barry K. Taniguchi are each directors of both HECO and HEI. Information concerning the directors of HECO who are also directors of HEI is incorporated herein by reference to the information set forth above under “HEI” and in HEI’s 2007 Proxy Statement.

Mr. Cole has been President and CEO of Maui Land & Pineapple Company, Inc. (MLP) since 2003 and its Chairman since 2004. MLP is a land holding and operating company dedicated to agriculture, resort operation and the creation and management of holistic communities. From 1996 – 2006, he was Chairman of Sunnyside Farms, LLC, a retailer of luxury goods based on a diversified organic farm serving mid-Atlantic fresh food markets. He

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serves on a number of nonprofit boards, including The Nature Conservancy of Hawaii, Sesame Workshop and the Chancellor’s Advisory Committee of Maui Community College.

Mr. Johns has been the Chief Operating Officer of the Estate of Samuel Mills Damon, a Hawaii-based private trust, primarily managing a diversified investment portfolio, including real estate assets in Hawaii, since 2000. He serves as an at-large member of the State Board of Land and Natural Resources and is Chair of the Federal Northwestern Hawaiian Islands Coral Reef Ecosystem Reserve Advisory Council. He also sits on the boards of several community organizations, including the YMCA of Honolulu, Hawaii Nature Center, Child and Family Service, Helping Hands Hawaii and St. Andrew’s Priory.

Mr. Kobayashi has been President and CEO of Kobayashi Group, LLC, a real estate development and investment company, since 2000. He is a trustee of The Nature Conservancy of Hawaii and The Contemporary Museum as well as co-founder of The GIFT (Giving Inspiration For Tomorrow) Foundation of Hawaii, a volunteer organization whose mission is to encourage young adults to participate in philanthropic giving.

Mr. Nakada has been the Executive Director of the Boys & Girls Club of Hawaii, an eleemosynary youth guidance, primary prevention organization, since 1979. He serves on the Board of the Hawaii Community Foundation.

Ms. Takabuki has been President of Wailea Golf LLC, owner/operator of golf courses, since October 1, 2003. At Wailea Golf Resort, Inc. she was President from March 2003 to September 2003 and Vice President/Secretary and General Counsel from 1993 to February 2003. She also serves on the boards of Wailea Community Association and Kapiolani Health Foundation.

Director independence

For a HECO director to be considered independent, the HECO Board must affirmatively determine that the director does not have any direct or indirect material relationship with HEI or its subsidiaries. For 2006, the HECO Board followed the New York Stock Exchange (NYSE) Listed Company Manual standards for determining director independence.

In its annual review of director independence, the HECO Board affirmatively determined that all directors of HECO are independent with the exception of Constance H. Lau and T. Michael May, who are both employee directors.

With respect to each of the nonemployee directors, the HECO Board considered the relationships between HECO and the nonemployee directors, including transactions with organizations with which the nonemployee directors are affiliated, other boards on which the nonemployee directors serve, any related person transactions, and Company charitable contributions.

In particular, the HEI Nominating and Corporate Governance Committee, which is charged with reviewing and approving (if the relationship is determined to be not inconsistent with the best interest of HEI, its subsidiaries or shareholders and is not in violation with the HEI’s Code of Conduct) relationships that may impact director independence, and the HECO Board considered the following relationships:

•

The HECO Board considered the amount of electricity purchased from the electric utility subsidiaries by the nonemployee HECO directors or their respective places of employment and any transactions related to ASB of the nonemployee HECO directors or their respective places of employment.

•

With respect to director Kelvin H. Taketa, the HECO Board considered the amount of charitable contributions HEI and its subsidiaries made to the Hawaii Community Foundation, for which Mr. Taketa serves as CEO.

•

With respect to director Bert A. Kobayashi, Jr., the HECO Board considered the position and compensation of his father, Bert A. Kobayashi, who is a director of ASB, a subsidiary of HEI and sister company of HECO, and the nature and extent of related party transactions between Bert A. Kobayashi, Jr. and ASB.

•

With respect to director David M. Nakada, the HECO Board considered the amount of charitable contributions HEI and its subsidiaries made to the Boys and Girls Club of Hawaii, for which Mr. Nakada serves as Executive Director.

•

With respect to director James K. Scott, the HECO board considered the amount of charitable contributions HEI and its subsidiary companies made to Punahou School, for which Dr. Scott serves as President.

In addition, the HECO Board also determined that HECO did not make contributions in 2006 to any tax exempt

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organization in which an independent director serves as an executive officer that exceeded the greater of $1 million, or 2% of such tax exempt organization’s consolidated gross revenues in 2006.

The HECO Board determined that the above relationships do not interfere with the directors’ independent judgment on matters concerning HECO. HECO directors understand that they should never act in a manner that would cause them to lose their independence and objectivity or that could adversely affect confidence in the integrity of HEI or its subsidiaries. HECO directors have agreed to recuse themselves from any discussions or decision-making on any matter involving the organizations with which they are affiliated or other significant relationships.

Audit Committee of the HECO Board

During 2006, the HECO Board had one standing committee, the Audit Committee. The current members of HECO’s Audit Committee are nonemployee directors Barry K. Taniguchi, Chairman, Thomas B. Fargo, Timothy E. Johns, and Anne M. Takabuki.

The HECO Audit Committee operates and acts under a written charter, which was adopted and approved by the HECO Board. The Committee provides independent and objective oversight of HECO’s (1) financial reporting processes, (2) audits of the financial statements, including appointment, compensation and oversight of the external auditor, (3) internal controls and (4) risk assessment and risk management policies set by management. The HECO Audit Committee also approves or disapproves related party transactions and reviews and resolves complaints from any employee regarding accounting, internal controls or auditing matters.

The HECO Audit Committee holds such meetings as it deems advisable to review the financial operations of HECO. In 2006, the HECO Audit Committee held five meetings to review various matters with management, the internal auditor and KPMG LLP (HECO’s independent registered public accounting firm), including the activities of the internal auditor, the results of the annual audit of HECO by KPMG LLP and the consolidated financial statements which are incorporated herein by reference to HECO Exhibit 99.4.

All members of the HECO Audit Committee are independent directors as independence for audit committee members is defined in the listing standards of the NYSE Listed Company Manual and the listing standards relating to Audit Committees set forth in the Securities Exchange Act of 1934. None of the members of the HECO Audit Committee are members of audit committees of any other publicly traded company, except that Admiral Fargo and Mr. Taniguchi are members of the HEI Audit Committee. Barry K. Taniguchi, Timothy E. Johns and Anne M. Takabuki have been determined by the HECO Board to be the HECO “audit committee financial experts.”

HECO Board interlocks and insider participation

The HECO Board has no subcommittee devoted to compensation matters. The entire HECO Board serves as the Compensation Committee for HECO. The HECO Board is responsible for establishing HECO executive compensation. The HEI Compensation Committee is charged with providing the staffing to the subsidiaries for the overall, comprehensive evaluation and establishment of executive compensation for HEI and its subsidiaries. Decisions of the HEI Compensation Committee and HECO Board on compensation matters are also approved by the HEI Board.

T. Michael May, President and CEO of HECO, is a member of the HECO Board. He is responsible for the evaluation (based on performance goals and subjective measures) of the vice presidents of HECO and recommendation to the HEI Compensation Committee of the merit increases for the HECO officers. He also recommends to the HEI Compensation Committee the financial and operational performance measures for HECO officers for the annual incentive plan.

Constance H. Lau, Chairman of HECO and President and CEO of HEI since May 2006, is a member of the HECO Board. She is responsible for the evaluation of Mr. May’s performance and recommendation of Mr. May’s merit increase in 2007 and onward. In 2006, Robert F. Clarke, then Chairman of HECO and President and CEO of HEI, was responsible for the evaluation of Mr. May’s performance and recommendation of Mr. May’s 2006 merit increase.

Messrs. Clarke and May and Ms. Lau have no HECO transactions which require disclosure under Rule 404, Transactions with Related Persons, Promoters and Certain Control Persons, of the Securities Exchange Act of 1934.

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Information regarding the HEI Compensation Committee Interlocks and Insider Participation is incorporated herein by reference to the 2007 HEI Proxy Statement.

Attendance at meetings

In 2006, there were six regular and three special meetings of the HECO Board. All incumbent directors attended at least 75% of the combined total number of meetings of the Board and (if applicable) the HECO Audit Committee during the period of their service, except David C. Cole and Anne M. Takabuki.

Family relationships; executive officer and director arrangements

There are no family relationships between any executive officer or director of HECO and any other executive officer or director of HECO, or any arrangement or understanding between any executive officer or director of HECO and any person pursuant to which the executive officer or director of HECO was selected.

There is a family relationship between a director of HECO, Bert A. Kobayashi, Jr. and a director of ASB, Bert A. Kobayashi. ASB is a subsidiary of HEI, and a sister company of HECO. Bert A. Kobayashi, Jr., President and CEO of the Kobayashi Group, LLC, was elected to the HECO Board on July 24, 2006. Bert A. Kobayashi, the Chairman and CEO of the Kobayashi Development Group LLC, has been a director of ASB since 2002. Bert A. Kobayashi is the father of Bert A. Kobayashi, Jr.

Code of Conduct

In connection with its periodic review of corporate governance trends and best practices, on January 30, 2007, the HEI Board adopted a Revised Code of Conduct, including the code of ethics for, among others, the CEO, senior financial officers and senior accounting officers of HECO, which may be viewed under “Corporate Governance” on HEI’s website at www.hei.com. HECO also elects to disclose the information required by Form 8-K, Item 5.05, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through this website and such information will remain available on this website for at least a 12-month period. A copy of the Revised Code of Conduct may be obtained free of charge upon written request from the HEI Vice President-Administration & Corporate Secretary, P.O. Box 730, Honolulu, Hawaii 96808-0730.

Section 16(a) beneficial ownership reporting compliance

Information required to be reported under this caption is incorporated herein by reference to the section relating to stock ownership in HEI’s 2007 Proxy Statement.

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ITEM 11.

EXECUTIVE COMPENSATION

HEI:

The information required under this item for HEI is incorporated herein by reference to the information relating to the HEI Board, Committees of the Board and executive compensation in HEI’s 2007 Proxy Statement.

HECO:

As T. Michael May is deemed an executive officer of HEI and certain directors of HECO are also directors of HEI, information required under this item for HECO, in addition to that set forth below, is incorporated herein by reference to the information relating to the HECO Board, Committees of the Board and executive compensation in HEI’s 2007 Proxy Statement.

Executive compensation

HECO Board and HEI Compensation Committee Report

The HECO Board and the Compensation Committee of the HEI Board (HEI Compensation Committee) evaluate and establish compensation for the HECO executives. Management has the primary responsibility for HECO’s financial statements and reporting process, including the disclosure of executive compensation. The HECO Board and the HEI Compensation Committee have reviewed and discussed with management the Compensation Discussion and Analysis that follows. The HECO Board and the HEI Compensation Committee are satisfied that the Compensation Discussion and Analysis fairly and completely represents the philosophy, intent, and actions of the HECO Board and HEI Compensation Committee with regard to executive compensation. The HEI Compensation Committee recommended, and the HECO Board and HEI Board concurred, that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for filing with the Securities and Exchange Commission.

SUBMITTED BY THE HECO BOARD OF DIRECTORS

Constance H. Lau, Chair

David C. Cole

Thomas B. Fargo

Timothy E. Johns

Bert A. Kobayashi, Jr.

T. Michael May

David M. Nakada

James K. Scott

Anne M. Takabuki

Kelvin H. Taketa

Barry K. Taniguchi

AND SUBMITTED BY THE COMPENSATION COMMITTEE OF

THE HEI BOARD OF DIRECTORS

Bill D. Mills, Chair

Don E. Carroll

Victor H. Li

A Maurice Myers

Diane J. Plotts

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Compensation Discussion and Analysis

The compensation processes

The HECO Board is responsible under the By-laws of HECO for determining the salaries and compensation of all HECO executives, including the HECO Named Executive Officers (NEOs) (the individuals named in the Summary Compensation Table below: Messrs. May, Alm, Joaquin and Stahlkopf and Ms. Sekimura). The authority to fix the salaries and compensation of executives other than his own position may be delegated by the HECO Board to the HECO President and CEO.

The HEI Compensation Committee has the responsibility for recommending the total compensation program for HEI and its subsidiaries, subject to the approval of the HEI and HECO Boards, as the case may be. The HEI Compensation Committee engages Towers Perrin, an independent compensation consultant, to provide the Committee with objective, independent advice and a full complement of technical, financial, industry and business data with respect to benchmarking, peers and best practices. Towers Perrin may also work collaboratively with management to support the Committee’s objective in serving the best interest of HEI and its shareholders. Decisions of the HEI Compensation Committee and HECO Board on compensation matters are also approved by the HEI Board.

The HEI Compensation Committee and the HECO Board reserve the right to amend, suspend or terminate incentive programs or any other executive compensation. In 2006, the HEI Compensation Committee determined that there should be no 2004-2006 LTIP payout solely by reason of the application of Financial Accounting Standard No. 158 (relating to retirement benefit plans), which resulted in a charge to equity and therefore increased the Return on Average Common Equity (ROACE).

The HEI Compensation Committee and the HECO Board have used the following processes to evaluate, further develop and/or improve HECO’s executive compensation programs.

•

Review of HECO Performance. The HEI Compensation Committee and the HECO Board review current performance and results and the proposed objectives and goals for the current and following year. Changes are considered to increase the effectiveness of the executive compensation program.

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Review of Individual Performance. The HEI Compensation Committee and HECO Board receive a performance assessment and compensation recommendation regarding Mr. May from the HEI President and CEO. The HECO Board also considers HECO’s overall performance and interactions with Mr. May, the achievement of Mr. May’s goals and objectives, and his overall contribution to HECO’s performance. For the other HECO NEOs, the HEI Compensation Committee and the HECO Board receive a performance assessment and compensation recommendation from Mr. May. The performance evaluations of these executives are based on achievement of pre-established objectives, his or her contribution to HECO’s performance, and other accomplishments.

•

Benchmarking. Because utility industry experience is highly specialized, the HEI Compensation Committee and HECO Board periodically benchmark HECO’s compensation programs against a peer group of national utility companies recommended by Towers Perrin and approved by the HEI Compensation Committee and HECO Board. These companies (Benchmark Peer Group) are considered comparable companies for competitors for labor, are comparable in size, and are industry specific. This peer group includes Allegheny Energy, Inc., Ameren Corp., Aquilla Inc., Avista Corp., Constellation Energy Group Inc., Northeast Utilities, NSTAR, OGE Energy Corporation, Peoples Energy Corp., Pinnacle West Capital Corp, PPL Corp., Progress Energy Inc., Puget Energy Inc., Questar Corporation, Sempra Energy (parent of San Diego Gas & Electric), TECO Energy Inc, UIL Holdings Corp, Unisource Energy Corp., and Vectren Corp. Benchmark data are size-adjusted where applicable, to reflect kind of organization (corporate or subsidiary) and financial size of the organization.

•

Tally Sheets. The HEI Compensation Committee and the HECO Board use tally sheets to determine total executive compensation and to benchmark against the Benchmark Peer Group.

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Executive compensation policy

As Hawaii’s major regulated electric public utility providing energy to approximately 95% of the state’s population, HECO is committed to enhancing shareholder value by providing reliable energy at a reasonable cost. HECO is also striving to reduce its dependency on fossil fuel by exploring new and better solutions for providing reliable, reasonably priced energy. In addition, the continuing pressure of rising or volatile oil prices requires HECO to continually improve its efficiency and productivity. To achieve its critical business objectives, HECO must continue to attract, motivate, and retain highly talented and skilled individuals at all levels of the organization.

With HECO’s strategic objectives in mind, the HECO Board and the HEI Compensation Committee base their executive compensation programs on a “total compensation” package which: (1) demonstrates a clear relationship of pay levels to organization performance, both annual and long-term, and returns to shareholders; (2) supports HECO’s strategic plan through tailoring the use of specific compensation components; (3) demonstrates HECO’s belief that its employees are vital to its success; and (4) serves as a guiding force to ensure employees are fairly rewarded, motivated and valued in their working relationship with HECO. HECO strives to provide competitive compensation based upon the value of the job in the marketplace. To attract and retain a highly skilled work force, HECO must remain competitive with the pay of other similarly situated local and national employers who compete with HECO for talent. HECO’s total compensation package is designed to match HECO and individual results with appropriate rewards. Given their key role in shaping and executing our strategic business plans, HECO’s executives have incentives tied to long-term performance. At the same time, HECO also promotes a culture of integrity where there is no undue pressure to meet or exceed financial targets for personal gain.

Components of executive total compensation for 2006

HECO’s executive compensation programs offer a package of annual and longer-term rewards, including cash and equity compensation and benefits. HECO chooses to pay these elements because they are necessary to remain competitive with the Benchmark Peer Group and other competitors for labor, while focusing on the kinds of behaviors and results HECO believes will enhance shareholder value. For 2006, the components of executive total compensation consisted of:

•

Base salary

•

Annual performance-based cash incentive compensation

•

Long-term performance-based equity and non-equity incentive compensation

•

Perquisites and other personal benefits, and

•

Retirement and other post-retirement benefits.

The most recent custom analysis on executive compensation performed by Towers Perrin at the request of the HEI Compensation Committee and the HECO Board was completed in November 2005 (Executive Custom Analysis). In the Executive Custom Analysis, total compensation levels were found to be positioned below the Benchmark Peer Group.

Employment agreements

Currently HECO does not have any employment agreements with any of the HECO NEOs.

Base salary

Base salary for services rendered during the year at HECO recognizes the market rate for the individual’s position and responsibilities, individual experience and performance, and internal relative equity with other executive officers. Base salary is the key determinant of HECO’s overall competitive positioning and is the foundation of a total system of rewards. Annual and long-term incentive awards for HECO NEOs are multiples of the HECO NEO’s salary midpoint. The Executive Custom Analysis found that HECO NEO base salaries were, on average, slightly below the Benchmark Peer Group median, although salary positioning relative to the market varied by individual. HECO considers base salaries that are below median to be competitive in the market, given the prevailing local market rates; however, in certain instances when it is necessary to attract national talent and critical skills for key positions, adjustments may be made. At the request of the HEI Compensation Committee and HECO Board, Towers Perrin recommends adjustments to the salary structure at HECO periodically based upon

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competitive salary structure trend rates and evaluates individual positions at HECO for possible re-grading based upon competitive market pay levels. Base salary levels are also reviewed when there are significant changes in job responsibility.

Robert F. Clarke, then HEI President and CEO, evaluated Mr. May’s 2005 performance and recommended an annual salary increase of 3% for Mr. May effective May 2006. Mr. May recommended salary increases of 4%, 5%, 5%, and 3%, effective May 2006, for Ms. Sekimura, and Messrs. Alm, Joaquin and Stahlkopf, respectively. The HEI Compensation Committee and the HECO Board accepted these recommendations.

Incentive programs

HECO’s incentive programs, paid on an annual basis and/or over the long-term, are designed to be motivating factors to align management and shareholder interests, provide a sense of ownership, and encourage greater commitment. HECO’s incentive goals are determined based upon HECO’s annual and long range strategic and business plans and are approved by the HEI Compensation Committee and HECO Board. HECO’s strategic plan identifies key areas of strategic focus that aim to enable HECO to increase shareholder value and strengthen earnings, achieve HECO’s energy future roadmap and provide reliable power. Payouts on HECO annual and long-term incentive programs based on achieved performance are approved as soon as practicable after the end of the applicable performance period. The HEI Compensation Committee and the HECO Board, however, reserve the right to amend, suspend or terminate HECO’s incentive programs or any portion of the programs at any time.

Executive Incentive Compensation Plan

The HEI Executive Incentive Compensation Plan (EICP) provides an opportunity for HECO executives (including all HECO NEOs) to earn annual incentive awards. Under the EICP, annual incentive awards are granted upon the achievement of financial and operational goals and performance measures established by the HEI Compensation Committee and HECO Board in the early part of each calendar year. The EICP award levels for each of the participants are established and approved by the HEI Compensation Committee and HECO Board. The current minimum, target and maximum award level ranges differ for each of the HECO NEOs and were based on the Executive Custom Analysis, which reviewed EICP award level opportunities from the Benchmark Peer Group with revenues that are comparable with HECO. The prospective awards under the EICP for each of the HECO NEOs range from 13% to 30%, from 25% to 60%, and from 38% to 120%, for the minimum, target, and maximum awards, respectively, of the midpoint of the executive salary grade ranges projected to the end of the performance period, but in any event not in any individual case in excess of $2.0 million. The EICP requires that the minimum net income threshold be achieved before any payout is made. The Executive Custom Analysis found that target total annual cash compensation (base salary plus target EICP award) for HECO NEOs was 10% below median, which is in keeping with HECO’s pay philosophy.

Based on Towers Perrin’s recommendations and approval by the HECO Board and HEI Compensation Committee, HECO EICP goals are focused entirely on the performance of the utilities. These goals were chosen as enhancing shareholder value in areas where utility executives may directly influence in the short-term. HECO NEOs have one or more key financial EICP goals such as utility net income, ROACE, and/or level of capital expenditures. HECO NEOs may also have one or more key operating, strategic, or major project EICP goals related to their respective area of responsibility. These goals may vary over the year, and have typically included goals on heat rate, reliability, customer satisfaction, major capital projects, corporate culture and safety.

In February 2006, the HEI Compensation Committee and HECO Board established the 2006 EICP financial and other operational measures for the HECO NEOs. All HECO NEOs had a consolidated utility net income goal (weighted 45%), a consolidated utility capital expenditures goal (weighted 10%) and utility operational goals (weighted a total of 45%), including an employee safety goal. Mr. May’s other operational goals related to increasing HECO’s generation reserve margin, continuous improvement and moving forward on HECO’s energy future roadmap. Ms. Sekimura’s other operational goals related to continuous improvement and financial process improvement and financial and information technology and service performance. Mr. Alm’s other operational goals related to public affairs, moving forward on HECO’s public affairs roadmap and continuous improvement. Mr. Joaquin’s other operational goals related to increasing HECO’s generation reserve margin, continuous improvement and moving forward on HECO’s operations roadmap. Mr. Stahlkopf’s other operational goals related to increasing HECO’s generation reserve margin, moving forward on HECO’s energy solutions roadmap and continuous improvement.

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Potential payouts if all 2006 EICP goals for the HECO NEOs had been met at the target level would have been as follows: Mr. May, $330,600; Ms. Sekimura, $54,000; Mr. Alm, $72,600; Mr. Joaquin, $72,600; and Mr. Stahlkopf, $87,000. For 2006, however, HECO did not achieve the minimum net income threshold, even though other goals were achieved, and therefore no payouts were earned by any HECO NEO. Over the last ten-year period, HECO had achieved an EICP net income payout 70% of the time (a payment above minimum, but below maximum, 60% of the time and a maximum payment 10% of the time). HECO believes that its EICP goals provide the appropriate difficulty intended to reward superior performance.

Long Term Incentive Plan

The HEI Long-Term Incentive Plan (LTIP) rewards select HECO executives based on HECO’s successful long-term financial performance. HECO chooses to pay LTIP because it provides a balanced performance measurement scorecard that aligns with key value drivers of financial performance and shareholder investments. The three-year LTIP performance horizon provides balance with the shorter-term annual focus of the EICP. LTIP awards are paid in a combination of cash (60%) and stock (40%). HECO awards a portion of the LTIP payout in shares to promote HEI share ownership. The LTIP goals are based on achieving financial criteria established by the HEI Compensation Committee and HECO board for a three-year period. A new three-year performance period starts each year. The HEI Compensation Committee and the HECO Board select participants in HECO LTIP for each performance period from those executives whose decisions and actions contribute directly to HECO’s long-term success. Prior to 2004, only the HECO, HELCO and MECO presidents were participants in the LTIP. In 2004, the eligibility requirement for the HECO LTIP was expanded to include all HECO Senior Vice Presidents in recognition of the positions they hold that significantly influence actions that align with HECO’s longer-term goals. In 2007, the HEI Compensation Committee and the HECO Board included Ms. Sekimura, HECO Financial Vice President, as a participant in LTIP for the 2007-2009 LTIP performance period.

The HEI Compensation Committee and the HECO Board consider performance goal weightings that are recommended by Towers Perrin based on benchmarking and consultant judgment and reflect a balance between HEI and subsidiary performance and alignment of key value drivers of financial performance and shareholder investments. Goals may vary for each three-year plan based upon changes in strategic focus or business objectives, and have typically included goals on reliability and major capital projects.

The LTIP award levels for each of the participants are established and approved by the HEI Compensation Committee and HECO Board. The current minimum, target and maximum award level ranges differ for each of the participating HECO NEOs and were based on the Executive Custom Analysis, which reviewed LTIP award level opportunities from the Benchmark Peer Group. The prospective awards under the LTIP for each of the participating HECO NEOs ranged from 25% to 40%, from 37.5% to 80%, and from 75% to 170%, for the minimum, target, and maximum awards, respectively, of the midpoint of the executive salary grade ranges projected to the end of the performance period, but in any event not in any individual case in excess of $2.5 million.

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2004-2006 performance period. Messrs. May, Alm, Joaquin and Stahlkopf were participants in the 2004-2006 performance period LTIP. These executives shared two common goals: (1) HEI consolidated ROACE and (2) HEI total shareholder return (TSR) measured against the Edison Electric Institute (EEI) Index of Investor-Owned Electric Companies (LTIP Peer Group) as of December 31, 2006, with performance of the LTIP Peer Group calculated on a noncapitalized weighted basis so as not to give a disproportionate emphasis to the larger companies in the LTIP Peer Group. Mr. May’s HEI consolidated ROACE goal was weighted 30% and his HEI TSR goal was weighted 20%. His third goal weighted 50% was based on a percent of a weighted allowed ROACE for consolidated HECO for the same three-year LTIP cycle. Messrs. Alm, Joaquin and Stahlkopf each had an HEI consolidated ROACE goal weighted 15% and an HEI TSR goal weighted 10%. They also had HECO performance-based operational goals weighted 25% each, related to energy policy, adequate supply of power, and reliable flow of power for the 2004-2006 LTIP cycle.

At the end of 2006, Mr. May had not achieved his minimum goals and therefore he did not earn any LTIP payout. Messrs. Alm, Joaquin and Stahlkopf achieved the minimum for only the reliable flow of power goal; their payouts for 2006 are $15,125, $15,125, and $18,125 respectively.

Over the last ten-year period, HECO had achieved an LTIP HEI TSR payout approximately 40% of the time (a payment above minimum, but below maximum, 10% of the time and a maximum payment 30% of the time). For the same period, HECO had achieved an LTIP HEI consolidated ROACE payout approximately 30% of the time with a payment above minimum but below maximum. HECO believes that its LTIP goals provide the appropriate difficulty intended to reward superior performance.

2006-2008 performance period. In February and March 2006, the HEI Compensation Committee and HECO Board established the financial measures for the 2006-2008 performance period LTIP for the HECO NEOs.

All the HECO NEOs, except for Ms. Sekimura, are participants in the 2006-2008 performance period LTIP. Each of the participating HECO NEOs have the following three LTIP goals: (1) HEI consolidated ROACE (weighted 40%), based on HEI’s percentile position measured against the LTIP Peer Group, (2) HECO consolidated net income (weighted 40%) and (3) HEI TSR (weighted 20%), based on HEI’s percentile position measured against the LTIP Peer Group. Potential payouts if all goals are met at the target level at the end of the three year period are estimated as follows: Mr. May, $463,200; Mr. Alm, $95,250; Mr. Joaquin, $95,250; and Mr. Stahlkopf, $114,375.

Stock awards

Stock awards are provided to HECO NEOs to create a linkage of executive interests with improvement in the value of HEI shareholder investments, to retain executives through multi-year vesting, and to offer a competitive long-term incentive compensation opportunity. Under the 1987 Stock Option and Incentive Plan of HEI, as amended and restated effective April 20, 2004 (SOIP), as approved by the HEI shareholders, HEI may grant nonqualified stock options (NQSOs), incentive stock options, restricted stock, stock appreciation rights (SARs), stock payments and dividend equivalents (DEs). These equity awards are intended to retain HECO executives, provide a continuing incentive to contribute to long-term stock performance and to increase their ownership position in HEI over time. Equity awards have been given annually to the Presidents and CEOs of the subsidiary operating companies of HEI because of their roles which have a direct linkage with the creation of shareholder value and to maintain competitive levels of their total compensation. Utility executives, other than the HECO President and CEO, are traditionally given stock awards every other year. According to the Executive Custom Analysis, HECO is about 21% below median compensation levels in target total direct compensation (target total annual cash compensation plus LTIP and equity compensation awards).

Before 2006, HEI typically granted equity awards in the form of NQSOs and SARs with DEs. Because of limits on the use of DEs in connection with NQSOs and SARs under Section 409A of the Internal Revenue Code (Section 409A) (generally effective as of January 1, 2005), DEs are not as effective as before the enactment of Section 409A. As a result, since 2006 HECO has been relying instead primarily on restricted stock to compensate the HECO NEOs.

In 2006, the HEI Compensation Committee and HECO Board approved the grant of a restricted stock award of 8,000 shares of HEI Common Stock to Mr. May. The number of restricted shares was recommended based on equivalent grants given to executives in comparable positions in the Benchmark Peer Group and roughly equivalent to the value of SARs with DEs awarded to Mr. May in the previous year. In accordance with HEI’s Stock Pricing and

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Dating Policy described below, Mr. May’s restricted stock was awarded based on the closing price of HEI Common Stock on the date of grant, April 13, 2006. HECO believes that Mr. May’s restricted stock awards, when taken together with his LTIP award targets, provide a competitive level of long-term incentive opportunity. None of the other HECO NEOs received stock awards in 2006.

Option awards

The HEI Compensation Committee, prior to 2006, granted NQSOs, SARs, and related DEs under the SOIP. In December 2005, to accommodate changes to the tax rules imposed by Section 409A, HEI modified the provisions for paying DEs on shares underlying NQSOs and SARs that were vested on December 31, 2004, and HEI similarly modified provisions for paying DEs on dividends declared after 2004. Before modification, DEs were paid when and to the extent that the employee exercised the NQSOs/SARs. In order to comply with Section 409A, any vested dividend equivalent subject to the modification is being paid not later than two and half months after the year in which the underlying dividend is declared (without regard to whether the underlying NQSO/SAR is exercised).

Stock Ownership Policy

HEI has established a stock ownership policy to align the interests of the executives of HEI and its subsidiaries with shareholders. At HECO, only Mr. May, as the HECO President and CEO, is required to follow HEI’s Stock Ownership Policy. The requirement is that the HECO President and CEO should hold common shares with a fair market value equal to 1.5 times his annual base salary by January 1, 2009 (within five years from the effective date of the initial policy). As of December 31, 2006 Mr. May exceeded this requirement.

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Stock Pricing and Dating Policy

On October 30, 2006, the HEI Board adopted a stock pricing and dating policy to ensure the proper pricing and dating of stock incentive awards. Backdating of awards is strictly prohibited. The HEI Compensation Committee, subject to the approval of the HEI Board, recommends stock award grants without regard to the timing or coordination of disclosure of information to the public or the possible effects of such information on stock price. HECO NEOs do not have any role in the timing of HEI stock option grants. Stock awards have been traditionally granted in April, prior to the annual HEI shareholders’ meeting. Stock awards granted outside of this normal cycle use the date of grant as the measurement date, which will be at the next duly held meeting of the HEI Compensation Committee


Type of Stock Award	Price Purpose	Measurement Date	Pricing Method
NQSOs	Set exercise price	On grant date	Average of the grant date high-low sales prices.

SARs	Set exercise price	On grant date	Average of the grant date high-low sales prices.

Restricted Stock	Set value of grant for financial reporting purposes	On grant date	Grant date closing sales price.

DEs (on NQSOs and SARs)	Set value of DE credit into shares	On record date of declared dividends	Average of the record date high-low sales prices.

Performance awards (under Executive Incentive Compensation Plan or Long- Term Incentive Plan or other performance program*)	Set value for converting dollar award into shares	On HEI Compensation Committee approval date	Average of the HEI Compensation Committee approval date high-low sales prices.

Director Stock Retainers (Annual and Initial election)	Set value of retainer	On issuance date	Average of the issuance date high-low sales prices.

*	Currently, only LTIP involves stock compensation.

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Perquisites and other personal benefits

Executive perquisites

HECO believes that executive perquisites are necessary to maintain a competitive and attractive total compensation program for leadership positions within HECO. Perquisites and other personal benefits are periodically reviewed by the HEI Compensation Committee and the HECO Board. During 2006, the HECO NEOs were eligible for an automobile and gas allowance or the use of a HECO-owned vehicle, business parking, club memberships, certain spousal travel expenses, business-related recreational expenses, voluntary annual physical exams and use of a HECO-owned recreational facility. In late 2006, HECO terminated executive and management use of the HECO-owned recreational facility and agreed to sell the facility. Also, in 2006, the decision was made that HECO executives should pay for their own business-related recreational expenses if the expenses are not related to a customer event and for their spouse’s expenses if the spouse accompanies them to an HEI or HECO board meeting. Reimbursement for Mr. May’s spouse’s travel is provided for other meetings when Mr. May’s spouse accompanies him to such meetings where spouse attendance is required or expected. The reimbursement is imputed as taxable income to Mr. May. Mr. May is allowed by HEI policy to take an undefined number of vacation days, consistent with the heavy workload demands of his position. No amount of “unused” vacation is taken into consideration in his pension or termination benefit calculations.

Change-in-control

On February 11, 1992, HEI entered into a change-in-control agreement with Mr. May to encourage and ensure his continued attention and dedication to the performance of his assigned duties without distraction in the event of potentially disruptive circumstances arising from a change-in-control of HEI. The agreement defines a change-in-control to mean a change-in-control of HEI of a nature that would be required to be reported under the rules of the Securities Exchange Act of 1934, including circumstances in which a person is or becomes the beneficial owner, directly or indirectly, of securities representing 25% or more of the combined voting power of HEI’s outstanding voting securities, or specified changes in the composition of the majority of the HEI Board following a merger, tender offer or certain other corporate transactions. The agreement addresses matters relating to Mr. May’s employment, including severance compensation, if his employment terminates under circumstances described in the agreement following a change-in-control of HEI. The change-in-control agreement provides that if, after a change-in-control and prior to the expiration of the agreement, the employment of Mr. May is terminated without cause, HEI shall pay to Mr. May in a lump sum a severance payment equal to 2.99 times his average W-2 earnings for the most recent five years, provided that the payment shall be subject to withholding taxes and shall be limited to an amount that is not subject to disallowance of deduction under Section 280G of the Internal Revenue Code when aggregated with any other amounts required to be considered for purposes of that provision. Where a termination without cause has occurred, HEI also will pay outplacement service fees on Mr. May’s behalf, not to exceed 30% of his base annual salary at the time of the change-in-control. HECO believes that it is appropriate to provide the benefit for the President and CEO position because of the vulnerability of that particular position in a change-in-control situation. HECO does not believe that other HECO NEOs are similarly vulnerable and therefore does not provide the other HECO NEOs with change-in-control agreements. During 2006, no payments or benefits were paid under the change-in-control agreement.

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Executive death benefits

In order to provide a competitive and attractive total compensation package, HECO also provides an Executive Death Benefit Plan of HEI and Participating Subsidiaries (HEI DB Plan). All HECO NEOs are covered by the HEI DB Plan, which provides death benefits to the participant’s beneficiary upon the participant’s death. If the HECO NEO dies while actively employed or, if disabled, dies prior to age 65, the benefit is equal to two times the HECO NEO’s base salary grossed up for taxes. If the HECO NEO dies after retirement, the benefit is equal to the HECO NEO’s base salary at retirement grossed up for taxes. Should any HECO NEO die before retirement while still employed by HECO, the gross amount of the executive death benefit payable to his/her designated beneficiary is listed below, using a tax gross up rate of 35%:


Name	Base Salary effective May 1, 2006 x 2 ($)	Tax Gross-up ($)	Total Benefit ($)
Mr. May	1,154,000	621,385	1,775,385
Ms. Sekimura	435,000	234,231	669,231
Mr. Alm	556,800	299,815	856,615
Mr. Joaquin	570,400	307,138	877,538
Mr. Stahlkopf	652,000	351,077	1,003,077

The executive death benefit during employment is self-funded by HECO, therefore there are no life insurance premiums to report. See discussion of post-retirement death benefits in the Pension Benefits table below.

Post-employment benefits

Retirement benefits

Retirement benefits are provided as part of HECO’s total compensation program to be competitive with the industry, attract and retain highly qualified employees and enable an orderly succession of the workforce.

HEI Plan. All regular employees of HECO (including the HECO NEOs) participate in the Retirement Plan for Employees of HEI and Participating Subsidiaries (HEI Plan), a noncontributory, qualified defined benefit pension plan. The HEI Plan provides benefits at normal retirement (age 65), early retirement or death prior to retirement. Benefits are vested when participants complete five years of service. Normal retirement benefits are calculated based on a formula of 2.04% x Credited Service (maximum 67%) x Final Average Pay (average monthly base salary for highest thirty-six consecutive months out of the last ten years). Retirement benefits are increased by an amount equal to three percent (3%) of the initial benefit every twenty-four months following retirement.

Early retirement benefits are available for participants who meet the age and service requirements at ages 50-64. Early retirement benefits are reduced for participants who retire prior to age 60, based on the participant’s age at the early retirement date. The accrued normal retirement benefit is reduced by the applicable percentage which ranges from 30% for early retirement at age 50 to 1% at age 59. Accrued or earned benefits are not reduced for eligible employees who retire at age 60 and above. All of the HECO NEOs are eligible for pension benefits under the HEI Plan, immediately upon termination of employment, except for Ms. Sekimura, who will be eligible for future pension benefits upon meeting the early retirement provisions of the HEI Plan.

Under the Internal Revenue Code (IRC), benefits payable from qualified plans such as the HEI Plan are limited. HECO has adopted the HEI Excess Benefit Plan (HEI Excess Benefit Plan) and the HEI Excess Pay Supplemental Executive Retirement Plan (HEI Excess Pay Plan), which are non-contributory, nonqualified plans, to make up for the portion of benefits that cannot be paid from the HEI Plan due to these IRC limits. HECO provides these benefits so that highly compensated employees may have a similar percentage of his or her earnings replaced as other employees.

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HEI Excess Benefit Plan. The IRC limits benefits that can be paid to participants from qualified plans to $175,000 in 2006. Benefits under the HEI Excess Benefit Plan are determined using the same formula as the HEI Plan reduced by the benefit payable from the HEI Plan. Early retirement, death benefits and vesting provisions are similar to the HEI Plan. No HECO NEO participates in the HEI Excess Benefit Plan.

HEI Excess Pay Plan. The IRC also limits the amount of annual compensation for purposes of calculating a participant’s eligible compensation from qualified plans to $220,000 in 2006. Benefits under the HEI Excess Pay Plan are determined using the same formula as the HEI Plan reduced by the benefit payable from the HEI Plan. Early retirement, death benefits and vesting provisions are similar to the HEI Plan. Ms. Sekimura and Messrs. Alm, Joaquin and Stahlkopf participate in the HEI Excess Pay Plan. Messrs. Alm, Joaquin and Stahlkopf are eligible for pension benefits under the HEI Excess Pay Plan immediately upon termination of employment; Ms. Sekimura will be eligible for future pension benefits upon meeting the early retirement provisions of the HEI Excess Pay Plan.

For the HEI Plan, Excess Benefit Plan and Excess Pay Plan, additional credited service of up to eight months may be granted to participants who retire at age 55 or later with respect to unused sick leave from the current year and prior two years. Credited service is also granted to disabled participants who are vested at the time of disability for the period of disability.

HEI SERP. To address the Internal Revenue Code limits on benefits payable from the HEI Plan and the integral role of bonuses paid under the EICP, HEI has adopted the HEI Supplemental Executive Retirement Plan (HEI SERP), a non-contributory non-qualified plan. The plan provides participating executives with potential additional retirement income by including EICP awards in the calculation of benefits. Benefits under the HEI SERP are determined based on a formula of 2.04% x Credited Service (maximum 60%) x Final Average Compensation (average monthly base salary plus EICP for any three calendar years out of the last sixty months prior to retirement). Benefits are reduced by benefits payable by the HEI Plan, social security and by any other pension plan provided by HEI, and will not be less than the benefit that would be payable under the HEI Plan before any IRC limits. Early retirement and death benefits similar to the HEI Plan are available in the HEI SERP. Only the HECO President and CEO participates in the HEI SERP, given his position, which is particularly susceptible to being adversely impacted in a change-in-control situation. Mr. May is eligible for pension benefits under the HEI SERP as of December 31, 2006. Towers Perrin included these benefits and other post-retirement benefits as part of its tally sheet analysis of Mr. May’s total compensation.

Other matters

Deductibility cap on executive compensation

The HEI Compensation Committee and the HECO Board reviewed the provisions of Section 162(m) of the IRC, relating to the $1 million deduction cap for executive compensation and its applicability in 2006 and believe that no compensation for the HECO NEOs will be limited by this regulation except for Mr. May. The HEI Compensation Committee and HECO Board will take Section 162(m) into account as one of the factors considered in establishing executive compensation and generally will award only deductible compensation. However, to the extent consistent with its overall compensation policy, the HEI Compensation Committee and HECO Board may determine that awarding compensation in excess of Section 162(m) deduction limits is reasonable and appropriate.

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Summary Compensation Table

The following summary compensation table shows the base salary, annual bonus, stock awards, option awards, non-equity incentive compensation, change in pension value and non-qualified deferred compensation earnings, and all other compensation and benefits of the HECO NEOs who served during and at the end of 2006. All compensation amounts presented for T. Michael May are the same amounts that will be presented in HEI’s 2007 Proxy Statement.

SUMMARY COMPENSATION TABLE


Name and Principal Position	Year	Salary ($)	Bonus ($) (1)	Stock Awards ($) (2)	Option Awards ($) (3)	Non-Equity Incentive Plan Compen- sation ($) (4)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (5)	All Other Compen- sation ($) (6)	Total ($)
T. Michael May	2006	571,334	–	36,955	144,312	–	389,129	21,317	1,163,047
President and Chief Executive Officer

Tayne S. Y. Sekimura	2006	214,700	–	–	8,890	–	90,136	14,446	328,172
Financial Vice President and Chief Financial Officer

Robert A. Alm	2006	273,967	–	–	46,394	15,125	96,312	17,303	449,101
Senior Vice President-Public Affairs

Thomas L. Joaquin	2006	280,666	–	–	21,295	15,125	129,864	14,389	461,339
Senior Vice President-Operations

Karl E. Stahlkopf	2006	322,833	–	28,176	18,615	18,125	85,571	14,652	487,972
Senior Vice President-Energy Solutions and Chief Technology Officer

(1)	No discretionary bonuses without pre-established goals were awarded to HECO NEOs in 2006.

(2)

Represents recognition of stock expense in the Company’s financial statements, without reduction for forfeitures, for restricted stock awards. On April 13, 2006, 8,000 shares of restricted stock were granted to Mr. May. On the date of grant, the closing price of HEI Common Stock was $26.32 on the NYSE. Quarterly dividends on the 8,000 shares of restricted stock are paid to Mr. May. The 8,000 shares of restricted stock become unrestricted on May 13, 2010. On May 1, 2002, 6,000 shares (split-adjusted) of restricted stock were granted to Mr. Stahlkopf. On the date of grant, the closing price of HEI Common Stock was $23.48 (split adjusted) on the NYSE. Quarterly dividends on the 6,000 shares (split-adjusted) of restricted stock are paid to Mr. Stahlkopf. The 6,000 shares (split-adjusted) of restricted stock become unrestricted on April 30, 2007. For a discussion of the assumptions underlying the amounts set out for restricted stock, see Note 9 to HEI’s Consolidated Financial Statements.

(3)

Represents recognition of option expense in the Company’s financial statements, without reduction for forfeitures, for NQSOs with DEs granted in 2002 and 2003 and SARs with DEs granted in 2004 and 2005. For a discussion of the assumptions underlying the amounts set out for option awards, see Note 9 to HEI’s Consolidated Financial Statements.

(4)

The HECO NEOs are eligible for an annual incentive award under the HEI’s EICP. EICP bonus payouts are reflected as compensation for the year earned, and none were earned by the HECO NEOs in 2006. LTIP payouts are determined in the first quarter of each year for the three-year cycle ending on December 31 of the previous calendar year.

(5)

Represents the change in pension value from December 31, 2005 to December 31, 2006. No HECO NEO currently participates in the HEI Nonqualified Deferred Compensation Plan. Negative present value change for the executive death benefit plan which were not included in the change in pension value for Messrs May, Joaquin and Stahlkopf are $13,700, $11,230 and $13,748, respectively.

(6)

Represents total perquisites for 2006. During 2006, the HECO NEOs were eligible for an automobile and gas allowance or the use of a HECO-owned vehicle, business parking, club memberships, certain spousal travel expenses, business-related recreational expenses, voluntary annual physical exams and use of a HECO-owned recreational facility. Mr. May is allowed by HEI policy to take an undefined number of vacation days, consistent with the heavy workload demands of his position, but there is no aggregate incremental cost to HECO in 2006 for this benefit. In 2006, no such perquisite had an aggregate incremental cost in excess of $25,000.

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Supplemental Grants of Plan-Based Awards

The following table relates to awards to the HECO NEOs in 2006 under the EICP tied to performance for 2006 and LTIP tied to performance over the 2006-2008 period. Also shown is the restricted stock award granted under SOIP only to Mr. May during 2006. All HECO NEOs participated in EICP. All HECO NEOs except Ms. Sekimura participated in LTIP.

GRANTS OF PLAN-BASED AWARDS


		Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number	All Other Option Awards:	Exercise or Base Price	Grant Date Fair Value
Name	Grant Date	Thres- hold ($)	Target ($)	Maximum ($)	Thres- hold ($)	Target ($)	Maximum ($)	of Shares of Stock or Units (#) (2)	Number of Securities Underlying Options (#)	of Option Awards ($/Sh)	of Stock and Option Awards ($)
T. Michael May	2/8/06 EICP	165,300	330,600	661,200	—	—	—	—	—	—	—
	2/8/06 LTIP	231,600	463,200	984,300	—	—	—	—	—	—	—
	4/13/06 RS	NA	NA	NA	NA	NA	NA	8,000	NA	NA	210,560

Tayne S. Y. Sekimura	2/8/06 EICP	28,080	54,000	82,080	—	—	—	—	—	—	—
	2/8/06 LTIP	NA	NA	NA	—	—	—	—	—	—	—
	4/13/06 RS	NA	NA	NA	NA	NA	NA	NA	NA	NA	NA

Robert A. Alm	2/8/06 EICP	36,300	72,600	108,900	—	—	—	—	—	—	—
	2/8/06 LTIP	63,500	95,250	190,500	—	—	—	—	—	—	—
	4/13/06 RS	NA	NA	NA	NA	NA	NA	NA	NA	NA	NA

Thomas L. Joaquin	2/8/06 EICP	36,300	72,600	108,900	—	—	—	—	—	—	—
	2/8/06 LTIP	63,500	95,250	190,500	—	—	—	—	—	—	—
	4/13/06 RS	NA	NA	NA	NA	NA	NA	NA	NA	NA	NA

Karl E. Stahlkopf	2/8/06 EICP	43,500	87,000	130,500	—	—	—	—	—	—	—
	2/8/06 LTIP	76,250	114,375	228,750	—	—	—	—	—	—	—
	4/13/06 RS	NA	NA	NA	NA	NA	NA	NA	NA	NA	NA

NA	Not applicable.

RS	Restricted stock

(1)	Includes awards under HEI’s 2006 EICP and 2006-2008 LTIP plans based on meeting performance goals at threshold, target and maximum levels. See further discussion of the features of the awards in Compensation Discussion and Analysis above.

(2)	Represents shares of restricted stock that vest on a cliff basis following four years of service. The closing price of HEI Common Stock on the NYSE on the date of grant was $26.32.

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Outstanding Equity Awards at Fiscal Year-End

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END


	Option Awards (1)						Stock Awards (2)
									Equity Incentive Plan Awards
		Number of Securities Underlying Unexercised Options		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)			Shares or Units of Stock That Have Not Vested		Number of Unearned Shares, Units, or Other Rights That Have Not Vested (#)	Market or Payout Value of Unearned Shares, Units, or Other Rights That Have Not Vested ($)
Name	Grant Year	Exer- ciseable (#)	Unexer- ciseable (#)		Option Exercise Price ($)	Option Expira- tion Date	Number (#)	Market Value ($)
T. Michael May	2002	50,000	—	—	21.68	4/22/12	—	—	—	—
	2002 DE	8,659	—	—	—	4/22/12	—	—	—	—
	2003	37,500	12,500	—	20.49	4/21/13	—	—	—	—
	2003 DE	5,533	1,845	—	—	4/21/13	—	—	—	—
	2004	25,000	25,000	—	26.02	4/19/14	—	—	—	—
	2004 DE	2,139	2,139	—	—	4/19/14	—	—	—	—
	2005	—	50,000	—	26.18	4/7/15	—	—	—	—
	2005 DE	—	2,362	—	—	4/7/15	—	—	—	—
	2006	NA	NA	NA	NA	NA	8,000	217,200	—	—

	Total	128,831	93,846	—			8,000	217,200	—	—

Tayne S. Y. Sekimura	2005	—	6,000	—	26.18	4/7/15	—	—	—	—
	2005 DE	—	510	—	—	4/7/15	—	—	—	—
	2006	NA	NA	NA	NA	NA	NA	—	—	—

	Total	—	6,510	—			—	—	—	—

Robert A. Alm	2003	9,000	3,000	—	20.49	4/21/13	—	—	—	—
	2003 DE	1,349	449	—	—	4/21/13	—	—	—	—
	2005	—	12,000	—	26.18	4/7/15	—	—	—	—
	2005 DE	—	1,020	—	—	4/7/15	—	—	—	—
	2006	NA	NA	NA	NA	NA	NA	—	—	—

	Total	10,349	16,469	—			—	—	—	—

Thomas L. Joaquin	2001	1,500	—	—	17.96	4/23/11	—	—	—	—
	2001 DE	353	—	—	—	4/23/11	—	—	—	—
	2003	9,000	3,000	—	20.49	4/21/13	—	—	—	—
	2003 DE	1,328	443	—	—	4/21/13	—	—	—	—
	2005	—	12,000	—	26.18	4/7/15	—	—	—	—
	2005 DE	—	567	—	—	4/7/15	—	—	—	—
	2006	NA	NA	NA	NA	NA	NA	—	—	—

	Total	12,181	16,010	—			—	—	—	—

Karl E. Stahlkopf	2002	NA	NA	NA	NA	NA	6,000	162,900	—	—
	2003	—	3,000	—	20.49	4/21/13	—	—	—	—
	2003 DE	—	142	—	—	4/21/13	—	—	—	—
	2005	—	12,000	—	26.18	4/7/15	—	—	—	—
	2005 DE	—	567	—	—	4/7/15	—	—	—	—
	2006	NA	NA	NA	NA	NA	NA	—	—	—

	Total	—	15,709	—			6,000	162,900	—	—

NA	Not applicable.

(1)	For option awards, the 2003 NQSO grant vests in 25% annual installments and will be fully vested on April 21, 2007; the 2004 SARs grant vests in 25% annual installments and will be fully vested on April 19, 2008 and the 2005 SARs grant cliff vest on April 7, 2009.

(2)	For stock awards, Mr. Stahlkopf’s 2002 restricted stock award become unrestricted on April 30, 2007 and Mr. May’s 2006 restricted stock award become unrestricted on May 13, 2010.

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Options Exercises and Stock Vested

OPTIONS EXERCISES AND STOCK VESTED


	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#) (1)	Value Realized on Exercise ($) (2)	Number of Shares Acquired on Vesting (#)	Value Realized on Vesting ($)
T. Michael May	58,458	851,605	—	—

Tayne S. Y. Sekimura	—	—	—	—

Robert A. Alm	601	15,773	—	—

Thomas L. Joaquin	904	23,728	—	—

Karl E. Stahlkopf	4,216	47,853	—	—

(1)

Includes shares paid with respect to DEs due to changes made to the provisions for the award of DEs in light of Section 409A: Mr. May, 9,049 shares; Mr. Alm, 601 shares; Mr. Joaquin, 904 shares; and Mr. Stahlkopf, 1,145 shares. Also includes Mr. May’s exercise of 40,000 NQSOs and 9,409 accompanying DEs and Mr. Stahlkopf exercise of 3,000 NQSOs and 71 accompanying DEs.

(2)

Includes the value realized on shares paid with respect to DEs due to changes made to the provisions for the award of DEs in light of Section 409A of the IRC: Mr. May, $237,457; Mr. Alm, $15,773; Mr. Joaquin, $23,728 and Mr. Stahlkopf, $30,033. Also includes Mr. May’s value realized on exercise of NQSOs and accompanying DEs of $614,148 and Mr. Stahlkopf’s value realized on exercise of NQSOs and accompanying DEs of $17,820.

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Pension Benefits

The present value (as of December 31, 2006) of the accumulated benefits under pension and retirement plans is as follows:

PENSION BENEFITS


Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($) (5)	Payments During the Last Fiscal Year ($)
T. Michael May	HEI Plan (1)	14.9	870,677	—
	HEI SERP (3)	14.9	1,947,817	—
	HEI Executive Death Benefit (4)	14.9	316,273	—

Tayne S. Y. Sekimura	HEI Plan (1)	15.6	325,294	—
	HEI Excess Pay Plan (2)	15.6	475	—
	HEI Executive Death Benefit (4)	15.6	36,045	—

Robert A. Alm	HEI Plan (1), (6)	5.5	238,117	—
	HEI Excess Pay Plan (2), (6)	5.5	56,431	—
	HEI Executive Death Benefit (4)	5.5	128,222	—

Thomas L. Joaquin	HEI Plan (1)	33.8	1,719,932	—
	HEI Excess Pay Plan (2)	33.8	452,468	—
	HEI Executive Death Benefit (4)	33.8	196,090	—

Karl E. Stahlkopf	HEI Plan (1), (6)	4.7	226,261	—
	HEI Excess Pay Plan (2), (6)	4.7	108,013	—
	HEI Executive Death Benefit (4)	4.7	247,243	—

(1)

Normal retirement benefits are calculated based on a formula of 2.04% x Credited Service (maximum 67%) x Final Average Pay (average monthly base salary for highest thirty-six consecutive months out of the last ten years). Retirement benefits are increased by an amount equal to three percent (3%) of the initial benefit every twenty-four months following retirement.

(2)	Benefits under the HEI Excess Benefit Plan and HEI Excess Pay Plan are determined using the same formula as the HEI Plan reduced by the benefit payable from the HEI Plan. Early retirement and death benefits similar to the HEI Plan are available.

(3)

Benefits under the HEI SERP are calculated based on a formula of 2.04% x Credited Service (maximum 60%) x Final Average Compensation (average monthly base salary plus EICP for any three calendar years out of the last sixty months prior to retirement). Benefits are reduced by benefits payable by the HEI Plan, social security and any other pension plan provided by HEI, and will not be less than the benefit that would be payable under the HEI Plan before any IRC limits.

(4)

Executive Death Benefit: All HECO NEOs are covered by the Executive Death Benefit Plan of HEI and Participating Subsidiaries which provides death benefits for participants who terminate (voluntary termination, termination for cause or without cause) after qualifying for immediate commencement of retirement benefits under the HEI Plan. Upon the participant’s death following retirement, the benefit is equal to one times the participant’s base salary prior to retirement, divided by one minus the highest marginal rate of federal income tax on such benefits. The present value of the executive death benefit during retirement is included in the Pension Benefits Table above. When the retired HECO NEO dies, the total amount of the executive death benefit payable to his/her designated beneficiary is listed below, using a tax gross up rate of 35% as of December 31, 2006:


Name	Base Salary effective May 1, 2006 ($)	Tax Gross-up ($)	Total Benefit ($)
Mr. May	577,000	310,692	887,692
Ms. Sekimura	217,500	117,115	334,615
Mr. Alm	278,400	149,908	428,308
Mr. Joaquin	285,200	153,569	438,769
Mr. Stahlkopf	326,000	175,538	501,538

(5)	The present value of accumulated benefits for the HECO NEOs included in the Pension Benefits Table was determined based on the following:

Methodology For each HECO NEO, the accumulated pension benefits are calculated as of December 31, 2006 based on the service and pay history of the HECO NEO as of such date. For each HECO NEO, the accumulated death benefit is calculated as of a December 31, 2006 based on the service and pay of the HECO NEO as of such date. The present value of these benefits were determined based on the assumptions described below and are the same as used in the preparation of HECO’s financial statements, unless otherwise noted.

Assumptions

(a)

Discount Rate – The discount rate is the interest rate used to discount future benefit payments in order to reflect the time value of money. The discount rate used in present value calculations is 6.00% as of December 31, 2006 and 5.75% as of December 31, 2005.

(b)

Mortality Table – The mortality table is used to discount future pension benefit payments in order to reflect the probability of survival to any given future date. For all benefits, mortality is applied post-retirement only.

(c)

Retirement Age – Each HECO NEO is assumed to retire at the earliest age when unreduced pension benefits would be payable, but no earlier than attained age as of December 31, 2006. For purposes of determining retirement eligibility, HECO NEOs are assumed to remain in active employment through retirement age.

(d)

Pre-Retirement Decrements – Pre-retirement decrements refer to events that could occur between the measurement date and the retirement age (such as withdrawal, early retirement, and death) that would impact the present value of benefits. No pre-retirement decrements are assumed in the calculation of pension benefit table present values, although decrements are assumed for financial statement purposes.

(6)	Additional credited service for unused sick leave is available for HECO NEOs: For Ms. Sekimura, the additional sick leave would increase the HEI Plan present value by $13,927 and the HEI Excess Pay Plan by $1. For Mr. Alm, the additional sick leave would increase the HEI Plan present value

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by $7,219 and the HEI Excess Pay Plan by $1,685. For Mr. Stahlkopf, the additional sick leave would increase the HEI Plan present value by $8,000 and the HEI Excess Pay Plan by $3,905.

Nonqualified Deferred Compensation

HECO NEOs may elect to participate in the HEI Executives’ Deferred Compensation Plan dated February 1, 1985, as amended, which allows an executive to defer compensation from the Company for performance awards under EICP and/or LTIP. No HECO NEO is currently participating in this plan.

Potential Payments Upon Termination or Change-in-control

The amount of potential payments to each HECO NEO under retirement, voluntary termination, termination for cause, termination without cause, and change-in-control situations are shown below, in the termination benefits table for each HECO NEO, assuming termination occurs on December 31, 2006. The amounts listed are estimates; actual amounts to be paid would depend on the actual date of termination and circumstances existing at that time.

Retirement Payments & Benefits

When the HECO NEO retires, he or she will be entitled to the following:

•

If vested, the accrued retirement benefit under the HEI Plan, HEI Excess Pay Plan and HEI SERP as applicable. (The HECO NEO may select from a variety of actuarial forms of the benefit. The amounts shown in the termination summary benefit tables are for a single life annuity.) The HECO NEO is also entitled to the 3% non-compounding biennial pension payment adjustment on the HEI Plan, HEI Excess Pay Plan, but not the HEI SERP, if eligible to retire.

•

Continued participation in EICP at a pro-rated amount, provided there has been a minimum service of nine months during the annual performance period, with payment to be made at the end of the EICP cycle if performance goals are achieved, using the salary midpoint at the time of retirement.

•

Continued participation in each ongoing LTIP cycle at a pro-rated amount, with a minimum service of twelve months during the 36-month performance period, with payment to be made at the end of the LTIP cycle if performance goals are achieved, using the salary midpoint at the time of retirement.

•

Accelerated vesting of unvested NQSOs, SARs, and accompanying DEs; all vested shares must be exercised within a period of three years, or within the original grant term, whichever comes first.

•

Post-retirement executive death benefit of one times base salary, grossed up for income taxes, payable to the HECO NEO’s named beneficiary, if eligible to retire.

When the HECO NEO retires, he or she loses the following:

•

The entire amount of unvested restricted stock is forfeited.

•

DEs on NQSOs/SARs stop accruing.

•

The pre-retirement executive death benefit of two times base salary, grossed up for income taxes, converts into one-times base salary, grossed up for income taxes.

•

Participation in change-in-control agreement, if any, ends.

Other post-employment benefits, including retiree medical, dental, group life insurance and discounted electricity are not listed above because they are available to all retirees on a non-discriminatory basis.

Voluntary Termination Payments & Benefits

When the HECO NEO voluntarily terminates, he or she will be entitled to the following:

•

If vested, the accrued retirement benefit under the HEI Plan, HEI Excess Pay Plan and HEI SERP as applicable, payable upon retirement. (No retirement amount is shown on the termination summary benefit tables since this is a vested right and not a termination benefit.) The HECO NEO is also entitled to the 3% non-compounding biennial pension payment adjustment on the HEI Plan, HEI Excess Pay Plan, but not the HEI SERP, if eligible.

•

Continued participation in each ongoing LTIP cycle at a pro-rated amount, provided there has been a minimum service of twelve months during the 36-month performance period, with payment to be made at

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the end of the LTIP cycle if performance goals are achieved, using the salary midpoint at the time of termination.

•

Vested NQSOs, SARs, and accompanying DEs, must be exercised within a period of one year of termination or within the original grant term, whichever comes first.

When the HECO NEO voluntarily terminates, he or she loses the following:

•

Unvested NQSOs, SARs and accompanying DEs are forfeited.

•

The entire amount of unvested restricted stock is forfeited.

•

DEs on vested NQSOs/SARs stop accruing.

•

The pre-retirement executive death benefit is lost. The post retirement executive death benefit is lost if the HECO NEO is not eligible to retire at termination.

•

Participation in change-in-control agreement, if any, ends.

Other post-termination benefits, including medical, dental, group life insurance, and discounted electricity are not listed because they are available to all employees on a non-discriminatory basis.

Termination for Cause Payments & Benefits

When the HECO NEO is terminated for cause, he or she will be entitled to the following:

•

When the HECO NEO is terminated for cause, he or she loses the following:

•

Based upon the HEI Compensation Committee’s right to amend, suspend or terminate the EICP or any portion of it at any time it is expected that continued participation in EICP would end and there would be no pro rata participation.

•

Based upon the HEI Compensation Committee’s right to amend, suspend or terminate the LTIP or any portion of it at any time it is expected that continued participation in any LTIP cycle would end and there would be no pro rata participation.

•

Vested and unvested NQSOs, SARs and accompanying DEs are forfeited.

•

The entire amount of unvested restricted stock is forfeited.

•

The pre-retirement executive death benefit is lost. The post-retirement executive death benefit is lost, if the HECO NEO is not eligible to retire at termination.

•

Participation in change-in-control agreement, if any, ends.

Other post-termination benefits, including medical, dental, group life insurance, and discounted electricity are not listed because they are available to all employees on a non-discriminatory basis. However, these benefits may be forfeited if the executive is terminated for cause as defined in the plan.

Termination without Cause Payments & Benefits

When the HECO NEO is terminated without cause, he or she will be entitled to the following:

•

If vested, accrued retirement benefit under the HEI Plan, HEI Excess Pay Plan and HEI SERP as applicable, payable upon retirement. (No retirement amount is shown on the termination summary benefit tables since this is a vested right and not a termination benefit.) The HECO NEO is also entitled to the 3% non-compounding biennial pension payment adjustment on the HEI Plan, HEI Excess Pay Plan, but not the HEI SERP, if eligible.

•

Continued participation in each ongoing LTIP cycle at a pro-rated amount, provided there has been a minimum service of twelve months during the 36-month performance period, with payment to be made at the end of the LTIP cycle if performance goals are achieved, using the salary midpoint at the time of termination.

174

•

Vested NQSOs, SARs and accompanying DEs must be exercised within a period of one year or the original grant term, whichever comes first.

•

A pro-rated portion of restricted stock vests, based on service to date compared to original vesting period.

When the HECO NEO is terminated without cause, he or she loses the following:

•

Unvested NQSOs, SARs and accompanying DEs are forfeited.

•

The remaining (after the pro-rated vesting described above) unvested restricted stock is forfeited.

•

DEs on vested NQSOs/SARs stop accruing.

•

The pre-retirement benefit is lost. The post-retirement executive death benefit is lost if the HECO NEO is not eligible to retire at termination.

•

Participation in change-in-control agreement, if any, ends.

Other post-termination benefits, including medical, dental, group life insurance, and discounted electricity are not listed because they are available to all employees on a non-discriminatory basis. This includes benefits available under the HEI Severance Plan, which would apply in a termination without cause situation.

Change-in-control Payments & Benefits

Only Mr. May has a change-in-control agreement. If there were a change-in-control and the benefits under the agreement were to be triggered, the change-in-control agreement provides for the following:

•

If vested, the accrued retirement benefit under the HEI Plan and HEI SERP, as applicable, payable upon retirement. (No retirement amount is shown on the termination summary benefit table since this is a vested right and not a termination benefit.) Mr. May would also be entitled to the 3% non-compounding biennial pension payment adjustment (except on HEI SERP).

•

EICP payout for two years, equal to the EICP payout of the preceding year.

•

LTIP participation at the same award level for the next two years, equal to the LTIP payout of the preceding year.

•

Stock incentive participation at the same award level for the next two years, equal to the participation of the preceding year.

•

Continued participation in any benefit plans and perquisites generally available to senior executives.

If the benefits described above are not provided to the participating executive, the change-in-control agreement provides for the payment of the following benefits (which are detailed in Mr. May’s termination summary benefits table):

•

A lump sum severance payment equal to 2.99 times his average W-2 earnings for the most recent five years, less withholding taxes and limited to an amount that is not subject to disallowance of deduction under Section 280G of the IRC when aggregated with any other amounts required to be considered for purposes of that provision.

•

Benefits and perquisites for two years after the change-in-control, but limited should the payments jeopardize the qualified tax status of any benefit plan.

•

Outplacement service fees, not to exceed 30% of base annual salary at the time of the change-in-control.

•

Vesting of unvested NQSOs, SARs and accompanying DEs.

•

Vesting of unvested restricted stock.

HECO NEOs, whether or not they have a change-in-control agreement, would be entitled to the following benefits (detailed in the termination summary benefits tables) if there were to be a change-in-control:

•

Vesting of unvested NQSOs, SARs and accompanying DEs.

•

Vesting of unvested restricted stock.

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Termination summary benefit tables

The following tables summarize benefits provided under each benefit plan and termination scenario for each HECO NEO. Amounts listed are defined as annual benefits, or a one-time benefit or other duration as specified. In instances where benefits are accelerated, the value of the acceleration is noted.

The following is the termination benefits table for Mr. May as of (and assuming, as applicable, death or termination on) December 31, 2006:


Benefit Plan or Program	Benefits payable for Retirement ($)	Benefits payable for Voluntary Termination ($)	Benefits payable for Termination for Cause ($)	Benefits payable for Termination without Cause ($)	Benefits payable for Change-in- control ($) (6)
HEI Plan (1)	65,785	NA	NA	NA	NA
HEI Excess Pay Plan (1)	NA	NA	NA	NA	NA
HEI SERP (1)	182,273	NA	NA	NA	NA
LTIP (2)	295,650	295,650	—	295,650	295,650
NQSOs/SARs (3)	332,294	—	—	—	332,294
Restricted Stock (4)	—	—	—	38,121	217,200
HEI Death Benefit Plan (5)	887,692	—	—	—	—
Change-in-control agreement (6)	NA	NA	NA	NA	4,321,300

NA	Not applicable.

Note: All option and stock-based award amounts were valued using the 2006 year-end closing price of HEI Common Stock of $27.15. Other benefits that are available to all employees on a non-discriminatory basis and perquisites aggregating less than $10,000 have not been listed.

(1)	Annual benefit accrued and available if the executive were to retire at year-end; Mr. May’s SERP benefit includes a $102,412 benefit attributed to the HEI Excess Pay Plan.

(2)	Estimate at target range for goals achievable for all applicable plan years, pro-rated based upon service period through December 31, 2006; actual payout will depend upon performance achieved at end of plan cycle.

(3)

Value of gain on accelerated vesting of option award. Upon Termination for Cause the executive forfeits all vested and unvested NQSOs and SARs, including related DEs, valued at $1,327,181; upon Voluntary Termination and Termination Without Cause, the value of unvested equity awards lost is $332,294.

(4)	Value of accelerated lifting of restrictions on restricted stock. Restricted stock vests at a pro-rated amount upon Termination Without Cause and becomes fully vested upon a Change-in-control. For all other termination events, the unvested restricted stock is forfeited.

(5)	When the retired executive officer dies, the gross amount of the executive death benefit payable in a lump sum to his/her designated beneficiary is one times base salary at the time of retirement, grossed up for taxes; the amount shown is using a 35% tax gross up rate.

(6)	Maximum lump sum payment consisting of the five-year annual average W-2 wages times 2.99, considering additional outplacement fees and benefits, and other accelerated vesting benefits as described above.

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The following is the termination benefits table for Ms. Sekimura as of (and assuming, as applicable, death or termination on) December 31, 2006:


Benefit Plan or Program	Benefits payable for Retirement ($)	Benefits payable for Voluntary Termination ($)	Benefits payable for Termination for Cause ($)	Benefits payable for Termination without Cause ($)	Benefits payable for Change-in- control ($) (6)
HEI Plan (1)	—	NA	NA	NA	NA
HEI Excess Pay Plan (1)	—	NA	NA	NA	NA
HEI SERP (1)	NA	NA	NA	NA	NA
LTIP (2)	NA	NA	NA	NA	NA
NQSOs/SARs (3)	19,667	—	—	—	19,667
Restricted Stock (4)	NA	NA	NA	NA	NA
HEI Death Benefit Plan (5)	334,615	—	—	—	—
Change-in-control agreement	NA	NA	NA	NA	NA

NA	Not applicable.

(1)	Annual benefit accrued and available if the executive were to retire at year-end; Ms. Sekimura is not eligible to retire.

(2)	Ms. Sekimura does not participate in the LTIP.

(3)	Value of gain on accelerated vesting of option award. Upon Termination for Cause the executive forfeits all vested and unvested NQSOs and SARs, including related DEs, valued at $19,667; upon Voluntary Termination and Termination Without Cause, the value of unvested equity awards lost is $19,667.

(4)	Value of accelerated lifting of restrictions on restricted stock. Restricted stock vests at a pro-rated amount upon Termination Without Cause and becomes fully vested upon a Change-in-control. For all other termination events, the unvested restricted stock is forfeited.

(5)	When the retired executive officer dies, the gross amount of the executive death benefit payable in a lump sum to his/her designated beneficiary is one times base salary at the time of retirement, grossed up for taxes; the amount shown is using a 35% tax gross up rate.

(6)	Executive does not participate in a formal change-in-control agreement but other plans provide change-in-control benefits as described above.

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The following is the termination benefits table for Mr. Alm as of (and assuming, as applicable, death or termination on) December 31, 2006:


Benefit Plan or Program	Benefits payable for Retirement ($)	Benefits payable for Voluntary Termination ($)	Benefits payable for Termination for Cause ($)	Benefits payable for Termination without Cause ($)	Benefits payable for Change-in- control ($) (6)
HEI Plan (1)	22,602	NA	NA	NA	NA
HEI Excess Pay Plan (1)	5,350	NA	NA	NA	NA
HEI SERP (1)	NA	NA	NA	NA	NA
LTIP (2)	93,750	93,750	—	93,750	93,750
NQSOs/SARs (3)	71,503	—	—	—	71,503
Restricted Stock (4)	NA	NA	NA	NA	NA
HEI Death Benefit Plan (5)	428,308	—	—	—	—
Change-in-control agreement	NA	NA	NA	NA	NA

NA	Not applicable.

(1)	Annual benefit accrued and available if the executive were to retire at year-end.

(2)	Estimate at target range for goals achievable for all applicable plan years, pro-rated based upon service period through December 31, 2006; actual payout will depend upon performance achieved at end of plan cycle.

(3)	Value of gain on accelerated vesting of option award. Upon Termination for Cause the executive forfeits all vested and unvested NQSOs and SARs, including related DEs, valued at $168,068; upon Voluntary Termination and Termination Without Cause, the value of unvested equity awards lost is $71,503.

(4)	Value of accelerated lifting of restrictions on restricted stock. Restricted stock vests at a pro-rated amount upon Termination Without Cause and becomes fully vested upon a Change-in-control. For all other termination events, the unvested restricted stock is forfeited.

(5)	When the retired executive officer dies, the gross amount of the executive death benefit payable in a lump sum to his/her designated beneficiary is one times base salary at the time of retirement, grossed up for taxes; the amount shown is using a 35% tax gross up rate.

(6)	Executive does not participate in a formal change-in-control agreement but other plans provide change-in-control benefits as described above.

178

The following is the termination benefits table for Mr. Joaquin as of (and assuming, as applicable, death or termination on) December 31, 2006:


Benefit Plan or Program	Benefits payable for Retirement ($)	Benefits payable for Voluntary Termination ($)	Benefits payable for Termination for Cause ($)	Benefits payable for Termination without Cause ($)	Benefits payable for Change-in- control ($) (6)
HEI Plan (1)	141,818	NA	NA	NA	NA
HEI Excess Pay Plan (1)	37,305	NA	NA	NA	NA
HEI SERP (1)	NA	NA	NA	NA	NA
LTIP (2)	93,750	93,750	—	93,750	93,750
NQSOs/SARs (3)	59,041	—	—	—	59,041
Restricted Stock (4)	NA	NA	NA	NA	NA
HEI Death Benefit Plan (5)	438,769	—	—	—	—
Change-in-control agreement	NA	NA	NA	NA	NA

NA	Not applicable.

(1)	Annual benefit accrued and available if the executive were to retire at year-end.

(2)	Estimate at target range for goals achievable for all applicable plan years, pro-rated based upon service period through December 31, 2006; actual payout will depend upon performance achieved at end of plan cycle.

(3)	Value of gain on accelerated vesting of option award. Upon Termination for Cause the executive forfeits all vested and unvested NQSOs and SARs, including related DEs, valued at $178,405; upon Voluntary Termination and Termination Without Cause, the value of unvested equity awards lost is $59,041.

(4)	Value of accelerated lifting of restrictions on restricted stock. Restricted stock vests at a pro-rated amount upon Termination Without Cause and becomes fully vested upon a Change-in-control. For all other termination events, the unvested restricted stock is forfeited.

(5)	When the retired executive officer dies, the gross amount of the executive death benefit payable in a lump sum to his/her designated beneficiary is one times base salary at the time of retirement, grossed up for taxes; the amount shown is using a 35% tax gross up rate.

(6)	Executive does not participate in a formal change-in-control agreement but other plans provide change-in-control benefits as described above.

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The following is the termination benefits table for Mr. Stahlkopf as of (and assuming, as applicable, death or termination on) December 31, 2006:


Benefit Plan or Program	Benefits payable for Retirement ($)	Benefits payable for Voluntary Termination ($)	Benefits payable for Termination for Cause ($)	Benefits payable for Termination without Cause ($)	Benefits payable for Change-in- control ($) (6)
HEI Plan (1)	20,165	NA	NA	NA	NA
HEI Excess Pay Plan (1)	9,623	NA	NA	NA	NA
HEI SERP (1)	NA	NA	NA	NA	NA
LTIP (2)	112,375	112,375	—	112,375	112,375
NQSOs/SARs (3)	50,869	—	—	—	50,869
Restricted Stock (4)	—	—	—	152,040	162,900
HEI Death Benefit Plan (5)	501,538	—	—	—	—
Change-in-control agreement	NA	NA	NA	NA	NA

NA	Not applicable.

(1)	Annual benefit accrued and available if the executive were to retire at year-end.

(2)	Estimate at target range for goals achievable for all applicable plan years, pro-rated based upon service period through December 31, 2006; actual payout will depend upon performance achieved at end of plan cycle.

(3)	Value of gain on accelerated vesting of option award. Upon Termination for Cause the executive forfeits all vested and unvested NQSOs and SARs, including related DEs, valued at $50,869; upon Voluntary Termination and Termination Without Cause, the value of unvested equity awards lost is $50,869.

(4)	Value of accelerated lifting of restrictions on restricted stock. Restricted stock vests at a pro-rated amount upon Termination Without Cause and becomes fully vested upon a Change-in-control. For all other termination events, the unvested restricted stock is forfeited.

(5)	When the retired executive officer dies, the gross amount of the executive death benefit payable in a lump sum to his/her designated beneficiary is one times base salary at the time of retirement, grossed up for taxes; the amount shown is using a 35% tax gross up rate.

(6)	Executive does not participate in a formal change-in-control agreement but other plans provide change-in-control benefits as described above.

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Director compensation

Compensation of non-employee directors is determined based upon competitive studies conducted by Towers Perrin, which periodically reviews the HEI and HECO director compensation programs, including cash retainers, stock awards and perquisites. The most recent analysis on director compensation performed by Towers Perrin at the request of the HEI Compensation Committee and the HECO Board was completed in January 2005 (Directors Custom Analysis). The analysis for HECO directors considered the duties, responsibilities and roles of HECO board members, the regulatory environment in which HECO operates, and the value of the director compensation relative to a peer group of electric utilities. The Directors Custom Analysis indicated that the HECO directors’ total compensation is competitive. HECO believes that a competitive package is necessary to attract and retain individuals with the talent and skills needed for the challenging role of a director on the board of a regulated electric utility and SEC registrant. HECO chooses to compensate directors using a mix of cash and stock to allow for an appropriate level of cash compensation for services and a level of stock awards that will align the HECO Board’s interests with HEI shareholders. In 2006, the HEI Board approved transferring the responsibility for determining director compensation from the HEI Nominating and Corporate Governance Committee to the HEI Compensation Committee.

Only nonemployee directors receive compensation for their service as directors. Compensation is paid in the form of a cash retainer and stock grants. No per meeting fees are paid. David C. Cole, Timothy E. Johns, Bert A. Kobayashi, Jr., David M. Nakada, and Anne M. Takabuki, are the nonemployee directors of HECO who are not also directors of HEI. Thomas B. Fargo, James K. Scott, Kelvin H. Taketa, and Barry K. Taniguchi, who are nonemployee directors of both HECO and HEI, receive only a cash retainer from HECO as they receive a stock grant for their services as HEI directors. HECO directors serving on the HELCO and MECO boards of directors are compensated an additional $8,000 per annum for each board, paid quarterly. Ms. Takabuki and Mr. Taniguchi began service on the boards of HELCO and MECO (both wholly-owned subsidiaries of HECO), effective December 2006.

Cash compensation of $20,000 per annum is paid quarterly to nonemployee HECO directors and pro-rated for a partial year of service. Service by HECO directors on the HECO Audit Committee is compensated as follows: members on the HECO Audit Committee are compensated an additional $4,000 per annum, paid quarterly, while the HECO Audit Committee chair is paid an additional $10,000 per annum, paid quarterly.

HECO nonemployee directors who are not also on the HEI Board receive 1,000 shares of HEI Common Stock, which is granted annually for the purpose of further aligning directors’ and shareholders’ interests in improving shareholder value. A one-time grant of 600 shares is given to new HECO directors in addition to the 1,000 shares annual grant. For fiscal year 2006, each of the HECO nonemployee directors who are not also on the HEI board received 1,000 shares of HEI Common Stock except Mr. Cole and Mr. Kobayashi, who also received an additional 600 shares of HEI Common Stock as newly elected directors. Stock grants are given as soon as practical after election of directors. Stock grants to existing directors are given during the quarter of HEI’s annual meeting. HEI’s Stock Pricing and Dating Policy requires that director stock grants for 2006 be given based upon the average of the high and low sales prices of the Common Stock on the issuance date.

The HEI Stock Ownership Policy applies only to HECO directors who are also HEI directors; see HEI’s 2007 Proxy Statement for a description of this program.

Nonemployee directors may elect to participate in the HEI Nonemployee Directors’ Deferred Compensation Plan, dated September 9, 1980, as amended, which allows a nonemployee director to defer compensation from HEI or its participating subsidiaries for service as a director. No HECO director is currently participating in this plan.

The HEI Board approved a recommendation of the HEI Nominating and Corporate Governance Committee that, effective June 30, 2006, previously permitted discounts on electricity bills be discontinued for all nonemployee directors of HECO. Admiral Fargo, Mr. Johns, Mr. Myers, Mr. Nakada, Ms. Plotts, Ms. Rose, Dr. Scott, Ms. Takabuki, Mr. Taketa, Mr. Taniguchi, and Mr. Watanabe received such discounts from January 1 until June 30, 2006, which totaled less than $600 per director.

Currently, HECO directors, at their election and at their cost, may participate in the group employee medical, vision and dental plans available to HECO employees. No HECO director participated in the program during 2006.

181

Information concerning the directors of HECO who are also directors of HEI, including Admiral Fargo, Dr. Scott, Mr. Taketa and Mr. Taniguchi is set forth above under “HEI” and in the sections of HEI’s 2007 Proxy Statement that are incorporated herein by reference.

The following table shows compensation paid to directors in 2006.

DIRECTOR COMPENSATION


Name	Fees Earned or Paid in Cash ($) (1)	Stock Awards ($) (2)		Option Awards ($)	Non-Equity Incentive Plan Compen- sation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compen- sation ($)	Total ($)
Barry K. Taniguchi	31,334	—	*	—	—	—	—	31,334
Chairman Audit Committee

David C. Cole	8,333	44,070		—	—	—	—	52,403
Elected July 2006 **

Thomas B. Fargo	24,000	—	*	—	—	—	—	24,000

Timothy E. Johns	20,667	28,200		—	—	—	—	48,867

Bert A. Kobayashi, Jr.	8,333	44,070		—	—	—	—	52,403
Elected July 2006 **

A. Maurice Myers	10,000	—	*	—	—	—	—	10,000
Resigned July 2006 **

David M. Nakada	20,000	28,200		—	—	—	—	48,200

Diane J. Plotts	14,000	—	*	—	—	—	—	14,000
Resigned July 2006 **

Crystal K. Rose	10,000	28,200		—	—	—	—	38,200
Resigned July 2006 **

James K. Scott	20,000	—	*	—	—	—	—	20,000

Anne M. Takabuki	25,334	28,200		—	—	—	—	53,534

Kelvin H. Taketa	20,000	—	*	—	—	—	—	20,000

Jeffrey N. Watanabe	11,667	—	*	—	—	—	—	11,667
Resigned July 2006 **

(1)	See detail of cash retainers for board and committee service below.

(2)

Represents the value of unrestricted HEI Common Stock determined by reference to the average of the high and low sales prices on the NYSE on the date of issuance. Each of the HECO nonemployee directors, who are not also on the HEI Board, received an annual grant in June 2006 of 1,000 shares of Common Stock with a fair value of $28,200. New HECO directors received an initial grant upon election in August 2006 of 600 shares of Common Stock with a fair value of $16,770 and an annual grant in August 2006 of 1,000 shares of Common Stock with a fair value of $27,300.

Also an HEI director who received an HEI stock retainer, but no additional retainer for HECO service. Information concerning the stock retainer available to HECO directors who are also HEI directors is incorporated herein by reference to the information relating to director compensation in HEI’s 2007 Proxy Statement.

**	In July 2006, the HECO Board was restructured as part of an overall board realignment.

182

Details of 2006 annual cash retainers for HECO board and committee service, which retainers are prorated for partial year service, are noted below:


Name	HECO Board Retainer ($)	HECO Audit Committee Retainer ($)	HELCO Board Retainer ($)	MECO Board Retainer ($)	Fees Earned or Paid in Cash ($)
Barry K. Taniguchi	20,000	10,000	667	667	31,334

David C. Cole	8,333	—	—	—	8,333

Thomas B. Fargo	20,000	4,000	—	—	24,000

Timothy E. Johns	20,000	667	—	—	20,667

Bert A. Kobayashi, Jr.	8,333	—	—	—	8,333

A. Maurice Myers	10,000	—	—	—	10,000

David M. Nakada	20,000	—	—	—	20,000

Diane J. Plotts	11,667	2,333	—	—	14,000

Crystal K. Rose	10,000	—	—	—	10,000

James K. Scott	20,000	—	—	—	20,000

Anne M. Takabuki	20,000	4,000	667	667	25,334

Kelvin H. Taketa	20,000	—	—	—	20,000

Jeffrey N. Watanabe	11,667	—	—	—	11,667

183

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

HEI:

Certain of the information required under this item is incorporated herein by reference to the sections relating to stock ownership in HEI’s 2007 Proxy Statement.

Equity compensation plan information

Information as of December 31, 2006 about HEI common stock that may be issued upon the exercise of awards granted under all of the Company’s equity compensation plans was as follows:


Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (2)
Equity compensation plans approved by shareholders	866,747	$	23.36	4,213,586
Equity compensation plans not approved by shareholders	—		—	—

Total	866,747	$	23.36	4,213,586

(1)	Includes 660,000 of outstanding NQSOs and 123,632 of DEs accrued as of December 31, 2006 for such NQSOs. Also includes the 37,041 of outstanding converted SARs and 46,074 of DEs accrued as of December 31, 2006 for SARs.

(2)

This represents the number of shares remaining available as of December 31, 2006, including 4,117,908, net of any shares underlying outstanding grants, under the SOIP and 95,678 under the HEI Nonemployee Director Plan. All of the shares remaining available for issuance under the HEI Nonemployee Director Plan may be issued in the form of unrestricted Common Stock. Of the shares remaining available for issuance under the SOIP, 361,200 shares may be issued in the form of restricted stock, stock payments, or stock-settled restricted stock units (i.e., other than in the form of options, warrants or rights).

184

HECO:

HEI owns all of HECO’s common stock, which is HECO’s only class of securities generally entitled to vote on matters requiring shareholder approval. HECO has also issued and has outstanding various series of preferred stock, the holders of which, upon certain defaults in dividend payments, have the right to elect a majority of the directors of HECO.

The following table shows the shares of HEI common stock beneficially owned by each HECO director (other than those who are also directors of HEI as to whom such beneficial ownership information is incorporated by reference to the section relating to stock ownership in HEI’s 2007 Proxy Statement), by each HECO NEO and by all HECO directors and all HECO executive officers as a group, as of February 26, 2007 (except HEIRSP, whose information is as of December 31, 2006), based on information furnished by the respective individuals.


Amount of Common Stock and Nature of Beneficial Ownership
Name of Individual or Group	Sole Voting or Investment Power	Shared Voting or Investment Power (1)	Other Beneficial Ownership (2)	Stock Options (3)	Total
Directors
David C. Cole	1,600	—	—	—	1,600
Timothy E. Johns	2,940	—	—	—	2,940
Bert A. Kobayashi, Jr.	1,618	—	—	—	1,618
David M. Nakada	3,072	—	—	—	3,072
Anne M. Takabuki	9,602	—	—	—	9,602

HECO NEOs
T. Michael May	45,384	—	—	121,537	166,921
Tayne S. Y. Sekimura	1,481	—	—	—	1,481
Robert A. Alm	11,020	—	1,497	13,957	26,474
Thomas L. Joaquin	16,917	3,670	—	15,782	36,369
Karl E. Stahlkopf	6,295	—	—	3,177	9,472
All directors and executive officers as a group (25 persons)	249,437	22,361	12,673	467,896	752,367

HECO directors Lau, Fargo, Scott, Taketa and Taniguchi, who also serve on the HEI Board, are not shown separately in this table, but are included in the total for all HECO directors and executive officers as a group. The number of shares of common stock beneficially owned by any HECO director or by all HECO directors and HECO executive officers as a group does not exceed 1% of the outstanding common stock of HEI.

(1)	Shares registered in name of the individual and spouse.

(2)	Shares owned by spouse, children or other relatives sharing the home of the director or officer in which the director or officer disclaims personal interest.

(3)	NQSOs, SARs, and accompanying DEs, exercisable within 60 days after February 26, 2007, under the SOIP.

185

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

HEI:

The information required under this item for HEI is incorporated herein by reference to the sections relating to indebtedness of management and transactions with directors and executive officers in HEI’s 2007 Proxy Statement.

HECO:

On December 15, 2006, the HEI Board adopted a written Related Person Transactions Policy to provide for transparency in reporting and disclosures. The policy requires that directors, director nominees and officers of HEI and its subsidiaries disclose all relevant facts and circumstances concerning any related person transaction to the Compliance Officers of HEI and the respective subsidiary prior to entering any related person transaction. These transactions are then reviewed by the appropriate HEI and/or subsidiary committee and approved only if determination is made that the related person transaction is not inconsistent with the best interests of HEI, its subsidiaries, or shareholders and that the transaction is not in violation of HEI’s Code of Conduct. Consideration of the transaction includes, but is not limited to, benefits and risks to HEI and/or the applicable subsidiary, impact on director independence (if the transaction involves a director or director nominee), impact on the ability to perform his or her duties without actual/perceived/potential conflicts of interest, terms of the transaction and terms available to unrelated third parties or employees generally. No director may review, consider or approve employment of his or her own immediate family member. The decision of the appropriate committee is then presented to the applicable company’s Board for ratification.

The policy also states that no immediate family member of a director or officer may be hired as an employee of HEI or its subsidiaries without prior approval by the appropriate committee. If an individual becomes a director or officer of HEI or its subsidiaries and an immediate family member of that individual is already an employee of HEI or its subsidiaries, prior approval by the appropriate committee is required before any material change in the employee’s terms of employment (including compensation) may be made.

There has been no transaction in 2006 and there are no currently proposed transactions, in which HECO was or is to be a participant and the amount involved exceeds $120,000 in which a related person had or will have a direct or indirect material interest. Information required under this Item with respect to transactions in which HEI or another HEI affiliated company was or is to be a participant is incorporated by reference herein to HEI’s 2007 Proxy Statement.

186

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

HEI:

The information required under this item is incorporated herein by reference to the relevant information in the section relating to the Audit Committee Report in HEI’s 2007 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated by reference).

HECO:

Certain information required as to HECO under this item is included in the disclosures for HEI in the Audit Committee Report section in HEI’s 2007 Proxy Statement, which is incorporated by reference to the extent set forth above.

Fees of HECO’s Principal Accountant

The following table sets forth the fees paid or payable to KPMG LLP (HECO’s independent registered public accounting firm) relating to the audit of the 2006 consolidated financial statements and fees for other professional services billed in 2006 with comparative amounts for 2005:


	2006		2005
Audit fees (principally consisted of fees associated with the audit of the consolidated financial statements and internal control over financial reporting, quarterly reviews, issuances of letters to underwriters, accounting consultations on matters reflected in the financial statements, review of registration statements, and issuance of consents)	$	877,000	$	907,000
Audit related fees (principally consisted of fees associated with the audit of the financial statements of certain employee benefit plans)		11,000		24,000
Tax fees		—		—
		—		—

All other fees	$	888,000	$	931,000

Pre-approval Policies

The HECO Audit Committee revised its preapproval policies and procedures for nonaudit services proposed to be performed by HECO’s independent registered public accounting firm. Departmental requests for nonaudit services are reviewed by senior management and, once found by management to be acceptable, will be sent to the HECO Audit Committee for approval via unanimous written consent or at a meeting of the HECO Audit Committee. The HECO Audit Committee, pursuant to the terms of its charter, approves all audit services to be performed by the independent registered public accounting firm.

187

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial statements

The financial statements for HEI are included in this report on the pages indicated below and incorporated herein by reference and the financial statements for HECO are incorporated herein by reference to pages 4 to 44 of HECO Exhibit 99.4:


	Page/s in Form 10-K	Pages in HECO Exhibit 99.4
	HEI	HECO
Report of Independent Registered Public Accounting Firm	146	4
Consolidated Statements of Income, Years ended December 31, 2006, 2005 and 2004	97	5
Consolidated Statements of Retained Earnings, Years ended December 31, 2006, 2005 and 2004	NA	5
Consolidated Balance Sheets, December 31, 2006 and 2005	98	6
Consolidated Statements of Capitalization, December 31, 2006 and 2005	NA	7-8
Consolidated Statements of Changes in Stockholders’ Equity, Years ended December 31, 2006, 2005 and 2004	99	NA
Consolidated Statements of Cash Flows, Years ended December 31, 2006, 2005 and 2004	100	9
Notes to Consolidated Financial Statements	101-145	10-44

NA	Not applicable.

(a)(2) and (c) Financial statement schedules

The following financial statement schedules for HEI and HECO are included in this report on the pages indicated below:


		Page/s in Form 10-K
		HEI	HECO
Report of Independent Registered Public Accounting Firm		189	190
Schedule I	Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2006 and 2005 and Years ended December 31, 2006, 2005 and 2004	191-193	NA
Schedule II	Valuation and Qualifying Accounts, Years ended December 31, 2006, 2005 and 2004	194	194

NA	Not applicable.

Certain schedules, other than those listed, are omitted because they are not required, or are not applicable, or the required information is shown in the consolidated financial statements (including the notes) included in HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements, which are included and incorporated by reference, respectively, in this report.

188

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Hawaiian Electric Industries, Inc.:

Under date of February 28, 2007, we reported on the consolidated balance sheets of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2006, which are included in the Company’s annual report on Form 10-K for the year 2006. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedules as listed in the accompanying index under Item 15.(a)(2). These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.

In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), Share-Based Payment, and effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).

/s/ KPMG LLP

Honolulu, Hawaii

February 28, 2007

189

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

Under date of February 28, 2007, we reported on the consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. (a subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, retained earnings and cash flows for each of the years in the three-year period ended December 31, 2006, which are included in the Company’s annual report on Form 10-K for the year 2006. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedule as listed in the accompanying index under Item 15.(a)(2). The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement schedule based on our audits.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).

/s/ KPMG LLP

Honolulu, Hawaii

February 28, 2007

190

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS


December 31	2006			2005
(dollars in thousands)

Assets
Cash and equivalents	$	984		$	1,172
Accounts receivable		1,611			1,187
Property, plant and equipment, net		1,298			1,840
Deferred income tax assets		28,491			27,156
Other assets		5,786			7,448
Net assets of discontinued operations		1,775			—
Intangibles		—			201
Investments in subsidiaries, at equity		1,565,056			1,657,519

	$	1,605,001		$	1,696,523

Liabilities and stockholders’ equity
Liabilities
Accounts payable	$	7,827		$	11,382
Notes payable to subsidiaries		55,880			62,430
Commercial paper		63,164			5,593
Long-term debt, net		367,000			377,000
Other		15,890			11,753
Net liabilities of discontinued operations		—			11,735

		509,761			479,893

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: 81,461,409 shares and 80,983,326 shares		1,028,101			1,018,966
Retained earnings		242,667			235,394
Accumulated other comprehensive loss		(175,528	)		(37,730	)

		1,095,240			1,216,630

	$	1,605,001		$	1,696,523

Note to Balance Sheets
Long-term debt consisted of :
HEI medium-term notes 6.545-7.56%, paid in 2006	$	—		$	110,000
HEI medium-term notes 4.00-4.23%, due 2008- 2011		100,000			100,000
HEI medium-term notes 5.25-6.14%, due 2011-2013		150,000			50,000
HEI medium-term notes 6.51-6.93%, due 2007-2014		110,000			110,000
HEI medium-term note 7.13%, due 2012		7,000			7,000

	$	367,000		$	377,000

The aggregate payments of principal required subsequent to December 31, 2006 on long-term debt are $10 million in 2007, $50 million in 2008 and nil in 2009 and 2010 and $150 million in 2011.

As of December 31, 2006, HEI has a General Agreement of Indemnity in favor of both SAFECO Insurance Company of America (SAFECO) and Travelers Casualty and Surety Company of America (Travelers) for losses in connection with any and all bonds, undertakings or instruments of guarantee and any renewals or extensions thereof executed by SAFECO or Travelers, including, but not limited to, a $3.2 million MECO performance bond and a $0.5 million self-insured automobile bond.

191

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME


Years ended December 31	2006			2005			2004
(in thousands)

Revenues ¹	$	(456	)	$	824		$	8,049

Equity in income from continuing operations of subsidiaries		132,584			156,787			128,465

		132,128			157,611			136,514

Expenses:

Operating, administrative and general		12,147			14,792			14,945

Depreciation of property, plant and equipment		262			285			328

Taxes, other than income taxes		516			388			340

		12,925			15,465			15,613

Operating income		119,203			142,146			120,901

Interest expense		25,891			27,114			28,029

Income from continuing operations before income tax benefits		93,312			115,032			92,872

Income tax benefits		14,689			12,412			14,867

Income from continuing operations		108,001			127,444			107,739

Income (loss) from discontinued subsidiary operations		—			(755	)		1,913

Net income	$	108,001		$	126,689		$	109,652

¹	2006 revenues include a writedown of real property held for sale. 2004 revenues include $5.6 million from the gain on the sale of income notes in 2004.

The Company’s financial reporting policy for income tax allocations is based upon a separate entity concept whereby each subsidiary provides income tax expense (or benefits) as if each were a separate taxable entity. The difference between the aggregate separate tax return income tax provisions and the consolidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.

192

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS


	Years ended December 31,
(in thousands)	2006			2005			2004
Cash flows from operating activities
Net income	$	108,001		$	126,689		$	109,652
Adjustments to reconcile net income to net cash provided by operating activities
Equity in net income of continuing subsidiaries		(132,584	)		(156,787	)		(128,465	)
Common stock dividends/distributions received from subsidiaries		77,662			86,234			19,828
Depreciation of property, plant and equipment		262			285			328
Other amortization		424			458			452
Gain on sale of income notes		—			—			(5,607	)
Deferred income taxes		1,550			(7,142	)		(399	)
Excess tax benefits from share-based payment arrangements		(1,052	)		—			—
Changes in assets and liabilities
Decrease (increase) in accounts receivable		(424	)		491			10,292
Increase (decrease) in accounts payable		(3,555	)		2,164			868
Increase (decrease) in taxes accrued		(777	)		1,585			(4,684	)
Changes in other assets and liabilities		(2,592	)		16,368			642

Net cash provided by operating activities		46,915			70,345			2,907

Cash flows from investing activities
Net decrease (increase) in advances to and notes receivable from subsidiaries		—			11,957			(5,957	)
Capital expenditures		(530	)		(307	)		(331	)
Additional (investments in) distributions to subsidiaries		(60	)		10			(70	)
Distribution from unconsolidated subsidiaries		—			—			21,817
Net proceeds from sale of investment		—			—			9,981
Proceeds from sale of fixed assets		8			—			—

Net cash provided by (used in) investing activities		(582	)		11,660			25,440

Cash flows from financing activities
Net increase (decrease) in notes payable to subsidiaries with original maturities of three months or less		(6,550	)		39,683			8,376
Net proceeds from issuance of short-term borrowings with original maturities of three months or less		58,270			5,593			—
Proceeds from issuance of short-term borrowings with original maturities greater than three months		44,891			—			—
Repayments of short-term borrowings with original maturities greater than three months		(45,590	)		—			—
Proceeds from issuance of long-term debt		100,000			—			50,000
Repayment of long-term debt		(110,000	)		(37,000	)		(104,000	)
Excess tax benefits from share-based payment arrangements		1,052			—			—
Net proceeds from issuance of common stock		5,481			3,689			110,017
Common stock dividends		(100,673	)		(100,238	)		(93,864	)
Other		(938	)		—			—

Net cash used in financing activities		(54,057	)		(88,273	)		(29,471	)

Cash flows from discontinued operations (revised—see below)
Cash flows provided by (used in) operating activities		7,536			(2,857	)		(6,588	)
Cash flows provided by investing activities		—			—			6,000

Net cash provided by (used in) discontinued operations		7,536			(2,857	)		(588	)

Net decrease in cash and equivalents		(188	)		(9,125	)		(1,712	)
Cash and equivalents, January 1		1,172			10,297			12,009

Cash and equivalents, December 31	$	984		$	1,172		$	10,297

Revised cash flows from discontinued operations:

HEI has separately disclosed the operating and investing portion of the cash flows attributable to its discontinued operations for 2004, which in prior periods were reported on a combined basis as a single amount. For 2006, 2005 and 2004, there were no cash flows from financing activities from the Company’s discontinued operations.

Supplemental disclosures of noncash activities:

In 2006, 2005 and 2004, $1.6 million, $1.0 million and $0.9 million, respectively, of HEI advances to HEIDI were converted to equity in noncash transactions.

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $5 million in 2004. Since March 2004, HEI has been satisfying the requirements of the 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 December 15, 2006, however, the HEI Board of Directors determined that the common stock requirements for the DRIP and HEIRSP will be satisfied by issuance of new HEI shares, commencing in March 2007.

193

Hawaiian Electric Industries, Inc.

and Hawaiian Electric Company, Inc.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2006, 2005 and 2004


Col. A	Col. B		Col. C						Col. D			Col. E
(in thousands)			Additions
Description	Balance at begin- ning of period		Charged to costs and expenses			Charged to other accounts			Deductions			Balance at end of period
2006
Allowance for uncollectible accounts–
Hawaiian Electric Company, Inc. and subsidiaries	$	986	$	2,684		$	979	(a)	$	2,975	(b)	$	1,674

Allowance for uncollectible interest (ASB)	$	99		—			—		$	56		$	43

Allowance for losses for loans receivable (ASB)	$	30,595	$	1,400		$	1,118	(a)	$	1,885	(b)	$	31,228

2005
Allowance for uncollectible accounts–
Hawaiian Electric Company, Inc. and subsidiaries	$	805	$	1,198		$	943	(a)	$	1,960	(b)	$	986

Allowance for uncollectible interest (ASB)	$	98	$	1			—			—		$	99

Allowance for losses for loans receivable (ASB)	$	33,857	$	(3,100	)	$	1,852	(a)	$	2,014	(b)	$	30,595

2004
Allowance for uncollectible accounts–
Hawaiian Electric Company, Inc. and subsidiaries	$	907	$	1,126		$	947	(a)	$	2,175	(b)	$	805

Allowance for uncollectible interest (ASB)	$	155		—			—		$	57		$	98

Allowance for losses for loans receivable (ASB)	$	44,285	$	(8,400	)	$	2,281	(a)	$	4,309	(b)	$	33,857

(a)	Primarily bad debts recovered.

(b)	Bad debts charged off.

194

(a)(3) and (b) Exhibits

The Exhibit Index attached to this Form 10-K is incorporated herein by reference. The exhibits listed for HEI and HECO are listed in the index under the headings “HEI” and “HECO,” respectively, except that the exhibits listed under “HECO” are also considered exhibits for HEI.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 execution of this report by registrant Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.


HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)		(Registrant)

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

Date: February 28, 2007		Date: February 28, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities indicated on February 28, 2007. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.


Signature				Title

/s/ Constance H. Lau				President of HEI and Director of HEI
Constance H. Lau				Chairman of the Board of Directors of HECO
				(Chief Executive Officer of HEI)

/s/ T. Michael May				President and Director of HECO
T. Michael May				(Chief Executive Officer of HECO)

/s/ Eric K. Yeaman				Financial Vice President, Treasurer and
Eric K. Yeaman				Chief Financial Officer of HEI
				(Principal Financial Officer of HEI)

/s/ Curtis Y. Harada				Controller of HEI
Curtis Y. Harada				(Principal Accounting Officer of HEI)

195

SIGNATURES (continued)


Signature				Title

/s/ Tayne S. Y. Sekimura				Financial Vice President
Tayne S. Y. Sekimura				(Principal Financial Officer of HECO)

/s/ Patsy H. Nanbu				Controller of HECO
Patsy H. Nanbu				(Principal Accounting Officer of HECO)

/s/ Don E. Carroll				Director of HEI
Don E. Carroll

/s/ David C. Cole				Director of HECO
David C. Cole

/s/ Shirley J. Daniel				Director of HEI
Shirley J. Daniel

/s/ Thomas B. Fargo				Director of HEI and HECO
Thomas B. Fargo

/s/ Timothy E. Johns				Director of HECO
Timothy E. Johns

/s/ Bert A. Kobayashi, Jr.				Director of HECO
Bert A. Kobayashi, Jr.

/s/ Victor Hao Li				Director of HEI
Victor Hao Li

196

SIGNATURES (continued)


Signature				Title

/s/ Bill D. Mills				Director of HEI
Bill D. Mills

/s/ A. Maurice Myers				Director of HEI
A. Maurice Myers

/s/ David M. Nakada				Director of HECO
David M. Nakada

/s/ Diane J. Plotts				Director of HEI
Diane J. Plotts

/s/ James K. Scott				Director of HEI and HECO
James K. Scott

/s/ Anne M. Takabuki				Director of HECO
Anne M. Takabuki

/s/ Kelvin H. Taketa				Director of HEI and HECO
Kelvin H. Taketa

/s/ Barry K. Taniguchi				Director of HEI and HECO
Barry K. Taniguchi

/s/ Jeffrey N. Watanabe				Chairman of the Board of Directors of HEI and Director of HEI
Jeffrey N. Watanabe

197

EXHIBIT INDEX

The exhibits designated by an asterisk (*) are filed herewith. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.


Exhibit no.		Description
HEI:
3(i).1		HEI’s Restated Articles of Incorporation (Exhibit 4(b) to Registration Statement on Form S-3, Registration No. 33-7895).

3(i).2		Articles of Amendment of HEI, amending HEI’s Restated Articles of Incorporation (Exhibit 4(b) to Registration Statement on Form S-3, Registration No. 33-40813).

3(i).3		Statement of Issuance of Shares of Preferred or Special Classes in Series for HEI Series A Junior Participating Preferred Stock (Exhibit 3(i).3 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-8503).

3(i).4		Articles of Amendment of HEI, amending HEI’s Restated Articles of Incorporation, Article Fourth (Exhibit 3(i).4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, File No. 1-8503).

3(i).5		Articles of Amendment of HEI, amending HEI’s Restated Articles of Incorporation, Article Sixth (Exhibit 3(i).5 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, File No. 1-8503).

3(ii)		HEI’s Amended and Restated By-Laws (Exhibit 3(ii) to HEI’s Current Report on Form 8-K, dated January 26, 2007, File No. 1-8503).

4.1		Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HEI and its subsidiaries (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

4.2(a)		Rights Agreement, dated as of October 28, 1997, between HEI and Continental Stock Transfer & Trust Company, as Rights Agent, which includes as Exhibit B thereto the Form of Rights Certificates (Exhibit 1 to HEI’s Form 8-A, dated October 28, 1997, File No. 1-8503).

4.2(b)		First Amendment, dated as of May 7, 2003, to Rights Agreement (dated as of October 28, 1997) between HEI and Continental Stock Transfer & Trust Company, as Rights Agent (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, File No. 1-8503).

4.2(c)		Second Amendment to Rights Agreement, dated as of October 26, 2004, between HEI and Continental Stock Transfer & Trust Company, as Rights Agent (Exhibit 4 to HEI’s Current Report on Form 8-K, dated October 26, 2004, File No. 1-8503).

4.3		Indenture, dated as of October 15, 1988, between HEI and Citibank, N.A., as Trustee (Exhibit 4 to Registration Statement on Form S-3, Registration No. 33-25216).

4.4(a)		First Supplemental Indenture dated as of June 1, 1993 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4(a) to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993, File No. 1-8503).

4.4(b)		Second Supplemental Indenture dated as of April 1, 1999 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, File No. 1-8503).

4.4(c)		Third Supplemental Indenture dated as of August 1, 2002 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4 to HEI’s Current Report on Form 8-K, dated August 16, 2002, File No. 1-8503).

4.5(a)		Pricing Supplements Nos. 13 through 14 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 26, 1997 in connection with the sale of Medium-Term Notes, Series B.

4.5(b)		Pricing Supplement No. 15 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 29, 1997 in connection with the sale of Medium-Term Notes, Series B.

4.5(c)		Pricing Supplement No. 1 to Registration Statement on Form S-3 of HEI (Registration No. 333-73225) filed on May 3, 1999 in connection with the sale of Medium-Term Notes, Series C.


Exhibit no.		Description
4.5(d)		Pricing Supplement No. 1 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on March 5, 2003 in connection with the sale of Medium-Term Notes, Series D.

4.5(e)		Pricing Supplement No. 2 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on March 5, 2003 in connection with the sale of Medium-Term Notes, Series D.

4.5(f)		Pricing Supplement No. 3 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on March 15, 2004 in connection with the sale of Medium-Term Notes, Series D.

4.5(g)		Pricing Supplement No. 4 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on August 4, 2006 in connection with the sale of Medium-Term Notes, Series D.

*10.1		Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc. dated September 23, 1982.

10.2		Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home Loan Bank of Seattle) (Exhibit (28)-2 to HEI’s Current Report on Form 8-K dated May 26, 1988, File No. 1-8503).

10.3		OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

HEI Exhibits 10.4 through 10.19 are management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 through 10.17 are management contracts or compensatory plans or arrangements with HECO participants.

10.4		Executive Incentive Compensation Plan (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, File No. 1-8503).

10.5		HEI Executives’ Deferred Compensation Plan (Exhibit 10.5 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990, File No. 1-8503).

10.6		Form of HEI and HECO Executives’ Deferred Compensation Agreement. The agreement pertains to and is substantially identical for all the HEI and HECO executive officers (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-8503).

10.7(a)		1987 Stock Option and Incentive Plan of HEI as amended and restated effective April 20, 2004 (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-8503).

10.7(b)		Form of Hawaiian Electric Industries, Inc. Stock Option Agreement with Dividend Equivalents (Exhibit 10.7(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-8503).

10.7(c)		Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-8503).

10.7(d)		Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents (effective for April 7, 2005 stock appreciation rights grant) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8503).

10.7(e)		Form of Restricted Stock Agreement Pursuant to the 1987 Stock Option and Incentive Plan of Hawaiian Electric Industries, Inc. (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8503).

10.8		HEI Long-Term Incentive Plan. (Exhibit 10.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, File No. 1-8503).

10.9		HEI Supplemental Executive Retirement Plan effective as of January 1, 1989 (Exhibit 10.8(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.10		HEI Excess Pay Supplemental Executive Retirement Plan (Exhibit 10.8(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.11		HEI Excess Benefit Plan effective as of January 1, 1994 (Exhibit 10.9 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).


Exhibit no.		Description
10.12		Form of Change-in-Control Agreement (Exhibit 10.14 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).

10.13		Nonemployee Director Retirement Plan, effective as of October 1, 1989 (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).

10.14		HEI 1990 Nonemployee Director Stock Plan, As Amended and Restated, effective May 2, 2006 (Exhibit 10 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 1-8503).

10.15		Nonemployee Director’s Compensation Schedule, as of April 1, 2005 (Exhibit 10.3 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8503).

10.16		HEI Nonemployee Directors’ Deferred Compensation Plan (Exhibit 10.14 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990, File No. 1-8503).

10.17		HEI Executive Death Benefit Plan of HEI and Participating Subsidiaries effective September 1, 2001 (Exhibit 10.16 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8503).

10.18		American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2005) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-8503).

10.19		American Savings Bank Supplemental Retirement, Disability, and Death Benefit Plan, effective January 1, 1996 (Exhibit 10.20 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-8503).

10.20		Credit Agreement, dated as of March 31, 2006, among HEI, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and First Hawaiian Bank, as Co-Syndication Agent, and Wells Fargo Bank, N.A., as Co-Documentation Agent, and U.S. Bank National Association, as Co-Documentation Agent, and Union Bank of California, N.A., as Co-Documentation Agent, and The Bank of New York, as Administrative Agent, and BNY Capital Markets, Inc., as Sole Lead Arranger and Book Runner (Exhibit 10.1 to HEI’s Current Report on Form 8-K, dated April 3, 2006, File No. 1-8503)

*11		Computation of Earnings per Share of Common Stock.

*12		Computation of Ratio of Earnings to Fixed Charges.

13		HEI’s 2006 Annual Report to Shareholders (Appendix A to HEI’s 2007 Proxy Statement to be filed).

*21		Subsidiaries of HEI.

*23.1		Consent of Independent Registered Public Accounting Firm.

*31.1		Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer).

*31.2		Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Eric K. Yeaman (HEI Chief Financial Officer).

*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.

*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.

99.1(a)		Hawaiian Electric Industries Retirement Savings Plan, as amended and restated, adopted December 28, 2000 (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-8501).

99.1(b)		Amendment 2001-1 to Hawaiian Electric Industries Retirement Savings Plan, adopted October 29, 2001 (Item 7, Exhibit 99 to HEI’s Current Report on Form 8-K, dated November 27, 2001, File No. 1-8501).

99.1(c)		Amendment 2002-1 to Hawaiian Electric Industries Retirement Savings Plan, adopted February 28, 2002 (Exhibit 99.2 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8501).

99.1(d)		Amendment 2002-2 to Hawaiian Electric Industries Retirement Savings Plan, adopted May 31, 2002 (Exhibit 99.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8501).

99.1(e)		Amendment 2002-3 to Hawaiian Electric Industries Retirement Savings Plan, adopted December 23, 2002 (Exhibit 99.3 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8501).


Exhibit no.		Description
99.1(f)		Amendment 2003-1 to Hawaiian Electric Industries Retirement Savings Plan, adopted March 14, 2003 (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, File No. 1-8501).

99.1(g)		Amendment 2003-2 to Hawaiian Electric Industries Retirement Savings Plan, adopted December 22, 2003 (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-8501).

99.1(h)		Amendment 2005-1 to Hawaiian Electric Industries Retirement Savings Plan, executed June 16, 2005 (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8501).

*99.1(i)		Amendment 2006-1 to Hawaiian Electric Industries Retirement Savings Plan, executed December 29, 2006.

99.2(a)		Trust Agreement dated as of February 1, 2000 between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1999, File No. 1-8501).

99.2(b)		First Amendment dated as of August 1, 2000 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8501).

99.2(c)		Second Amendment dated as of November 1, 2000 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8501).

99.2(d)		Third Amendment dated as of April 1, 2001 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99 to HEI’s Current Report on Form 8-K dated June 19, 2001, File No. 1-8501).

99.2(e)		Fourth Amendment dated as of December 31, 2001 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8501).

99.2(f)		Fifth Amendment dated as of April 1, 2002, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8501).

99.2(g)		Sixth Amendment dated as of January 1, 2002, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.8 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8501).

99.2(h)		Seventh Amendment dated as of July 1, 2002, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 1-8501).

99.2(i)		Eighth Amendment dated as of September 1, 2003, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8501).

99.2(j)		Ninth Amendment dated as of February 2, 2004, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-8501).

99.2(k)		Tenth Amendment dated as of October 3, 2005, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(k) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, File No. 1-8501).

*99.2(l)		Eleventh Amendment dated as of November 1, 2006, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee.
HECO:

3(i).1		HECO’s Certificate of Amendment of Articles of Incorporation (Exhibit 3.1 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

3(i).2		Articles of Amendment to HECO’s Amended Articles of Incorporation (Exhibit 3.1(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No 1-4955).

3(i).3		Articles of Amendment to HECO’s Amended Articles of Incorporation (Exhibit 3(i).4 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No 1-4955).


Exhibit no.		Description
*3(ii)		HECO’s By-Laws.

4.1		Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HECO, HELCO and MECO (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-4955).

4.2		Certificate of Trust of HECO Capital Trust III (incorporated by reference to Exhibit 4(a) to Registration No. 333-111073).

4.3		Amended and Restated Trust Agreement of HECO Capital Trust III dated as of March 1, 2004 (Exhibit 4(c) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.4		HECO Junior Indenture with The Bank of New York, as Trustee, dated as of March 1, 2004 (Exhibit 4(f) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.5		6.500% Quarterly Income Trust Preferred Security issued by HECO Capital Trust III, dated March 18, 2004 (Exhibit 4(d) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.6		6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by HECO, dated March 18, 2004 (Exhibit 4(g) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.7		Trust Guarantee Agreement between The Bank of New York, as Trust Guarantee Trustee, and HECO dated as of March 1, 2004 (Exhibit 4(l) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.8		MECO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(h) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.9		HELCO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(j) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.10		6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by MECO, dated March 18, 2004 (Exhibit 4(i) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.11		6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by HELCO, dated March 18, 2004 (Exhibit 4(k) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

4.12		Expense Agreement, dated March 1, 2004, among HECO Capital Trust III, HECO, MECO and HELCO (Exhibit 4(m) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

10.1(a)		Power Purchase Agreement between Kalaeloa Partners, L.P., and HECO dated October 14, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1988, File No. 1-4955).

10.1(b)		Amendment No. 1 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated June 15, 1989 (Exhibit 10(c) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.1(c)		Lease Agreement between Kalaeloa Partners, L.P., as Lessor, and HECO, as Lessee, dated February 27, 1989 (Exhibit 10(d) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.1(d)		Restated and Amended Amendment No. 2 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated February 9, 1990 (Exhibit 10.2(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.1(e)		Amendment No. 3 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated December 10, 1991 (Exhibit 10.2(e) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-4955).

10.1(f)		Amendment No. 4 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 1, 1999 (Exhibit 10.1 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

10.1(g)		Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.3 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).

10.1(h)		Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement between HECO and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.4 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).

10.2(a)		Power Purchase Agreement between AES Barbers Point, Inc. and HECO, entered into on March 25, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, File No. 1-4955).


Exhibit no.		Description
10.2(b)		Agreement between HECO and AES Barbers Point, Inc., pursuant to letters dated May 10, 1988 and April 20, 1988 (Exhibit 10.4 to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 1988, File No. 1-4955).

10.2(c)		Amendment No. 1, entered into as of August 28, 1988, to Power Purchase Agreement between AES Barbers Point, Inc. and HECO (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, File No. 1-4955).

10.2(d)		HECO’s Conditional Notice of Acceptance to AES Barbers Point, Inc. dated January 15, 1990 (Exhibit 10.3(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.2(e)		Amendment No. 2, entered into as of May 8, 2003, to Power Purchase Agreement between AES Hawaii, Inc. and HECO (Exhibit 10.2(e) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2003, File No. 1-4955).

10.3(a)		Agreement between MECO and Hawaiian Commercial & Sugar Company pursuant to letters dated November 29, 1988 and November 1, 1988 (Exhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

10.3(b)		Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989 (Exhibit 10(e) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

10.3(c)		First Amendment to Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 1, 1990, amending the Amended and Restated Power Purchase Agreement dated November 30, 1989 (Exhibit 10(f) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

10.3(d)		Letter agreement dated December 11, 1997 to Extend Term of Amended and Restated Power Purchase Agreement Between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO dated November 30, 1989, as Amended on November 1, 1990 (Exhibit 10.4(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.3(e)		Letter agreement dated October 22, 1998 to Extend Term of Amended and Restated Power Purchase Agreement Between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO dated November 30, 1989, as Amended on November 1, 1990 (Exhibit 10.4(d) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

10.3(f)		Termination Notice dated December 27, 1999 for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.2 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

10.3(g)		Rescission dated January 23, 2001 of Termination Notice for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.4(f) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.4(a)		Purchase Power Contract between HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.4(b)		Firm Capacity Amendment between HELCO and Puna Geothermal Venture (assignee of AMOR VIII, who is the assignee of Thermal Power Company) dated July 28, 1989 to Purchase Power Contract between HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(b) to HECO’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

10.4(c)		Amendment made in October 1993 to Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.4(d)		Third Amendment dated March 7, 1995 to the Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.4(e)		Performance Agreement and Fourth Amendment dated February 12, 1996 to the Purchase Power Contract between HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-4955).


Exhibit no.		Description
10.5(a)		Purchase Power Contract between HECO and the City and County of Honolulu dated March 10, 1986 (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

10.5(b)		Amendment No. 1 to Purchase Power Contract between HECO and the City and County of Honolulu dated March 10, 1986 (Exhibit 10.6 (a) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.5(c)		Firm Capacity Amendment, dated April 8, 1991, to Purchase Power Contract, dated March 10, 1986, by and between HECO and the City & County of Honolulu (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, File No. 1-4955).

10.5(d)		Amendment No. 2 to Purchase Power Contract Between HECO and City and County of Honolulu dated March 10, 1986 (Exhibit 10.6(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.6(a)		Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (but with the following attachments omitted: Attachment C, “Selected portions of the North American Electric Reliability Council Generating Availability Data System Data Reporting Instructions dated October 1996” and Attachment E, “Form of the Interconnection Agreement between Encogen Hawaii, L.P. and HELCO,” which is provided in final form as Exhibit 10.6(b)) (Exhibit 10.7 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.6(b)		Interconnection Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(a) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.6(c)		Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

10.6(d)		Power Purchase Agreement Novation dated November 8, 1999 by and among Encogen Hawaii, L.P., Hamakua Energy Partners and HELCO (Exhibit 10.7(c) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

10.6(e)		Guarantee Agreement between Black River Energy, LLC and HELCO effective May 26, 2004 (Exhibit 10.7(e) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2004, File No. 1-4955).

10.6(f)		Guarantee Agreement between Black River Energy, LLC and HELCO dated July 15, 2004 (Exhibit 10.7(f) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2004, File No. 1-4955).

10.7(a)		Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.7(b)		First Amendment to Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO entered into as of April 12, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(c) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.8(a)		Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and HECO, MECO, HELCO, HTB and YB dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.8(b)		Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and HECO, MECO and HELCO entered into as of April 12, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(d) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.9		Facilities and Operating Contract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.10 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.10(a)		Low Sulfur Fuel Oil Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.11 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).


Exhibit no.		Description
10.10(b)		First Amendment to Low Sulfur Fuel Oil Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc., and HECO dated March 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(a) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.11(a)		Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO, MECO and HELCO dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.12 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.11(b)		First Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc., and HECO, MECO and HELCO dated March 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(b) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

10.12		Contract of private carriage by and between HITI and HELCO dated December 4, 2000 (Exhibit 10.13 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

10.13		Contract of private carriage by and between HITI and MECO dated December 4, 2000 (Exhibit 10.14 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

HECO Exhibit 10.14 is a management plan required to be filed as an exhibit pursuant to Item 15(b) of this report.

10.14		HECO Nonemployee Directors’ Deferred Compensation Plan (Exhibit 10.16 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990, File No. 1-4955).

10.15		Credit Agreement, dated as of March 31, 2006, among HECO, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and First Hawaiian Bank, as Co-Syndication Agent, and Wells Fargo Bank, N.A., as Co-Documentation Agent, and U.S. Bank National Association, as Co-Documentation Agent, and Union Bank of California, N.A., as Co-Documentation Agent, and The Bank of New York, as Administrative Agent, and BNY Capital Markets, Inc., as Sole Lead Arranger and Book Runner (Exhibit 10.2 to HECO’s Current Report on Form 8-K, dated April 3, 2006, File No. 1-4955)

11		Computation of Earnings Per Share of Common Stock (See note on HECO’s Selected Financial Data on page 1 of HECO Exhibit 99.4).

*12		Computation of Ratio of Earnings to Fixed Charges.

*21		Subsidiaries of HECO.

*23.2		Consent of Independent Registered Public Accounting Firm.

*31.3		Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of T. Michael May (HECO Chief Executive Officer).

*31.4		Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer).

*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.

*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.

*99.3		Reconciliation of electric utility operating income per HEI and HECO Consolidated Statements of Income.

*99.4		Selected Financial Data, Annual Report of Management on Internal Control Over Financial Reporting, Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting and HECO’s Consolidated 2006 Financial Statements (with Report of Independent Registered Public Accounting Firm thereon).