Edgar Filing: HAWAIIAN ELECTRIC INDUSTRIES 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, 2005

¨	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 June 30, 2005	Number of shares of common stock outstanding of the registrants as of
		June 30, 2005	February 28, 2006
Hawaiian Electric Industries, Inc. (HEI)	$2,169,840,781.29	80,934,009	81,059,892
		(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 2005 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 2006 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	36
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	46
Item 4.	Submission of Matters to a Vote of Security Holders	47
Executive Officers of the Registrant (HEI)		47

	PART II

Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	48
Item 6.	Selected Financial Data	49
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
	HEI Consolidated	51
	Electric Utilities	61
	Bank	74
	Certain Factors that May Affect Future Results and Financial Condition	80
	Material Estimates and Critical Accounting Policies	86
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	90
Item 8.	Financial Statements and Supplementary Data	94
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	137
Item 9A.	Controls and Procedures	137
Item 9B.	Other Information	140

	PART III

Item 10.	Directors and Executive Officers of the Registrants	141
Item 11.	Executive Compensation	144
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	149
Item 13.	Certain Relationships and Related Transactions	151
Item 14.	Principal Accountant Fees and Services	151
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	152
Report of Independent Registered Public Accounting Firm - HEI		153
Report of Independent Registered Public Accounting Firm - HECO		154
Index to Exhibits		159
Signatures		159

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) and 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., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.) and HEI Power Corp. and its subsidiaries (discontinued operations, except for subsidiary HEI Investments, Inc.). 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 dissolved HEIPC subsidiaries (discontinued operations). (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, Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III and Renewable Hawaii, Inc. 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

DOD		Department of Defense – federal

DOH		Department of Health of the State of Hawaii

DSM		Demand-side management

DTCC		Dual-train combined-cycle

ECA		Energy cost adjustment

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
FIRREA		Financial Institutions Reform, Recovery, and Enforcement Act of 1989

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 Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III* and Renewable Hawaii, Inc. 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 into Parts I, II, III and IV of this Form 10-K, which is filed as HECO Exhibit 99.4 and incorporated into this Form 10-K by reference

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., Hycap Management, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.) and HEI Power Corp. (discontinued operations, except for subsidiary HEI Investments, Inc.). 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). (*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 2006 Proxy Statement		Portions of Hawaiian Electric Industries, Inc.’s 2006 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 wholly-owned subsidiary of HEI Power Corp.

HEIPC		HEI Power Corp., 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 Group		HEI Power Corp. and its subsidiaries

HEIPI		HEI Properties, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.

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

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

NOV		Notice of Violation

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

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 Corp. 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.

UIC		Underground Injection Control

UST		Underground storage tank

VIE		Variable interest entities

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;

•

global developments, including the effects of terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan and potential conflict or crisis with North Korea;

•

the timing and extent of changes in interest rates;

•

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;

•

demand for services and market acceptance risks;

•

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 reserve margins on Oahu are lower than considered desirable;

•

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;

•

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 and governmental fees and assessments); decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases 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 with respect to environmental conditions, 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 continued regulatory accounting under Statement of Financial Accounting Standards (SFAS) No. 71 (Accounting for the Effects of Certain Types of Regulation), and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R (Consolidation of Variable Interest Entities) and Emerging Issues Task Force (EITF) Issue No. 01-8 (Determining Whether an Arrangement Contains a Lease) to power purchase arrangements 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;

•

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 the 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, MECO and HELCO. 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); 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) and its subsidiaries (discontinued operations).

ASB, acquired in 1988, is the third largest financial institution in the State of Hawaii based on total assets as of December 31, 2005. 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 $6.9 million as of December 31, 2005.

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.

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. 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.

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, MECO and HELCO are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Maui, Lanai and Molokai; and Hawaii, 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 2005, the electric utilities’ revenues and net income from continuing operations amounted to approximately 82% and 57%, respectively, of HEI’s consolidated amounts, compared to approximately 81% and 75% in 2004 and approximately 78% and 67% in 2003, respectively.

The islands of Oahu, Maui, Lanai, Molokai and Hawaii have a combined population currently estimated at 1,212,000, 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, 2005, 2004 and 2003 and electric sales revenues by company for each of the years then ended:


Years ended December 31	2005			2004			2003
(dollars in thousands)	Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues
HECO	291,580	$	1,201,156	288,456	$	1,050,388	286,677	$	960,717
MECO	63,901		301,755	61,996		250,750	61,423		213,806
HELCO	73,835		293,739	71,594		240,947	68,893		213,268

	429,316	$	1,796,650	422,046	$	1,542,085	416,993	$	1,387,791

*	As of December 31.

Revenues from the sale of electricity in 2005 were from the following types of customers in the proportions shown:


	HECO		MECO		HELCO		Total
Residential	32	%	37	%	40	%	34	%
Commercial	32		34		41		34
Large light and power	35		29		18		32
Other	1		—		1		—

	100	%	100	%	100	%	100	%

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.

HECO and its subsidiaries derived approximately 10% of their operating revenues from the sale of electricity to various federal government agencies in each of 2005, 2004 and 2003.

In 1995, HECO and the U.S. General Services Administration (GSA) entered into a Basic Ordering Agreement (GSA-BOA) 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) and in 2001, a new DOD-BOA was signed. Under these and other agreements, HECO has completed energy conservation and other projects for federal agencies over 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 demand-side management 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,	2005		2004		2003		2002		2001
KWH sales (millions)
Residential		3,008.0		3,000.6		2,875.9		2,778.5		2,665.2
Commercial		3,288.5		3,247.3		3,168.3		3,073.6		3,016.1
Large light and power		3,742.0		3,762.6		3,676.5		3,639.2		3,636.5
Other		51.4		52.8		54.4		53.0		52.6

		10,089.9		10,063.3		9,775.1		9,544.3		9,370.4

KWH net generated and purchased (millions)
Net generated		6,485.3		6,572.5		6,280.2		6,249.7		6,042.4
Purchased		4,167.5		4,066.5		4,054.3		3,829.6		3,861.6

		10,652.8		10,639.0		10,334.5		10,079.3		9,904.0

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

Energy supply (December 31)
Net generating capability—MW		1,644		1,642		1,606		1,606		1,608
Firm purchased capability—MW		540		529		531		510		531

		2,184		2,171		2,137		2,116		2,139

Net peak demand—MW ¹		1,641		1,694		1,638		1,583		1,564
Btu per net KWH generated		10,873		10,767		10,663		10,673		10,675
Average fuel oil cost per Mbtu (cents)		908.6		684.3		580.5		466.4		539.3

Customer accounts (December 31)
Residential		372,638		366,217		362,400		356,244		352,132
Commercial		54,647		53,854		52,659		51,386		50,974
Large light and power		559		555		549		551		542
Other		1,472		1,420		1,385		1,374		1,344

		429,316		422,046		416,993		409,555		404,992

Electric revenues (thousands)
Residential	$	607,031	$	527,970	$	471,697	$	426,291	$	425,287
Commercial		611,403		522,230		474,017		425,595		436,751
Large light and power		569,016		483,737		434,319		389,312		409,977
Other		9,200		8,148		7,758		7,028		7,349

	$	1,796,650	$	1,542,085	$	1,387,791	$	1,248,226	$	1,279,364

Average revenue per KWH sold (cents)		17.81		15.32		14.20		13.08		13.65
Residential		20.18		17.60		16.40		15.34		15.96
Commercial		18.59		16.08		14.96		13.85		14.48
Large light and power		15.21		12.86		11.81		10.70		11.27
Other		17.92		15.44		14.26		13.26		13.98

Residential statistics
Average annual use per customer account (KWH)		8,141		8,239		8,004		7,840		7,620
Average annual revenue per customer account	$	1,643	$	1,450	$	1,313	$	1,203	$	1,216
Average number of customer accounts		369,495		364,225		359,288		354,419		349,782

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, 2005. The 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 Maui- MECO		Island of Lanai- MECO		Island of Molokai- MECO		Island of Hawaii- HELCO		Total
Net generating and firm purchased capability (MW) as of December 31, 2005¹
Conventional oil-fired steam units	1,106.8		35.9		—		—		62.2		1,204.9
Diesel	14.8		82.5		10.3		9.6		30.8		148.0
Combustion turbines (peaking units)	101.8		—		—		—		—		101.8
Combustion turbines	—		41.6		—		2.2		88.9		132.7
Combined-cycle unit	—		56.8		—		—		—		56.8
Firm contract power²	434.0		16.0		—		—		90.0		540.0

	1,657.4		232.8		10.3		11.8		271.9		2,184.2

Net peak demand (MW)	1,230.0		202.1		5.1		6.3		197.0		1,640.5³

Reserve margin	36.0	%	15.2	%	101.9	%	89.1	%	38.0	%	34.0	%

Annual load factor	75.2	%	71.3	%	65.9	%	71.8	%	70.5	%	74.1	%³

KWH net generated and purchased (millions)	8,104.3		1,262.2		29.4		39.4		1,217.5		10,652.8

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); MECO: 16 MW (Hawaiian Commercial & Sugar Company, primarily bagasse-fired); HELCO: 30 MW (Puna Geothermal Venture, geothermal) and 60 MW (Hamakua Energy Partners, L.P., oil-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.

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. The PUC adopted a “framework,” which established the process and guidelines for developing IRPs and directed that each plan cover a 20-year planning horizon with a five-year program implementation schedule and that the planning cycle will be repeated every three years.

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs. The PUC has approved IRP cost recovery provisions for HECO, MECO and HELCO, pursuant to which the utilities have recovered the costs for approved DSM programs (including DSM program lost margins and shareholder incentives), and IRP costs incurred by the utilities and approved by the PUC, either through a surcharge or through their base rates.

See “Other regulatory matters—Demand-side management programs—agreements with the Consumer Advocate” in HEI’s MD&A, which includes a discussion of the electric utilities’ residential and commercial and industrial load management programs and of the agreements between the utilities and the Consumer Advocate concerning caps on the recovery of lost margins and shareholders incentives.

Incremental IRP costs are deferred until approved for recovery, at which time they are amortized to expense. Procedural schedules for the IRP cost proceedings have been established with respect to the 2000-2005 IRP costs, such that the electric utilities can begin recovering incremental IRP costs in the month after the filing of the actual costs incurred for the year, subject to refund with interest, pending the PUC’s final decision and order (D&O) approving recovery of the costs. HECO completed recovery of its 2004 incremental IRP costs in August 2005 and MECO is scheduled to complete recovery of its 2004 costs in June 2006. In HECO’s 2005 test year rate case, the parties to the rate case reached a settlement agreement to include $0.6 million for IRP costs in base rates. The PUC issued its interim D&O in HECO’s rate case granting an increase effective September 28, 2005, at which time HECO’s IRP costs will be recovered through base rates, and the separate surcharge for recovery is discontinued, pending the PUC’s final D&O. The Consumer Advocate has objected to the recovery of $3.2 million (before interest) of the $11.8 million of incremental IRP costs incurred during the 1995-2004 period, and the PUC’s decision is pending on this matter. As of December 31, 2005, the amount of revenues, including interest and revenue taxes, that the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $18 million. HECO and MECO expect to begin recovering their incremental 2005 IRP costs incurred through September 28, 2005 and December 31, 2005, respectively, subject to refund with interest, following the filing of actual 2005 costs (which is expected to occur in late March or early April 2006).

In early 2001, the PUC issued its final D&O in the HELCO 2000 test year rate case, in which the PUC concluded that it is appropriate for HELCO to recover its IRP costs through base rates (and included an estimated amount for such costs in HELCO’s test year revenue requirements) and to discontinue recovery of incremental IRP costs through the separate surcharge. HELCO’s IRP costs incurred for 2001 and future years are recovered through HELCO’s base rates. HELCO will continue to recover its DSM program costs, lost margins and shareholder incentives approved by the PUC in a separate surcharge.

The utilities have characterized their proposed IRPs as 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 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, in which the PUC further reviews the details of the proposed programs and the utilities’ proposals for the recovery of DSM program expenditures, lost margins and shareholder incentives.

HECO’s IRP. In December 2002, HECO filed with the PUC its IRP evaluation report, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

In September 2003, the PUC opened a docket to commence HECO’s third IRP (IRP-3). In June 2004, HECO conducted an updated 5-year sales and peak forecast for Oahu that projects increased system peak requirements based on the island’s strengthening economy. Based on this forecast, HECO supplied information to the PUC in its 2005 annual Adequacy of Supply letter. This letter concluded that HECO’s generation capacity for Oahu for the next three years (2005-2007) is sufficiently large to meet all reasonably expected demands for service if HECO is able to acquire the forecast peak reduction benefits of its energy efficiency and load management DSM programs and there is expeditious review and approval of its proposed enhanced energy efficiency DSM programs, and either the CHP program currently pending before the PUC or individual CHP contracts submitted to the PUC.

New larger energy efficiency DSM programs were developed during the on-going IRP process and, pursuant to the DSM stipulation, approval for the enhanced DSM programs were requested in HECO’s rate increase application, which was filed in November 2004. The energy efficiency DSM programs were bifurcated from the rate case into a separate Energy Efficiency Docket, which is still pending. On the supply-side, CHP system installations are behind schedule, due to suspension of the CHP program application and individual CHP contract applications pending action in the generic DG docket (see “Certain factors that may affect future results and financial condition-Consolidated-Competition-Distributed generation proceeding” in HEI’s MD&A). Also on the supply-side, HECO and Kalaeloa Partners, L.P. (Kalaeloa) executed amendments to the Kalaeloa PPA, under which Kalaeloa now provides

28 megawatts (MW) of additional firm capacity (see FIN 46R discussion in Note 1 to HECO’s Consolidated Financial Statements).

HECO’s gross peak demand was 1,250 MW in 2002, 1,284 MW in 2003 and 1,327 MW in 2004. 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 decreased to 1,273 MW, demand for electricity on Oahu is projected to increase. In October 2004, November 2005 and January 2006, HECO issued a public request that its customers voluntarily conserve energy as generating units were out for scheduled maintenance or were unexpectedly unavailable. In addition to making the requests, in November 2005 and January 2006, HECO remotely turned off water heaters of a number of residential customers who participate in its Energy Scout load-control program.

For a discussion of HECO’s 2005 and 2006 Adequacy of supply letters, see “Integrated resource planning, requirements for additional generating capacity and adequacy of supply” in HEI’s MD&A.

On October 28, 2005, HECO filed its 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. IRP-3 included a potential wind energy project above HECO’s Kahe power plant. However, HECO currently is reviewing other potential sites, such as Kahuku, due to the Mayor of Honolulu’s opposition to the Kahe project site.

In June 2005, HECO filed with the PUC an application for approval of funds to build a new nominal 100 MW simple cycle combustion turbine generating unit at Campbell Industrial Park on Oahu, the site of three other existing power plants, each owned and operated by an IPP (AES Hawaii, Inc., Kalaeloa and HPower). Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, operating mainly between the weekday peak electricity demand periods or during times when other generating units are not available. The air permit application for the unit, filed in October 2003 and currently under review by the Department of Health of the State of Hawaii (DOH), requests approval to burn naphtha or diesel and specifies that the unit will have the ability to convert to using biofuels, such as ethanol, when they are commercially available. On December 15, 2005, HECO signed a contract with Siemens for the right to purchase up to two combustion turbine units. The contract allows the Company to terminate the contract at a specified payment amount if necessary combustion turbine (CT) project approvals are not obtained.

The generating unit application also requests approval to build an additional 138 kilovolt (kV) transmission line approximately two miles long, within and adjacent to Campbell Industrial Park, to more reliably transmit power from the new and existing generating units to the Oahu electric grid. Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $137 million. As of December 31, 2005 accumulated project costs for planning, engineering, permitting and AFUDC amounted to $2.7 million. HECO has prepared a draft Environmental Impact Statement (EIS) for the proposed project. Notice of the availability of the draft EIS was published on February 8, 2006 and the public comment period ends on March 25, 2006.

In a related application filed with the PUC in June 2005, HECO requested approval for an approximately $11.5 million package of community benefit measures 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 those 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 in Kahe power plant’s operations.

In July 2005, the Consumer Advocate filed Preliminary Statements of Position on HECO’s Campbell Industrial Park generating unit and transmission line additions application and community benefits application. Also in July 2005, HECO filed memoranda in response opposing the Consumer Advocate’s recommendations to suspend the two applications, suspend the start of the procedural schedule for both applications until after the filing of the IRP-3 (which was filed on October 28, 2005), and consolidate the applications.

In September 2005, the PUC suspended HECO’s Campbell Industrial Park generating unit and transmission line additions application to allow more time to review the application. Also in September 2005, the PUC ordered HECO and the Consumer Advocate to submit a stipulated prehearing order for the community benefits application. In January 2006, the PUC granted an environmental group’s motion to intervene and a neighboring business entity’s motion to participate in the generating unit and transmission line application, and ordered HECO, the Consumer Advocate and the other parties (the environmental group and the business entity) to submit a stipulated prehearing order by March 13, 2006.

In addition to the 100 MW simple-cycle combustion turbine anticipated to be added in 2009, IRP-3 also includes plans to build a 180 MW coal unit in 2022. However, the report notes there is flexibility to allow HECO to modify its plan in response to changing market conditions and to also consider alternative generation technologies should they advance to the point they are economically and technically feasible substitutes for conventional generation. In addition, pursuant to HECO’s generation asset management program, all existing generating units are currently planned to be operated (future environmental considerations permitting) beyond the 20-year IRP planning period (2006-2025).

MECO’s IRP. MECO filed its second IRP with the PUC in May 2000. In April 2004 and 2005, MECO filed with the PUC its IRP evaluation reports, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

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 planned to be added in 2011), and 10 MW from the acquisition of a wind resource in 2003 (currently, MECO expects to begin purchasing 30 MW of wind energy in 2006). Approximately 4 MW of additional generation through the year 2020 is planned 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, is currently expected to be installed in the third quarter of 2006.

In December 2005, Maalaea Unit 13, a 12.34 MW diesel generator suffered an equipment failure. The unit is not expected to be available for service until approximately June 2007. MECO’s Maui system should have sufficient installed capacity to meet the forecasted loads, except that the Maui system may not have sufficient capacity at times in the event of an unexpected outage of its largest unit, until Maalaea Unit 13 returns to service. MECO intends to implement appropriate mitigation measures to overcome insufficient reserve capacity situations.

MECO’s third IRP is scheduled to be filed with the PUC in October 2006.

HELCO’s IRP. In September 1998, HELCO filed with the PUC its second IRP, which was updated in March 1999 and revised in June 1999. In March 2004, HELCO filed its IRP evaluation report with the PUC, updating the second IRP to reflect the latest sales and fuel forecasts and updated key planning assumptions.

On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. Due to delays in adding new generation, the near-term additions proposed in HELCO’s second IRP included installing two 20 MW CTs at its Keahole power plant site and proceeding in parallel with a PPA with Hamakua Energy Partners, L.P. (HEP, formerly Encogen Hawaii, L.P.) for a 60 MW (net) dual-train combined-cycle (DTCC) facility.

The HEP PPA was approved in 1999 and its DTCC facility was completed in December 2000. See the discussion of HELCO power purchase agreements in “Nonutility generation” and “HELCO power situation” in Note 11 to HECO’s Consolidated Financial Statements. HELCO has deferred the retirements of some of its older generating units. Subject to obtaining zoning approval and obtaining all other necessary permits and approvals, 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 for the next firm capacity addition is the 2017 timeframe. The timing of the need for additional new generation may change, however, based on factors such as the condition of the units whose retirements have been deferred, and the status of the nonutility generators providing firm capacity, including Puna Geothermal Venture (PGV) and HEP.

HELCO’s third IRP is scheduled to be filed with the PUC by December 31, 2006.

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 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 HELCO’s Keahole power plant expansion project, including ST-7, HECO’s East Oahu Transmission Project (see discussion in Note 11 to HECO’s Consolidated Financial Statements), MECO’s Maalaea and Waena power plant expansion projects, and HECO’s $25 million project to construct a New Dispatch Center, which will house a modernized Energy Management System and which will be integrated with new Outage Management and Customer Information systems. The New Dispatch Center project is expected to be completed in 2007, with the Energy Management System operational in 2006. HECO has also requested approval from the PUC to install a new generating unit in Campbell Industrial Park (an approximately 100 MW combustion turbine scheduled for commercial operation in 2009) and a two mile long 138 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 preceding discussion in “Integrated resource planning and requirements for additional generating capacity.”

Nonutility generation

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

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). See discussion of a lawsuit against The AES Corporation, AES Hawaii, HECO and HEI in Note 11 to HECO’s Consolidated Financial Statements. 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, 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. 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 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 1 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 diesel-fired qualifying cogeneration facilities at the two oil refineries (10 MW and 18 MW) on Oahu.

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, 2005. 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, 2005, HELCO and MECO had PPAs for 90 MW and 16 MW (includes 4 MW of system protection) of currently available firm capacity, which PPAs have been approved by the PUC.

HELCO has a 35-year PPA with 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. In 2005, PGV generally exported to HELCO between 25 MW and 30 MW. 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, and $0.1 million for 2002, 2003, 2004 and 2005, respectively. In 2005, PGV re-drilled an existing well, and drilled for a new production and a new injection well. As a result, PGV can export 30 MW to HELCO with all of its wells and converters in service. 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.

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 HEP. The agreement provides that HELCO will purchase up to 60 MW (net) of firm capacity for a period of 30 years. The 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 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 returned to providing 60 MW in 2003.

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, has an existing 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. On September 7, 2005, Apollo informed HELCO that its wind turbine supplier will not be able to supply any wind turbines to the project in 2005 or 2006, and any delivery in 2007 is not yet known. Apollo is claiming an event of force majeure under the PPA, since the PPA requires that Apollo’s windfarm meet an in-service date which is two years following the date of receipt of a non-appealable PUC approval order. HELCO is seeking information from Apollo regarding its claim of force majeure.

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 expects to purchase as-available energy from the HRD wind farm beginning in 2006.

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 2006, MECO expects to purchase as-available energy from Kaheawa Wind Power, LLC (KWP) under a PPA between MECO and KWP dated December 3, 2004. KWP plans to install a 30 MW windfarm at Ukumehame, Maui. The PUC 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 is refurbishing. The PPA was submitted to the PUC for approval on June 28, 2005.

The PUC has allowed rate recovery for the firm capacity and purchased energy costs for MECO’s and HELCO’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 (ECA) clauses 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 ECA clause 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.

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 Corp. (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 permits the inclusion of costs incurred under these contracts in HECO’s ECA clauses. 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, commencing January 1, 2005, for the purchase of diesel and MSFO with Chevron and Tesoro, 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. On March 1, 2000, the PUC approved an amended contract with a term extending through December 31, 2001. This agreement has been informally extended on a year-by-year basis since a second amendment to the contract is currently being negotiated.

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, MECO and HELCO to generate electricity in the years 2005, 2004 and 2003:


	HECO		MECO		HELCO		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
2005	52.61	833.1	70.88	1,188.3	57.44	935.4	56.61	908.6
2004	40.53	641.8	51.02	855.1	42.32	688.3	42.67	684.3
2003	35.49	561.3	39.52	662.1	34.96	566.4	36.23	580.5

The average per-unit cost of fuel oil consumed to generate electricity for HECO, MECO and HELCO reflects a different volume mix of fuel types and grades. In 2005, over 98% of HECO’s generation fuel consumption consisted of LSFO. The balance of HECO’s fuel consumption was diesel. Diesel made up approximately 76% of MECO’s and 36% of HELCO’s fuel consumption. MSFO made up the remainder of the fuel consumption of MECO and HELCO. 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. By the spring of 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 of the year as hurricanes Katrina and Rita seriously damaged U.S. Gulf crude oil and natural gas production facilities and 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. During 2004, the prices of LSFO, MSFO and diesel rose above the levels reached at the end of 2003 reflecting stronger demand for petroleum products world wide, particularly in the U.S. and China, tight U.S. crude oil and petroleum product inventories and continued geopolitical uncertainty. Thus the annual prices paid by the electric utilities for LSFO, MSFO and diesel averaged approximately 15%, 14% and 38%, respectively, above the average price for that grade of fuel in 2003.

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. The contracts provide for the employment of a double-hull bulk petroleum barge (since March 2002). The contracts are for an initial term of 5 years with options for three additional 5-year extensions. 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 ECA clauses.

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 contractually obligated to indemnify HELCO and/or MECO. 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 and/or fines that HITI or its insurance carrier does not cover.

The prices that HECO, MECO and HELCO 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 79.5% of the net energy generated and purchased by HECO and its subsidiaries in 2006 will be generated from the burning of oil. Increases in fuel oil prices are passed on to customers through the electric utility subsidiaries’ ECA clauses. 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. By state 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, 2005) located in West Oahu (1,055 MW); Waiau, adjacent to Pearl Harbor (481 MW); and Honolulu (107 MW). HECO also leases nine 1.64 MW generating units that provide a total of 14.8 MW (net) of firm power and are located at two substation sites and at HECO’s Iwilei tank farm. HECO’s non-firm power sources (approximately 28 MW) are located primarily in West Oahu. 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. 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, 2005) located in West Hawaii (77 MW) and East Hawaii (195 MW). HELCO’s non-firm power sources total 24 MW, but are expected to increase in 2006 from additional wind power. 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, 2005) located on the island of Maui (233 MW), Molokai (12 MW) and Lanai (10 MW). Beginning in 2006, MECO expects to purchase 30 MW of as-available energy under a PPA between MECO and Kaheawa Wind Power, LLC (KWP), which was approved by the PUC in March 2005. 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 86 miles of 23 kV overhead lines.

Rates

HECO, MECO and HELCO 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 ECA clauses 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 ECA clauses 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.

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.

Public Utilities Commission 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 commissioners are Janet E. Kawelo (whose term expires June 30, 2006 and who previously served as the Deputy Director for the State Department of Land and Natural Resources) and Wayne H. Kimura (whose term expires June 30, 2008 and who previously served as State Comptroller with the State Department of Accounting and General Services).

John E. Cole was appointed Executive Director of the Division of Consumer Advocacy effective May 17, 2004. Prior to becoming the Executive Director, Mr. Cole was a member of the Governor of the State of Hawaii’s Policy Team, which serves as advisor to the Governor on state-wide policy matters. Mr. Cole is an attorney.

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.

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 situation; HECO’s East Oahu Transmission Project; the lawsuit against The AES Corporation, AES Hawaii, HECO and HEI; and the Honolulu Harbor environmental investigation.

City and County sewer line. On July 22, 2004, a contractor (hired by HECO for a utility line extension project to support the expansion of the City and County of Honolulu’s wastewater treatment plant) accidentally drilled into a force main sewer line owned by the City and County. The City and County made a formal demand that HECO provide full compensation for damages to the force main sewer line. Management believes HECO has defenses against any claims that it has liability for the incident and responded to the demand asserting its defenses. In addition, HECO has insurance coverage (over a deductible amount).

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, 2005, 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 2005, ASB’s revenues and net income from continuing operations amounted to approximately 18% and 51%, respectively, of HEI’s consolidated amounts, compared to approximately 19% and 38% in 2004 and approximately 21% and 48% in 2003, 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, 2005, 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 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 loan losses, gains or losses on sales of securities available-for-sale, and noninterest expenses.

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:


	Years ended December 31
	2005		2004		2003
Common equity to assets ratio
Average common equity divided by average total assets ¹	8.15	%	7.10	%	7.20	%
Return on assets
Net income for common stock divided by average total assets ¹	0.95		0.62		0.88
Return on common equity
Net income for common stock divided by average common equity ¹	11.7		8.7		12.2
Tangible efficiency ratio
Total noninterest expense divided by net interest income and noninterest income	61		61		61

¹	Average balances calculated using the average daily balances (except for common equity, which is calculated using the average month-end balances).

ASB’s tangible efficiency ratio – the cost of earning $1 of revenue – remained flat at 61% from 2003 to 2005 as ASB has been undergoing a transformation, involving four major lines of business, to become a full-service community bank serving both consumer and commercial business customers. The transformation project will require continued investment in people and technology. 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
(in thousands)	2005		2004		2003
Assets
Investment securities	$	207,258	$	240,466	$	200,891
Mortgage-related securities		2,755,736		2,799,303		2,707,395
Loans receivable, net		3,411,389		3,121,878		3,071,877
Other		442,368		424,464		418,296

	$	6,816,751	$	6,586,111	$	6,398,459

Liabilities and stockholder’s equity
Deposit liabilities	$	4,453,762	$	4,114,070	$	3,888,145
Other borrowings		1,703,353		1,819,598		1,851,258
Other		104,009		109,544		123,167
Stockholder’s equity		555,627		542,899		535,889

	$	6,816,751	$	6,586,111	$	6,398,459

In 2005, the average loans receivables 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.

In 2004, the low interest rate environment and continued strength in the Hawaii real estate market also resulted in an increase in average loans receivables. The average residential mortgage portfolio for 2004 grew by $37.7 million, or 1.5%, over the 2003 average residential mortgage portfolio. Average commercial real estate loans, net of undisbursed loan funds, increased $12.4 million, or 6.2%, over 2003 primarily due to commercial construction real estate loans originated in 2004 of $85.8 million. ASB’s average commercial portfolio increased by $11.0 million, or 4.0%, during 2004 as ASB’s transformation to a full-service community bank continued. The average consumer loan portfolio decreased $8.2 million, or 3.6%, from 2003 as low interest rates and improving real estate values resulted in higher mortgage refinancing and high consumer loan payoffs. Average deposits increased during the year as ASB continued to attract deposits. Average other borrowings also decreased during 2004 as the increase in average deposits enabled ASB to repay some of its higher costing other borrowings.

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, 2005, 2004 and 2003.

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 portfolio balance) and (2) changes in volume (change in average portfolio balance multiplied by prior period rate). Any remaining change is allocated to the above two categories on a pro rata basis.


(in thousands)	2005 vs. 2004									2004 vs. 2003
Increase (decrease) due to	Rate			Volume			Total			Rate			Volume			Total
Income from earning assets
Loans receivable, net	$	2,861		$	17,450		$	20,311		$	(17,381	)	$	3,206		$	(14,175	)
Mortgage-related securities		7,206			(1,830	)		5,376			5,250			3,725			8,975
Investment securities		(1,048	)		(751	)		(1,799	)		(1,637	)		1,129			(508	)

		9,019			14,869			23,888			(13,768	)		8,060			(5,708	)

Expense from costing liabilities
Deposit liabilities		(15	)		4,895			4,880			(5,349	)		(1,275	)		(6,624	)
FHLB advances and other borrowings		8,091			(4,332	)		3,759			(2,739	)		(1,174	)		(3,913	)

		8,076			563			8,639			(8,088	)		(2,449	)		(10,537	)

Net interest income	$	943		$	14,306		$	15,249		$	(5,680	)	$	10,509		$	4,829

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 $56.9 million in 2005, $57.2 million in 2004 and $58.5 million in 2003. Noninterest income for 2005 was relatively stable when compared to 2004. The decrease in noninterest income for 2004 was due to net gains on sales of securities totaling $4.1 million in 2003 compared to a net loss of $0.1 million in 2004, partially offset by higher fee income in 2004.

Lending activities

General. Loans and mortgage-related securities of $6.2 billion represented 90.3% of total assets as of December 31, 2005, compared to $6.2 billion, or 91.3%, and $5.8 billion, or 88.8%, as of December 31, 2004 and 2003, 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
	2005					2004					2003					2002					2001
(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)	$	2,617,194		42.4		$	2,464,133		39.9		$	2,438,573		42.1		$	2,347,446		40.9		$	2,242,329		43.0
Commercial		229,430		3.7			226,699		3.6			208,683		3.6			193,627		3.4			196,515		3.8
Construction and development		241,311		3.9			202,466		3.3			100,986		1.8			46,150		0.8			52,043		1.0

		3,087,935		50.0			2,893,298		46.8			2,748,242		47.5			2,587,223		45.1			2,490,887		47.8
Less:
Deferred fees and discounts		(21,484	)	(0.3	)		(20,701	)	(0.3	)		(20,268	)	(0.4	)		(18,937	)	(0.3	)		(17,946	)	(0.3	)
Undisbursed loan funds		(140,271	)	(2.3	)		(132,208	)	(2.1	)		(69,884	)	(1.2	)		(21,412	)	(0.4	)		(22,910	)	(0.5	)
Allowance for loan losses		(16,212	)	(0.3	)		(15,663	)	(0.3	)		(14,734	)	(0.3	)		(23,708	)	(0.4	)		(26,085	)	(0.5	)

Total real estate loans, net		2,909,968		47.1			2,724,726		44.1			2,643,356		45.6			2,523,166		44.0			2,423,946		46.5

Other loans
Consumer and other		259,048		4.2			232,189		3.8			222,743		3.9			245,853		4.3			252,487		4.8
Commercial		412,816		6.7			310,999		5.0			286,068		4.9			247,114		4.3			197,333		3.8

		671,864		10.9			543,188		8.8			508,811		8.8			492,967		8.6			449,820		8.6
Less:
Deferred fees and discounts		(613	)	—			(526	)	—			(606	)	—			(416	)	—			—		—
Undisbursed loan funds		(2	)	—			(3	)	—			(31	)	—			(1	)	—			(5	)	—
Allowance for loan losses		(14,383	)	(0.2	)		(18,194	)	(0.3	)		(29,551	)	(0.5	)		(21,727	)	(0.4	)		(16,139	)	(0.3	)

Total other loans, net		656,866		10.7			524,465		8.5			478,623		8.3			470,823		8.2			433,676		8.3

Mortgage-related securities, net		2,604,920		42.2			2,928,507		47.4			2,666,619		46.1			2,736,679		47.8			2,354,849		45.2

Total loans and mortgage-related securities, net	$	6,171,754		100.0		$	6,177,698		100.0		$	5,788,598		100.0		$	5,730,668		100.0		$	5,212,471		100.0

¹	Includes renegotiated loans.

The following table summarizes ASB’s loan portfolio, excluding loans held for sale and undisbursed commercial real estate construction and development loan funds as of December 31, 2005 and 2004, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:


	December 31
	2005								2004
Due (in millions)	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
Residential loans - Fixed	$	361	$	920	$	1,120	$	2,401	$	427	$	890	$	855	$	2,172
Residential loans - Adjustable		82		142		82		306		115		208		63		386

		443		1,062		1,202		2,707		542		1,098		918		2,558

Commercial real estate loans - Fixed		4		19		42		65		5		11		20		36
Commercial real estate loans - Adjustable		107		38		65		210		73		41		87		201

		111		57		107		275		78		52		107		237

Consumer loans – Fixed		11		19		14		44		12		19		14		45
Consumer loans – Adjustable		52		106		47		205		50		93		36		179

		63		125		61		249		62		112		50		224

Commercial loans – Fixed		109		104		51		264		89		69		38		196
Commercial loans – Adjustable		107		38		4		149		63		47		5		115

		216		142		55		413		152		116		43		311

Total loans - Fixed		485		1,062		1,227		2,774		533		989		927		2,449
Total loans - Adjustable		348		324		198		870		301		389		191		881

	$	833	$	1,386	$	1,425	$	3,644	$	834	$	1,378	$	1,118	$	3,330

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, 2005, approximately $7.8 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 2005, 2004, 2003, 2002 and 2001 were $1.4 billion, $1.4 billion, $1.6 billion, $1.2 billion and $1.0 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 2004 compared to 2003 was due to a slowdown in residential refinancing activity. The increase in loan originations in 2003 and 2002 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 95% 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, 2005, 2004 and 2003, ASB had commercial real estate construction and development loans of $149 million, $108 million and $35 million and residential construction and development loans of $93 million, $94 million and $66 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 2005, 2004 and 2003, ASB originated $77 million, $153 million and $81 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 2005, 2004 and 2003, ASB originated $189 million, $156 million and $138 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 2005, 2004 and 2003, gross commercial loan originations of $436 million, $351 million and $195 million, respectively, accounted for approximately 30%, 26% and 12%, respectively, of ASB’s total loan originations.

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, 0.01% and 0.12% of total assets as of December 31, 2005, 2004 and 2003, 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
(dollars in thousands)	2005			2004			2003			2002			2001
Nonaccrual loans—
Real estate
One-to-four unit residential	$	1,394		$	2,240		$	2,784		$	9,783		$	22,495
Commercial		—			235			—			983			10,129

Total real estate		1,394			2,475			2,784			10,766			32,624
Consumer		377			411			341			1,382			1,965
Commercial		598			3,510			2,236			3,633			3,018

Total nonaccrual loans	$	2,369		$	6,396		$	5,361		$	15,781		$	37,607

Nonaccrual loans to total net loans		0.1	%		0.2	%		0.2	%		0.5	%		1.3	%

Renegotiated loans not included above—
Real estate
One-to-four unit residential	$	731		$	1,243		$	2,148		$	—		$	—
Commercial		3,446			3,653			3,877			7,582			3,874
Commercial		790			427			1,919			2,175			2,681

Total renegotiated loans	$	4,967		$	5,323		$	7,944		$	9,757		$	6,555

Nonaccrual and renegotiated loans to total net loans		0.2	%		0.4	%		0.4	%		0.9	%		1.5	%

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 2002, the decrease in nonaccrual loans of $21.8 million was due to $12.7 million lower delinquencies in residential loans, a $5.0 million payoff of a commercial real estate loan and a $4.1 million reclassification of a commercial real estate loan to accrual status. 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.

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)	2005			2004			2003			2002			2001
Allowance for loan losses, January 1	$	33,857		$	44,285		$	45,435		$	42,224		$	37,449
Provision (reversal of allowance) for loan losses		(3,100	)		(8,400	)		3,075			9,750			12,500

Charge-offs
Residential real estate loans		—			40			892			2,345			4,651
Commercial real estate loans		—			—			174			441			315
Consumer loans		1,558			1,790			3,027			3,479			3,644
Commercial loans		456			2,479			2,601			1,479			1,013

Total charge-offs		2,014			4,309			6,694			7,744			9,623

Recoveries
Residential real estate loans		459			346			1,244			858			1,210
Commercial real estate loans		—			562			426			52			342
Consumer loans		525			549			586			257			313
Commercial loans		868			824			213			38			33

Total recoveries		1,852			2,281			2,469			1,205			1,898

Allowance for loan losses, December 31	$	30,595		$	33,857		$	44,285		$	45,435		$	42,224

Ratio of allowance for loan losses, December 31, to average loans outstanding		0.90	%		1.08	%		1.44	%		1.60	%		1.42	%

Ratio of provision for loan losses during the year to average loans outstanding		NM			NM			0.10	%		0.34	%		0.42	%

Ratio of net charge-offs during the year to average loans outstanding		NM			0.06	%		0.14	%		0.23	%		0.26	%

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
	2005				2004				2003				2002				2001
(dollars in thousands)	Balance		% of total		Balance		% of total		Balance		% of total		Balance		% of total		Balance		% of total
Residential real estate	$	8,613	72.1	%	$	10,137	74.4	%	$	4,031	76.9	%	$	6,246	77.6	%	$	9,933	78.0	%
Commercial real estate		7,450	10.0			5,355	9.7			6,008	7.5			6,343	6.4			9,031	6.7
Consumer		3,111	6.9			4,008	6.8			6,540	6.8			8,489	8.0			8,538	8.6
Commercial		11,139	11.0			13,986	9.1			14,758	8.8			12,118	8.0			6,388	6.7
Unallocated		282	NA			371	NA			12,948	NA			12,239	NA			8,334	NA

	$	30,595	100.0	%	$	33,857	100.0	%	$	44,285	100.0	%	$	45,435	100.0	%	$	42,224	100.0	%

NA Not applicable.

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.

In 2002, ASB’s allowance for loan losses increased by $3.2 million compared to an increase of $4.8 million in 2001. The 2002 increase was due to a higher loans receivable balance and a higher unallocated component of the allowance for loan losses. The allowance was increased to account for ASB’s strategic focus of diversifying its loan portfolio from single-family home mortgages to commercial loans that have higher credit risk. Charge-offs were lower in 2002 compared to 2001 as a result of lower delinquencies. The strong Hawaii real estate market and low interest rates gave debtors the opportunity to sell their properties or refinance before defaulting. In addition, ASB improved its collection efforts. Residential and commercial real estate loan delinquencies decreased during 2002 and lower loan loss reserves were required for those lines of business. The allowance for loan losses on consumer loans remained essentially the same during 2002.

Investment activities

Currently, ASB’s investment portfolio consists primarily of mortgage-related securities, stock of the FHLB of Seattle and a federal agency obligation. 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, 2005, 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 2005, 2004 or 2003.

As of December 31, 2005, 2004 and 2003, ASB’s investment in stock of FHLB of Seattle amounted to $97.8 million, $97.4 million and $94.6 million, respectively. The weighted-average yield on investments during 2005, 2004 and 2003 was 1.13%, 3.29% and 5.45%, respectively. The amount that ASB is required to invest in FHLB stock is determined by regulatory requirements. See “Bank operations” 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, 2005, ASB owned private-issue mortgage related securities issued by Countrywide Financial with an aggregate book value of $187.3 million and aggregate market value of $184.1 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, 2005, 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)	In 1 year or less			After 1 year through 5 years			After 5 years through 10 years			After 10 years			Total
Federal agency obligation	$	—		$	24		$	—		$	—		$	24
FNMA, FHLMC and GNMA		419			1,228			433			96			2,176
Private issue		108			266			54			1			429

	$	527		$	1,518		$	487		$	97		$	2,629

Weighted average yield		4.10	%		4.16	%		4.88	%		5.07	%

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 that have a higher cost of funds than deposits.

Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow in 2005, 2004 and 2003 was $261.2 million, $269.9 million and $225.5 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
	2005						2004						2003
(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	$	1,721,988	38.7	%	0.51	%	$	1,613,856	39.2	%	0.40	%	$	1,352,507	34.8	%	0.56	%
Checking		1,151,345	25.8		0.05			1,019,464	24.8		0.03			913,228	23.5		0.05
Money market		288,731	6.5		0.89			322,806	7.8		0.45			397,590	10.2		0.61
Certificate		1,291,698	29.0		3.10			1,157,944	28.2		3.36			1,224,820	31.5		3.54

Total deposits	$	4,453,762	100.0	%	1.17	%	$	4,114,070	100.0	%	1.15	%	$	3,888,145	100.0	%	1.38	%

As of December 31, 2005, ASB had $406.5 million in certificate accounts of $100,000 or more, maturing as follows:


(in thousands)	Amount
Three months or less	$	152,803
Greater than three months through six months		63,879
Greater than six months through twelve months		88,741
Greater than twelve months		101,066

	$	406,489

Deposit-insurance premiums and regulatory developments. In general, ASB’s deposits are insured by the Savings Association Insurance Fund (SAIF) or the Bank Insurance Fund (BIF), which assess quarterly insurance premiums to thrifts and commercial banks, respectively. In addition to deposit insurance premiums, Financing Corporation (FICO) imposes a quarterly assessment on SAIF and BIF deposits to service the interest on FICO bond obligations. As a “well capitalized” thrift, ASB’s base deposit insurance premium effective for the December 31, 2005 quarterly payment is zero and its annual FICO assessment is 1.32 cents per $100 of SAIF and BIF deposits as of September 30, 2005.

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

Borrowings. ASB obtains 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, 2005, 2004 and 2003, advances from the FHLB amounted to $0.9 billion, $1.0 billion and $1.0 billion, respectively. The weighted-average rates on the advances from the FHLB outstanding as of December 31, 2005, 2004 and 2003 were 4.53%, 4.48% and 4.28%, respectively. The maximum amount

outstanding at any month-end during 2005, 2004 and 2003 was $1.1 billion, $1.0 billion and $1.1 billion, respectively. Advances from the FHLB averaged $1.0 billion during each of 2005, 2004 and 2003 and the approximate weighted-average rate on the advances was 4.48%, 4.43% and 4.62%, 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
(dollars in thousands)	2005			2004			2003
Advances from the FHLB	$	935,500		$	988,231		$	1,017,053
Securities sold under agreements to repurchase		686,794			811,438			831,335

Total borrowings	$	1,622,294		$	1,799,669		$	1,848,388

Weighted-average rate		4.23	%		4.01	%		3.48	%

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 7 FDIC-insured financial institutions, of which 2 were thrifts and 5 were commercial banks, and approximately 100 credit unions as of December 31, 2005. 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 continued to build its commercial and commercial real estate lines of business in 2002. 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.

In September 2002, ASB launched its STAR initiative (Strategic & Tactical Alignment of Resources), in which four of its lines of business–Retail Banking, Mortgage Banking, Commercial Real Estate and Commercial Banking–began implementing changes intended to increase profitability and enhance customer service. Changes to two lines of business–commercial real estate and mortgage banking–have been completed, and a third is nearing completion–commercial banking. The remaining transformation involving retail banking is intended to make ASB’s retail area more customer-centric, rather than product-centric. In addition to these transformation projects, 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.

In recent years, there has been significant bank and thrift merger activity affecting Hawaii, including the merger in 2004 of the holding companies for the state’s 4th and 5th largest financial institutions (based on assets). Management cannot predict the impact, if any, of these mergers on the Company’s future competitive position, results of operations or financial condition.

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 were exempt from the comprehensive regulation of the SEC under the Public Utility Holding Company Act of 1935 (1935 Act) except for Section 9(a)(2) (relating to the acquisition of securities of other public utility companies) through compliance with the requirement to file annually Form U-3A-2 under the 1935 Act for holding companies which own utility businesses that are intrastate in character. The 1935 Act was repealed, effective February 8, 2006, and was essentially replaced by the Public Utility Holding Company Act of 2005 and implementing regulations (2005 Act). HEI and HECO are each holding companies within the meaning of the 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 on February 21, 2006, seeking a waiver of these record retention, accounting and reporting requirements. If FERC takes no action within 60 days of such filing, this waiver will be automatically granted.

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 2005, 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, 2005, the consolidated common stock equity of HEI’s electric utility subsidiaries was 56% of their total capitalization (as previously defined). As of December 31, 2005, HECO and its subsidiaries had common stock equity of $1.0 billion, 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 distribution, 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 an 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&O issued by the PUC in the DG proceeding in January 2006, 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, MECO and HELCO) 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 DOD that HECO, MECO and HELCO 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 MECO and HELCO rate cases, the presentations made by MECO and HELCO that there was no such impact in those cases. HECO made a similar presentation in its current rate case, which was accepted 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 reserve requirements.

Deposit insurance coverage. The Federal Deposit Insurance Act, as amended by the Federal Deposit Insurance Corporation Insurance Act of 1991 (FDICIA), 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.

Institutions that are “well capitalized” under the FDIC’s prompt corrective action regulations are generally able to provide “pass-through” insurance coverage (i.e., insurance coverage that passes through to each owner/beneficiary of the applicable deposit) for the deposits of most employee benefit plans (i.e., $100,000 per individual participating, not $100,000 per plan). As of December 31, 2005, ASB was “well capitalized”.

On February 8, 2006, federal deposit insurance reform became law. Among other things, this major reform: 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. Although ASB believes that this insurance deposit reform may eventually result in a decrease in its premiums, proposed implementing regulations have not yet been issued for comment and it is too soon to evaluate the impact of this reform on ASB.

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) imposed on financial institutions an obligation to protect the security and confidentiality of its customers’ nonpublic personal information and the FDIC and OTS issued final guidelines for the establishment of standards for safeguarding such information effective from July 1, 2001. 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.

In June 2004, the SEC issued for public comment 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. On October 8, 2004, the federal financial institution regulatory agencies submitted to the SEC a joint objection to the proposed final rules. Included among the agencies’ concerns was the impact of the proposed rules on “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. The agencies viewed the SEC’s proposed rules in this regard as “highly complex, restrictive and inflexible” and inconsistent with longstanding guidance from the SEC staff and the agencies themselves. ASB does have a networking arrangement with UVEST Financial Services that would be potentially affected by the proposed rules and 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. Since October 1, 2003, financial institutions have been required to fully implement a customer identification program. 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. Under the Financial Institutions Reform, Recovery, and Enforcement Act of 1989 (FIRREA), 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, 2005, ASB was in compliance with all of the minimum standards with a core capital ratio of 7.4% (compared to a 4.0% requirement), a tangible capital ratio of 7.4% (compared to a 1.5% requirement) and total risk-based capital ratio of 15.1% (based on risk-based capital of $536.8 million, $251.8 million in excess of the 8.0% requirement).

Effective April 1, 1999, the OTS revised its risk-based capital standards as part of the effort by the OTS, FDIC, the Board of Governors of the Federal Reserve System and the Office of the Comptroller of the Currency to implement the provisions of the Riegle Community Development and Regulatory Improvement Act of 1994, which requires these agencies to work together to make uniform their respective regulations and guidelines implementing common statutory or supervisory policies. These OTS revisions affect the risk-based capital treatment of certain types of loans and investments and core capital requirements. Under the new rules, an institution 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, 2005, ASB met the applicable minimum core capital requirement of the revised OTS regulations.

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. The new 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. BCBS expects that its proposed revisions to the 1988 Accord (Basel II) will begin to be implemented as of year-end 2006, with “parallel running” both of some of its more advanced approaches and current risk-based capital regulations during 2007, and full implementation of its proposed revisions as of year-end 2007. On August 4, 2003, the federal financial institution regulatory agencies, including OTS, issued an advance notice of proposed rule making (Advance Notice) soliciting comment on possible changes to U.S. risk-based capital requirements in light of Basel II. The agencies have also issued for public comment three proposed supervisory guidances on internal ratings-based systems for computing corporate credit risk, retail credit risk and operational risk in a manner consistent with Basel II. The Advance Notice describes the purpose of Basel II as making risk-based capital requirements more risk sensitive than are the requirements of the 1988 Accord and current U.S. (including OTS) rules implementing the 1988 Accord. The agencies’ most recently announced time table is to issue a notice of proposed rule making during the first quarter of 2006, with “parallel running” anticipated during calendar year 2008. The possible changes to the U.S. rules described in the Advance Notice are greatest with respect to financial institutions with banking and thrift assets of $250 billion or more or total on-balance-sheet foreign exposure of $10 billion or more. However, impacts on smaller financial institutions such as ASB are possible. ASB will continue to monitor these regulatory developments.

The review of U.S. risk-based capital requirements given impetus by Basel II resulted in the agencies’ issuance on October 20, 2005 of an advanced notice of rule making addressing the risk-based capital requirements of those financial institutions that will not come within the scope of the yet-to-be-proposed Basel II-inspired rules. The proposed changes described in this advanced notice would increase the number of risk-weight categories from five to nine in an effort to improve the risk sensitivity of the capital rules. ASB believes that the proposals would, if implemented in their current form, result in some improvement in its risk-based capital ratios. The agencies’ announced intention is to issue a notice of proposed rule making with respect to these proposals in a similar timeframe as the notice of rule making for the Basel II-inspired rules (currently scheduled for the first quarter of 2006) in order to allow the comparative evaluation of the two sets of risk-based capital standards.

Affiliate transactions. Significant restrictions apply to certain transactions between ASB and its affiliates, including HEI and its direct and indirect subsidiaries. FIRREA 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 Federal Reserve Board (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 Federal Reserve Board 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, including 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’s minimum standards for thrift institutions’ interest rate risk management practices with regard to board-approved risk limits and interest rate risk measurement systems, and made several significant changes to the original TB 13. First, under TB 13a, institutions no longer set board-approved limits or provide measurements for the plus and minus 400 basis point interest rate scenarios prescribed by the original TB 13. TB 13a also changes the form in which those limits should be expressed. Second, TB 13a provides guidance on how the OTS will assess the prudence of an institution’s risk limits. Third, TB 13a raises the size threshold above which institutions should calculate their own estimates of the interest rate sensitivity of Net Portfolio Value (NPV) from $500 million to $1 billion in assets. Fourth, TB 13a specifies a set of desirable features that an institution’s risk measurement methodology should utilize. Fifth, TB 13a provides an extensive discussion of “sound practices” for interest rate risk management.

TB 13a 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. TB 13a also provides guidelines on the use of certain types of securities and financial derivatives for purposes other than reducing portfolio risk.

Finally, TB 13a provides detailed guidelines for implementing part of the Notice announcing the revision of the CAMELS rating system, published by the Federal Financial Institutions Examination Council. That publication announced revised interagency policies that, among other things, established the Sensitivity to Market Risk component rating (the “S” rating). TB 13a provides quantitative guidelines for an initial assessment of an institution’s level of interest rate risk. Examiners have broad discretion in implementing those guidelines. It also provides guidelines concerning the factors examiners consider in assessing the quality of an institution’s risk management systems and procedures.

Liquidity. Effective July 18, 2001, the OTS removed the regulation that required a savings association to maintain an average daily balance of liquid assets of at least 4% of their liquidity base and retained a provision requiring a savings association 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, 2005, ASB’s unused FHLB borrowing capacity was approximately $1.5 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, 2005, 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, 2005, 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, 2005, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

Qualified thrift lender test. FDICIA amended the QTL test provisions of FIRREA by reducing the percentage of assets thrifts must maintain in “qualified thrift investments” from 70% to 65%, and changing the computation period to require that the percentage be reached on a monthly average basis in 9 out of the previous 12 months. The 1997 Omnibus Appropriations Act expanded the types of loans that constitute “qualified thrift investments.” 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 2005, ASB was in compliance with the QTL test. As of December 31, 2005, 86.5% 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. 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 a result of the Gramm-Leach-Bliley Act, each regional FHLB is required to formulate and submit for Federal Housing Finance Board (Board) approval a plan to meet new minimum capital standards to be promulgated by the Board. The Board issued the final regulations establishing the new minimum capital standards on January 30, 2001. As mandated by Gramm-Leach-Bliley, these 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 submitted to and 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 3.5% 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) 0.75% of ASB’s mortgage loans and pass through securities. As of December 31, 2005, ASB was required under the capital plan to own capital stock in the FHLB of Seattle in the amount of $62 million and owned capital stock in the amount of $98 million, or $36 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.

Congress is considering legislation to revamp oversight of government-sponsored enterprises (GSEs). This legislation would abolish the Office of Federal Housing Enterprise Oversight (regulator of Fannie Mae and Freddie Mac) and the Federal Housing Finance Board (regulator of the FHLB), create a new regulatory agency to oversee GSEs, and invest in this new agency the authority, among other things, to place limitations on “non-mission” assets, to establish prudent management and operation standards for GSEs concerning matters such as the management of asset and investment portfolio growth, to impose “prompt-corrective action” measures on a GSE in the event of under-capitalization, and to exercise oversight enforcement powers. By possibly restricting GSE asset growth, if enacted, this legislation could potentially limit the availability of advances from the FHLB of Seattle to ASB and sale of loans to Fannie Mae. ASB believes, however, that if this bill is adopted and implemented in these ways, its results will not be materially adversely affected because ASB has access to other funding sources and secondary markets to sell its loans.

Community Reinvestment. In 1977, Congress enacted the Community Reinvestment Act (CRA) to ensure that 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 correction 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 (UIC) (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, see “Environmental regulation” in Note 11 to HECO’s Consolidated Financial Statements.

In 2000, the EPA introduced new regulations that required all large capacity cesspools to be permanently closed by April 2005. The regulations affected HECO’s Kahe generating station, HELCO’s Kanoelehua Base Yard, MECO’s Maalaea and Kahului generating stations. MECO completed its cesspool replacement projects in late 2003. HECO and HELCO closed their cesspools in 2005 prior to the April deadline.

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 to 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.

HELCO experienced two pipeline-related releases in Hilo during 2004. The first occurred on January 13, 2004 when a third party contractor accidentally ruptured HELCO’s fuel oil pipeline on Hualani Street. Response and remediation efforts were completed by HELCO and HELCO successfully completed arbitration in 2005 whereby it recovered a substantial portion of its costs from the third party contractor. The second incident took place on September 13, 2004 at Pier 3 in Hilo Harbor when a pipeline beneath a pier jointly owned by HELCO and Chevron leaked fuel oil owned by HELCO beneath a pier at storage facilities owned by Chevron. Cleanup activities at the pier were completed on October 9, 2004. Costs associated with pipeline maintenance, repair and replacement, as well as cleanup costs are shared 50%-50% between Chevron and HELCO.

During 2005 and up through March 7, 2006, 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 start operations after August 16, 2002, also must prepare and implement an SPCC Plan by October 31, 2007. HECO, HELCO and MECO are currently developing 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 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. HECO boilers may be affected by the air toxics provisions (Title III) of the CAA when the Maximum Allowable Control Technology (MACT) emission standards are established for those units.

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). Based on the EPA comments accompanying

the Notice of Reconsideration, HECO does not anticipate that the agency will relist oil-fired utility units for regulation under Title III. Further, because a decision by the EPA to relist oil-fired utility units would require the EPA to determine whether it should propose rules to control nickel emissions from existing oil-fired utility units, HECO believes that attempts to evaluate the impact of such regulations, if any, are both premature and speculative.

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. The installation of the planned noise mitigation equipment measures for Keahole CT-4 was completed in November 2004. The installation of the planned noise mitigation equipment measures for Keahole CT-5 was completed in January 2005.

Hazardous waste and toxic substances controls. The operations of the electric utility and former freight transportation subsidiaries 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, MECO and HELCO 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, MECO and HELCO 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, MECO and HELCO 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. All HECO, MECO and HELCO facilities are currently believed to be 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 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, installed soil borings and 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 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, 2005 were approximately $0.96 million. An estimated $0.2 million is expected to be expended during 2006-2007 to address ongoing response efforts. 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.

ASB may be subject to the provisions of the 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 great for ASB.

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 under “Liquidity and capital resources” (both “Consolidated” and “Electric utility”) in HEI’s MD&A. These ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating. 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 $3.9 million, $3.3 million and $3.1 million in 2005, 2004 and 2003, respectively, for research and development. Contributions to the Electric Power Research Institute accounted for more than half of the expenses. There were also expenses in the areas of energy conservation, new technologies and environmental and emissions controls.

Employees

As of December 31, 2005 and 2004, the Company had full-time employees as follows:


December 31	2005	2004
HEI	42	45
HECO and its subsidiaries	2,066	2,013
ASB and its subsidiaries	1,272	1,291
Other subsidiaries	3	5

	3,383	3,354

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 2,066 full time employees of HECO and its subsidiaries as of December 31, 2005, 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

Holding Company and Company-Wide Risks

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

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, 2005) upon request of the regulators in order to maintain ASB’s regulatory capital at the level required by regulation;

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

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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

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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 kilowatthour 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 income or 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 (returns).

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 its subsidiaries may incur higher retirement benefits expenses and could be required to recognize a substantial additional minimum liability for pension 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 and trends in interest rates and health care costs. 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 the need to request a rate increase.

Depending on investment results at each year end from the assets held in trust to satisfy retirement benefit plan obligations and the status of interest rates, the Company, like many sponsors of defined benefit pension plans, could be required in future years to recognize an additional minimum liability as prescribed by Statement of Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions.” The recognition of an additional minimum liability is required if the accumulated benefit obligation exceeds the fair value of plan assets on the measurement date. The electric utilities’ recognition of the liability would also require the removal of the prepaid pension asset ($106 million as of December 31, 2005) from their consolidated balance sheet and from their rate bases and the sum of these amounts (net of taxes) would be recorded as a reduction to stockholders’ equity

through a non-cash charge to accumulated other comprehensive income (AOCI), and would not affect net income. By application filed on December 8, 2005, the electric utilities have 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,” and include in rate base, any amount that would otherwise be charged to AOCI as a result of recording a minimum pension liability, but no assurance can be given concerning how or when the PUC will act on this request.

The amount of additional minimum liability and charge to AOCI, if any, that might be recorded could be material and will depend upon a number of factors, including the year-end discount rate assumption, asset returns experienced during the year, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during the year. In addition, retirement benefits expenses and cash funding requirements could increase in future years depending on the performance of the U.S. equity markets and trends in interest rates. 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 the need to request an electric rate increase. If HEI and its subsidiaries are required to record substantially greater charges to AOCI in the future, the consolidated financial ratios of HEI and its subsidiaries may deteriorate, which could result in security ratings downgrades and difficulty (or greater expense) in obtaining future financing. In addition, there may be possible financial covenant violations (although there are no advances currently outstanding under any credit facility subject to financial covenants). For example, certain of HECO’s bank lines of credit require that it maintain a minimum ratio of consolidated common equity to consolidated capitalization of 35% (actual ratio was 56% as of December 31, 2005). In addition, the rates of return for the electric utilities could increase if they were required to record significant charges to AOCI and could impact the rates the electric utilities are allowed to charge, which may ultimately result in reduced revenues and lower earnings.

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 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 kilowatthour sales of some or all of the electric utility subsidiaries.

Certain geographic regions of the U.S. may from time-to-time experience natural disasters or weaker regional economic conditions and housing markets and, consequently, may experience higher rates of loss and delinquency on loans. 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 hazards that may affect 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:

•

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.

•

HECO and its subsidiaries face competition from independent power producers (IPPs), including alternate energy providers, and customer self-generation, with or without cogeneration. The PUC has an ongoing investigative proceeding on competitive bidding as a mechanism for acquiring or building new electric generating capacity. New technological developments, such as the commercial development of fuel cells or distributed generation, may render the operations of HEI’s electric utility subsidiaries less competitive or obsolete. The PUC recently issued a decision in its ongoing 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 utilities have requested that the PUC clarify how the conditions will be administered. The electric utilities cannot predict the ultimate outcome of the PUC’s competitive bidding and DG investigations, 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.

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 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.

Events like the September 11, 2001 terrorist attacks and financial failures of Enron and other companies have resulted generally in a decreased availability of insurance and higher deductibles, higher premiums and more restrictive policy terms.

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. For example, HECO is a defendant in a suit, brought as a purported qui tam and class action, which claims that the State of Hawaii and HECO’s other customers have been overcharged for electricity as a result of allegedly excessive prices charged under a power purchase agreement between defendants HECO and AES Hawaii, Inc. The complaint asserted that HECO’s payments to AES Hawaii, Inc. for power have been “excessive” by over $1 billion since September 1992, and that approval of the power purchase agreement by the PUC in 1989 was wrongfully obtained through alleged misrepresentations or material omissions by the defendants of the estimated future costs under the power purchase agreement compared to the costs that would have been incurred if HECO-owned units had been constructed instead. Although a final judgment dismissing this complaint with prejudice was entered in HECO’s favor on September 17, 2003, one of the plaintiffs has appealed from this dismissal. On July 16, 2004, the Hawaii Supreme Court retained jurisdiction over the appeal (rather than assign the appeal to the Intermediate Court of Appeals) and the matter has been fully briefed and is awaiting decision. Because of the uncertainties associated with litigation, there is a risk that litigation against HEI and 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 or the Company’s application of existing accounting principles could materially affect HEI’s consolidated financial position 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 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 $111 million as of December 31, 2005) 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 $219 million as of December 31, 2005) 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 pending before the PUC in which it is seeking rate increases largely to recover the costs of capital improvements since its last rate case, the purchase of additional firm capacity and energy from Kalaeloa, the cost of measures taken to address peak load increases until generation capacity can be added on Oahu and increased operation and maintenance (O&M) expenses. In addition, HELCO has notified the PUC of its intention to file a request for a rate increase in spring 2006 intended to recover the cost of improvements to its transmission and distribution lines and the two generating units at its Keahole generating plant that became available for commercial operation since its last rate case in 2000. The increased level of the electric utilities’ O&M expenses (including increased retirement benefits expenses), which management expects will continue in 2006, increased capital expenditures, or other factors could 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. At the end of September 2005, HECO received and implemented an interim general rate increase of $53.3 million in annual base revenues granted by the PUC in HECO’s current rate case. As of December 31, 2005, HECO had recognized an aggregate of $32 million of revenues with respect to this interim general rate increase and other interim orders regarding certain integrated resource planning costs.

The rate schedules of each of HEI’s electric utilities include energy cost adjustment clauses 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 energy cost adjustment clauses 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 energy cost adjustment clauses in rate cases. While there was no opposition to the continuation of the clause by the parties in the pending HECO rate case, there can be no assurance concerning actions the PUC may take in its final order in the pending HECO rate case or otherwise in the future with respect to these clauses.

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.

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 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 79.5% of the net energy generated or purchased by the electric utilities in 2005 was generated from the burning of oil, and purchases of power by the electric utilities provided about 39.1% 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 power purchase agreement, 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 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 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 of substations and encouraging energy conservation. The marginal costs of supplying growing demand, however, is increasing because of HECO’s decreasing reserve margin situation and the rate of this increase is not likely to lessen until after HECO adds its proposed new generating unit on Oahu in 2009.

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. The Energy Policy Act of 2005 also replaced the Public Utility Holding Company Act of 1935 with the Public Utility Holding Company Act of 2005. On February 8, 2006, HEI and HECO became holding companies under the Public Utility Holding Company Act of 2005. The Public Utility Holding Company Act of 2005 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 have filed a notification claiming a waiver of such requirements as single-state public utility holding companies. There can be no assurance that the waiver will be obtained.

A number of bills on energy were introduced in the 2006 Hawaii State legislative session. While the majority of measures contained in these bills do not negatively affect the electric utilities, the electric utilities are actively engaged in deliberations before the Legislature on matters that may affect them if adopted, such as bills that would

direct the PUC to review and consider alternatives to the current energy cost adjustment clause, require the outsourcing of demand-side management programs, require the use of long-term fixed-price power purchase contracts for renewable energy generators, or modify the renewable portfolio standards law. At this time, it is not possible to predict the outcome of those deliberations.

The 2001 Hawaii Legislature passed a law establishing renewable portfolio standard (RPS) goals for the electric utilities, on a consolidated basis, of 7% by December 31, 2003, 8% by December 31, 2005 and 9% by December 31, 2010. The law was amended in 2004 to require electric utilities to meet a renewable portfolio standard of 8% by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015 and 20% by December 31, 2020. It may be difficult for the electric utilities to attain the renewables percentages in the future (although they have in the past), and management cannot predict the future consequences of failure to do so.

The renewable standards law also required the PUC to develop and implement a utility ratemaking structure, which may include performance-based ratemaking, to provide incentives that encourage Hawaii’s electric utilities to use cost-effective renewable energy resources found in Hawaii to meet the RPS goals, 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. In November 2004, the PUC initiated a process, consisting of three sets of workshops (two sets of which have been completed) that are intended to lead to the creation of a document forming the basis of a set of rules to be adopted in a rule-making process relating to electric utility rate design. The electric utilities cannot predict the ultimate outcome of this process.

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 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 control 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:

•

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;

•

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;

•

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;

•

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;

•

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

•

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, 2005, 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, 2005, 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 2007 and March 2011. HEI also subleases office space in a downtown Honolulu building leased by HECO under a lease that expires in November 2021. 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 two substation sites and at HECO’s Iwilei tank farm, have an aggregate net generating capability of 1,223.4 MW as of December 31, 2005. 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 122 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 6,734,855 kilovoltamperes as of December 31, 2005.

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 January 31, 2015 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. These plants at Hilo (2), Waimea, Kona and Puna, along with distributed generators at substation sites, have an aggregate net generating capability of 181.9 MW as of December 31, 2005 (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 43 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 administrative offices. HELCO also leases 4 acres of land for its baseyard in Hilo under a lease expiring in 2030. The deeds to the sites located in Hilo contain certain restrictions, which do not materially interfere with the use of the sites for public utility purposes. HELCO occupies 78 acres of land for the windfarm (with an aggregate net capability of 2.3 MW as of December 31, 2005), pursuant to a long-term operating agreement.

MECO owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 216.8 MW as of December 31, 2005. 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, 2005) 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 Oahu.

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


	Number of branches
December 31, 2005	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

In January 2006, ASB opened a new leased branch on the island of Oahu bringing the total number of branches to 65.

As of December 31, 2005, the net book value of branches and office facilities is approximately $44 million. Of this amount, $34 million represents the net book value of the land and improvements for the branches and office facilities owned by ASB and $10 million represents the net book value of ASB’s leasehold improvements. The leases expire on various dates from January 2006 through November 2036 and 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” 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) are involved in ordinary routine 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 2005, 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 March 6, 2006 and their years of company service are given as of December 31, 2005. Officers are appointed to serve until the meeting of the HEI Board of Directors after the next Annual Meeting of Shareholders (which will occur on May 2, 2006) 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		Business experience for past five years
Robert F. Clarke, age 63
Chairman of the Board, President and Chief Executive Officer		9/98 to date
Director		4/89 to date
(Company service: 18 years)

Eric K. Yeaman, age 38
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).
(Company service: 3 years)

Patricia U. Wong, age 49
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
(Company service: 15 years)

Charles F. Wall, age 66
Vice President and Corporate Information Officer		7/90 to date
(Company service: 15 years)

Andrew I. T. Chang, age 66
Vice President – Government Relations		4/91 to date
(Company service: 20 years)

Curtis Y. Harada, age 50
Controller		1/91 to date
(Company service: 16 years)

T. Michael May, age 59
President and Chief Executive Officer, HECO		9/95 to date
Director, HEI		9/95 to 12/04
Senior Vice President, HEI		9/95 to 4/01
(Company service: 13 years)

Constance H. Lau, age 53
President and Chief Executive Officer, ASB		6/01 to date
Director, HEI		6/01 to 12/04
Senior Executive Vice President and Chief Operating Officer, ASB		12/99 to 6/01
(Company service: 21 years)

HEI’s executive officers, with the exception of Charles F. Wall and Andrew I. T. Chang, are also officers and/or directors of one or more of HEI’s subsidiaries. Mr. May and Ms. Lau are deemed to be executive officers of HEI for purposes of this Item under the definition of 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 or any arrangements or understandings, between any executive officer or director of HEI and any person, pursuant to which the executive officer or director of HEI was selected.

Robert F. Clarke will relinquish his title as Chairman, President and CEO of HEI, effective at HEI’s Annual Meeting of Shareholders on May 2, 2006 and will not be renominated as a director of HEI. He will retire on May 31, 2006. HEI’s board of directors has named Constance H. Lau, President and CEO of ASB, to succeed Mr. Clarke on May 2, 2006, as HEI President and CEO, as well as Chairman of HECO. Ms. Lau will also retain her position as

President and CEO of ASB and will add the title of Chairman of the ASB board. She will also be nominated to be elected by the shareholders as a director of HEI. There are no arrangements or understandings between her and any person, pursuant to which she was selected. Also, effective in May 2006, Charles F. Wall, Vice President and Corporate Information Officer, will retire.

PART II

ITEM 5.

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

HEI:

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 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 March 1, 2006, was 12,568.

In 2005, HEI issued an aggregate of 28,200 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective March 8, 2005 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,400 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 an HEI nonemployee 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 (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

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 (the HEI Nonemployee Director Plan). In 2003, HEI issued an aggregate of 16,200 shares (split-adjusted) of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 1, 2002 (the HEI Nonemployee Director Plan).

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, 2005	110,054	$	26.24	—	NA
November 1 to 30, 2005	45,761		26.27	—	NA
December 1 to 31, 2005	267,176		26.28	—	NA

	422,991	$	26.27	—	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 DRIP and 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 brokers making the purchases for the DRIP and HEIRSP. Of the shares listed in column (a), 78,654 of the 110,054 shares, 45,761 of the 45,761 shares and 231,676 of the 267,176 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:

The information required with respect to “Market information” and “holders” is not applicable to 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.

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. The dividends declared and paid on HECO’s common stock for the quarter ended March 31, 2004 was $11,613,000. There were no dividends declared and paid on HECO’s common stock for the quarters ended June 30, 2004, September 30, 2004 and December 31, 2004 because HECO was strengthening its capital structure. 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 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	2005			2004			2003			2002			2001
(dollars in thousands, except per share amounts)
Results of operations
Revenues	$	2,215,564		$	1,924,057		$	1,781,316		$	1,653,701		$	1,727,277
Net income (loss)
Continuing operations	$	127,444		$	107,739		$	118,048		$	118,217		$	107,746
Discontinued operations		(755	)		1,913			(3,870	)		—			(24,041	)

	$	126,689		$	109,652		$	114,178		$	118,217		$	83,705

Basic earnings (loss) per common share
Continuing operations	$	1.58		$	1.36		$	1.58		$	1.63		$	1.60
Discontinued operations		(0.01	)		0.02			(0.05	)		—			(0.36	)

	$	1.57		$	1.38		$	1.53		$	1.63		$	1.24

Diluted earnings per common share	$	1.56		$	1.38		$	1.52		$	1.62		$	1.23

Return on average common equity-continuing operations *		10.5	%		9.4	%		11.1	%		12.0	%		12.2	%

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

Financial position **
Total assets	$	9,951,577		$	9,719,257		$	9,307,700		$	9,039,121		$	8,663,417
Deposit liabilities		4,557,419			4,296,172			4,026,250			3,800,772			3,679,586
Securities sold under agreements to repurchase		686,794			811,438			831,335			667,247			683,180
Advances from Federal Home Loan Bank		935,500			988,231			1,017,053			1,176,252			1,032,752
Long-term debt, net		1,142,993			1,166,735			1,064,420			1,106,270			1,145,769
HEI- and HECO-obligated preferred securities of trust subsidiaries		—			—			200,000			200,000			200,000
Preferred stock of subsidiaries – not subject to mandatory redemption		34,293			34,405			34,406			34,406			34,406
Stockholders’ equity		1,216,630			1,210,945			1,089,031			1,046,300			929,665

Common stock
Book value per common share **	$	15.02		$	15.01		$	14.36		$	14.21		$	13.06
Market price per common share
High		29.79			29.55			24.00			24.50			20.63
Low		24.60			22.96			19.10			17.28			16.78
December 31		25.90			29.15			23.69			21.99			20.14
Dividends per common share		1.24			1.24			1.24			1.24			1.24

Dividend payout ratio		79	%		90	%		81	%		76	%		100	%
Dividend payout ratio-continuing operations		78	%		91	%		78	%		76	%		78	%
Market price to book value per common share **		172	%		194	%		165	%		155	%		154	%
Price earnings ratio ***		16.4	x		21.4	x		15.0	x		13.5	x		12.6	x
Common shares outstanding (thousands) **		80,983			80,687			75,838			73,618			71,200
Weighted-average		80,828			79,562			74,696			72,556			67,508
Shareholders ****		35,645			35,292			34,439			34,901			37,387

Employees **		3,383			3,354			3,197			3,220			3,189

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

**	At December 31.

***	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 March 1, 2006, HEI had 35,624 registered shareholders and participants.

The Company discontinued its international power operations in 2001. See Note 14, “Discontinued operations,” of the “Notes to Consolidated Financial Statements.” Also see “Commitments and contingencies” in Note 3 of the “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 Exhibit 99 to HECO’s Form 8-K dated March 7, 2006.

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), supplies power to 93% of the Hawaii electric public utility market. 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 2005, income from continuing operations was $127 million, compared to $108 million in 2004. Basic earnings per share from continuing operations were $1.58 per share in 2005, up 16% from $1.36 per share in 2004 due primarily to a 2004 after-tax charge of $20 million, or $0.25 per share, as a result of a June 2004 tax ruling and subsequent settlement (see “Bank franchise taxes” sections below). Also impacting results in 2005 were lower electric utility earnings, partly offset by $8 million higher net gains on investments and lower financing costs in the “other” segment. The Company’s operations will be 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 a forecasted 3.5% in 2005 and is expected to grow by a forecasted 2.8% in 2006.

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, 2005 was 4.8%. HEI’s Board believes that HEI should achieve a 65% payout ratio 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 2005, 2004 and 2003 were 79%, 90% and 81% (payout ratios of 78%, 91% and 78% based on income from continuing operations), respectively. The high payout ratio for 2004 was primarily due to the 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 forecast by the DBEDT to be a moderate 3.0% in 2006.

It was a record year for tourism in Hawaii with visitor days exceeding the 2004 record by 6.6%. In 2005, visitor expenditures were $11.8 billion, which is an 8.7% increase over 2004. State economists expect continued growth in 2006 with projected increases of 3.1% in visitor days and 4.6% 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. After five years of increases, real estate prices climbed again in 2005, resulting in $6 billion in total dollar residential resale volumes on Oahu, a 25.8% increase over 2004.

The construction industry continues to remain healthy indicated by a 28.1% increase in building permits in 2005 compared with 2004. Local economists forecast contracting receipts to grow by 5% in 2006.

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 prices of electricity on usage and (2) interest rates because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Crude oil prices rose considerably during 2005 as strong demand from the U.S. and China and geopolitical uncertainty continued. Futures prices began 2005 near $27 per barrel and spiked to a high of $69.81 per barrel in August 2005 in the wake of Hurricane Katrina. Prices moved down in the last quarter of the year as regional production in the Gulf was restored. More recently, however, prices are climbing due to political tension and uncertainty in oil producing countries such as Iran and Nigeria. On February 3, 2006, crude oil futures closed at $65.37 per barrel.

For most of 2005, long-term interest rates fluctuated in the 4.0% to 4.5% trading range and the short-end of the yield curve continued to increase. This resulted in a flattening yield curve throughout the year which is indicative of a difficult earning environment for ASB. As of December 31, 2005, the yield curve was inverted with a spread between the 10-year and 2-year Treasuries of (0.02)%, compared to the yield curve as of December 31, 2004 with a spread of 1.16%.

Results of Operations


(dollars in millions, except per share amounts)	2005			% change		2004			% change		2003
Revenues	$	2,216		15		$	1,924		8		$	1,781
Operating income		271		—			271		3			264
Income from continuing operations	$	128		18		$	108		(9	)	$	118
Loss from discontinued operations		(1	)	NM			2		NM			(4	)

Net income	$	127		16		$	110		(4	)	$	114

Electric utility	$	73		(10	)	$	81		3		$	79
Bank		65		58			41		(27	)		56
Other		(10	)	NM			(14	)	NM			(17	)

Income from continuing operations	$	128		18		$	108		(9	)	$	118

Basic earnings (loss) per share
Continuing operations	$	1.58		16		$	1.36		(14	)	$	1.58
Discontinued operations		(0.01	)	NM			0.02		NM			(0.05	)

	$	1.57		14		$	1.38		(10	)	$	1.53

Dividends per share	$	1.24		—		$	1.24		—		$	1.24

Weighted-average number of common shares outstanding (millions)		80.8		2			79.6		7			74.7
Dividend payout ratio		79	%				90	%				81	%
Dividend payout ratio – continuing operations		78	%				91	%				78	%

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 the “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 the “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 and including additional bank franchise taxes in prior periods as if the Company had not taken a dividends received deduction on income from its real estate investment trust (REIT) subsidiary. 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 accounting principles generally accepted in the United States of America (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	2005			2004			2003
(dollars in thousands, except per share amounts)
Income from continuing operations	$	127,444		$	107,739		$	118,048
Basic earnings per share - continuing operations	$	1.58		$	1.36		$	1.58

Cumulative bank franchise taxes, net of taxes, through December 31, 2003	$	—		$	20,340		$	—
Additional bank franchise taxes, net of taxes (if recorded in prior periods)	$	—		$	—		$	(3,793	)

As adjusted
Income from continuing operations	$	127,444		$	128,079		$	114,255
Basic earnings per share - continuing operations	$	1.58		$	1.61		$	1.53
Return on average common equity ¹		10.5	%		11.2	%		10.9	%

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 (pension and other postretirement benefits)

The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of 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 2005, 2004 and 2003 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 benefits 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 considers the Moody’s Daily Long-Term Corporate Bond Aa Yield Average (which was 5.41% as of December 31, 2005 compared to 5.66% as of December 31, 2004) and changes in this rate from period to period. In addition, the plans’ actuarial consultant prepared a 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, 2005, which supports the 5.75% discount rate adopted as of December 31, 2005. In selecting an assumed rate of return on plan assets, the Company considers economic forecasts for the types of inv