Hawaiian Electric Industries (HE) 8-K Results of Operations and Financial Condition

HECO Exhibit 99

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Company, Inc. (HECO) and its 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 HECO and its subsidiaries (collectively, the Company), the performance of the industry in which it does 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, decisions concerning the extent of the presence of the federal government and military in Hawaii, and the implications and potential impacts of current capital and credit market conditions and federal and state responses to those conditions, such as the Emergency Economic Stabilization Act of 2008 (plan for a $700 billion bailout of the financial industry) and American Economic Recovery and Reinvestment Act of 2009 (economic stimulus package);

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

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

• the timing and extent of changes in interest rates;

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

• the risks inherent in changes in the value of pension and other retirement plan assets;

• changes in laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;

• increasing competition in the electric utility industry (e.g., increased self-generation of electricity may have an adverse impact on the Company’s revenues );

• the effects of the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement) setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), the fulfillment by the Company of its commitments under the Energy Agreement and revenue decoupling;

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

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

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

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

• the ability of the Company to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

• new technological developments that could affect the operations and prospects of the Company or its competitors;

• federal, state, county and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to the Company (including changes in taxation, regulatory changes resulting from the HCEI, environmental laws and regulations, the potential regulation of greenhouse gas emissions and governmental fees and assessments); decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases (including decisions on ECACs) and other proceedings and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, for example with respect to environmental conditions or renewable portfolio standards (RPS));

• increasing operation and maintenance expenses and investment in infrastructure for the Company, resulting in the need for more frequent rate cases;

• the risks associated with the geographic concentration of the Company’s business;

1

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

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

• the final outcome of tax positions taken by the Company;

• the risks of suffering losses and incurring liabilities that are uninsured; and

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

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, the Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

2

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

HECO incorporates by reference all of the “electric utility” sections and all information related to or including HECO and its subsidiaries in HEI’s MD&A (except for HEI’s Selected contractual obligations and commitments table), included in HEI Exhibit 13 to the Form 8-K dated February 19, 2009.

Selected contractual obligations and commitments. The following table presents HECO and subsidiaries aggregated information as of December 31, 2008 about total payments due during the indicated periods under the specified contractual obligations and commitments:

December 31, 2008		Payment due by period
(in millions)		1 year or less		2-3 years		4-5 years		More than 5 years		Total
Long-term debt, net	$	–	$	–	$	58	$	800	$	858
Operating leases		4		6		5		13		28
Open purchase order obligations		120		13		–		–		133
Fuel oil purchase obligations (estimate based on January 1, 2009 fuel oil prices)		435		870		870		435		2,610
Purchase power obligations– minimum fixed capacity charges		119		234		237		897		1,487
Liabilities for uncertain tax positions (FIN 48 liability)		4		1		–		–		5
Total (estimated)	$	682	$	1,124	$	1,170	$	2,145	$	5,121

The tables above do not include other categories of obligations and commitments, such as deferred taxes, interest (on long-term debt and uncertain tax positions), trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans and potential refunds of amounts collected under interim decision and orders (D&Os) of the PUC. Minimum funding requirements for retirement benefit plans have not been included in the tables above, and such requirements could be substantial in 2009 and future periods in light of the substantial gap between the projected benefit obligation under such plans and the fair value of the assets held in trust to satisfy the obligations. HECO incorporates by reference the section “Retirement benefits” in HEI’s MD&A and Note 10 (“Retirement benefits”) of HECO’s “Notes to Consolidated Financial Statements” for a discussion of retirement benefit plan obligations, including estimated minimum required contributions for 2009 and 2010.

Quantitative and Qualitative Disclosures about Market Risk

HECO and its subsidiaries manage various market risks in the ordinary course of business, including credit risk and liquidity risk, but management believes their exposures to these two risks are not material as of December 31, 2008.

HECO and its subsidiaries are exposed to some commodity price risk primarily related to its fuel supply and IPP contracts. HECO and its subsidiaries’ commodity price risk is substantially mitigated so long as they have their current ECACs in their rate schedules. See discussion of the ECACs in “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates” in HEI’s MD&A, included in HEI Exhibit 13 to the Form 8-K dated February 19, 2009. HECO and its subsidiaries currently have no hedges against their commodity price risk.

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

HECO and its subsidiaries consider interest rate risk to be a significant market risk as it may affect the discount rate used to determine pension liabilities, the market value of pension plans’ assets and the allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.

HECO incorporates by reference the section “Other than bank interest rate risk” in HEI’s Quantitative and Qualitative Disclosures about Market Risk,” included in HEI Exhibit 13 to the Form 8-K dated February 19, 2009, and the discussion in Note 10 of HECO’s “Notes to Consolidated Financial Statements.”

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Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31		2008			2007			2006			2005			2004
(in thousands)
Income statement data
Operating revenues	$	2,853,639		$	2,096,958		$	2,050,412		$	1,801,710		$	1,546,875
Operating expenses		2,723,702			1,996,683			1,933,257			1,688,168			1,425,583
Operating income		129,937			100,275			117,155			113,542			121,292
Other income		15,049			4,592			9,471			8,643			8,926
Income before interest and other charges		144,986			104,867			126,626			122,185			130,218
Interest and other charges		51,931			51,631			50,599			48,303			47,961
Income before preferred stock dividends of HECO		93,055			53,236			76,027			73,882			82,257
Preferred stock dividends of HECO		1,080			1,080			1,080			1,080			1,080
Net income for common stock	$	91,975		$	52,156		$	74,947		$	72,802		$	81,177
At December 31		2008			2007			2006			2005			2004
(in thousands)
Balance sheet data
Utility plant	$	4,586,668		$	4,320,607		$	4,133,883		$	3,930,321		$	3,709,857
Accumulated depreciation		(1,741,453	)		(1,647,113	)		(1,558,913	)		(1,456,537	)		(1,361,703	)
Net utility plant	$	2,845,215		$	2,673,494		$	2,574,970		$	2,473,784		$	2,348,154
Total assets	$	3,856,109		$	3,423,888		$	3,063,134		$	3,081,461		$	2,879,615
Capitalization:1
Short-term borrowings from non-affiliates and affiliate	$	41,550		$	28,791		$	113,107		$	136,165		$	88,568
Long-term debt, net		904,501			885,099			766,185			765,993			752,735
Preferred stock not subject to mandatory redemption		34,293			34,293			34,293			34,293			34,293
Common stock equity		1,188,842			1,110,462			958,203			1,039,259			1,017,104
Total capitalization	$	2,169,186		$	2,058,645		$	1,871,788		$	1,975,710		$	1,892,700
Capital structure ratios (%)1
Debt		43.6			44.4			47.0			45.7			44.5
Preferred stock		1.6			1.7			1.8			1.7			1.8
Common stock equity		54.8			53.9			51.2			52.6			53.7

¹ Includes amounts due within one year, short-term borrowings from nonaffiliates and affiliate, and sinking fund and optional redemption payments.

HEI owns all of HECO’s common stock. Therefore, per share data is not meaningful.

See Forward-Looking Statements above, the “electric utility” sections and all information related to, or including, HECO and its subsidiaries incorporated by reference from HEI’s MD&A included in HEI Exhibit 13 to the Form 8-K dated February 19, 2009, and Note 10 (“Retirement benefits”) and Note 11 (“Commitments and contingencies”) of HECO’s “Notes to Consolidated Financial Statements” for a discussion of certain contingencies, risks and uncertainties that could adversely affect the Company’s future results of operations, financial condition and liquidity.

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Annual Report of Management on Internal Control Over Financial Reporting

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control system was designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of its consolidated financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2008.

KPMG LLP, an independent registered public accounting firm, has issued an audit report on the Company’s internal control over financial reporting as of December 31, 2008. This report appears on page 6.

/s/ Richard M. Rosenblum	/s/ Tayne S. Y. Sekimura	/s/ Patsy H. Nanbu
Richard M. Rosenblum	Tayne S. Y. Sekimura	Patsy H. Nanbu
President and Chief Executive Officer	Senior Vice President, Finance & Administration and Chief Financial Officer	Controller and Chief Accounting Officer

February 20, 2009

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[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

We have audited Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Hawaiian Electric Company, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying annual report of management on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Hawaiian Electric Company, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of income, retained earnings, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated February 20, 2009 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Honolulu, Hawaii

February 20, 2009

6

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of income, retained earnings, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 1 and 7 to the consolidated financial statements, the Company adopted the provisions of FASB Interpretation No. 48Accounting for Uncertainty in Income Taxes, as of January 1, 2007.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 20, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Honolulu, Hawaii

February 20, 2009

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Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31		2008			2007			2006
(in thousands)
Operating revenues	$	2,853,639		$	2,096,958		$	2,050,412
Operating expenses
Fuel oil		1,229,193			774,119			781,740
Purchased power		689,828			536,960			506,893
Other operation		243,249			214,047			186,449
Maintenance		101,624			105,743			90,217
Depreciation		141,678			137,081			130,164
Taxes, other than income taxes		261,823			194,607			190,413
Income taxes		56,307			34,126			47,381
		2,723,702			1,996,683			1,933,257
Operating income		129,937			100,275			117,155
Other income
Allowance for equity funds used during construction		9,390			5,219			6,348
Other, net		5,659			(627	)		3,123
		15,049			4,592			9,471
Income before interest and other charges		144,986			104,867			126,626
Interest and other charges
Interest on long-term debt		47,302			45,964			43,109
Amortization of net bond premium and expense		2,530			2,440			2,198
Other interest charges		4,925			4,864			7,256
Allowance for borrowed funds used during construction		(3,741	)		(2,552	)		(2,879	)
Preferred stock dividends of subsidiaries		915			915			915
		51,931			51,631			50,599
Income before preferred stock dividends of HECO		93,055			53,236			76,027
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	91,975		$	52,156		$	74,947

Consolidated Statements of Retained Earnings

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31		2008			2007			2006
(in thousands)
Retained earnings, January 1	$	724,704		$	700,252		$	654,686
Net income for common stock		91,975			52,156			74,947
Adjustment to initially apply FIN 48		–			(620	)		–
Common stock dividends		(14,089	)		(27,084	)		(29,381	)
Retained earnings, December 31	$	802,590		$	724,704		$	700,252

See accompanying “Notes to Consolidated Financial Statements.”

8

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31		2008			2007
(in thousands)
Assets
Utility plant, at cost
Land	$	42,541		$	38,161
Plant and equipment		4,277,499			4,131,226
Less accumulated depreciation		(1,741,453	)		(1,647,113	)
Plant acquisition adjustment, net		–			41
Construction in progress		266,628			151,179
Net utility plant		2,845,215			2,673,494
Current assets
Cash and equivalents		6,901			4,678
Customer accounts receivable, net		166,422			146,112
Accrued unbilled revenues, net		106,544			114,274
Other accounts receivable, net		7,918			6,915
Fuel oil stock, at average cost		77,715			91,871
Materials and supplies, at average cost		34,532			34,258
Prepayments and other		12,626			9,490
Total current assets		412,658			407,598
Other long-term assets
Regulatory assets		530,619			284,990
Unamortized debt expense		14,503			15,635
Other		53,114			42,171
Total other long-term assets		598,236			342,796
	$	3,856,109		$	3,423,888
Capitalization and liabilities
Capitalization(see Consolidated Statements of Capitalization)
Common stock equity	$	1,188,842		$	1,110,462
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
Long-term debt, net		904,501			885,099
Total capitalization		2,127,636			2,029,854
Current liabilities
Short-term borrowings-nonaffiliates		–			28,791
Short-term borrowings-affiliate		41,550			–
Accounts payable		122,994			137,895
Interest and preferred dividends payable		15,397			14,719
Taxes accrued		220,046			189,637
Other		55,268			57,799
Total current liabilities		455,255			428,841
Deferred credits and other liabilities
Deferred income taxes		166,310			162,113
Regulatory liabilities		288,602			261,606
Unamortized tax credits		58,796			58,419
Retirement benefits liability		392,845			129,288
Other		54,949			54,030
Total deferred credits and other liabilities		961,502			665,456
Contributions in aid of construction		311,716			299,737
	$	3,856,109		$	3,423,888

See accompanying “Notes to Consolidated Financial Statements.”

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Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31		2008		2007		2006
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding:
2008, 2007 and 2006, 12,805,843 shares	$	85,387	$	85,387	$	85,387
Premium on capital stock		299,214		299,214		299,214
Retained earnings		802,590		724,704		700,252
Accumulated other comprehensive income (loss), net of income tax benefits:
Retirement benefit plans		1,651		1,157		(126,650	)
Common stock equity		1,188,842		1,110,462		958,203
Cumulative preferred stock
not subject to mandatory redemption
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value.
Outstanding: 2008 and 2007, 1,234,657 shares.

Series		Par Value			Shares Outstanding December 31, 2008 and 2007		2008		2007
(dollars in thousands, except par value and shares outstanding)
C-4 1/4%	$	20	(HECO	)	150,000		3,000		3,000
D-5%		20	(HECO	)	50,000		1,000		1,000
E-5%		20	(HECO	)	150,000		3,000		3,000
H-5 1/4%		20	(HECO	)	250,000		5,000		5,000
I-5%		20	(HECO	)	89,657		1,793		1,793
J-4 3/4%		20	(HECO	)	250,000		5,000		5,000
K-4.65%		20	(HECO	)	175,000		3,500		3,500
G-7 5/8%		100	(HELCO	)	70,000		7,000		7,000
H-7 5/8%		100	(MECO	)	50,000		5,000		5,000
					1,234,657	$	34,293	$	34,293

(continued)

See accompanying “Notes to Consolidated Financial Statements.”

10

Consolidated Statements of Capitalization,continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31		2008		2007
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 4.60%, refunding series 2007B, due 2026	$	62,000	$	62,000
HELCO, 4.60%, refunding series 2007B, due 2026		8,000		8,000
MECO, 4.60%, refunding series 2007B, due 2026		55,000		55,000
HECO, 4.65%, series 2007A, due 2037		100,000		100,000
HELCO, 4.65%, series 2007A, due 2037		20,000		20,000
MECO, 4.65%, series 2007A, due 2037		20,000		20,000
HECO, 4.80%, refunding series 2005A, due 2025		40,000		40,000
HELCO, 4.80%, refunding series 2005A, due 2025		5,000		5,000
MECO, 4.80%, refunding series 2005A, due 2025		2,000		2,000
HECO, 5.00%, refunding series 2003B, due 2022		40,000		40,000
HELCO, 5.00%, refunding series 2003B, due 2022		12,000		12,000
HELCO, 4.75%, refunding series 2003A, due 2020		14,000		14,000
HECO, 5.10%, series 2002A, due 2032		40,000		40,000
HECO, 5.70%, refunding series 2000, due 2020		46,000		46,000
MECO, 5.70%, refunding series 2000, due 2020		20,000		20,000
HECO, 6.15%, refunding series 1999D, due 2020		16,000		16,000
HELCO, 6.15%, refunding series 1999D, due 2020		3,000		3,000
MECO, 6.15%, refunding series 1999D, due 2020		1,000		1,000
HECO, 6.20%, series 1999C, due 2029		35,000		35,000
HECO, 5.75%, refunding series 1999B, due 2018		30,000		30,000
HELCO, 5.75%, refunding series 1999B, due 2018		11,000		11,000
MECO, 5.75%, refunding series 1999B, due 2018		9,000		9,000
HELCO, 5.50%, refunding series 1999A, due 2014		11,400		11,400
HECO, 4.95%, refunding series 1998A, due 2012		42,580		42,580
HELCO, 4.95%, refunding series 1998A, due 2012		7,200		7,200
MECO, 4.95%, refunding series 1998A, due 2012		7,720		7,720
HECO, 5.65%, series 1997A, due 2027		50,000		50,000
HELCO, 5.65%, series 1997A, due 2027		30,000		30,000
MECO, 5.65%, series 1997A, due 2027		20,000		20,000
HECO, 5.45%, series 1993, due 2023		50,000		50,000
HELCO, 5.45%, series 1993, due 2023		20,000		20,000
MECO, 5.45%, series 1993, due 2023		30,000		30,000
		857,900		857,900
Less funds on deposit with trustee		3,186		22,461
Total obligations to the State of Hawaii		854,714		835,439
Other long-term debt – unsecured:
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034		51,546		51,546
Total long-term debt		906,260		886,985
Less unamortized discount		1,759		1,886
Long-term debt, net		904,501		885,099
Total capitalization	$	2,127,636	$	2,029,854

See accompanying “Notes to Consolidated Financial Statements.”

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Consolidated Statements of Changes in Common Stock Equity

Hawaiian Electric Company, Inc. and Subsidiaries

	Common stock				Premium on capital stock		Retained earnings			Accumulated other comprehensive income (loss)			Total
(in thousands)	Shares		Amount
Balance, December 31, 2005	12,806	$	85,387	$	299,212	$	654,686		$	(26	)	$	1,039,259
Comprehensive income:
Net income	–		–		–		74,947			–			74,947
Minimum pension liability adjustment, net of taxes of $18	–		–		–		–			26			26
Comprehensive income	–		–		–		74,947			26			74,973
Adjustment to initially apply SFAS No. 158, net of tax benefits of $80,666	–		–		–		–			(126,650	)		(126,650	)
Common stock dividends	–		–		–		(29,381	)		–			(29,381	)
Other	–		–		2		–			–			2
Balance, December 31, 2006	12,806		85,387		299,214		700,252			(126,650	)		958,203
Comprehensive income:
Net income	–		–		–		52,156			–			52,156
Retirement benefit plans:
Net gains arising during the period, net of taxes of $9,861	–		–		–		–			15,484			15,484
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $5,001	–		–		–		–			7,854			7,854
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $11,007	–		–		–		–			(17,282	)		(17,282	)
Comprehensive income	–		–		–		52,156			6,056			58,212
Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes of $77,546	–		–		–		–			121,751			121,751
Adjustment to initially apply FIN 48	–		–		–		(620	)		–			(620	)
Common stock dividends	–		–		–		(27,084	)		–			(27,084	)
Balance, December 31, 2007	12,806		85,387		299,214		724,704			1,157			1,110,462
Comprehensive income:
Net income	–		–		–		91,975			–			91,975
Retirement benefit plans:
Net losses arising during the period, net of tax benefits of $100,141	–		–		–		–			(157,226	)		(157,226	)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,481	–		–		–		–			5,464			5,464
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $96,975	–		–		–		–			152,256			152,256
Comprehensive income	–		–		–		91,975			494			92,469
Common stock dividends	–		–		–		(14,089	)		–			(14,089	)
Balance, December 31, 2008	12,806	$	85,387	$	299,214	$	802,590		$	1,651		$	1,188,842

See accompanying “Notes to Consolidated Financial Statements.”

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Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31		2008			2007			2006
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	93,055		$	53,236		$	76,027
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		141,678			137,081			130,164
Other amortization		8,619			8,230			7,932
Writedown of utility plant		–			11,701			–
Deferred income taxes		3,882			(31,888	)		(9,671	)
Tax credits, net		1,470			1,992			3,810
Allowance for equity funds used during construction		(9,390	)		(5,219	)		(6,348	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(21,313	)		(23,080	)		8,709
Decrease (increase) in accrued unbilled revenues		7,730			(22,079	)		(874	)
Decrease (increase) in fuel oil stock		14,156			(27,559	)		21,138
Increase in materials and supplies		(274	)		(3,718	)		(3,566	)
Increase in regulatory assets		(3,229	)		(1,968	)		(6,123	)
Increase (decrease) in accounts payable		(14,901	)		35,383			(19,689	)
Changes in prepaid and accrued income and utility revenue taxes		28,055			37,455			18,599
Decrease in prepaid pension benefit cost		–			–			20,064
Other		(5,445	)		16,108			(12,641	)
Net cash provided by operating activities		244,093			185,675			227,531
Cash flows from investing activities
Capital expenditures		(278,476	)		(209,821	)		(195,072	)
Contributions in aid of construction		17,319			19,011			19,707
Other		1,157			5,440			407
Net cash used in investing activities		(260,000	)		(185,370	)		(174,958	)
Cash flows from financing activities
Common stock dividends		(14,089	)		(27,084	)		(29,381	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Proceeds from issuance of long-term debt		19,275			242,538			–
Repayment of long-term debt		–			(126,000	)		–
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		12,759			(84,316	)		(23,058	)
Other		1,265			(3,544	)		4,662
Net cash provided by (used in) financing activities		18,130			514			(48,857	)
Net increase in cash and equivalents		2,223			819			3,716
Cash and equivalents, January 1		4,678			3,859			143
Cash and equivalents, December 31	$	6,901		$	4,678		$	3,859

See accompanying “Notes to Consolidated Financial Statements.”

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Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General

Hawaiian Electric Company, Inc. (HECO) and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the Public Utilities Commission of the State of Hawaii (PUC). HECO also owns non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which will invest in renewable energy projects, Uluwehiokama Biofuels Corp. (UBC), which was formed to own a new biodiesel refining plant to be built on the island of Maui and is intended to direct its profits into a trust to be created for the purpose of funding biofuels development in Hawaii, and HECO Capital Trust III, which is an unconsolidated financing entity.

Basis of presentation

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

Material estimates that are particularly susceptible to significant change include the amounts reported for property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; revenues; and variable interest entities (VIEs).

Consolidation

The consolidated financial statements include the accounts of HECO and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable-interest entities of which the Company is not the primary beneficiary. Investments in companies over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method. The Company is a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. (HEI). All material intercompany accounts and transactions have been eliminated in consolidation.

See Note 3 for information regarding the application of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 46(R).

Regulation by the Public Utilities Commission of the State of Hawaii (PUC)

HECO, HELCO and MECO are regulated by the PUC and account for the effects of regulation under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes its operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory assets would be charged to expense and the regulatory liabilities would be credited to income or refunded to ratepayers. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers.

Equity method

Investments in up to 50%-owned affiliates over which the Company has the ability to exercise significant influence over the operating and financing policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the Company’s equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses is reflected in other income. Equity method investments are evaluated for other-than-temporary impairment.

Utility plant

Utility plant is reported at cost. Self-constructed plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in

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construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make utility plant more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

If a power purchase agreement (PPA) falls within the scope of Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” and results in the classification of the agreement as a capital lease, the Company would recognize a capital asset and a lease obligation.

Depreciation

Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Utility plant additions in the current year are depreciated beginning January 1 of the following year. Utility plant has lives ranging from 20 to 45 years for production plant, from 25 to 60 years for transmission and distribution plant and from 7 to 45 years for general plant. The composite annual depreciation rate, which includes a component for cost of removal, was 3.8% in 2008 and 2007 and 3.9% in 2006.

Cash and equivalents

The Company considers cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper and liquid investments (with original maturities of three months or less) to be cash and equivalents.

Accounts receivable

Accounts receivable are recorded at the invoiced amount. The Company generally assesses a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company adjusts its allowance on a monthly basis, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Retirement benefits

Pension and other postretirement benefit costs are charged primarily to expense and utility plant. Funding for the Company’s qualified pension plan is based on actuarial assumptions adopted by the Pension Investment Committee administering the plan on the advice of an enrolled actuary. The participating employers contribute amounts to a master pension trust for the plan in accordance with the funding requirements of Employee Retirement Income Security Act of 1974, as amended (ERISA), including changes promulgated by the Pension Protection Act of 2006, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost as calculated using SFAS No. 87 “Employers’ Accounting for Pensions” during the fiscal year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the PUC on an interim basis, HECO generally will make contributions to the pension fund at the minimum level required under the law, until its pension asset (existing at the time of the PUC decision and determined based on the cumulative fund contributions in excess of the cumulative net periodic pension cost recognized) is reduced to zero, at which time HECO would fund the pension cost as specified in the pension tracking mechanism. HELCO and MECO will generally fund the net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions as calculated using SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and the amortization of the regulatory asset for postretirement benefits other than pensions (OPEB), while maximizing the use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The Company must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC on an interim basis. Future decisions in rate cases could further impact funding amounts.

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Effective December 31, 2006, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” and recognized on its balance sheet the funded status of its defined benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.

Financing costs

The Company uses the straight-line method to amortize long-term debt financing costs and premiums or discounts over the term of the related debt. Unamortized financing costs and premiums or discounts on long-term debt retired prior to maturity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

The Company uses the straight-line method to amortize the fees and related costs paid to secure a firm commitment under its line-of-credit arrangements.

Contributions in aid of construction

The Company receives contributions from customers for special construction requirements. As directed by the PUC, contributions are amortized on a straight-line basis over 30 years as an offset against depreciation expense.

Electric utility revenues

Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the meter readings in the beginning of the following month, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. As of December 31, 2008, customer accounts receivable include unbilled energy revenues of $107 million on a base of annual revenue of $2.9 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

The rate schedules of the Company include energy cost adjustment clauses (ECACs) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The ECACs also include a provision requiring a quarterly reconciliation of the amounts collected through the ECACs. See “Energy cost adjustment clauses” in Note 11 for a discussion of the ECACs and Act 162 of the 2006 Hawaii State Legislature.

The Company’s operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. The Company’s payments to the taxing authorities are based on the prior years’ revenues. For 2008, 2007 and 2006, the Company included approximately $252 million, $185 million and $182 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Repairs and maintenance costs

Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.

Allowance for Funds Used During Construction (AFUDC)

AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, as it was in the case of HELCO’s installation of CT-4 and CT-5, AFUDC on the delayed project may be stopped.

The weighted-average AFUDC rate was 8.1% in 2008 and 2007 and 8.4% in 2006, and reflected quarterly compounding.

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Environmental expenditures

The Company is subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Income taxes

The Company is included in the consolidated income tax returns of HECO’s parent, HEI. Income tax expense has been computed for financial statement purposes as if HECO and its subsidiaries filed separate consolidated HECO income tax returns.

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

Federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset might be impaired and written down or written off or an unanticipated tax liability might be incurred.

Effective January 1, 2007, the Company adopted FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” and uses a “more-likely-than-not” recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

Impairment of long-lived assets and long-lived assets to be disposed of

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.

Recent accounting pronouncements and interpretations

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

Noncontrolling interests. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” SFAS No. 160 requires the recognition of a noncontrolling interest (i.e., a minority interest) as equity in the consolidated financial statements, separate from the parent’s equity, and requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the income statement. Under SFAS No. 160, changes in the parent’s ownership interest that

17

leave control intact are accounted for as capital transactions (i.e., as increases or decreases in ownership), a gain or loss will be recognized when a subsidiary is deconsolidated based on the fair value of the noncontrolling equity investment (not carrying amount), and entities must provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and of the noncontrolling owners. The Company adopted SFAS No. 160 prospectively on January 1, 2009, except for the presentation and disclosure requirements which must be applied retrospectively.

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

Fair value measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 applies to fair value measurements that are already required or permitted under existing accounting pronouncements with some exceptions. SFAS No. 157 retains the exchange price notion in defining fair value and clarifies that the exchange price is the price that would be received upon sale of an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability. It emphasizes that fair value is a market-based, not an entity-specific, measurement based upon the assumptions that consider credit and nonperformance risk market participants would use in pricing an asset or liability. As a basis for considering assumptions in fair value measurements, SFAS No. 157 establishes a hierarchy that gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). SFAS No. 157 expands disclosures about the use of fair value, including disclosure of the level within the hierarchy in which the fair value measurements fall and the effect of the measurements on earnings (or changes in net assets) for the period. The Company adopted SFAS No. 157 on January 1, 2008. The adoption of SFAS No. 157 for fair value measures of financial assets and financial liabilities had no impact on the Company’s financial results, but have impacted the Company’s fair value measurement disclosures.

FASB Staff Position (FSP) FAS 157-2 “Effective Date of FASB Statement No. 157,” delays the effective date of SFAS No. 157 until fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis.

On January 1, 2009, the Company will be required to apply the provisions of SFAS No. 157 to fair value measurements of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The Company is in the process of evaluating the impact, if any, of applying these provisions on its financial position and results of operations.

In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active,” which was effective immediately. FSP FAS 157-3 clarifies the application of SFAS No. 157 in cases where the market for a financial instrument is not active and provides an example to illustrate key considerations in determining fair value in those circumstances. The Company has considered the guidance provided by FSP FAS 157-3 in its determination of estimated fair values during 2008.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2008 presentation.

2. Cumulative preferred stock

The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:

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December 31, 2008	Voluntary Liquidation Price		Redemption Price
Series
C, D, E, H, J and K (HECO)	$	20	$	21
I (HECO)		20		20
G (HELCO)		100		100
H (MECO)		100		100

HECO is obligated to make dividend, redemption and liquidation payments on the preferred stock of either of its subsidiaries if the respective subsidiary is unable to make such payments, but such obligation is subordinated to any obligation to make payments on HECO’s own preferred stock.

3. Unconsolidated variable interest entities

HECO Capital Trust III.HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million, (iii) making distributions on the trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are redeemable at the issuer’s option without premium beginning on March 18, 2009. The 2004 Debentures, together with the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with FIN 46R. Trust III’s balance sheet as of December 31, 2008 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for 2008 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements. As of December 31, 2008, HECO and its subsidiaries had six PPAs for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities) that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for 2008 totaled $690 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $141 million, $273 million, $92 million and $60 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

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

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

As required under FIN 46R since 2004, HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In each year beginning from 2005 through 2009, HECO and its subsidiaries sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs declined to provide necessary information, except that Kalaeloa provided the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under the PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as MECO and HELCO do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

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

Kalaeloa Partners, L.P.In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, 2) a fuel additives cost component, and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

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

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4. Long-term debt

For special purpose revenue bonds, funds on deposit with trustees represent the undrawn proceeds from the issuance of the special purpose revenue bonds and earn interest at market rates. These funds are available only to pay (or reimburse payment of) expenditures in connection with certain authorized construction projects and certain expenses related to the bonds.

On March 27, 2007, the Department of Budget and Finance of the State of Hawaii (the Department) issued (pursuant to a 2005 legislative authorization), at par, Series 2007A SPRBs in the aggregate principal amount of $140 million, with a maturity of March 1, 2037 and a fixed coupon interest rate of 4.65%, and loaned the proceeds to HECO ($100 million), HELCO ($20 million) and MECO ($20 million). Payment of the principal and interest on the SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company. Proceeds are being used to finance capital expenditures, including reimbursements to the electric utilities for previously incurred capital expenditures which, in turn, have been used primarily to repay short-term borrowings. As of December 31, 2008, approximately $3 million of proceeds from the Series 2007A SPRBs had not yet been drawn and were held by the construction fund trustee for HELCO. HELCO’s long-term debt will increase from time to time as these remaining proceeds are drawn down. Proceeds from the Series 2007A SPRBs for HECO and MECO were fully drawn as of December 31, 2008.

On March 27, 2007, the Department also issued, at par, Refunding Series 2007B SPRBs in the aggregate principal amount of $125 million, with a maturity of May 1, 2026 and a fixed coupon interest rate of 4.60%, and loaned the proceeds to HECO ($62 million), HELCO ($8 million) and MECO ($55 million). Proceeds from the sale were applied, together with other funds provided by the electric utilities, to the redemption at par on May 1, 2007 of the $75 million aggregate principal amount of 6.20% Series 1996A SPRBs (which had an original maturity of May 1, 2026) and to the redemption at a 2% premium on April 27, 2007 of the $50 million aggregate principal amount of 5 7/8% Series 1996B SPRBs (which had an original maturity of December 1, 2026). Payment of the principal and interest on the refunding SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company.

At December 31, 2008, the aggregate payments of principal required on long-term debt are nil during the next three years, $57.5 million in 2012 and nil in 2013.

5. Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2008. Short-term borrowings from nonaffiliates at December 31, 2007 had a weighted average interest rate of 5.4%, and consisted entirely of commercial paper.

At December 31, 2008 and 2007 the Company maintained syndicated credit facilities of $250 million and $175 million, respectively. The facilities are not secured. There were no borrowings under any line of credit during 2008 and 2007. See Note 13, “Related-party transactions,” concerning borrowings from affiliates.

Credit agreement. Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. On March 14, 2007 the PUC issued a D&O approving HECO’s request to maintain the credit facility for five years (until March 31, 2011), to borrow under the credit facility (including borrowings with maturities in excess of 364 days), to use the proceeds from any borrowings with maturities in excess of 364 days to finance capital expenditures and/or to repay short-term or other borrowings used to finance or refinance capital expenditures and to use an expedited approval process to obtain PUC approval to increase the facility amount, renew the facility, refinance the facility or change other terms of the facility if such changes are required or desirable.

Any draws on the facility bear interest, at the option of HECO, at either the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. The annual fee is 8 basis points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On

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the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions that must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting HECO’s ability, as well as the ability of any of its subsidiaries, to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratios of 48% for HELCO and 44% for MECO as of December 31, 2008, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 55% as of December 31, 2008, as calculated under the agreement), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity. HECO’s syndicated credit facility is maintained to support the issuance of commercial paper, but it may also be drawn for general corporate purposes and capital expenditures.

Effective December 8, 2008, HECO entered into a 9-month revolving unsecured credit agreement establishing a line of credit facility of $75 million, expiring on September 8, 2009, with Wells Fargo Bank National Association, as Administrative Agent and a lender, and U.S. Bank National Association, Bank of America, N.A. and Bank of Hawaii, as lenders. Similar to HECO’s existing $175 million, 5-year revolving unsecured credit agreement, this agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade nor does it have a broad “material adverse change” clause. Major provisions of the credit agreement are substantially the same as provisions in HECO’s existing $175 million credit agreement, except for pricing and prepayment requirements as noted below.

The annual fee is 25 basis points on the daily commitment amount. Any draws on the facility bear interest, at the option of HECO, at either the “Adjusted LIBO Rate” plus 175 basis points or the greatest of (a) the “Prime Rate”, (b) the sum of the “Federal Funds Rate” plus 150 basis points, and (c) the “Adjusted LIBO Rate” for a one month Interest Period plus 150 basis points, as defined in the agreement. A ratings change would result in revised pricing. For example, a ratings downgrade of HECO’s Issuer Ratings (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a facility fee increase of 5 basis points, and an interest rate increase of 20 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3 by S&P or Moody’s, respectively) would result in a facility fee decrease of 5 basis points, and an interest rate decrease of 20 basis points on any drawn amounts. This agreement includes a provision for mandatory prepayments and reductions in the commitment amount in the event of any Debt Issuance or Equity Capital Markets Transaction, as defined by the agreement, in the amount of 100% of the net cash proceeds received (provided, however, for purposes of the agreement, HECO’s receipt of proceeds from special purpose revenue bond financings do not occur until such proceeds are disbursed to HECO by the construction fund trustee in accordance with the indenture pursuant to which the bonds are issued). This credit facility is maintained to provide back-up and liquidity for commercial paper borrowings and to provide funding for working capital needs, intercompany loans to subsidiaries and general corporate purposes.

On May 23, 2007, S&P lowered the long-term corporate credit and unsecured debt ratings on HECO, HELCO and MECO to BBB from BBB+ and stated that the downgrade “is the result of sustained weak bondholder protection parameters compounded by the financial pressure that continuous need for regulatory relief, driven by heightened capital expenditure requirements, is creating for the next few years.” The pricing for future borrowings under the line of credit facility did not change since the pricing level is "determined by the higher of the two" ratings by S&P and Moody's, and Moody’s ratings did not change.

6. Regulatory assets and liabilities

In accordance with SFAS No. 71, the Company’s financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Continued accounting under SFAS No. 71 generally

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requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes its operations currently satisfy the SFAS No. 71 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory assets would be charged to expense and the regulatory liabilities would be credited to income or refunded to ratepayers. In the event of unforeseen regulatory actions or other circumstances, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers.

Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, the Company does not earn a return on its regulatory assets; however, it has been allowed to recover interest on its regulatory assets for demand-side management program costs. Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Noted in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2008, if different.

Regulatory assets were as follows:

December 31	2008		2007
(in thousands)
Retirement benefit plans (5 years; 3 years for HELCO’s $8 million prepaid pension regulatory asset, indeterminate for remainder)	$	416,680	$	169,814
Income taxes, net (1 to 36 years)		77,660		74,605
Postretirement benefits other than pensions (18 years; 4 years)		7,159		8,949
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 1 to 20 years)		16,191		17,510
Demand-side management program costs, net (1 year)		2,571		4,113
Vacation earned, but not yet taken (1 year)		6,654		5,997
Other (1 to 20 years)		3,704		4,002
	$	530,619	$	284,990

Regulatory liabilities were as follows:

December 31	2008		2007
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	282,400	$	259,765
Retirement benefit plans (5 years beginning with respective utility’s next rate case)		4,718		–
Other (5 years; 1 to 5 years)		1,484		1,841
	$	288,602	$	261,606

The regulatory asset and liability relating to retirement benefit plans was created as a result of pension and OPEB tracking mechanisms adopted by the PUC in interim rate case decisions for HECO, MECO and HELCO in 2007 (see Note 10).

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7. Income taxes

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” which prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate resolution with tax authorities) for the financial statement recognition and measurement of an income tax position taken or expected to be taken in a tax return. The Company adopted FIN 48 in the first quarter of 2007.

As a result of the implementation of FIN 48, the Company reclassified certain deferred tax liabilities to a liability for uncertain tax positions (FIN 48 liability) and reduced retained earnings by $0.6 million as of January 1, 2007 for the cumulative effect of the adoption of FIN 48.

The Company records interest on income taxes in “Interest and other charges.” For 2008, 2007 and 2006, interest (income) expense on income taxes was $0.5 million, $0.6 million and ($0.3) million, respectively.

The Company will record penalties, if any, in “Other, net” under “Other income”. As of December 31, 2008 and 2007, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet was $1.7 million and $1.2 million, respectively.

As of December 31, 2008, the total amount of FIN 48 liability was $5.5 million and, of this amount, $0.3 million, if recognized, would affect the Company’s effective tax rate. Management concluded that it is reasonably possible that the FIN 48 liability will significantly change within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service and estimates the range of the reasonably possible change to be a decrease of between nil to $4.3 million in 2009.

The changes in total unrecognized tax benefits were as follows:

Years ended December 31	2008			2007
(in millions)
Unrecognized tax benefits, January 1	$	24.4		$	23.6
Additions based on tax positions taken during the year		–			–
Reductions based on tax positions taken during the year		–			–
Additions for tax positions of prior years		0.1			0.8
Reductions for tax positions of prior years		(0.3	)		–
Decreases due to tax positions taken		–			–
Settlements		–			–
Lapses of statute of limitations		–			–
Unrecognized tax benefits, December 31	$	24.2		$	24.4

In addition to the FIN 48 liability, the Company’s unrecognized tax benefits include $18.7 million of tax benefits related to refund claims, which did not meet the recognition threshold. Consequently, tax benefits have not been recorded on these claims and no FIN 48 liability was required to offset these potential benefits.

Tax years 2003 to 2007 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii.

The Company’s effective federal and state income tax rate for 2008 was 38%, compared to an effective tax rate for 2007 of 37%.

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The components of income taxes charged to operating expenses were as follows:

December 31	2008			2007			2006
(in thousands)
Federal:
Current	$	44,759		$	54,767		$	50,208
Deferred		6,040			(22,853	)		(7,000	)
Deferred tax credits, net		(1,094	)		(1,154	)		(1,259	)
		49,705			30,760			41,949
State:
Current		6,522			5,073			2,889
Deferred		(1,391	)		(3,699	)		(1,267	)
Deferred tax credits, net		1,471			1,992			3,810
		6,602			3,366			5,432
Total	$	56,307		$	34,126		$	47,381

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $0.5 million, $3.2 million and $0.9 million for 2008, 2007 and 2006, respectively.

A reconciliation between income taxes charged to operating expenses and the amount of income taxes computed at the federal statutory rate of 35% on income before income taxes and preferred stock dividends follows:

December 31	2008			2007			2006
(in thousands)
Amount at the federal statutory income tax rate	$	52,907		$	32,559		$	44,024
State income taxes on operating income, net of effect on federal income taxes		4,291			2,188			3,530
Other		(891	)		(621	)		(173	)
Income taxes charged to operating expenses	$	56,307		$	34,126		$	47,381

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31	2008		2007
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	109,882	$	101,075
Contributions in aid of construction and customer advances		78,834		76,342
Other		16,529		21,753
		205,245		199,170
Deferred tax liabilities:
Property, plant and equipment		313,250		287,231
Regulatory assets, excluding amounts attributable to property, plant and equipment		30,240		29,050
Retirement benefits		4,728		15,590
Change in accounting method		16,020		23,036
Retirement benefits in Accumulated Other Comprehensive Income (AOCI)		1,052		736
Other		6,265		5,640
		371,555		361,283
Net deferred income tax liability	$	166,310	$	162,113

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon historical taxable income and

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projections for future taxable income and available tax planning strategies, management believes it is more likely than not the Company will realize substantially all of the benefits of the deferred tax assets.

As of December 31, 2008, the FIN 48 disclosures above present the Company’s accrual for potential tax liabilities and related interest. Based on information currently available, the Company believes this accrual has adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

8. Cash flows

Supplemental disclosures of cash flow information

Cash paid for interest (net of AFUDC-Debt) and income taxes was as follows:

Years ended December 31	2008		2007		2006
(in thousands)
Interest	$	48,357	$	47,155	$	47,206
Income taxes	$	91,043	$	26,106	$	52,782

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $9.4 million, $5.2 million and $6.3 million in 2008, 2007 and 2006, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $9.8 million, $17.7 million and $13.5 million in 2008, 2007 and 2006, respectively.

9. Major customers

HECO and its subsidiaries received approximately 10% ($295 million), 9% ($194 million) and 10% ($197 million), of their operating revenues from the sale of electricity to various federal government agencies in 2008, 2007 and 2006, respectively.

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10. Retirement benefits

Pensions

Substantially all of the employees of HECO, HELCO and MECO participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (the Plan). The Plan is a qualified, non-contributory defined benefit pension plan and includes benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plan is subject to the provisions of the ERISA. In addition, some current and former executives and directors participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.

The continuation of the Plan and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Directors’ Plan has been frozen since 1996. The HEI Supplemental Executive Retirement Plan (noncontributory, nonqualified, defined benefit plan) was frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time. If a participating employer terminates its participation in the Plan, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plan, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plan are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

To determine pension costs for HECO, HELCO and MECO under the Plan and the Supplemental Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified below.

Postretirement benefits other than pensions

The Company provides eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (HECO Benefits Plan). Health benefits are also provided to dependents of eligible retired employees. The contribution for health benefits paid by the participating employers is based on the retirees’ years of service and retirement dates. Generally, employees are eligible for these benefits if, upon retirement from active employment, they are eligible to receive benefits from the Plan.

Among other provisions, the HECO Benefits Plan provides prescription drug benefits for Medicare-eligible participants who retire after 1998. Retirees who are eligible for the drug benefits are required to pay a portion of the cost each month. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the 2003 Act) expanded Medicare to include for the first time coverage for prescription drugs. The 2003 Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28 percent of a participant’s drug costs between $250 and $5,000 (indexed for inflation) if the participant waives coverage under Medicare Part D.

The continuation of the HECO Benefits Plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the plan at any time.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to Accumulated Other Comprehensive Income (AOCI) in stockholders’ equity (using the projected benefit obligation (PBO) rather than the accumulated benefit obligation (ABO), to calculate the funded status of pension plans).

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By application filed on December 8, 2005 (AOCI Docket), the Company requested the PUC to permit it to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension liability as prescribed by SFAS No. 87. The Company updated its application in the AOCI Docket in November 2006 to take into account SFAS No. 158. On January 26, 2007, the PUC issued a D&O in the updated AOCI Docket, which denied the Company’s request to record a regulatory asset on the grounds that the Company had not met its burden of proof to show that recording a regulatory asset was warranted, or that there would be adverse consequences if a regulatory asset was not recorded. The PUC also required HECO to submit a pension study (determining whether ratepayers are better off with a well-funded pension plan, a minimally-funded pension plan, or something in between) in its pending 2007 test year rate case, as proposed by the Company in support of its request.

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

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

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

In its 2007 interim decisions for HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the PUC approved the adoption of the proposed pension and OPEB tracking mechanisms on an interim basis (subject to the PUC’s final D&Os) and established the amount of net periodic benefit costs to be recovered in rates by each utility. Under HELCO’s interim order, a regulatory asset (representing HELCO’s $12.8 million prepaid pension asset as of December 31, 2006 prior to the adoption of SFAS No. 158) was allowed to be recovered (and is being amortized) over a period of five years and was allowed to be included in HELCO’s rate base, net of deferred income taxes. On October 25, 2007, however, the PUC issued an amended proposed final D&O for HECO’s 2005 test year rate case, which reversed the portion of the interim D&O related to the inclusion of HECO’s approximately $50 million pension asset, net of deferred income taxes, in rate base, and required a refund of revenues associated with that reversal, including interest, retroactive to September 28, 2005 (the date the interim increase became effective). In 2007, HECO accrued $16 million for the potential customer refunds, including interest, reducing 2007 net income by $9 million. The final D&O for HECO’s 2005 test year rate case confirmed the refund. In the settlement agreement and interim PUC decision in HECO’s 2007 test year rate case, HECO’s pension asset was not included in HECO’s rate base and amortization of the pension asset was not included as part of the pension tracking mechanism adopted in the proceeding on an interim basis. In HECO’s rate increase application based on a 2009 test year, HECO’s pension asset was not included in rate base and the amortization of the pension asset was not included in the revenue requirements. In the settlement agreement and interim PUC decision in MECO’s 2007 test year rate case, MECO’s pension asset ($1 million as of December 31, 2007) was not included in MECO’s rate base and amortization of the pension asset was not included as part of the pension tracking mechanism adopted in the proceeding on an interim basis.

As a result of the 2007 interim orders, the Company has reclassified to a regulatory asset charges for retirement benefits that would otherwise be recorded in AOCI pursuant to SFAS No. 158 (amounting to the elimination of a potential charge to AOCI of $249 million pre-tax and $171 million pre-tax at December 31, 2008 and at December 31, 2007, respectively, compared to a retirement benefits pre-tax charge of $207 million at December 31, 2006).

Retirement benefits expense for the Company for 2008, 2007 and 2006 was $27 million, $27 million and $22 million, respectively.

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Pension and other postretirement benefit plans information

The changes in the obligations and assets of the Company’s retirement benefit plans and the changes in AOCI (gross) for 2008 and 2007 and the funded status of these plans and amounts related to these plans reflected in the Company’s balance sheet as of December 31, 2008 and 2007 were as follows:

	2008						2007
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Benefit obligation, January 1	$	903,012		$	181,926		$	877,365		$	186,359
Service cost		26,902			4,643			25,527			4,652
Interest cost		53,973			10,699			51,588			10,512
Actuarial (gain) loss		(65,390	)		(12,541	)		(7,084	)		(10,671	)
Benefits paid and expenses		(45,655	)		(9,167	)		(44,384	)		(8,926	)
Benefit obligation, December 31		872,842			175,560			903,012			181,926
Fair value of plan assets, January 1		809,901			145,524			784,163			133,815
Actual return (loss) on plan assets		(218,941	)		(40,378	)		67,378			11,390
Employer contribution		5,294			8,402			2,846			9,293
Benefits paid and expenses		(45,522	)		(9,152	)		(44,486	)		(8,974	)
Fair value of plan assets, December 31		550,732			104,396			809,901			145,524
Accrued benefit liability, December 31		(322,110	)		(71,164	)		(93,111	)		(36,402	)
AOCI, January 1 (excluding impact of PUC D&Os)		153,206			15,909			176,057			31,258
Recognized during year – net recognized transition obligation		–			(3,130	)		(1	)		(3,130	)
Recognized during year – prior service (cost)/credit		762			–			762			–
Recognized during year – net actuarial losses		(6,577	)		–			(10,486	)		–
Occurring during year – net actuarial losses (gains)		218,742			38,625			(13,126	)		(12,219	)
		366,133			51,404			153,206			15,909
Cumulative impact of PUC D&Os		(365,874	)		(54,365	)		(152,888	)		(18,120	)
AOCI, December 31		259			(2,961	)		318			(2,211	)
Net actuarial loss		369,489			38,886			157,324			260
Prior service gain		(3,356	)		–			(4,118	)		–
Net transition obligation		–			12,518			–			15,649
		366,133			51,404			153,206			15,909
Cumulative impact of PUC D&Os		(365,874	)		(54,365	)		(152,888	)		(18,120	)
AOCI, December 31		259			(2,961	)		318			(2,211	)
Income tax benefits		(101	)		1,152			(124	)		860
AOCI, net of taxes, December 31	$	158		$	(1,809	)	$	194		$	(1,351	)

The Company does not expect any plan assets to be returned to the Company during calendar year 2009.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2008, 2007 and 2006.

The defined benefit pension plans’ ABO, which do not consider projected pay increases (unlike the PBO shown in the table above), as of December 31, 2008 and 2007 were $783 million and $794 million, respectively.

The Company’s current estimate of contributions to the retirement benefit plans in 2009 is $31 million. The Pension Protection Act provides that more conservative assumptions be used to value obligations if a pension plan's funded status falls below certain levels. Depending on the funded status of the plans and whether funding relief is provided through legislation, the Company’s projected contribution level for the qualified pension plans for the 2010 plan year could fall in a range between $76 million and $136 million. Other factors could cause required contribution levels to fall outside this estimated range. Further, if the funded status of the pension plans continue to decline, restrictions on participant benefit accruals may be placed on the plans.

As of December 31, 2008, the benefits expected to be paid under the retirement benefit plans in 2009, 2010, 2011, 2012, 2013 and 2014 through 2018 amounted to $59 million, $61 million, $63 million, $65 million, $68 million and $385 million, respectively.

The Company has determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the

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difference over future years – 0% in the first year and 25% in years two to five, and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual net periodic benefit cost.

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style.

The weighted-average asset allocation of retirement defined benefit plans was as follows:

	Pension benefits								Other benefits
					Investment policy								Investment policy
December 31	2008		2007		Target		Range		2008		2007		Target		Range
Asset category
Equity securities	62	%	72	%	70	%	65-75	%	63	%	70	%	70	%	65-75	%
Fixed income	37		27		30		25-35	%	37		30		30		25-35	%
Other1	1		1		–		–		–		–		–		–
	100	%	100	%	100	%			100	%	100	%	100	%

¹ Other includes alternative investments, which are relatively illiquid in nature and will remain as plan assets until an appropriate liquidation opportunity occurs.

The following weighted-average assumptions were used in the accounting for the plans:

	Pension benefits						Other benefits
December 31	2008		2007		2006		2008		2007		2006
Benefit obligation
Discount rate	6.625	%	6.125	%	6.00	%	6.50	%	6.125	%	6.00	%
Rate of compensation increase	3.5		4.0		4.0		3.5		4.0		4.0
Net periodic benefit cost (years ended)
Discount rate	6.125		6.00		5.75		6.125		6.00		5.75
Expected return on plan assets	8.5		8.5		9.0		8.5		8.5		9.0
Rate of compensation increase	4.2		4.0		4.6		4.2		4.0		4.6

The Company based its selection of an assumed discount rate for 2009 net periodic cost and December 31, 2008 disclosure on a cash flow matching analysis that utilized bond information provided by Standard & Poor’s for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2008. In selecting the expected rate of return on plan assets of 8.25% for 2009 net periodic benefit cost, the Company considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the plans’ asset allocations and the past performance of the plans’ assets. The methods of selecting the assumed discount rate and expected return on plan assets at December 31, 2008 did not change from December 31, 2007.

As of December 31, 2008, the assumed health care trend rates for 2009 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2014 and thereafter; dental, 5.00%; and vision, 4.00%. As of December 31, 2007, the assumed health care trend rates for 2008 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2013 and thereafter; dental, 5.00%; and vision, 4.00%.

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The components of net periodic benefit cost were as follows:

	Pension benefits									Other benefits
(in thousands)	2008			2007			2006			2008			2007			2006
Service cost	$	26,902		$	25,527		$	26,719		$	4,643		$	4,652		$	4,965
Interest cost		53,973			51,588			48,348			10,699			10,512			10,337
Expected return on plan assets		(65,191	)		(61,101	)		(64,467	)		(10,789	)		(9,778	)		(9,758	)
Amortization of net transition obligation		–			1			2			3,130			3,130			3,130
Amortization of net prior service gain		(762	)		(762	)		(770	)		–			–			–
Amortization of net actuarial loss		6,577			10,486			10,699			–			–			388
Net periodic benefit cost		21,499			25,739			20,531			7,683			8,516			9,062
Impact of PUC D&Os		5,859			1,195			–			1,038			187			–
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	27,358		$	26,934		$	20,531		$	8,721		$	8,703		$	9,062

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefits pension plans that will be amortized from AOCI or regulatory asset into net periodic pension benefit cost over 2009 are $0.7 million, $14.7 million and nil, respectively. The estimated prior service cost, net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI or regulatory asset into net periodic other than pension benefit cost over 2009 are nil, $0.5 million and $3.1 million, respectively.

The Company recorded pension expense of $20 million, $20 million and $15 million and OPEB expense of $7 million each year in 2008, 2007 and 2006, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans had ABOs exceeding plan assets as of December 31, 2008. The PBO, ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets were $4 million, $3 million and nil, respectively, as of December 31, 2007. All other benefits plans had APBOs exceeding plan assets as of December 31, 2008 and December 31, 2007.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2008, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.1 million and the PBO by $2.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the PBO by $3.0 million.

11. Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through December 31, 2014 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel as of January 1, 2009, the estimated cost of minimum purchases under the fuel supply contracts is $0.4 billion per year for 2009 through 2012 and a total of $0.9 billion for the period 2013 through 2014. The actual cost of purchases in 2009 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $1.2 billion, $795 million and $755 million of fuel under contractual agreements in 2008, 2007 and 2006, respectively.

Power purchase agreements.As of December 31, 2008, HECO and its subsidiaries had six firm capacity PPAs for a total of 540 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $690 million, $537 million and $507 million for 2008, 2007 and 2006, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 2009 through 2013 and a total of $0.9 billion in the period from 2014 through 2030.

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In general, HECO and its subsidiaries base their payments under the PPAs upon available capacity and energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules (see “Energy cost adjustment clauses” below). HECO and its subsidiaries do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

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

On October 20, 2008, the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State of Hawaii Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an Energy Agreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement). The Energy Agreement provides that the parties pursue a wide range of actions with the purpose of decreasing the State of Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation.

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

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

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

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

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

In December 2007, the PUC issued a D&O approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. In a follow up order in December 2008, the PUC approved a penalty of $20 for every MWh that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable

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control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated, as described in the RPS law and in the RPS Framework. In addition, the PUC ordered that: (1) any penalties assessed against HECO and its subsidiaries for failure to meet the RPS will go into the public benefits fund account used to support energy efficiency and DSM programs and services, unless otherwise directed; and (2) the utilities will be prohibited from recovering any RPS penalty costs through rates.

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

To help fund energy efficiency programs, incentives, program administration, customer education, and other related program costs, as expended by the third-party administrator for the energy efficiency programs or by program contractors, which may include the utilities, the Energy Agreement provides that the parties will request that the PUC establish a Public Benefits Fund (PBF) that is funded by collecting 1% of the utilities’ revenues in years one and two after implementation of a PBF; 1.5% in years three and four; and 2% thereafter. Such PBF funds are expected to be collected from customers in lieu of the amounts currently collected for specific existing DSM programs. In December 2008, the PUC issued an order directing the utilities to collect revenue equal to 1% of the projected total electric revenue of the utilities, of which 60% shall be collected via the DSM surcharge and 40% via the PBF surcharge. Beginning January 1, 2009, the 1% is being assessed statewide. Such PBF funds are currently being collected from customers in lieu of the amounts currently collected for specific existing DSM programs.

The Energy Agreement provides for the establishment of a Clean Energy Infrastructure Surcharge (CEIS). The CEIS, which will need to be approved by the PUC, is to be designed to expedite cost recovery for a variety of infrastructure that supports greater use of renewable energy or grid efficiency within the utility systems (such as advanced metering, energy storage, interconnections and interfaces). The Energy Agreement provides that the surcharge should be available to recover costs that would normally be expensed in the year incurred and capital costs (including the allowed return on investment, AFUDC, depreciation, applicable taxes and other approved costs), and could also be used to recover costs stranded by clean energy initiatives. On November 28, 2008, HECO and the Consumer Advocate filed a joint letter informing the PUC that the pending REIP Surcharge satisfies the Energy Agreement provision for an implementation procedure for the CEIS recovery mechanism and that no further regulatory action on the CEIS is necessary, and reaffirming that the REIP Surcharge is ready for PUC decision-making. In February 2009, the PUC issued to the parties information requests prepared by its consultant.

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

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

As another method of accelerating the acquisition of renewable energy by the utilities, the Energy Agreement includes support of the parties for the development of a feed-in tariff (FIT) system with standardized purchase prices for renewable energy. The PUC is requested to conclude an investigative proceeding by March 2009 to determine the

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best design for FIT that support the HCEI goals, considering such factors as categories of renewables, size or locational limits for projects qualifying for the FIT, what annual limits should apply to the amount of renewables allowed to utilize the FIT, what factors to incorporate into the prices set for FIT payments, and other terms and conditions. Based on these understandings, the Energy Agreement requires that the parties request the PUC to suspend the pending intra-governmental wheeling and avoided cost (Schedule Q) dockets for a period of 12 months. On October 24, 2008, the PUC opened an investigative proceeding to examine the implementation of FITs. The utilities and Consumer Advocate were named as initial parties to the proceeding and almost twenty other parties were granted intervention. The procedural schedule for the proceeding includes final position statements by the parties at the end of March 2009, and panel hearings during the week of April 13, 2009. On December 11, 2008, the PUC issued a scoping paper prepared by its consultant that specified certain issues and questions for the parties to address and for the utilities and the Consumer Advocate to consider in a joint FIT proposal. On December 23, 2008, the utilities and the Consumer Advocate filed a joint proposal on FITs that called for the establishment of simple, streamlined and broad standard payment rates, which can be offered to as many renewable technologies as feasible. It proposed that the initial FIT be focused on photovoltaics (PV), concentrated solar power (CSP), in-line hydropower and wind, with individual project sizes targeted to provide a greater likelihood of more straightforward interconnection, project implementation and use of standardized energy rates and power purchase contracting. The FIT would be regularly reviewed to update tariff pricing to applicable technologies, project sizes and annual targets. An FIT update would be conducted for all islands in the utilities’ service territory not later than two years after initial implementation of the FIT and every three years thereafter. The proposed initial target project sizes are:

• PV systems up to and including 500 kilowatts (kW) on Oahu, PV systems up to and including 250 kW on Maui and the island of Hawaii and PV systems up to and including 100 kW on Lanai and Molokai.

• CSP systems up to and including 500 kW on Oahu, Maui, and the island of Hawaii and up to and including 100 kW on Lanai and Molokai.

• In-line hydropower systems up to and including 100 kW on Oahu, Maui, Lanai, Molokai and the island of Hawaii.

• Wind power systems up to and including 100 kW on Oahu, Maui, Lanai, Molokai and the island of Hawaii.

The FIT joint proposal also recommended that no applications for new net energy metering contracts be accepted once the FIT is formally made available to customers (although existing net energy metering systems under contract would be grandfathered), and no applications for new Schedule Q contracts would be accepted once an FIT is formally made available for the resource type. Schedule Q would continue as an option for qualifying projects of 100 kW and less for which an FIT is not available.

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

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

In recognition of the need to recover the infrastructure and other investments required to support significantly increased levels of renewable energy and to eliminate the potential conflict between encouraging energy efficiency and conservation and lower sales revenues, the parties agree that it is appropriate to adopt a regulatory rate-making model, which is subject to PUC approval, under which HECO, HELCO and MECO revenues would be decoupled from KWH sales. If approved by the PUC, the new regulatory model, which is similar to the regulatory models currently used in California, would employ a revenue adjustment mechanism to track on an ongoing basis the differences between the amount of revenues allowed in the last rate case and (a) the current costs of providing electric service and (b) a reasonable return on and return of additional capital investment in the electric system. On October 24, 2008, the PUC opened an investigative proceeding to examine implementing a decoupling mechanism for the utilities. In addition to the utilities and the Consumer Advocate, there are six other parties in the proceeding. The utilities and the Consumer

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Advocate submitted separate proposals for consideration by the parties in January 2009. The schedule for the proceeding includes technical workshops on the proposals, final position statements of the parties to be submitted in May 2009, and panel hearings during the week of June 29, 2009.

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

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

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

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

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

On October 22, 2007, the PUC issued, and HECO immediately implemented, an interim D&O in HECO’s 2007 test year rate case, granting HECO an increase of $70 million in annual revenues, a 4.96% increase over rates effective at the time of the interim decision ($78 million in annual revenues over rates granted in the final decision in HECO’s 2005 test year rate case).

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

As of December 31, 2008, HECO and its subsidiaries had recognized $145 million of revenues with respect to interim orders ($5 million related to interim orders regarding certain integrated resource planning costs and $140 million related to interim orders regarding general rate increase requests). Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, pending a final order.

Energy cost adjustment clauses. Hawaii Act 162 was signed into law in June 2006 and requires that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the utility and its customers, (2) provide the utility with incentive to manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the

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utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through commercially reasonable means, such as through fuel hedging contracts, (4) preserve the utility’s financial integrity, and (5) minimize the utility’s need to apply for frequent general rate increases for fuel cost changes. While the PUC already had reviewed the automatic fuel adjustment clauses in rate cases, Act 162 requires that these five specific factors be addressed in the record.

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

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

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

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

In December 2008, HECO filed updates to its 2009 test year rate case. The updates proposed the establishment of a purchased power adjustment clause to recover non-energy purchased power costs, pursuant to the Energy Agreement provision stating the utilities “will be allowed to pass through reasonably incurred purchase power contract costs, including all capacity, operation and maintenance (O&M) and other non-energy payments” approved by the PUC through a separate surcharge. The purchased power adjustment clause will be adjusted monthly and reconciled quarterly.

On December 30, 2008, HECO and the Consumer Advocate filed joint proposed findings of fact and conclusions of law in the HECO 2007 test year rate case, which stated that, given the Energy Agreement, which documents a course of action to make Hawaii energy independent and recognizes the need to maintain HECO’s financial health while achieving that objective, as well as the overwhelming support in the record for maintaining the ECAC in its current form, the PUC should determine that HECO’s proposed ECAC complies with the requirements of Act 162.

Major projects.Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of the project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects (with capitalized and deferred costs accumulated through December 31, 2008 noted in parentheses) include generating unit in and transmission line to Campbell Industrial Park ($96 million), HECO’s East Oahu Transmission Project ($38 million), HELCO’s ST-7 ($55 million) and a Customer Information system ($20 million).

Campbell Industrial Park (CIP) generating unit. HECO is building a new 110 MW simple-cycle combustion turbine (CT) generating unit at CIP and plans to add an additional 138 kilovolt transmission line to transmit power from generating units at CIP (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). Plans are

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for the CT to be run primarily as a “peaking” unit beginning in mid-2009, fueled by biodiesel. On December 15, 2005, HECO signed a contract with Siemens to purchase a 110 MW CT unit.

HECO’s Final Environmental Impact Statement for the Project was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and to take the steps necessary for HECO to reach that goal. In May 2007, the PUC issued a D&O approving the Project and the Hawaii Department of Health (DOH) issued the final air permit, which became effective at the end of June 2007. The D&O further stated that no part of the Project costs may be included in HECO’s rate base unless and until the Project is in fact installed, and is used and useful for public utility purposes. HECO’s 2009 test year rate case application, filed in July 2008, requests inclusion of the Project investment in rate base when the new unit is placed in service (expected to be at the end of July 2009). Construction on the Project began in May 2008.

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

As of December 31, 2008, HECO’s cost estimate for the Project (exclusive of the costs of the community benefit measures described above) was $186 million (of which $96 million had been incurred, including $4 million of AFUDC) and outstanding commitments for materials, equipment and outside services totaled $43 million. Management believes no adjustment to project costs is required as of December 31, 2008. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

In August 2007, HECO entered into a contract with Imperium Services, LLC (Imperium), to supply biodiesel for the planned generating unit, subject to PUC approval. Imperium agreed to comply with HECO’s procurement policy requiring sustainable sources of biofuel and biofuel feedstocks. In October 2007, HECO filed an application with the PUC for approval of this biodiesel supply contract. An evidentiary hearing on the application was held in October 2008. Due to deteriorating market conditions in the biodiesel industry, Imperium requested that HECO enter into negotiations to amend the original contract terms in order for Imperium to supply the biodiesel. In January 2009, HECO filed an amended biofuel supply contract with the PUC. In February 2009, HECO filed with the PUC a related terminalling and trucking agreement with Aloha Petroleum, Ltd. to support the delivery and storage of biodiesel from Imperium. In February 2009, the PUC approved modifications to the procedural schedule for this proceeding, calling for a re-opening of the evidentiary hearing in March 2009.

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

HECO continued to believe that the proposed reliability project was needed and, in 2003, filed an application with the PUC requesting approval to commit funds (then estimated at $56 million; see costs incurred below) for an EOTP, revised to use a 46 kV system and modified route, none of which is in conservation district lands. The environmental review process for the EOTP, as revised, was completed in 2005.

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

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The project is currently estimated to cost $74 million and HECO plans to construct the EOTP in two phases. The first phase is currently in construction and projected to be completed in 2010. The projected completion date of the second phase is being evaluated.

As of December 31, 2008, the accumulated costs recorded for the EOTP amounted to $38 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $8 million of planning, permitting and construction costs incurred after 2002 and (iii) $18 million for AFUDC. Management believes no adjustment to project costs is required as of December 31, 2008. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

HELCO generating units.In 1991, HELCO began planning to meet increased demand for electricity forecast for 1994. HELCO planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time the units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”

There were a number of environmental and other permitting challenges to construction of the units, including several lawsuits, which resulted in significant delays. However, in 2003, all but one of the parties actively opposing the plant expansion project entered into a settlement agreement with HELCO and several Hawaii regulatory agencies (the Settlement Agreement) intended in part to permit HELCO to complete CT-4 and CT-5. The Settlement Agreement required HELCO to undertake a number of actions, which have been completed or are ongoing. As a result of the final resolution of various proceedings due primarily to the Settlement Agreement, there are no pending lawsuits involving the project.

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

HELCO has completed engineering and design activities and construction work for ST-7 is progressing towards completion in mid-2009. As of December 31, 2008, HELCO’s cost estimate for ST-7 was $92 million (of which $55 million had been incurred) and outstanding commitments for materials, equipment and outside services totaled $28 million, a substantial portion of which are subject to cancellation charges.

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

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

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

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

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

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

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

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

Additionally, current environmental laws may require HECO and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

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

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

For administrative management purposes, the Iwilei Unit has been subdivided into four subunits. The Participating Parties have developed analyses of various remedial alternatives for the four subunits. The DOH uses the analyses to make a final determination of which remedial alternatives the Participating Parties will be required to implement. Once the DOH makes a remedial determination, the Participating Parties are required to develop remedial designs for the various elements of the remedy chosen. The DOH has completed remedial determinations for two subunits to date and the Participating Parties have initiated the remedial design work for those subunits. The Participating Parties anticipate that the DOH will complete the remaining remedial determinations during 2009 and anticipate that all remedial design work will be completed by the end of 2009 or early 2010. The Participating Parties will begin implementation of the remedial design elements as they are approved by the DOH.

Through December 31, 2008, HECO has accrued a total of $3.3 million (including $0.4 million in the first quarter of 2008) for estimates of HECO’s share of costs for continuing investigative work, remedial activities and monitoring for the Iwilei unit. As of December 31, 2008, the remaining accrual (amounts expensed less amounts expended) for the Iwilei unit was $1.8 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the PRPs has not yet been established and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei unit (such as its Honolulu power plant located in the Downtown unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material costs may be incurred.

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

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Hazardous Air Pollutant (HAP) Control.In February 2008, the federal Circuit Court of Appeals for the District of Columbia vacated the EPA’s Delisting Rule, which had removed coal- and oil-fired electric generating units (EGUs) from the list of sources requiring control under Section 112 of the Clean Air Act. The EPA’s request for a rehearing was denied. The EPA is thus required to develop Maximum Achievable Control Technology (MACT) standards for oil-fired EGU HAP emissions, including nickel compounds. Depending on the MACT standards developed (and the success of a potential challenge, after the MACT standards are issued, that the EPA inappropriately listed oil-fired EGUs initially), costs to comply with the standards could be significant. The Company is currently evaluating its options regarding potential MACT standards for applicable HECO steam units.

In October 2008, the EPA petitioned the U.S. Supreme Court to review the decision of the Circuit Court of Appeals for the District of Columbia vacating the EPA’s Delisting Rule. Also, an industry group is seeking review of the Delisting Rule decision. On February 6, 2009, the EPA filed a motion with the Supreme Court to withdraw its petition for review. In the motion, the EPA indicated that it would begin rulemaking to establish MACT standards for EGUs. Management cannot predict if the Supreme Court will grant the industry petitioners’ request for review and is evaluating options available regarding the rulemaking if the Supreme Court rejects industry petitioners’ request for review or upholds the Court of Appeals decision.

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

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

Collective bargaining agreements.As of December 31, 2008, approximately 57% of the Company’s employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. On March 1, 2008, members of the union ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. The new agreements cover a three-year term, from November 1, 2007 to October 31, 2010, and provide for non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective January 1, 2009 and 4.5% effective January 1, 2010.

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

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limit of the available insurance were substantially exceeded, HECO, HELCO and MECO could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

12. Regulatory restrictions on distributions to parent

As of December 31, 2008, net assets (assets less liabilities and preferred stock) of approximately $506 million were not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval.

13. Related-party transactions

HEI charged HECO and its subsidiaries $4.7 million, $3.4 million and $3.4 million for general management and administrative services in 2008, 2007 and 2006, respectively. The amounts charged by HEI to its subsidiaries are allocated primarily on the basis of actual labor hours expended in providing such services.

HECO’s short-term borrowings from HEI fluctuate during the year, and totaled $41.6 million and nil at December 31, 2008 and 2007, respectively. The interest charged on short-term borrowings from HEI is based on the lower of HEI’s or HECO’s effective weighted average short-term external borrowing rate. If both HEI and HECO do not have short-term external borrowings, the interest is based on the average of the effective rate for 30-day dealer-placed commercial paper quoted by the Watt Street Journal.

Borrowings among HECO and its subsidiaries are eliminated in consolidation. Interest charged by HEI to HECO was de minimis in 2008, 2007 and 2006.

14. Significant group concentrations of credit risk

HECO and its utility subsidiaries are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. HECO and its utility subsidiaries provide the only electric public utility service on the islands they serve. HECO and its utility subsidiaries grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

15. Fair value of financial instruments

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and equivalents and short-term borrowings

The carrying amount approximated fair value because of the short maturity of these instruments.

Long-term debt

Fair value was obtained from a third-party financial services provider based on the current rates offered for debt of the same or similar remaining maturities.

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Off-balance sheet financial instruments

Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of the financial instruments held or issued by the Company were as follows:

December 31	2008				2007
(in thousands)	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and equivalents	$	6,901	$	6,901	$	4,678	$	4,678
Financial liabilities:
Short-term borrowings from nonaffiliates		–		–		28,791		28,791
Long-term debt, net, including amounts due within one year		904,501		660,380		885,099		904,092
Off-balance sheet item:
HECO-obligated preferred securities of trust subsidiary		50,000		40,420		50,000		46,200

16. Sale of non-electric utility property

In August 2007, HECO sold land and a building that executives and management had been using as a recreational facility. The sale of the non-electric utility property resulted in an after-tax gain in the third quarter of 2007 of approximately $2.9 million.

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17. Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2008
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassi- fications and Elimina- tions				HECO Consolidated
Assets
Utility plant, at cost
Land	$	33,213		4,982		4,346		–	–	–				$	42,541
Plant and equipment		2,567,018		874,322		836,159		–	–	–					4,277,499
Less accumulated depreciation		(1,028,501	)	(352,382	)	(360,570	)	–	–	–					(1,741,453	)
Construction in progress		188,754		68,650		9,224		–	–	–					266,628
Net utility plant		1,760,484		595,572		489,159		–	–	–					2,845,215
Investment in wholly owned subsidiaries, at equity		437,033		–		–		–	–	(437,033	)	[2	]		–
Current assets
Cash and equivalents		2,264		3,148		1,349		123	17	–					6,901
Advances to affiliates		62,000		–		12,000		–	–	(74,000	)	[1	]		–
Customer accounts receivable, net		109,724		32,108		24,590		–	–	–					166,422
Accrued unbilled revenues, net		74,657		17,876		14,011		–	–	–					106,544
Other accounts receivable, net		3,983		2,217		1,143		–	11	564		[1	]		7,918
Fuel oil stock, at average cost		53,546		10,326		13,843		–	–	–					77,715
Materials & supplies, at average cost		16,583		4,366		13,583		–	–	–					34,532
Prepayments and other		6,918		2,311		3,664		–	–	(267	)	[3	]		12,626
Total current assets		329,675		72,352		84,183		123	28	(73,703	)				412,658
Other long-term assets
Regulatory assets		388,054		77,038		65,527		–	–	–					530,619
Unamortized debt expense		9,802		2,282		2,419		–	–	–					14,503
Other		38,099		7,699		7,197		–	119	–					53,114
Total other long-term assets		435,955		87,019		75,143		–	119	–					598,236
	$	2,963,147		754,943		648,485		123	147	(510,736	)			$	3,856,109
Capitalization and liabilities
Capitalization
Common stock equity	$	1,188,842		221,405		215,382		105	141	(437,033	)	[2	]	$	1,188,842
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		–	–	–					34,293
Long-term debt, net		582,132		148,030		174,339		–	–	–					904,501
Total capitalization		1,793,267		376,435		394,721		105	141	(437,033	)				2,127,636
Current liabilities
Short-term borrowings-affiliate		53,550		62,000		–		–	–	(74,000	)	[1	]		41,550
Accounts payable		84,238		27,795		10,961		–	–	–					122,994
Interest and preferred dividends payable		10,242		2,547		2,819		–	–	(211	)	[1	]		15,397
Taxes accrued		144,366		38,117		37,830		–	–	(267	)	[3	]		220,046
Other		33,462		9,015		11,992		18	6	775		[1	]		55,268
Total current liabilities		325,858		139,474		63,602		18	6	(73,703	)				455,255
Deferred credits and other liabilities
Deferred income taxes		134,359		19,621		12,330		–	–	–					166,310
Regulatory liabilities		202,003		49,843		36,756		–	–	–					288,602
Unamortized tax credits		32,501		13,476		12,819		–	–	–					58,796
Retirement benefits liability		284,826		54,664		53,355		–	–	–					392,845
Other		11,576		35,432		7,941		–	–	–					54,949
Total deferred credits and other liabilities		665,265		173,036		123,201		–	–	–					961,502
Contributions in aid of construction		178,757		65,998		66,961		–	–	–					311,716
	$	2,963,147		754,943		648,485		123	147	(510,736	)			$	3,856,109

43

Consolidating balance sheet

	December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassi- fications and Elimina- tions				HECO Consolidated
Assets
Utility plant, at cost
Land	$	28,833		4,982		4,346		–	–	–				$	38,161
Plant and equipment		2,504,389		830,237		796,600		–	–	–					4,131,226
Less accumulated depreciation		(988,732	)	(324,517	)	(333,864	)	–	–	–					(1,647,113	)
Plant acquisition adjustment, net		–		–		41		–	–	–					41
Construction in progress		114,227		26,262		10,690		–	–	–					151,179
Net utility plant		1,658,717		536,964		477,813		–	–	–					2,673,494
Investment in wholly owned subsidiaries, at equity		410,911		–		–		–	–	(410,911	)	[2	]		–
Current assets
Cash and equivalents		203		3,069		773		198	435	–					4,678
Advances to affiliates		36,600		–		2,000		–	–	(38,600	)	[1	]		–
Customer accounts receivable, net		98,129		26,554		21,429		–	–	–					146,112
Accrued unbilled revenues, net		82,550		16,795		14,929		–	–	–					114,274
Other accounts receivable, net		6,657		2,481		3,025		–	–	(5,248	)	[1	]		6,915
Fuel oil stock, at average cost		57,289		12,494		22,088		–	–	–					91,871
Materials & supplies, at average cost		15,723		4,404		14,131		–	–	–					34,258
Prepayments and other		6,946		1,239		1,305		–	–	–					9,490
Total current assets		304,097		67,036		79,680		198	435	(43,848	)				407,598
Other long-term assets
Regulatory assets		209,034		40,663		35,293		–	–	–					284,990
Unamortized debt expense		10,555		2,458		2,622		–	–	–					15,635
Other		30,449		5,671		6,051		–	–	–					42,171
Total other long-term assets		250,038		48,792		43,966		–	–	–					342,796
	$	2,623,763		652,792		601,459		198	435	(454,759	)			$	3,423,888
Capitalization and liabilities
Capitalization
Common stock equity	$	1,110,462		201,820		208,521		182	388	(410,911	)	[2	]	$	1,110,462
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		–	–	–					34,293
Long-term debt, net		567,657		145,811		171,631		–	–	–					885,099
Total capitalization		1,700,412		354,631		385,152		182	388	(410,911	)				2,029,854
Current liabilities
Short-term borrowings-nonaffiliates		28,791		–		–		–	–	–					28,791
Short-term borrowings-affiliate		2,000		36,600		–		–	–	(38,600	)	[1	]		–
Accounts payable		97,699		21,810		18,386		–	–	–					137,895
Interest and preferred dividends payable		9,774		2,370		2,738		–	–	(163	)	[1	]		14,719
Taxes accrued		119,032		35,380		35,225		–	–	–					189,637
Other		41,792		9,835		11,194		16	47	(5,085	)	[1	]		57,799
Total current liabilities		299,088		105,995		67,543		16	47	(43,848	)				428,841
Deferred credits and other liabilities
Deferred income taxes		130,573		17,791		13,749		–	–	–					162,113
Regulatory liabilities		180,725		46,460		34,421		–	–	–					261,606
Unamortized tax credits		32,664		12,941		12,814		–	–	–					58,419
Retirement benefits liability		92,863		16,414		20,011		–	–	–					129,288
Other		11,013		35,558		7,459		–	–	–					54,030
Total deferred credits and other liabilities		447,838		129,164		88,454		–	–	–					665,456
Contributions in aid of construction		176,425		63,002		60,310		–	–	–					299,737
	$	2,623,763		652,792		601,459		198	435	(454,759	)			$	3,423,888

44

Consolidating statement of income

	Year ended December 31, 2008
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions				HECO Consolidated
Operating revenues	$	1,954,772		446,297		452,570		–		–		–				$	2,853,639
Operating expenses
Fuel oil		866,827		109,617		252,749		–		–		–					1,229,193
Purchased power		475,205		176,248		38,375		–		–		–					689,828
Other operation		172,663		33,027		37,559		–		–		–					243,249
Maintenance		68,670		16,796		16,158		–		–		–					101,624
Depreciation		82,208		31,279		28,191		–		–		–					141,678
Taxes, other than income taxes		179,418		40,811		41,594		–		–		–					261,823
Income taxes		33,330		12,097		10,880		–		–		–					56,307
		1,878,321		419,875		425,506		–		–		–					2,723,702
Operating income		76,451		26,422		27,064		–		–		–					129,937
Other income
Allowance for equity funds used during construction		7,088		1,737		565		–		–		–					9,390
Equity in earnings of subsidiaries		37,009		–		–		–		–		(37,009	)	[2	]		–
Other, net		6,134		1,562		305		(77	)	(347	)	(1,918	)	[1	]		5,659
		50,231		3,299		870		(77	)	(347	)	(38,927	)				15,049
Income before interest and other charges		126,682		29,721		27,934		(77	)	(347	)	(38,927	)				144,986
Interest and other charges
Interest on long-term debt		30,412		7,844		9,046		–		–		–					47,302
Amortization of net bond premium and expense		1,606		436		488		–		–		–					2,530
Other interest charges		4,383		2,001		459		–		–		(1,918	)	[1	]		4,925
Allowance for borrowed funds used during construction		(2,774	)	(735	)	(232	)	–		–		–					(3,741	)
Preferred stock dividends of subsidiaries		–		–		–		–		–		915		[3	]		915
		33,627		9,546		9,761		–		–		(1,003	)				51,931
Income before preferred stock dividends of HECO		93,055		20,175		18,173		(77	)	(347	)	(37,924	)				93,055
Preferred stock dividends of HECO		1,080		534		381		–		–		(915	)	[3	]		1,080
Net income for common stock	$	91,975		19,641		17,792		(77	)	(347	)	(37,009	)			$	91,975

Consolidating statement of retained earnings

	Year ended December 31, 2008
(in thousands)	HECO			HELCO	MECO		RHI		UBC		Reclassi- fications and Elimina- tions				HECO Consolidated
Retained earnings, beginning of period	$	724,704		101,055	113,377		(599	)	(47	)	(213,786	)	[2	]	$	724,704
Net income for common stock		91,975		19,641	17,792		(77	)	(347	)	(37,009	)	[2	]		91,975
Common stock dividends		(14,089	)	–	(10,965	)	–		–		10,965		[2	]		(14,089	)
Retained earnings, end of period	$	802,590		120,696	120,204		(676	)	(394	)	(239,830	)			$	802,590

45

Consolidating statement of income

	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions				HECO Consolidated
Operating revenues	$	1,385,137		361,411		350,410		–		–		–				$	2,096,958
Operating expenses
Fuel oil		525,555		74,965		173,599		–		–		–					774,119
Purchased power		368,766		134,919		33,275		–		–		–					536,960
Other operation		148,857		32,960		32,230		–		–		–					214,047
Maintenance		62,208		20,700		22,835		–		–		–					105,743
Depreciation		78,972		30,094		28,015		–		–		–					137,081
Taxes, other than income taxes		129,015		33,274		32,318		–		–		–					194,607
Income taxes		17,648		9,534		6,944		–		–		–					34,126
		1,331,021		336,446		329,216		–		–		–					1,996,683
Operating income		54,116		24,965		21,194		–		–		–					100,275
Other income
Allowance for equity funds used during construction		4,404		461		354		–		–		–					5,219
Equity in earnings of subsidiaries		19,907		–		–		–		–		(19,907	)	[2	]		–
Other, net		7,927		(6,299	)	349		(83	)	(47	)	(2,474	)	[1	]		(627	)
		32,238		(5,838	)	703		(83	)	(47	)	(22,381	)				4,592
Income before interest and other charges		86,354		19,127		21,897		(83	)	(47	)	(22,381	)				104,867
Interest and other charges
Interest on long-term debt		29,310		7,625		9,029		–		–		–					45,964
Amortization of net bond premium and expense		1,539		419		482		–		–		–					2,440
Other interest charges		4,415		2,531		392		–		–		(2,474	)	[1	]		4,864
Allowance for borrowed funds used during construction		(2,146	)	(234	)	(172	)	–		–		–					(2,552	)
Preferred stock dividends of subsidiaries		–		–		–		–		–		915		[3	]		915
		33,118		10,341		9,731		–		–		(1,559	)				51,631
Income before preferred stock dividends of HECO		53,236		8,786		12,166		(83	)	(47	)	(20,822	)				53,236
Preferred stock dividends of HECO		1,080		534		381		–		–		(915	)	[3	]		1,080
Net income for common stock	$	52,156		8,252		11,785		(83	)	(47	)	(19,907	)			$	52,156

Consolidating statement of retained earnings

	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions				HECO Consolidated
Retained earnings, beginning of period	$	700,252		92,836		111,536		(516	)	–		(203,856	)	[2	]	$	700,252
Net income for common stock		52,156		8,252		11,785		(83	)	(47	)	(19,907	)	[2	]		52,156
Adjustment to initially apply FIN 48		(620	)	(33	)	(44	)	–		–		77		[2	]		(620	)
Common stock dividends		(27,084	)	–		(9,900	)	–		–		9,900		[2	]		(27,084	)
Retained earnings, end of period	$	724,704		101,055		113,377		(599	)	(47	)	(213,786	)			$	724,704

46

Consolidating statement of income

	Year ended December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and Elimina- Tions				HECO Consolidated
Operating revenues	$	1,365,593		339,554		345,265		–		–				$	2,050,412
Operating expenses
Fuel oil		516,239		85,229		180,272		–		–					781,740
Purchased power		358,115		122,324		26,454		–		–					506,893
Other operation		126,300		29,907		30,242		–		–					186,449
Maintenance		56,732		19,669		13,816		–		–					90,217
Depreciation		74,798		29,722		25,644		–		–					130,164
Taxes, other than income taxes		126,849		31,553		32,011		–		–					190,413
Income taxes		31,215		4,339		11,827		–		–					47,381
		1,290,248		322,743		320,266		–		–					1,933,257
Operating income		75,345		16,811		24,999		–		–					117,155
Other income
Allowance for equity funds used during construction		4,059		195		2,094		–		–					6,348
Equity in earnings of subsidiaries		25,583		–		–		–		(25,583	)	[2	]		–
Other, net		4,387		503		1,176		(153	)	(2,790	)	[1	]		3,123
		34,029		698		3,270		(153	)	(28,373	)				9,471
Income before interest and other charges		109,374		17,509		28,269		(153	)	(28,373	)				126,626
Interest and other charges
Interest on long-term debt		26,967		7,233		8,909		–		–					43,109
Amortization of net bond premium and expense		1,378		411		409		–		–					2,198
Other interest charges		6,818		2,474		754		–		(2,790	)	[1	]		7,256
Allowance for borrowed funds used during construction		(1,816	)	(90	)	(973	)	–		–					(2,879	)
Preferred stock dividends of subsidiaries		–		–		–		–		915		[3	]		915
		33,347		10,028		9,099		–		(1,875	)				50,599
Income before preferred stock dividends of HECO		76,027		7,481		19,170		(153	)	(26,498	)				76,027
Preferred stock dividends of HECO		1,080		534		381		–		(915	)	[3	]		1,080
Net income for common stock	$	74,947		6,947		18,789		(153	)	(25,583	)			$	74,947

Consolidating statement of retained earnings

	Year ended December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI		Reclassi- fications and Elimina- tions				HECO Consolidated
Retained earnings, beginning of period	$	654,686		88,763		99,269		(363	)	(187,669	)	[2	]	$	654,686
Net income for common stock		74,947		6,947		18,789		(153	)	(25,583	)	[2	]		74,947
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	–		9,396		[2	]		(29,381	)
Retained earnings, end of period	$	700,252		92,836		111,536		(516	)	(203,856	)			$	700,252

47

Consolidating Statements of Changes in Common Stock Equity

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and elimina- tions		HECO consoli- dated
Balance, December 31, 2005	$	1,039,259		189,407		194,190		118		–		(383,715	)	$	1,039,259
Comprehensive income:
Net income (loss)		74,947		6,947		18,789		(153	)	–		(25,583	)		74,947
Minimum pension liability adjustment, net of taxes of $ 18		26		–		–		–		–		–			26
Comprehensive income (loss)		74,973		6,947		18,789		(153	)	–		(25,583	)		74,973
Adjustment to initially apply SFAS No. 158, net of tax benefits of $80,666		(126,650	)	(18,381	)	(14,226	)	–		–		32,607			(126,650	)
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	–		–		9,396			(29,381	)
Issuance of common stock		–		–		–		300		–		(300	)		–
Other		2		–		–		–		–		–			2
Balance, December 31, 2006		958,203		175,099		192,231		265		–		(367,595	)		958,203
Comprehensive income:
Net income (loss)		52,156		8,252		11,785		(83	)	(47	)	(19,907	)		52,156
Retirement benefit plans:
Net gains arising during the period, net of taxes of $9,861		15,484		1,262		1,773		–		–		(3,035	)		15,484
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $5,001		7,854		1,104		903		–		–		(2,007	)		7,854
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $11,007		(17,282	)	(2,069	)	(1,733	)	–		–		3,802			(17,282	)
Comprehensive income (loss)		58,212		8,549		12,728		(83	)	(47	)	(21,147	)		58,212
Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes of $77,546		121,751		18,205		13,506		–		–		(31,711	)		121,751
Adjustment to initially apply FIN 48		(620	)	(33	)	(44	)	–		–		77			(620	)
Common stock dividends		(27,084	)	–		(9,900	)	–		–		9,900			(27,084	)
Issuance of common stock		–		–		–		–		435		(435	)		–
Balance, December 31, 2007		1,110,462		201,820		208,521		182		388		(410,911	)		1,110,462
Comprehensive income:
Net income (loss)		91,975		19,641		17,792		(77	)	(347	)	(37,009	)		91,975
Retirement benefit plans:
Net losses arising during the period, net of tax benefits of $100,141		(157,226	)	(24,243	)	(20,329	)	–		–		44,572			(157,226	)
Less: amortization of transition obligation, prior service cost and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,481		5,464		760		621		–		–		(1,381	)		5,464
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $96,975		152,256		23,427		19,742		–		–		(43,169	)		152,256
Comprehensive income (loss)		92,469		19,585		17,826		(77	)	(347	)	(36,987	)		92,469
Common stock dividends		(14,089	)	–		(10,965	)	–		–		10,965			(14,089	)
Issuance of common stock		–		–		–		–		100		(100	)		–
Balance, December 31, 2008	$	1,188,842		221,405		215,382		105		141		(437,033	)	$	1,188,842

48

Consolidating statement of cash flows

	Year ended December 31, 2008
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows				HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	93,055		20,175		18,173		(77	)	(347	)	(37,924	)	[2	]	$	93,055
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(37,109	)	–		–		–		–		37,009		[2	]		(100	)
Common stock dividends received from subsidiaries		11,065		–		–		–		–		(10,965	)	[2	]		100
Depreciation of property, plant and equipment		82,208		31,279		28,191		–		–		–					141,678
Other amortization		3,145		743		4,731		–		–		–					8,619
Deferred income taxes		3,457		1,866		(1,441	)	–		–		–					3,882
Tax credits, net		555		696		219		–		–		–					1,470
Allowance for equity funds used during construction		(7,088	)	(1,737	)	(565	)	–		–		–					(9,390	)
Changes in assets and liabilities:
Increase in accounts receivable		(8,921	)	(5,290	)	(1,279	)	–		(11	)	(5,812	)	[1	]		(21,313	)
Decrease (increase) in accrued unbilled revenues		7,893		(1,081	)	918		–		–		–					7,730
Decrease in fuel oil stock		3,743		2,168		8,245		–		–		–					14,156
Decrease (increase) in materials and supplies		(860	)	38		548		–		–		–					(274	)
Increase in regulatory assets		(151	)	(87	)	(2,991	)	–		–		–					(3,229	)
Increase (decrease) in accounts payable		(13,461	)	5,985		(7,425	)	–		–		–					(14,901	)
Changes in prepaid and accrued income and utility revenue taxes		25,155		2,638		262		–		–		–					28,055
Changes in other assets and liabilities		(7,551	)	(4,089	)	422		2		(41	)	5,812		[2	]		(5,445	)
Net cash provided by (used in) operating activities		155,135		53,304		48,008		(75	)	(399	)	(11,880	)				244,093
Cash flows from investing activities:
Capital expenditures		(162,041	)	(84,948	)	(31,487	)	–		–		–					(278,476	)
Contributions in aid of construction		9,928		4,669		2,722		–		–		–					17,319
Advances from (to) affiliates		(25,400	)	–		(10,000	)	–		–		35,400		[1	]		–
Other		1,276		–		–		–		(119	)	–					1,157
Investment in consolidated subsidiary		(100	)	–		–		–		–		100		[2	]		–
Net cash used in investing activities		(176,337	)	(80,279	)	(38,765	)	–		(119	)	35,500					(260,000	)
Cash flows from financing activities:
Common stock dividends		(14,089	)	–		(10,965	)	–		–		10,965		[2	]		(14,089	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	–		–		915		[2	]		(1,080	)
Proceeds from issuance of long-term debt		14,407		2,188		2,680		–		–		–					19,275
Proceeds from issuance of common stock		–		–		–		–		100		(100	)	[2	]		–
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		22,759		25,400		–		–		–		(35,400	)	[1	]		12,759
Other		1,266		–		(1	)	–		–		–					1,265
Net cash provided by (used in) financing activities		23,263		27,054		(8,667	)	–		100		(23,620	)				18,130
Net increase (decrease) in cash and equivalents		2,061		79		576		(75	)	(418	)	–					2,223
Cash and equivalents, beginning of year		203		3,069		773		198		435		–					4,678
Cash and equivalents, end of year	$	2,264		3,148		1,349		123		17		–				$	6,901

49

Consolidating statement of cash flows

	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows				HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	53,236		8,786		12,166		(83	)	(47	)	(20,822	)	[2	]	$	53,236
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(20,008	)	–		–		–		–		19,907		[2	]		(101	)
Common stock dividends received from subsidiaries		10,001		–		–		–		–		(9,900	)	[2	]		101
Depreciation of property, plant and equipment		78,972		30,094		28,015		–		–		–					137,081
Other amortization		3,892		375		3,963		–		–		–					8,230
Writedown of utility plant		–		11,701		–		–		–		–					11,701
Deferred income taxes		(18,748	)	(6,280	)	(6,860	)	–		–		–					(31,888	)
Tax credits, net		1,070		288		634		–		–		–					1,992
Allowance for equity funds used during construction		(4,404	)	(461	)	(354	)	–		–		–					(5,219	)
Changes in assets and liabilities:
Increase in accounts receivable		(19,664	)	(3,710	)	(4,297	)	–		–		4,591		[1	]		(23,080	)
Increase in accrued unbilled revenues		(18,315	)	(2,358	)	(1,406	)	–		–		–					(22,079	)
Increase in fuel oil stock		(16,609	)	(2,733	)	(8,217	)	–		–		–					(27,559	)
Decrease (increase) in materials and supplies		(1,764	)	488		(2,442	)	–		–		–					(3,718	)
Decrease (increase) in regulatory assets		2,252		(559	)	(3,661	)	–		–		–					(1,968	)
Increase (decrease) in accounts payable		36,027		(762	)	118		–		–		–					35,383
Changes in prepaid and accrued income and utility revenue taxes		22,186		8,399		6,870		–		–		–					37,455
Changes in other assets and liabilities		11,485		7,100		2,061		6		47		(4,591	)	[2	]		16,108
Net cash provided by (used in) operating activities		119,609		50,368		26,590		(77	)	–		(10,815	)				185,675
Cash flows from investing activities:
Capital expenditures		(129,045	)	(52,554	)	(28,222	)	–		–		–					(209,821	)
Contributions in aid of construction		10,834		4,952		3,225		–		–		–					19,011
Advances from (to) affiliates		17,800		–		(2,000	)	–		–		(15,800	)	[1	]		–
Proceeds from sales of assets		5,440		–		–		–		–		–					5,440
Investment in consolidated subsidiary		(435	)	–		–		–		–		435		[2	]		–
Net cash used in investing activities		(95,406	)	(47,602	)	(26,997	)	–		–		(15,365	)				(185,370	)
Cash flows from financing activities:
Common stock dividends		(27,084	)	–		(9,900	)	–		–		9,900		[2	]		(27,084	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	–		–		915		[2	]		(1,080	)
Proceeds from issuance of long-term debt		147,593		22,625		72,320		–		–		–					242,538
Repayment of long term debt		(62,280	)	(8,020	)	(55,700	)	–		–		–					(126,000	)
Proceeds from issuance of common stock		–		–		–		–		435		(435	)	[2	]		–
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(82,316	)	(12,800	)	(5,000	)	–		–		15,800		[1	]		(84,316	)
Other		(1,161	)	(1,706	)	(677	)	–		–		–					(3,544	)
Net cash provided by (used in) financing activities		(26,328	)	(435	)	662		–		435		26,180					514
Net increase in cash and equivalents		(2,125	)	2,331		255		(77	)	435		–					819
Cash and equivalents, beginning of year		2,328		738		518		275		–		–					3,859
Cash and equivalents, end of year	$	203		3,069		773		198		435		–				$	4,678

50

Consolidating statement of cash flows

	Year ended December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI		Elimination addition to (deduction from) cash flows				HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	76,027		7,481		19,170		(153	)	(26,498	)	[2	]	$	76,027
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(25,684	)	–		–		–		25,583		[2	]		(101	)
Common stock dividends received from subsidiaries		9,497		–		–		–		(9,396	)	[2	]		101
Depreciation of property, plant and equipment		74,798		29,722		25,644		–		–					130,164
Other amortization		3,898		582		3,452		–		–					7,932
Deferred income taxes		(7,666	)	(155	)	(1,850	)	–		–					(9,671	)
Tax credits, net		1,997		620		1,193		–		–					3,810
Allowance for equity funds used during construction		(4,059	)	(195	)	(2,094	)	–		–					(6,348	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		6,960		(901	)	1,401		–		1,249		[1	]		8,709
Decrease (increase) in accrued unbilled revenues		(1,534	)	238		422		–		–					(874	)
Decrease (increase) in fuel oil stock		23,629		(1,893	)	(598	)	–		–					21,138
Decrease (increase) in materials and supplies		169		(1,688	)	(2,047	)	–		–					(3,566	)
Increase in regulatory assets		(1,652	)	(1,519	)	(2,952	)	–		–					(6,123	)
Increase (decrease) in accounts payable		(25,171	)	3,069		2,413		–		–					(19,689	)
Changes in prepaid and accrued income and utility revenue taxes		12,792		2,729		3,078		–		–					18,599
Decrease in prepaid pension benefit cost		14,237		2,617		3,210		–		–					20,064
Changes in other assets and liabilities		(13,081	)	2,610		(921	)	–		(1,249	)	[2	]		(12,641	)
Net cash provided by (used in) operating activities		145,157		43,317		49,521		(153	)	(10,311	)				227,531
Cash flows from investing activities:
Capital expenditures		(94,141	)	(44,217	)	(56,714	)	–		–					(195,072	)
Contributions in aid of construction		10,760		4,587		4,360		–		–					19,707
Advances from (to) affiliates		(4,700	)	–		5,250		–		(550	)	[1	]		–
Proceeds from sales of assets		407		–		–		–		–					407
Investment in consolidated subsidiary		(300	)	–		–		–		300		[2	]		–
Net cash used in investing activities		(87,974	)	(39,630	)	(47,104	)	–		(250	)				(174,958	)
Cash flows from financing activities:
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	–		9,396		[2	]		(29,381	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	–		915		[2	]		(1,080	)
Proceeds from issuance of common stock		–		–		–		300		(300	)	[2	]		–
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(28,308	)	(300	)	5,000		–		550		[1	]		(23,058	)
Other		3,906		756		–		–		–					4,662
Net cash provided by (used in) financing activities		(54,863	)	(2,952	)	(1,903	)	300		10,561					(48,857	)
Net increase in cash and equivalents		2,320		735		514		147		–					3,716
Cash and equivalents, beginning of year		8		3		4		128		–					143
Cash and equivalents, end of year	$	2,328		738		518		275		–				$	3,859

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Explanation of reclassifications and eliminations on consolidating schedules

[1] Eliminations of intercompany receivables and payables and other intercompany transactions.

[2] Elimination of investment in subsidiaries, carried at equity.

[3] Reclassification of preferred stock dividends of Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited and of accrued income taxes for financial statement presentation.

HECO has not provided separate financial statements and other disclosures concerning HELCO and MECO because management has concluded that such financial statements and other information are not material to holders of the trust preferred securities issued by HECO Capital Trust III, which trust holds the 2004 junior deferrable debentures issued by HELCO and MECO, which debentures have been fully and unconditionally guaranteed by HECO.

18. Consolidated quarterly financial information(unaudited)

Selected quarterly consolidated financial information of the Company for 2008 and 2007 follows:

		Quarters ended								Year ended
2008		March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues (1)	$	622,494	$	686,647	$	826,124	$	718,374	$	2,853,639
Operating income (1)		34,666		37,388		35,414		22,469		129,937
Net income for common stock (1)		24,585		27,432		25,932		14,026		91,975
		Quarters ended								Year ended Dec. 31
2007		March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues (2),(3)	$	446,797	$	491,249	$	561,720	$	597,192	$	2,096,958
Operating income (2),(3)		19,503		21,222		20,736		38,814		100,275
Net income for common stock (2),(3),(4)		453		10,650		12,875		28,178		52,156

Note: HEI owns all of HECO’s common stock, therefore per share data is not meaningful.

(1) For 2008, amounts include interim rate relief for HECO (2007 test year), HELCO (2006 test year) and MECO (2007 test year). The fourth quarter of 2008 includes a reduction of $1.3 million, net of taxes, of revenues related to prior periods.

(2) For 2007, amounts include interim rate relief for HECO (2005 test year; 2007 test year since October 22, 2007), HELCO (2006 test year since April 5, 2007) and MECO (2007 test year since December 21, 2007).

(3) The third quarter of 2007 includes a $9 million, net of tax benefits, reserve accrued for the potential refund (with interest) of a portion of HECO’s 2005 test year interim rate increase.

(4) The first quarter of 2007 includes a $7 million, net of tax benefits, write-off of plant in service costs at HELCO as part of a settlement in HELCO’s 2006 test year rate case.

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