HECO Exhibit 99.2

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 or 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:

·international, national and local economic conditions, including the state of the Hawaii tourism 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;

·weather and natural disasters, such as hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming (such as more severe storms and rising sea levels);

·global developments, including terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan, potential conflict or crisis with North Korea or in the Middle East;

·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 (including lines of credit) and the cost of such financings, if available;

·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 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), revenue decoupling and the fulfillment by the Company of its commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering HCEI-related costs; reliance by the Company on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cable (to bring power to Oahu from Lanai and/or Molokai), biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

·capacity and supply constraints or difficulties, especially if generating units (utility-owned or 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;

·the risk to generation reliability when generation peak reserve margins on Oahu are 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 impact of fuel price volatility on customer satisfaction and political and regulatory support for the Company;

·the risks associated with increasing reliance on renewable energy, as contemplated under the Energy Agreement, including the availability and cost of non-fossil fuel supplies for renewable generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;

·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 their 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, increases in capital requirements, regulatory changes resulting from the HCEI, environmental laws and regulations, the regulation of greenhouse gas emissions (GHG), healthcare reform, and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);

·decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs);

·decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions and restrictions and penalties that may arise, such as with respect to environmental conditions or renewable portfolio standards (RPS));

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·ability to recover and earn on increasing costs and capital investments not covered by revenue adjustment mechanisms;

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

·changes in accounting principles applicable to the Company, including the adoption of International Financial Reporting Standards or new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of variable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;

·changes by securities rating agencies in their ratings of the securities of HECO 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 or underinsured; 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 (SEC).

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, 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.

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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 Management’s Discussion and Analysis of Financial Condition and Results of Operations (except for HEI’s Selected contractual obligations and commitments table), included in the Form 10-K dated February 18, 2011 (HEI’s MD&A). The information incorporated by reference should be read in conjunction with HECO’s consolidated financial statements and accompanying notes.

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

	Payments due by period
December 31, 2010 (in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Long-term debt	$	—	$	58	$	11	$	991	$	1,060
Interest on long-term debt	57		110		109		733		1,009
Operating leases	5		10		8		11		34
Open purchase order obligations (1)	69		40		1		—		110
Fuel oil purchase obligations (estimate based on December 31, 2010 fuel oil prices)	967		1,715		653		—		3,335
Purchase power obligations— minimum fixed capacity charges	119		234		232		665		1,250
Liabilities for uncertain tax positions	—		10		2		—		12
Total (estimated)	$	1,217	$	2,177	$	1,016	$	2,400	$	6,810

(1) Includes contractual obligations and commitments for capital expenditures and expense amounts.

The table above does not include other categories of obligations and commitments, such as deferred taxes, 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. As of December 31, 2010, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the table above; however, 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” (included below in this report) for a discussion of retirement benefit plan obligations, including estimated minimum required contributions for 2011 and 2012.

See Note 11 of HECO’s “Notes to Consolidated Financial Statements” (included below in this report) for a discussion of fuel and power purchase commitments.

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

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. HECO and its subsidiaries believe their exposures to these two risks are not material as of December 31, 2010.

HECO and its subsidiaries are exposed to some commodity price risk primarily related to their 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.  HECO and its subsidiaries currently have no hedges against their

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commodity price risk. Because HECO and its subsidiaries do not have a portfolio of trading assets, they currently have no exposure to market risk from trading activities nor foreign currency exchange rate risk.

HECO and its subsidiaries consider interest rate risk to be a significant market risk as it may affect the discount rate used to determine retirement benefit liabilities, the market value of retirement benefit 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 the Form 10-K dated February 18, 2011, and the discussion in Note 10 of HECO’s “Notes to Consolidated Financial Statements.”

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2010		2009		2008		2007		2006
(in thousands)
Results of operations
Operating revenues	$	2,367,441	$	2,026,672	$	2,853,639	$	2,096,958	$	2,050,412
Operating expenses	2,247,600		1,912,264		2,723,702		1,996,683		1,933,257
Operating income	119,841		114,408		129,937		100,275		117,155
Other income	17,695		19,709		15,049		4,592		9,471
Interest and other charges	58,952		52,676		51,016		50,716		49,684
Net income	78,584		81,441		93,970		54,151		76,942
Preferred stock dividends of subsidiaries	915		915		915		915		915
Net income attributable to HECO	77,669		80,526		93,055		53,236		76,027
Preferred stock dividends of HECO	1,080		1,080		1,080		1,080		1,080
Net income for common stock	$	76,589	$	79,446	$	91,975	$	52,156	$	74,947

At December 31	2010			2009			2008			2007			2006
(in thousands)
Financial position
Utility plant	$	5,049,900		$	4,881,767		$	4,586,668		$	4,320,607		$	4,133,883
Accumulated depreciation	(1,941,059		)	(1,848,416		)	(1,741,453		)	(1,647,113		)	(1,558,913		)
Net utility plant	$	3,108,841		$	3,033,351		$	2,845,215		$	2,673,494		$	2,574,970
Total assets	$	4,285,680		$	3,978,392		$	3,856,109		$	3,423,888		$	3,063,134
Capitalization:(1)
Short-term borrowings from non-affiliates and affiliate	$	—		$	—		$	41,550		$	28,791		$	113,107
Long-term debt, net	1,057,942			1,057,815			904,501			885,099			766,185
Common stock equity	1,337,398			1,306,408			1,188,842			1,110,462			958,203
Cumulative preferred stock—not subject to mandatory redemption	34,293			34,293			34,293			34,293			34,293
Total capitalization	$	2,429,633		$	2,398,516		$	2,169,186		$	2,058,645		$	1,871,788
Capital structure ratios (%)(1)
Debt	43.5			44.1			43.6			44.4			47.0
Cumulative preferred stock	1.4			1.4			1.6			1.7			1.8
Common stock equity	55.1			54.5			54.8			53.9			51.2

(1) Includes current portion of long-term debt, and sinking fund and optional redemption amounts (if any) payable within one year for preferred stock.

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 the Form 10-K dated February 18, 2011, and Note 11 (“Commitments and contingencies”) of HECO’s “Notes to Consolidated Financial Statements” for discussions of certain contingencies that could adversely affect future results of operations, financial condition and cash flows.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Hawaiian Electric Company, Inc.:

In our opinion, the accompanying consolidated balance sheet and statement of capitalization as of December 31, 2010 and the related statements of income, changes in common stock equity and cash flows for the year then ended present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and its subsidiaries (the “Company”) at December 31, 2010, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.  We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of January 1, 2010.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 18, 2011

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2009, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the years in the two-year period ended December 31, 2009. 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, 2009, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Honolulu, Hawaii
February 19, 2010

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Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2010			2009			2008
(in thousands)
Operating revenues	$	2,367,441		$	2,026,672		$	2,853,639
Operating expenses
Fuel oil	900,408			671,970			1,229,193
Purchased power	548,800			499,804			689,828
Other operation	251,027			248,515			243,249
Maintenance	127,487			107,531			101,624
Depreciation	149,708			144,533			141,678
Taxes, other than income taxes	222,117			191,699			261,823
Income taxes	48,053			48,212			56,307
	2,247,600			1,912,264			2,723,702
Operating income	119,841			114,408			129,937
Other income
Allowance for equity funds used during construction	6,016			12,222			9,390
Other, net	11,679			7,487			5,659
	17,695			19,709			15,049
Interest and other charges
Interest on long-term debt	57,532			51,820			47,302
Amortization of net bond premium and expense	2,975			3,254			2,530
Other interest charges	1,003			2,870			4,925
Allowance for borrowed funds used during construction	(2,558		)	(5,268		)	(3,741		)
	58,952			52,676			51,016
Net income	78,584			81,441			93,970
Preferred stock dividends of subsidiaries	915			915			915
Net income attributable to HECO	77,669			80,526			93,055
Preferred stock dividends of HECO	1,080			1,080			1,080
Net income for common stock	$	76,589		$	79,446		$	91,975

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2010			2009
(in thousands)
Assets
Utility plant, at cost
Land	$	51,364		$	52,530
Plant and equipment	4,896,974			4,696,257
Less accumulated depreciation	(1,941,059		)	(1,848,416		)
Construction in progress	101,562			132,980
Net utility plant	3,108,841			3,033,351
Current assets
Cash and equivalents	122,936			73,578
Customer accounts receivable, net	138,171			133,286
Accrued unbilled revenues, net	104,384			84,276
Other accounts receivable, net	9,376			8,449
Fuel oil stock, at average cost	152,705			78,661
Materials and supplies, at average cost	36,717			35,908
Prepayments and other	55,216			16,201
Regulatory assets	7,349			6,849
Total current assets	626,854			437,208
Other long-term assets
Regulatory assets	470,981			420,013
Unamortized debt expense	14,030			14,288
Other	64,974			73,532
Total other long-term assets	549,985			507,833
	$	4,285,680		$	3,978,392
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,337,398		$	1,306,408
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,057,942			1,057,815
Total capitalization	2,429,633			2,398,516
Current liabilities
Accounts payable	178,959			132,711
Interest and preferred dividends payable	20,603			21,223
Taxes accrued	175,960			156,092
Other	56,354			48,192
Total current liabilities	431,876			358,218
Deferred credits and other liabilities
Deferred income taxes	269,286			180,603
Regulatory liabilities	296,797			288,214
Unamortized tax credits	58,810			56,870
Retirement benefits liability	355,844			296,623
Other	108,070			77,804
Total deferred credits and other liabilities	1,088,807			900,114
Contributions in aid of construction	335,364			321,544
	$	4,285,680		$	3,978,392

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2010		2009		2008
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding  2010, 13,830,823 shares, 2009, 13,786,959 shares and 2008, 12,805,843 shares	$	92,224	$	91,931	$	85,387
Premium on capital stock	389,609		385,659		299,214
Retained earnings	854,856		827,036		802,590
Accumulated other comprehensive income, net of income taxes:
Retirement benefit plans	709		1,782		1,651
Common stock equity	1,337,398		1,306,408		1,188,842

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.

Series	ParValue			Shares outstanding December 31, 2010 and 2009	2010		2009
(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)

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2010		2009
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds (subsidiary obligations unconditionally guaranteed by HECO):
HECO, 6.50%, series 2009, due 2039	$	90,000	$	90,000
HELCO, 6.50%, series 2009, due 2039	60,000		60,000
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
Total obligations to the State of Hawaii	1,007,900		1,007,900
Other long-term debt — unsecured:
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034	51,546		51,546
Total long-term debt	1,059,446		1,059,446
Less unamortized discount	1,504		1,631
Long-term debt, net	1,057,942		1,057,815
Total capitalization	$	2,429,633	$	2,398,516

The accompanying notes are an integral part of these 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		Retained			Accumulated other comprehensive
(in thousands)	Shares	Amount		stock		earnings			income (loss)			Total
Balance, December 31, 2007	12,806	$	85,387	$	299,214	$	724,704		$	1,157		$	1,110,462
Comprehensive income:
Net income for common stock	—	—		—		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 assets, net of tax benefits of $96,975	—	—		—		—			152,256			152,256
Other comprehensive income									494
Comprehensive income												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
Comprehensive income:
Net income for common stock	—	—		—		79,446			—			79,446
Retirement benefit plans:
Net transition asset arising during the period, net of taxes of $4,172	—	—		—		—			6,549			6,549
Prior service credit arising during the period, net of taxes of $922	—	—		—		—			1,446			1,446
Net gains arising during the period, net of taxes of $36,990	—	—		—		—			58,081			58,081
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 $6,250	—	—		—		—			9,811			9,811
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,251	—	—		—		—			(75,756		)	(75,756		)
Other comprehensive income									131
Comprehensive income												79,577
Issuance of common stock, net of expenses	981	6,544		86,445		—			—			92,989
Common stock dividends	—	—		—		(55,000		)	—			(55,000		)
Balance, December 31, 2009	13,787	91,931		385,659		827,036			1,782			1,306,408
Comprehensive income:
Net income for common stock	—	—		—		76,589			—			76,589
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of $3,001	—	—		—		—			4,712			4,712
Net losses arising during the period, net of tax benefits of $27,408	—	—		—		—			(43,031		)	(43,031		)
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 $2,387	—	—		—		—			3,747			3,747
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $21,336	—	—		—		—			33,499			33,499
Other comprehensive loss									(1,073		)
Comprehensive income												75,516
Issuance of common stock, net of expenses	44	293		3,950		—			—			4,243
Common stock dividends	—	—		—		(48,769		)	—			(48,769		)
Balance, December 31, 2010	13,831	$	92,224	$	389,609	$	854,856		$	709		$	1,337,398

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2010			2009			2008
(in thousands)
Cash flows from operating activities
Net income	$	78,584		$	81,441		$	93,970
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of utility plant	149,708			144,533			141,678
Other amortization	7,725			10,045			8,619
Changes in deferred income taxes	95,685			14,762			3,882
Changes in tax credits, net	2,841			(1,332		)	1,470
Allowance for equity funds used during construction	(6,016		)	(12,222		)	(9,390		)
Decrease in cash overdraft	(141		)	—			—
Changes in assets and liabilities
Decrease (increase) in accounts receivable	(5,812		)	32,605			(21,313		)
Decrease (increase) in accrued unbilled revenues	(20,108		)	22,268			7,730
Decrease (increase) in fuel oil stock	(74,044		)	(946		)	14,156
Increase in materials and supplies	(809		)	(1,376		)	(274		)
Increase in regulatory assets	(2,936		)	(17,597		)	(3,229		)
Increase (decrease) in accounts payable	25,392			9,717			(14,901		)
Changes in prepaid and accrued income taxes and revenue taxes	(10,170		)	(61,951		)	28,055
Other	7,890			(2,571		)	(5,445		)
Net cash provided by operating activities	247,789			217,376			245,008
Cash flows from investing activities
Capital expenditures	(174,344		)	(302,327		)	(278,476		)
Contributions in aid of construction	22,555			14,170			17,319
Other	1,327			340			1,157
Net cash used in investing activities	(150,462		)	(287,817		)	(260,000		)
Cash flows from financing activities
Common stock dividends	(48,769		)	(55,000		)	(14,089		)
Preferred stock dividends of HECO and subsidiaries	(1,995		)	(1,995		)	(1,995		)
Proceeds from issuance of common stock	4,250			61,914			—
Proceeds from issuance of long-term debt	—			153,186			19,275
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	—			(10,464		)	12,759
Increase (decrease) in cash overdraft	—			(9,545		)	1,265
Other	(1,455		)	(978		)	—
Net cash provided by (used in) financing activities	(47,969		)	137,118			17,215
Net increase in cash and cash equivalents	49,358			66,677			2,223
Cash and cash equivalents, January 1	73,578			6,901			4,678
Cash and cash equivalents, December 31	$	122,936		$	73,578		$	6,901

The accompanying notes are an integral part of these 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 the following non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which was formed to invest in renewable energy projects; Uluwehiokama Biofuels Corp. (UBC), which was formed to invest in a new biodiesel refining plant to be built on the island of Maui, which project has been terminated; and HECO Capital Trust III, which is a 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; and revenues.

Consolidation.  The consolidated financial statements include the accounts of HECO and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable interest entities (VIEs) 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 unconsolidated VIEs.

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 FASB Accounting Standards CodificationTM  (ASC) Topic 980, “Regulated Operations.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the electric utilities expect that their regulatory assets would be charged to expense and regulatory liabilities would be credited to income or refunded to ratepayers immediately. 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 immediately.

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. Also see “Variable interest entities” below.

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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 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.

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 in accordance with rate-making. Utility plant has lives ranging from 20 to 69 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 3.5% in 2010 and 3.8% in 2009 and 2008.

Leases.  HECO and its subsidiaries have entered into lease agreements for the use of equipment and office space. The provisions of some of the lease agreements contain renewal options.

Operating lease expense was $6 million, $7 million and $7 million in 2010, 2009 and 2008, respectively. Future minimum lease payments are $5 million each year for 2011, 2012, 2013, $4 million for 2014, $3 million for 2015 and $11 million thereafter.

Cash and cash equivalents.  The Company considers cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper of non-affiliates and liquid investments (with original maturities of three months or less) to be cash and cash 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. On a monthly basis, the Company adjusts its allowance, with a corresponding charge (credit) on the statement of income, 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 electric utility plant. Funding for the Company’s qualified pension plans (Plans) is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary. The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of the 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 during the year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the PUC, 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 also generally fund the net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

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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 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 electric utilities must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC. Future decisions in rate cases could further impact funding amounts.

The Company recognizes 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.

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.

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. However, the Company’s payments to the taxing authorities are based on the prior years’ revenues. For 2010, 2009 and 2008, the Company included approximately $211 million, $181 million and $252 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Power purchase agreements.  If a power purchase agreement (PPA) falls within the scope of ASC Topic 840, “Leases,” and results in the classification of the agreement as a capital lease, the Company would recognize a capital asset and a lease obligation. Currently, none of the PPAs is required to be recorded as a capital lease.

The Company evaluates PPAs to determine if the PPAs are VIEs, if the Company is the primary beneficiary and if consolidation is required. See Note 3.

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 after assessing the causes of the delay and probability of recovery.

The weighted-average AFUDC rate was 8.1% in 2010, 2009 and 2008, 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.  However, 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 federal and state 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.

The Company uses a “more-likely-than-not” recognition threshold and measurement standard 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 cost to sell.

Recent accounting pronouncements and interpretations

Noncontrolling interests.  In December 2007, the FASB issued a standard that 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 to be clearly identified and presented on the face of the income statement. Changes in the parent’s ownership interest that leave control intact are accounted for as capital transactions (i.e., as increases or decreases in ownership), a gain or loss will be recognized when a subsidiary is deconsolidated based on the fair value of the noncontrolling equity investment (not carrying amount), and entities must provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and of the noncontrolling owners. The Company adopted the standard prospectively on January 1, 2009, except for the presentation and disclosure requirements which must be applied retrospectively.

In April 2010, management evaluated the impact of Accounting Standards Update (ASU) 2009-04, “Accounting for Redeemable Equity Instruments,” and the provisions of the Company’s $34 million of preferred stock that allowed preferred shareholders to potentially control the board if preferred dividends were not paid for four quarters, which could lead to the redemption of the preferred shares. This evaluation resulted in the movement of preferred stock of subsidiaries on the consolidated balance sheet from stockholder’s equity to mezzanine equity and the removal of preferred stock of subsidiaries from the consolidated statement of changes in common stock equity for

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all prior periods presented, which changes were immaterial to the financial statements. There were no changes to previously reported operating income, net income, earnings per share and cash flows.

Variable interest entities.In June 2009, the FASB issued a standard that amends the guidance in FASB Accounting Standards CodificationTM (ASC) Topic 810 related to the consolidation of VIEs. The standard eliminates exceptions to consolidating qualifying special-purpose entities, contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. The Company adopted this standard in the first quarter of 2010 and the adoption did not impact the Company’s financial condition, results of operations or cash flows.

Reclassifications.  Certain reclassifications have been made to prior years’ financial statements to conform to the 2010 presentation, which did not affect previously reported results of operations.

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:

December 31, 2010	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 HELCO and MECO in the respective principal amounts of $10 million, (iii) making distributions on these 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 currently redeemable at the issuer’s option without premium. 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 accounting rules on the consolidation of VIEs. Trust III’s balance sheet as of December 31, 2010 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 2010 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

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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, 2010, HECO and its subsidiaries had six PPAs totaling 540 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), none of which are currently required to be consolidated as VIEs. 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 2010 totaled $549 million with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $143 million, $225 million, $57 million and $44 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

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 accounting standards for VIEs 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 accounting standards for VIEs 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 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), and thus excluded from the scope of accounting standards for VIEs. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of accounting standards for VIEs.

Since 2004, HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2010, HECO and its subsidiaries sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the 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 HELCO and MECO 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 accounting standards for VIEs.

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

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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 current accounting standards for VIEs, 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 have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO could potentially 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.

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 generally 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 July 30, 2009 the Department also issued, at par, Series 2009 SPRBs in the aggregate principal amount of $150 million, with a maturity of July 1, 2039 and a fixed coupon interest rate of 6.50%, and loaned the proceeds to HECO ($90 million) and HELCO ($60 million). HECO and HELCO drew the full amount of the proceeds from the issuance of the SPRBs as reimbursement for previously incurred capital expenditures, and used the proceeds principally to repay short-term borrowings. Payment of the principal and interest on the SPRBs are not insured.

At December 31, 2010, the aggregate payments of principal required on long-term debt are nil in 2011, $58 million in 2012, nil in 2013, $11 million in 2014 and nil in 2015.

5.  Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2010 and 2009.

At December 31, 2010 and 2009 the Company maintained syndicated credit facilities of $175 million.  HECO had no borrowings under its facilities in 2010. HECO drew on its facility in June and July 2009; all such borrowings were repaid in August 2009. The facility is not collateralized. See Note 13, “Related-party transactions,” concerning borrowings from affiliates.

Credit agreement.  Effective May 7, 2010, HECO entered into a revolving noncollateralized credit agreement establishing a line of credit facility of $175 million, with a letter of credit sub-facility expiring on May 6, 2011, with a syndicate of eight financial institutions. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 225 basis points or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 100 basis points per annum, as defined in the agreement. Annual fees on the undrawn commitments are 40 basis points. The agreement contains provisions for revised pricing in the event of a long-term ratings change (such as when S&P lowered its long-term ratings for HECO, HELCO and MECO in November 2010). The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions that must be met in order to draw on it, including compliance with several covenants. The agreement’s termination date was extended to May 7, 2013 after having received PUC approval.

HECO’s $175 million credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital

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expenditures, working capital and general corporate purposes. HECO’s $175 million syndicated credit facility expiring March 31, 2011 was terminated concurrently with the effectiveness of this new syndicated credit facility.

6.  Regulatory assets and liabilities

In accordance with ASC Topic 980, “Regulated Operations,” the Company’s financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes its operations currently satisfy the ASC Topic 980 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 immediately. 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 immediately.

Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, HECO and its subsidiaries do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. 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. Generally, HECO and its subsidiaries include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. Noted in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2010, if different.

Regulatory assets were as follows:

December 31	2010		2009
(in thousands)
Retirement benefit plans (9 years; 5 years remaining for HELCO’s $2 million prepaid pension regulatory asset; 5 years, 4 years remaining for HECO’s $7 million pension tracking mechanism; 5 years remaining for HELCO’s $6 million and MECO’s $3 million pension and OPEB tracking mechanisms; indeterminate for remainder)	$	356,591	$	303,927
Income taxes, net (1 to 36 years)	82,615		82,046
Unamortized expense and premiums on retired debt and equity issuances (5 to 30 years; 1 to 18 years remaining)	13,589		14,878
Vacation earned, but not yet taken (1 year)	7,349		6,849
Postretirement benefits other than pensions (18 years; 2 years remaining)	3,579		5,369
Other (1 to 50 years; 1 to 49 years remaining)	14,607		13,793
	$	478,330	$	426,862

Regulatory liabilities were as follows:

December 31	2010		2009
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	277,341	$	280,674
Retirement benefit plans (5 years beginning with respective utility’s next rate case; 4 years remaining for HECO’s $4 million regulatory liability; 5 years remaining for HELCO’s $0.8 million and MECO’s $0.4 million regulatory liability)	18,617		5,193
Other (1 to 5 years)	839		2,347
	$	296,797	$	288,214

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 rate case decisions for HECO, MECO and HELCO in 2007 (see Note 10).

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7.  Income taxes

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

Years ended December 31	2010			2009			2008
(in thousands)
Federal:
Current	$	(40,043	)	$	27,857		$	44,759
Deferred	83,739			15,621			6,040
Deferred tax credits, net	(901		)	(593		)	(1,094		)
	42,795			42,885			49,705
State:
Current	(10,746		)	7,123			6,522
Deferred	13,163			(464		)	(1,391		)
Deferred tax credits, net	2,841			(1,332		)	1,471
	5,258			5,327			6,602
Total	$	48,053		$	48,212		$	56,307

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $1.2 million, $0.4 million and $0.5 million for 2010, 2009 and 2008, 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 of HECO and subsidiaries follows:

December 31	2010			2009			2008
(in thousands)
Amount at the federal statutory income tax rate Increase (decrease) resulting from:	$	44,755		$	45,646		$	52,907
State income taxes on operating income, net of effect on federal income taxes	3,418			3,463			4,291
Other	(120		)	(897		)	(891		)
Income taxes charged to operating expenses	$	48,053		$	48,212		$	56,307
Effective income tax rate	37.9		%	37.2		%	37.5		%

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

December 31	2010		2009
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	107,913	$	109,210
Contributions in aid of construction and customer advances	78,958		77,766
Retirement benefits	—		1,541
Other	12,686		18,985
	199,557		207,502
Deferred tax liabilities:
Property, plant and equipment	376,148		338,910
Change in accounting method related to repairs	46,702		—
Regulatory assets, excluding amounts attributable to property, plant and equipment	32,074		31,947
Change in accounting method related to contributions in aid of construction	—		8,010
Retirement benefits	3,394		—
Retirement benefits in Accumulated Other Comprehensive Income (AOCI)	452		1,135
Other	10,073		8,103
	468,843		388,105
Net deferred income tax liability	$	269,286	$	180,603

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible.  Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company will realize

21

substantially all of the benefits of the deferred tax assets. In 2010, the significant increase in the net deferred income tax liability was primarily due to accelerated tax deductions taken for bonus depreciation (resulting from the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act) and the change in accounting method for repairs deductions for tax purposes.

In 2010, interest income on income tax refunds was reflected in “Other income—Other, net” in the amount of $9.6 million, which resulted from the settlement with the IRS of appealed issues for the tax years 1996 to 2006 and was due in large part to a change in the method of allocating overhead costs to self-constructed assets. In 2010, 2009 and 2008, interest expense (and adjustments to expense) on income taxes was reflected in “Interest and other charges” in the amount of $(1.3) million, $0.5 million and $0.5 million, respectively. As of December 31, 2010 and 2009, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and preferred dividends payable” was $0.8 million and $2.1 million, respectively.

As of December 31, 2010, the total amount of liability for uncertain tax positions was $11.7 million and, of this amount, $0.2 million, if recognized, would affect the Company’s effective tax rate. Management concluded that no significant changes to the liability for uncertain tax positions will occur within the next 12 months.

The changes in total unrecognized tax benefits were as follows:

Years ended December 31	2010			2009
(in millions)
Unrecognized tax benefits, January 1	$	24.1		$	24.2
Additions based on tax positions taken during the year	10.9			—
Additions for tax positions of prior years	1.4			0.4
Reductions for tax positions of prior years	(16.2		)	(0.5		)
Settlements	(6.0		)	—
Unrecognized tax benefits, December 31	$	14.2		$	24.1

In addition to the liability for uncertain tax positions, the Company’s unrecognized tax benefits include $1.4 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 liability for uncertain tax positions was required to offset these potential benefits.

Tax years 2005 to 2009 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii.

As of December 31, 2010, the 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 cash flows.

8.  Cash flows

Supplemental disclosures of cash flow information. Cash paid (received) for interest to HEI and non-affiliates (net of AFUDC-Debt) and income taxes was as follows:

Years ended December 31	2010			2009		2008
(in thousands)
Interest	$	56,184		$	43,616	$	48,357
Income taxes	$	(7,277	)	$	24,309	$	91,043

Supplemental disclosures of noncash activities

In 2010, 2009 and 2008, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $6 million, $12 million and $9 million, respectively.

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In 2010, 2009 and 2008, the estimated fair value of noncash contributions in aid of construction amounted to $7 million, $12 million and $10 million, respectively.

In December 2009, HECO sold $93 million of its common stock to HEI. HECO received $62 million of cash from HEI and reduced its intercompany note payable to HEI by $31 million in a noncash transaction.

9.  Major customers

HECO and its subsidiaries received approximately 10% ($242 million), 10% ($199 million) and 10% ($295 million) of their operating revenues from the sale of electricity to various federal government agencies in 2010, 2009 and 2008, respectively.

10.  Retirement benefits

Defined benefit plans.  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, noncontributory 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 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 respective 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.

In the third quarter of 2009, the Company amended the executive life benefit plan to limit it to current participants and to freeze the executive life benefits at current levels. In November 2010, August 2010 and August 2009, HELCO, MECO and HECO, respectively, eliminated the electric discount benefit for merit employees and retirees, and the electric discount benefit for bargaining unit employees and retirees was eliminated on January 31, 2011. The Company’s cost for OPEB has been adjusted to reflect the plan amendment, which reduced benefits. The elimination of the electric discount benefit will generate credits through other benefit costs over the next few years as the total amendment credit is amortized.

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

23

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% 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.

Balance sheet recognition of the funded status of retirement plans.  Employers must recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO), to calculate the funded status).

The PUC allowed the utilities to adopt pension and OPEB tracking mechanisms in recent rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the utilities’ tracking mechanisms, any actual costs determined in accordance with U.S. generally accepted accounting principles (GAAP) that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.6 million in 2010) determined in accordance with U.S. GAAP will be recovered.

Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), which amounts include the prepaid pension asset, net of taxes, as well as other pension and OPEB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The electric utilities have reclassified to a regulatory asset charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge/(credit) to AOCI of $55 million pretax and $(124) million pretax at December 31, 2010 and 2009, respectively).

In the PUC’s 2007 interim decision on HELCO’s 2006 test year rate case, the PUC allowed HELCO to record a regulatory asset in the amount of $12.8 million (representing HELCO’s prepaid pension asset and reflecting the accumulated pension contributions to its pension fund in excess of accumulated NPPC), which is included in rate base, and allowed recovery of that asset over a period of five years. HELCO is required to make contributions to the pension trust in the amount of the actuarially calculated NPPC that would be allowed without penalty by the tax laws.

In the PUC’s 2007 interim decisions on HECO and MECO’s 2007 test year rate cases (and in its final decision on HECO’s 2005 test year rate case), the PUC did not allow HECO and MECO to include their pension assets (representing the accumulated contributions to their pension fund in excess of accumulated NPPC), in their rate bases. However, under the tracking mechanisms, HECO and MECO are required to fund only the minimum level required under the law until their pension assets are reduced to zero, at which time HECO and MECO will make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitations on deductible contributions imposed by the Internal Revenue Code.

The PUC’s exclusion of HECO’s and MECO’s pension assets from rate base does not allow HECO and MECO to earn a return on the pension asset, but this exclusion does not result in the exclusion of any pension benefit costs from their rates. The pension asset is to be (or was, in the case of MECO) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2010, MECO did not have any remaining pension asset, and HECO’s pension asset had been reduced to $3 million.

The OPEB tracking mechanisms generally require the electric utilities to make contributions to the OPEB trust in the amount of the actuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations.

Retirement benefits expense for the electric utilities for 2010, 2009 and 2008 was $39 million, $32 million and $27 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 2010 and 2009 and the funded status of these plans and amounts related to these plans reflected in the Company’s consolidated balance sheet as of December 31, 2010 and 2009 were as follows:

	2010						2009
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Benefit obligation, January 1	$	922,801		$	165,826		$	872,842		$	175,560
Service cost	27,576			4,584			24,577			4,699
Interest cost	58,868			10,080			56,095			10,648
Amendments	—			(7,713		)	109			(13,199		)
Actuarial (gains) losses	113,857			11,323			17,203			(3,180		)
Benefits paid and expenses	(50,698		)	(9,355		)	(48,025		)	(8,702		)
Benefit obligation, December 31	1,072,404			174,745			922,801			165,826
Fair value of plan assets, January 1	658,917			132,714			550,732			104,396
Actual return on plan assets	106,552			20,963			137,716			26,862
Employer contribution	27,164			3,904			14,759			9,327
Benefits paid and expenses	(50,553		)	(8,713		)	(44,290		)	(7,871		)
Fair value of plan assets, December 31	742,080			148,868			658,917			132,714
Accrued benefit liability, December 31	(330,324		)	(25,877		)	(263,884		)	(33,112		)
AOCI, January 1 (excluding impact of PUC D&Os)	279,198			14,118			366,133			51,404
Recognized during year — net recognized transition asset (obligation)	—			8			—			(1,822		)
Recognized during year — prior service credit	747			409			747			92
Recognized during year — net actuarial losses	(7,300		)	—			(14,697		)	(381		)
Occurring during year — prior service (cost) credit	—			(7,713		)	109			(2,477		)
Occurring during year — net actuarial losses (gains)	69,052			1,387			(73,094		)	(21,977		)
Other adjustments	—			—			—			(10,721		)
	341,697			8,209			279,198			14,118
Cumulative impact of PUC D&Os	(340,187		)	(10,880		)	(278,582		)	(17,650		)
AOCI, December 31	1,510			(2,671		)	616			(3,532		)
Net actuarial loss	343,449			17,915			281,698			16,528
Prior service gain	(1,752		)	(9,689		)	(2,500		)	(2,385		)
Net transition obligation	—			(17		)	—			(25		)
	341,697			8,209			279,198			14,118
Cumulative impact of PUC D&Os	(340,187		)	(10,880		)	(278,582		)	(17,650		)
AOCI, December 31	1,510			(2,671		)	616			(3,532		)
Income taxes	(587		)	1,039			(240		)	1,374
AOCI, net of taxes, December 31	$	923		$	(1,632	)	$	376		$	(2,158	)

The Company does not expect any plan assets to be returned to the Company during calendar year 2011.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2010, 2009 and 2008.

The defined benefit pension plans’ accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), as of December 31, 2010 and 2009 were $956 million and $828 million, respectively.

The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan and restrictions on participant benefit accruals may be placed on the plan. If the plans fall below these thresholds, then, to avoid adverse consequences, funds in excess of the minimum required contribution may be contributed to the plan trust. Other factors could cause changes to the required contribution levels. The Company’s current estimate of contributions to the qualified defined benefit plans and all other retirement benefit plans in 2011 is $63 million.

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The Company estimates that the cash funding for the qualified defined benefit pension plan in 2011 and 2012 will be $59 million and $116 million, respectively, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanism and the Plan’s funding policy.

As of December 31, 2010, the benefits expected to be paid under the retirement benefit plans in 2011, 2012, 2013, 2014, 2015 and 2016 through 2020 amounted to $62 million, $65 million, $68 million, $70 million, $73 million and $417 million, respectively.

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

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for 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 defined benefit retirement plans was as follows:

	Pension benefits							Other benefits
					Investment policy							Investment policy
December 31	2010		2009		Target		Range	2010		2009		Target		Range
Asset category
Equity securities	71	%	68	%	70	%	65-75%	70	%	67	%	70	%	65-75%
Fixed income	29		32		30		25-35%	30		33		30		25-35%
	100	%	100	%	100	%		100	%	100	%	100	%

See Note 15 for additional disclosures about the fair value of the retirement benefit plans’ assets.

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

	Pension benefits						Other benefits
December 31	2010		2009		2008		2010		2009		2008
Benefit obligation
Discount rate	5.68	%	6.50	%	6.625	%	5.60	%	6.50	%	6.50	%
Rate of compensation increase	3.5		3.5		3.5		NA		NA		3.5
Net periodic benefit cost (years ended)
Discount rate	6.50		6.625		6.125		6.50		6.50		6.125
Expected return on plan assets	8.25		8.25		8.50		8.25		8.25		8.50
Rate of compensation increase	3.5		3.5		4.2		NA		3.5		4.2

NA Not applicable

The Company based its selection of an assumed discount rate for 2011 net periodic benefit cost and December 31, 2010 disclosure on a cash flow matching analysis that utilized bond information provided by Bloomberg for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2010. In selecting the expected rate of return on plan assets of 8% for 2011 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 matching of bond income to anticipated benefit cash flows was refined for 2010 but the basic methods of selecting the assumed discount rate and expected return on plan assets at December 31, 2010 did not change from December 31, 2009.

As of December 31, 2010, the assumed health care trend rates for 2011 and future years were as follows: medical, 9%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2009,

26

the assumed health care trend rates for 2010 and future years were as follows: medical, 10%, grading down to 5% for 2015 and thereafter; dental, 5%; and vision,4%.

The components of net periodic benefit cost were as follows:

	Pension benefits									Other benefits
(in thousands)	2010			2009			2008			2010			2009			2008
Service cost	$	27,576		$	24,577		$	26,902		$	4,584		$	4,699		$	4,643
Interest cost	58,868			56,095			53,973			10,080			10,648			10,699
Expected return on plan assets	(61,491		)	(50,838		)	(65,191		)	(10,960		)	(8,755		)	(10,789		)
Amortization of net transition obligation	—			—			—			(8		)	1,822			3,130
Amortization of net prior service gain	(747		)	(747		)	(762		)	(409		)	(92		)	—
Amortization of net actuarial loss	7,300			14,697			6,577			—			381			—
Net periodic benefit cost	31,506			43,784			21,499			3,287			8,703			7,683
Impact of PUC D&Os	10,207			(10,570		)	5,859			5,400			(132		)	1,038
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	41,713		$	33,214		$	27,358		$	8,687		$	8,571		$	8,721

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefit pension plans that will be amortized from AOCI or regulatory assets into net periodic pension benefit cost during 2011 are $(0.7) million, $16.5 million and nil, respectively. The estimated prior service cost (gain), net actuarial loss and net transitional asset for other benefit plans that will be amortized from AOCI or regulatory assets into net periodic other than pension benefit cost during 2011 are $(0.9) million, $0.1 million and de minimis, respectively.

The Company recorded pension expense of $32 million, $25 million and $20 million and OPEB expense of $7 million each year in 2010, 2009 and 2008, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans and other benefit plans had accumulated benefit obligations exceeding plan assets as of December 31, 2010 and 2009.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2010, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.2 million and the PBO by $3.0 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the PBO by $3.4 million.

11.  Commitments and contingencies

Fuel contracts.HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2014. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. Midwest. Based on the average price per barrel as of December 31, 2010, the estimated cost of minimum purchases under the fuel supply contracts is $1.0 billion in each of 2011 and 2012 and a total of $0.8 billion in 2013 and $0.7 billion in 2014. The actual cost of purchases in 2011 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 $1.0 billion, $0.7 billion and $1.2 billion of fuel under contractual agreements in 2010, 2009 and 2008, respectively.

On December 2, 2009, HECO and Chevron Products Company, a division of Chevron USA, Inc. (Chevron) executed an amendment to their existing contract for the purchase/sale of low sulfur fuel oil (LSFO). The amendment modified the pricing formula, which could result in higher prices. The amended agreement terminates on April 30, 2013. On January 28, 2010, the PUC approved the amendment on an interim basis, and allowed HECO to include the costs incurred under the amendment in its ECAC, to the extent such costs are not recovered through HECO’s base rates. HECO is awaiting a final D&O from the PUC.

On May 5, 2010, HECO and Tesoro Hawaii Corporation (Tesoro) executed a second amendment to their existing LSFO supply contract (LSFO contract), subject to PUC approval. The amendment modified the pricing formula, which could result in higher prices. It also reduced the minimum fuel volumes HECO is obligated to buy under the LSFO

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contract and reduced the maximum volumes Tesoro is obligated to sell HECO under the LSFO contract. The term of the amended agreement runs through April 30, 2013 and may automatically renew for annual terms thereafter unless earlier terminated by either party. On June 7, 2010, HECO submitted an application for PUC approval of the second amendment, such that the changes in fuel prices under the amendment would be included in HECO’s ECAC.

The utilities pay market-related prices for fuel supplies purchased under the Chevron and Tesoro agreements.

HECO and Renewable Energy Group Marketing & Logistics Group LLC (REG) entered into a supply contract dated December 21, 2009 and expiring in 2012 for biodiesel to be consumed in the operation of the Campbell Industrial Park combustion turbine. On June 4, 2010, the PUC approved the biodiesel supply contract and allowed HECO to include the costs in its ECAC, to the extent such costs are not recovered through HECO’s base rates. HECO’s price for biodiesel purchased under this agreement reflects market-related prices for animal fat and other process feedstocks.

In January 2011, HELCO signed a 20-year contract with Aina Koa Pono-Ka’u LLC to supply 16 million gallons of biodiesel per year from a biorefinery to be constructed by Aina Koa Pono-Ka’u LLC on the island of Hawaii, with initial consumption at HELCO’s Keahole Power Plant to begin by 2015. The Company filed an application with the PUC requesting approval of, among other things, the contract and the establishment of a Biofuel Surcharge Provision that will pass through the differential between the cost of the biofuel and the cost of the petroleum fuel that the biofuel is replacing, in the event the cost of the biofuel is higher, over the customer base of the utilities based on KWH usage. The effectiveness of the contract is contingent upon PUC approval of, among other items, the proposed methodology for spreading the cost differential between the price of biodiesel and petroleum diesel being replaced over the customers base of all three utilities and the recovery of the contract costs in the utilities’ respective ECACs to the extent not included in base rates.

Power purchase agreements.  As of December 31, 2010, 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 $0.5 billion, $0.5 billion and $0.7 billion for 2010, 2009 and 2008, 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 2011 through 2015 and a total of $0.7 billion in the period from 2016 through 2030.

In general, HECO and its subsidiaries base their payments under the PPAs upon available capacity and actually supplied 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. 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.

The energy charge for energy purchased from Kalaeloa under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for fuel oil under a Facility Fuel Supply Contract (fuel contract) between them. Kalaeloa and Tesoro have negotiated a proposed amendment to the pricing formula in their fuel contract. The amendment could result in higher fuel prices for Kalaeloa. In September 2010, HECO submitted a request for PUC approval to include the costs incurred under the PPA as a result of the amendment in HECO’s ECAC.

Purchase power adjustment clause. The final decision and order (D&O) for the HECO 2009 test year rate case approved a purchased power adjustment clause (PPAC). Purchased power capacity, O&M and other non-energy costs previously recovered through base rates will be recovered in the PPAC, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPAC outside of a rate case. The PPAC will be adjusted monthly and reconciled quarterly and will implement a provision in the Energy Agreement that called for surcharge recovery of these costs.  Purchased energy costs will continue to be recovered through the ECAC to the extent they are not recovered through base rates. Upon approval of the final rates in the HECO 2009 test year rate case, HECO will implement the PPAC.

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Hawaii Clean Energy Initiative.  In January 2008, the State of Hawaii (State) and the U.S. Department of Energy signed a memorandum of understanding establishing the HCEI. In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State 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), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement require approval of the PUC.

Among the major provisions of the Energy Agreement are the following: (a) pursuing an overall goal of providing 70% of Hawaii’s electricity and ground transportation energy needs from clean energy sources by 2030; (b) developing a feed-in tariff system with standardized purchase prices for renewable energy; (c) replacing system-wide caps on net energy metering (NEM) with per circuit thresholds that require a further study before a proposed interconnection that would take the circuit over the threshold may proceed; (d) adopting a regulatory rate-making model under which the utilities’ revenues would be decoupled from kilowatthour (KWH) sales; (e) continuing the existing ECACs, subject to periodic review by the PUC; (f) establishing a surcharge to allow the utilities to pass through all reasonably incurred purchased power costs; (g) supporting the development and use of renewable biofuels; (h) promoting greater use of renewable energy, including wind power and solar energy; (i) 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; (j) improving and expanding “load management” and “demand response” programs that allow the utilities to control customer loads to improve grid reliability and cost management; (k) the filing of PUC applications for approval of the installation of Advanced Metering Infrastructure, coupled with time-of-use or dynamic rate options for customers; (l) supporting prudent and cost effective investments in smart grid technologies; (m) delinking prices paid under all new renewable energy contracts from oil prices; and (n) exploring establishment of lifeline rates for low income customers.

Many actions have been taken, and continue to be taken, to further the goals of the HCEI. For example, in May 2010, HECO received PUC approval of its power purchase agreement with Kahuku Wind Power, LLC for the purchase of as-available energy. In October 2010, the PUC approved the implementation of FITs for renewable energy generators, including applicable pricing, other terms and conditions and a standard form contract. In December 2010, the PUC allowed HECO to implement immediately the decoupling mechanism approved in August 2010. The PUC also approved HECO’s proposed Purchase Power Adjustment Clause to recover non-energy purchased power agreement costs and ordered that the existing ECAC continue. In January 2011, the PUC approved the replacement of the present system-wide caps for NEM, with a 15% per circuit distribution threshold for DG penetration.

Renewable energy projects.  HECO and its subsidiaries continue to negotiate with developers of proposed projects (identified in the Energy Agreement) to integrate into its grid 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, 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. The State and HECO have agreed to work together to ensure the supporting infrastructure needed 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. In December 2009, the PUC issued a decision and order (D&O) that allows HECO to defer the costs of studies for this large wind project for later review of prudence and reasonableness.

Interim increases.As of December 31, 2010, HECO and its subsidiaries had recognized $4 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

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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 it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in the Company’s consolidated net income. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order include the following:

Campbell Industrial Park combustion turbine No. 1 and transmission line.  HECO built a 110 MW simple cycle combustion turbine generating unit and added an additional 138 kilovolt (kV) transmission line to transmit power from generating units at Campbell Industrial Park (CIP) to the rest of the Oahu electric grid (collectively, the Project).

In a second interim D&O to HECO’s 2009 test year rate case issued in February 2010, the PUC granted HECO an increase of $12.7 million in annual revenues to recover $163 million of the costs of the Project. As of December 31, 2010, HECO’s cost estimate for the Project was $195 million (of which $195 million had been incurred, including $9 million of AFUDC). In its 2011 test year rate case, HECO is seeking to recover actual project costs in excess of the $163 million estimate included in its 2009 test year rate case. Management believes no adjustment to project costs is required as of December 31, 2010.

East Oahu Transmission Project (EOTP). HECO had planned a project to construct a partially underground 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. In October 2007, the PUC approved HECO’s request to expend funds (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2) for a revised EOTP using different routes requiring the construction of subtransmission lines, but stated 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.

Phase 1 was placed in service on June 29, 2010 and is currently estimated to cost $58 million (as a result of higher costs and the project delays). In its 2011 test year rate case, HECO is seeking to recover Phase 1 costs. In April 2010, HECO proposed a modification of Phase 2 that uses smart grid technology and is estimated to cost $10 million (total cost of $15 million less $5 million of funding through the Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion in 2012.

As of December 31, 2010, the accumulated costs recorded for the EOTP amounted to $61 million ($59 million for Phase 1 and $2 million for Phase 2), including (i) $12 million of planning and permitting costs incurred prior to the 2002 denial of the permit, (ii) $25 million of planning, permitting and construction costs incurred after the denial of the permit and (iii) $24 million for AFUDC. Management believes no adjustment to project costs is required as of December 31, 2010.

HELCO generating units. In 1991, HELCO began planning to meet increased forecast demand for electricity. 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 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.”

After numerous delays due to environmental and other permitting challenges, CT-4 and CT-5 became operational in mid-2004 and the costs of CT-4 and CT-5 (less a previously agreed to $12 million write-off) were included in HELCO’s 2006 test year rate case interim and final rate increases.

On June 22, 2009, ST-7 was placed into service. As of December 31, 2010, HELCO’s cost estimate, and incurred costs, for ST-7 were both $92 million. The costs of ST-7 were included in HELCO’s 2010 test year rate case interim increase.

Management believes that no further adjustment to project costs is required at December 31, 2010.

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Customer Information System Project.  In 2005, the PUC approved the Company’s request to (i) expend the then-estimated $20 million for a new Customer Information System (CIS), provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.

HECO signed a contract with a software company in March 2006 with a transition to the new CIS originally scheduled to occur in February 2008, which transition did not occur. Disputes over the parties’ contractual obligations resulted in litigation, which subsequently was settled. HECO subsequently contracted with a new CIS software vendor and a new system integrator. The CIS Project is proceeding with the implementation of the new software system. As of December 31, 2010, HECO’s total deferred and capital cost estimate for the CIS was $57 million (of which $22 million was recorded). Management believes no adjustment to project costs is required as of December 31, 2010.

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. In recent years, legislative and regulatory activity related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act, has increased significantly and management anticipates that such activity will continue. Depending upon the final outcome of the legislative and regulatory activity (including under the Clean Water Act with respect to cooling water intake controls and changes in effluent standards and the Clean Air Act with respect to hazardous air pollutant emissions, tightening of the National Ambient Air Quality Standards, and the Regional Haze rule), HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs.

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 consolidated results of operations, financial condition or cash flows.

Honolulu Harbor investigation.  HECO has been involved since 1995 in a work group with several other potentially responsible parties (PRPs) identified by the State of HawaiiDepartment of Health (DOH), including oil companies, in investigating and responding to historical subsurface petroleum contamination in the Honolulu Harbor area. A subset of the PRPs (the Participating Parties) entered into a joint defense agreement and ultimately entered into an Enforceable Agreement with the DOH to address petroleum contamination at the site. 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.

The Participating Parties have conducted subsurface investigations, assessments and preliminary oil removal, and anticipate finalizing remedial design work for the Iwilei unit in 2011.

As of December 31, 2010, HECO’s remaining accrual for its estimated share of environmental costs for the Iwilei unit was $1.4 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the Participating Parties 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), the cost estimate may be subject to significant change and additional material costs may be incurred.

Global climate change and greenhouse gas (GHG) emissions reduction.  National and international concern about climate change and the contribution of GHG emissions to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions. Carbon dioxide emissions, including those from the combustion of fossil fuels, comprise the largest percentage of GHG emissions.

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In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The Company is participating in a Task Force established under Act 234, which is charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those to be undertaken under the Energy Agreement. A Task Force consultant prepared a work plan, which was submitted to the Hawaii Legislature in December 2009. Because the regulations implementing Act 234 have not yet been developed or promulgated, management cannot predict the impact of Act 234 on the Company, but compliance costs could be significant.

In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009 (ACES). Among other things, ACES establishes a declining cap on GHG emissions requiring a 3% emissions reduction by 2012 that increases periodically to 83% by 2050. ACES also establishes a trading and offset scheme for GHG allowances. The trading program combined with the declining cap is known as a “cap and trade” approach to emissions reduction. In September 2009, the U.S. Senate began consideration of the Clean Energy Jobs and American Power Act, which also includes cap and trade provisions. Since then, several other approaches to GHG emission reduction have been either introduced or discussed in the U.S. Senate; however, no legislation has yet been enacted.

On September 22, 2009, the federal Environmental Protection Agency (EPA) issued the Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions beginning in 2010. The utilities’ GHG emissions reports for 2010 are due on March 31, 2011. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Management believes the EPA will make the same or similar endangerment finding regarding GHG emissions from stationary sources like the utilities’ generating units.

In addition, the Prevention of Significant Deterioration (PSD) permit program of the CAA applies to designated air pollutants from new or modified stationary sources, such as utility electrical generation units. In June 2010, the EPA issued its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing facilities. States may need to increase fees to cover the increased level of activity caused by this rule. The GHG Tailoring Rule requires a number of existing HECO, HELCO and MECO facilities that are not currently subject to the Covered Source Permit program to submit an initial Covered Source Permit application to the DOH within one year. The EPA has stated that the PSD program applies to GHG emissions effective January 2, 2011 because that is the date the federal GHG emission standards for motor vehicles (Tailpipe Rule) take effect. Accordingly, permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis, and potentially control requirements. On January 12, 2011, the EPA issued a notice that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation units that are or will be fired on biofuels.

HECO and its subsidiaries have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, committing to burn renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generation units, and testing biofuel blends in other HECOand MECO generating units. Managementisunabletoevaluate the ultimate impact on its operations ofeventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing its carbon footprint and meeting GHG reduction goals that will ultimately emerge.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition

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and cash flows of the Company. For example, severe weather could cause significant harm to the Company’s physical facilities.

Given Hawaii’s unique geographic location and its isolated electric grids, physical risks of the type associated with climate change have been considered by the utilities in the planning, design, construction, operation and maintenance of its facilities. To ensure the reliability of each island’s grid, the utilities design and construct their electric generation systems with greater levels of redundancy than is typical for U.S. mainland, interconnected systems. Although a major natural disaster could have severe financial implications, such risks have existed since the Company’s inception and the Company makes a concerted effort to prepare for a fast response in the event of an emergency.

The utilities are undertaking an adaptation survey of their facilities as a step in developing a longer-term strategy for responding to the consequences of global climate change.

BlueEarth Biofuels LLC.  BlueEarth Maui Biodiesel LLC (BlueEarth Maui), a joint venture to pursue biodiesel development, was formed in early 2008 between BlueEarth Biofuels LLC (BlueEarth) and Uluwehiokama Biofuels Corp. (UBC), a non-regulated subsidiary of HECO. UBC invested $400,000 in BlueEarth Maui for a minority ownership interest. MECO began negotiating with BlueEarth Maui for a biodiesel fuel purchase contract, however, negotiations stalled. In October 2008, BlueEarth filed a civil action in federal district court against MECO, HECO and others alleging claims based on the parties’ failure to have reached agreement on the biodieselsupplyand related landagreements. The lawsuit seeks damages and equitable relief. Trial had been scheduled for April 2012. The project was terminated because the litigation was filed and UBC’s investment in the venture was written off in 2009.

Apollo Energy Corporation/Tawhiri Power LLC.  HELCO purchases energy generated at the Kamao’a wind farm pursuant to the Restated and Amended PPA for As-Available Energy (the RAC) dated October 13, 2004 between HELCO and Apollo Energy Corporation (Apollo), later assigned to Apollo’s affiliate, Tawhiri Power LLC (Tawhiri). The maximum allowed output of the wind farm is 20.5 MW.

In June 2010, HELCO and Tawhiri participated in an arbitration relating to disputes surrounding HELCO’s ownership and possessory interest in the switching station and reimbursement of certain interconnection costs. In December 2010, the arbitration panel issued its final award and order finding in favor of HELCO. Thus, Tawhiri transferred title to the switching station and rights to the land to HELCO and paid HELCO $0.6 million (which included reimbursement of certain interconnection costs, prejudgment interest and HELCO’s attorneys’ fees and costs). Tawhiri’s appeal from the PUC’s decision not to hear the issues presented to the arbitration panel remains pending before the Hawaii Intermediate Court of Appeals.

Asset retirement obligations.  Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on its earnings. Regulatory assets are established to recognize future recoveries through depreciation rates for accretion and depreciation expenses related to AROs and associated assets. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials. In September 2009, HECO recorded an ARO related to removing retired generating units at its Honolulu power plant, including abating asbestos and lead-based paint. The obligation was subsequently increased in June 2010, due to an increase in the estimated costs of the removal project. In August 2010, HECO recorded a similar ARO related to removing retired generating units at HECO’s Waiau power plant.

Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:

(in thousands)	2010			2009
Balance, January 1	$	23,746		$	286
Accretion expense	2,519			21
Liabilities incurred	11,949			23,479
Liabilities settled	(725		)	(40		)
Revisions in estimated cash flows	11,141			—
Balance, December 31	$	48,630		$	23,746

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Collective bargaining agreements. As of December 31, 2010, approximately 54% 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 collective bargaining and benefit agreements with HECO, HELCO and MECO. The 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. The agreements had been extended to January 31, 2011. On January 31, 2011, a tentative settlement agreement was reached, subject to ratification by the utilities’ union members.

12.  Regulatory restrictions on distributions to parent

As of December 31, 2010, net assets (assets less liabilities and preferred stock) of approximately $588 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 $5.0 million, $4.5 million and $4.7 million for general management and administrative services in 2010, 2009 and 2008, 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 nil at December 31, 2010 and 2009.  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 Wall Street Journal.

Borrowings among HECO and its subsidiaries are eliminated in consolidation. Interest charged by HEI to HECO was nil in 2010, $0.2 million in 2009 and de minimis in 2008.

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 measurements

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 active trading 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.

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The Company groups its financial assets measured at fair value in three levels outlined as follows:

Level 1:Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and shall be used to measure fair value whenever available.

Level 2:Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

Level 3:Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

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 cash 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.

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:

	2010				2009
December 31 (in thousands)	Carrying amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and cash equivalents	$	122,936	$	122,936	$	73,578	$	73,578
Financial liabilities:
Long-term debt, net, including amounts due within one year	1,057,942		1,020,550		1,057,815		1,018,900
Off-balance sheet item:
HECO-obligated preferred securities of trust subsidiary	50,000		52,500		50,000		48,480

Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain liabilities at fairvalue on anonrecurring basis in accordance withU.S. GAAP.  The fair value of AROs (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 11).

35

Retirement benefit plans.  On January 1, 2008, the retirement benefit plans (Plans) adopted new standards for fair value measurements of financial assets and liabilities and for fair value measurements of nonfinancial items that are recognized or disclosed at fair value in the financial statements on a recurring basis.

Assets held in various trusts are measured at fair value on a recurring basis (including items that are required to be measured at fair value and items for which the fair value option has been elected) and were as follows:

	Pension benefits									Other benefits
				Fair value measurements using								Fair value measurements using
	December 31,			Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobserv-able inputs		December 31,		Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobserv-able inputs
(in millions)	2010			(Level 1)		(Level 2)		(Level 3)		2010		(Level 1)		(Level 2)		(Level 3)
Equity securities	$	453		$	453	$	—	$	—	$	80	$	80	$	—	$	—
Equity index funds	80			80		—		—		14		14		—		—
Fixed income securities	238			55		183		—		8		2		6		—
Pooled and mutual funds	78			9		69		—		49		39		10		—
Total	$	849		$	597	$	252	$	—	151		$	135	$	16	$	—
Receivables and payables, net	(17		)							—
Fair value of plan assets	$	832								$	151
HECO’s fair value of plan assets	$	742								$	149

	Pension benefits										Other benefits
				Fair value measurements using									Fair value measurements using
	December 31,			Quoted prices in active markets for identical assets		Significant other observable inputs			Significant unobserv-able inputs		December 31,		Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobserv-able inputs
(in millions)	2009			(Level 1)		(Level 2)			(Level 3)		2009		(Level 1)		(Level 2)		(Level 3)
Equity securities	$	405		$	384	$	—		$	21	$	71	$	67	$	—	$	4
Equity index funds	70			70		—			—		46		46		—		—
Fixed income securities	241			32		209			—		8		1		7		—
Pooled and mutual funds	26			—		—			26		5		—		—		5
Other	18			—		(2		)	20		5		—		—		5
Total	760			$	486	$	207		$	67	135		$	114	$	7	$	14
Receivables and payables, net	(21		)								—
Fair value of plan assets	$	739									$	135
HECO’s fair value of plan assets	$	659									$	133

The fair values of the financial instruments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset or liability.  Those judgments are developed by the Company based on the best information available in the circumstances.

In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of ASU No. 2009-12, “Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for which the investment does not have a readily determinable fair value, using net asset value per share or its equivalent as a practical expedient.

36

The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2010 and 2009.

Equity securities, equity index funds and U.S. Treasury fixed income securities (Level 1).  Valued at the closing price reported on the active market on which the individual securities are traded.

Fixed income securities, equity securities, pooled securities and mutual funds (Level 2).  Fixed income securities, other than those issued by the U.S. Treasury, are valued based on yields currently available on comparable securities of issuers with similar credit ratings. Equity securities and pooled and mutual funds include commingled equity funds and other closed funds, respectively, that are not open to public investment and are valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses.

Other (Level 3).  The venture capital and limited partnership interests are valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.

For 2010 and 2009, the changes in Level 3 assets were as follows:

	2010						2009
(in thousands)	Pension benefits			Other benefits			Pension benefits		Other benefits
Balance, January 1	$	67,420		$	13,703		$	49,641	$	12,713
Realized and unrealized gains	6,650			1,445			15,132		3,301
Purchases and settlements, net	(317		)	(3,854		)	2,647		(2,311		)
Transfer in or out of Level 3	(73,612		)	(11,289		)	—		—
Balance, December 31	$	141		$	5		$	67,420	$	13,703

37

16.  Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2010
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassi- fications and Elimina- tions		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,240		5,108		3,016		—	—	—		$	51,364
Plant and equipment	2,984,887			1,030,520		881,567		—	—	—		4,896,974
Less accumulated depreciation	(1,134,423		)	(408,704	)	(397,932	)	—	—	—		(1,941,059		)
Construction in progress	78,934			9,828		12,800		—	—	—		101,562
Net utility plant	1,972,638			636,752		499,451		—	—	—		3,108,841
Investment in wholly owned subsidiaries, at equity	500,801			—		—		—	—	(500,801	)[2]	—
Current assets
Cash and equivalents	121,019			1,229		594		89	5	—		122,936
Advances to affiliates	—			30,950		29,500		—	—	(60,450	)[1]	—
Customer accounts receivable, net	93,474			23,484		21,213		—	—	—		138,171
Accrued unbilled revenues, net	71,712			16,018		16,654		—	—	—		104,384
Other accounts receivable, net	11,536			3,319		668		—	—	(6,147	)[1]	9,376
Fuel oil stock, at average cost	121,280			15,751		15,674		—	—	—		152,705
Materials & supplies, at average cost	18,890			4,498		13,329		—	—	—		36,717
Prepayments and other	36,974			9,825		8,417		—	—	—		55,216
Regulatory assets	5,294			1,064		991		—	—	—		7,349
Total current assets	480,179			106,138		107,040		89	5	(66,597	)	626,854
Other long-term assets
Regulatory assets	352,038			61,051		57,892		—	—	—		470,981
Unamortized debt expense	9,240			2,681		2,109		—	—	—		14,030
Other	41,236			8,257		15,481		—	—	—		64,974
Total other long-term assets	402,514			71,989		75,482		—	—	—		549,985
	$	3,356,132		814,879		681,973		89	5	(567,398	)	$	4,285,680
Capitalization and liabilities
Capitalization
Common stock equity	$	1,337,398		270,573		230,137		86	5	(500,801	)[2]	$	1,337,398
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	672,268			211,279		174,395		—	—	—		1,057,942
Total capitalization	2,031,959			488,852		409,532		86	5	(500,801	)	2,429,633
Current liabilities
Short-term borrowings-affiliate	60,450			—		—		—	—	(60,450	)[1]	—
Accounts payable	135,739			22,888		20,332		—	—	—		178,959
Interest and preferred dividends payable	13,648			4,196		2,762		—	—	(3	)[1]	20,603
Taxes accrued	116,840			31,229		27,891		—	—	—		175,960
Other	35,784			13,065		13,646		3	—	(6,144	)[1]	56,354
Total current liabilities	362,461			71,378		64,631		3	—	(66,597	)	431,876
Deferred credits and other liabilities
Deferred income taxes	198,753			44,971		25,562		—	—	—		269,286
Regulatory liabilities	201,587			56,190		39,020		—	—	—		296,797
Unamortized tax credits	33,661			12,857		12,292		—	—	—		58,810
Retirement benefits liability	271,499			39,811		44,534		—	—	—		355,844
Other	66,898			28,739		12,433		—	—	—		108,070
Total deferred credits and other liabilities	772,398			182,568		133,841		—	—	—		1,088,807
Contributions in aid of construction	189,314			72,081		73,969		—	—	—		335,364
	$	3,356,132		814,879		681,973		89	5	(567,398	)	$	4,285,680

38

Consolidating balance sheet

	December 31, 2009
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassi- fications and Elimina- tions		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,075		5,109		4,346		—	—	—		$	52,530
Plant and equipment	2,833,296			995,585		867,376		—	—	—		4,696,257
Less accumulated depreciation	(1,081,441		)	(379,526	)	(387,449	)	—	—	—		(1,848,416		)
Construction in progress	115,644			10,920		6,416		—	—	—		132,980
Net utility plant	1,910,574			632,088		490,689		—	—	—		3,033,351
Investment in wholly owned subsidiaries, at equity	462,006			—		—		—	—	(462,006	)[2]	—
Current assets
Cash and equivalents	70,981			2,006		474		98	19	—		73,578
Advances to affiliates	20,100			—		11,000		—	—	(31,100	)[1]	—
Customer accounts receivable, net	89,365			24,502		19,419		—	—	—		133,286
Accrued unbilled revenues, net	58,022			13,648		12,606		—	—	—		84,276
Other accounts receivable, net	5,967			2,294		1,317		—	—	(1,129	)[1]	8,449
Fuel oil stock, at average cost	49,847			12,640		16,174		—	—	—		78,661
Materials & supplies, at average cost	18,378			4,006		13,524		—	—	—		35,908
Prepayments and other	10,163			4,268		2,614		—	—	(844	)[3]	16,201
Regulatory assets	4,918			995		936		—	—	—		6,849
Total current assets	327,741			64,359		78,064		98	19	(33,073	)	437,208
Other long-term assets
Regulatory assets	308,035			58,377		53,601		—	—	—		420,013
Unamortized debt expense	9,392			2,679		2,217		—	—	—		14,288
Other	47,502			9,718		16,312		—	—	—		73,532
Total other long-term assets	364,929			70,774		72,130		—	—	—		507,833
	$	3,065,250		767,221		640,883		98	19	(495,079	)	$	3,978,392
Capitalization and liabilities
Capitalization
Common stock equity	$	1,306,408		240,576		221,319		94	17	(462,006	)[2]	$	1,306,408
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	672,200			211,248		174,367		—	—	—		1,057,815
Total capitalization	2,000,901			458,824		400,686		94	17	(462,006	)	2,398,516
Current liabilities
Short-term borrowings-affiliate	11,000			20,100		—		—	—	(31,100	)[1]	—
Accounts payable	103,073			17,369		12,269		—	—	—		132,711
Interest and preferred dividends payable	14,186			4,088		2,954		—	—	(5	)[1]	21,223
Taxes accrued	101,288			31,274		24,374		—	—	(844	)[3]	156,092
Other	28,956			8,670		11,684		4	2	(1,124	)[1]	48,192
Total current liabilities	258,503			81,501		51,281		4	2	(33,073	)	358,218
Deferred credits and other liabilities
Deferred income taxes	141,160			25,984		13,459		—	—	—		180,603
Regulatory liabilities	196,284			52,669		39,261		—	—	—		288,214
Unamortized tax credits	31,393			12,886		12,591		—	—	—		56,870
Retirement benefits liability	221,311			35,584		39,728		—	—	—		296,623
Other	36,113			30,207		11,484		—	—	—		77,804
Total deferred credits and other liabilities	626,261			157,330		116,523		—	—	—		900,114
Contributions in aid of construction	179,585			69,566		72,393		—	—	—		321,544
	$	3,065,250		767,221		640,883		98	19	(495,079	)	$	3,978,392

39

Consolidating statement of income

	Year ended December 31, 2010
(in thousands)		HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions		HECO Consolidated
Operating revenues		$	1,649,608		372,633		345,200		—		—		—		$	2,367,441
Operating expenses
Fuel oil		631,159			93,480		175,769		—		—		—		900,408
Purchased power		412,382			113,031		23,387		—		—		—		548,800
Other operation		180,095			34,273		36,659		—		—		—		251,027
Maintenance		76,792			23,800		26,895		—		—		—		127,487
Depreciation		86,932			36,483		26,293		—		—		—		149,708
Taxes, other than income taxes		155,084			34,664		32,369		—		—		—		222,117
Income taxes		32,307			10,341		5,405		—		—		—		48,053
		1,574,751			346,072		326,777		—		—		—		2,247,600
Operating income		74,857			26,561		18,423		—		—		—		119,841
Other income
Allowance for equity funds used during construction		4,956			507		553		—		—		—		6,016
Equity in earnings of subsidiaries		25,600			—		—		—		—		(25,600	)[2]	—
Other, net		9,190			2,356		231		(8	)	(12	)	(78	)[1]	11,679
		39,746			2,863		784		(8	)	(12	)	(25,678	)	17,695
Interest and other charges
Interest on long-term debt		36,522			11,938		9,072		—		—		—		57,532
Amortization of net bond premium and expense		1,942			537		496		—		—		—		2,975
Other interest charges		553			65		463		—		—		(78	)[1]	1,003
Allowance for borrowed funds used during construction		(2,083		)	(258	)	(217	)	—		—		—		(2,558		)
		36,934			12,282		9,814		—		—		(78	)	58,952
Net income (loss)		77,669			17,142		9,393		(8	)	(12	)	(25,600	)	78,584
Preferred stock of subsidiaries		—			534		381		—		—		—		915
Net income (loss) attributable to HECO		77,669			16,608		9,012		(8	)	(12	)	(25,600	)	77,669
Preferred stock dividends of HECO		1,080			—		—		—		—		—		1,080
Net income (loss) for common stock		$	76,589		16,608		9,012		(8	)	(12	)	(25,600	)	$	76,589

40

Consolidating statement of income

	Year ended December 31, 2009
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions		HECO Consolidated
Operating revenues	$	1,384,885		343,943		297,844		—		—		—		$	2,026,672
Operating expenses
Fuel oil	460,070			74,403		137,497		—		—		—		671,970
Purchased power	367,110			112,640		20,054		—		—		—		499,804
Other operation	174,573			36,998		36,944		—		—		—		248,515
Maintenance	65,910			21,391		20,230		—		—		—		107,531
Depreciation	82,031			33,005		29,497		—		—		—		144,533
Taxes, other than income taxes	131,367			32,219		28,113		—		—		—		191,699
Income taxes	32,538			9,527		6,147		—		—		—		48,212
	1,313,599			320,183		278,482		—		—		—		1,912,264
Operating income	71,286			23,760		19,362		—		—		—		114,408
Other income
Allowance for equity funds used during construction	9,945			1,621		656		—		—		—		12,222
Equity in earnings of subsidiaries	25,825			—		—		—		—		(25,825	)[2]	—
Other, net	6,591			1,126		350		(11	)	(149	)	(420	)[1]	7,487
	42,361			2,747		1,006		(11	)	(149	)	(26,245	)	19,709
Interest and other charges
Interest on long-term debt	33,109			9,639		9,072		—		—		—		51,820
Amortization of net bond premium and expense	2,174			602		478		—		—		—		3,254
Other interest charges	2,135			673		482		—		—		(420	)[1]	2,870
Allowance for borrowed funds used during construction	(4,297		)	(702	)	(269	)	—		—		—		(5,268		)
	33,121			10,212		9,763		—		—		(420	)	52,676
Net income (loss)	80,526			16,295		10,605		(11	)	(149	)	(25,825	)	81,441
Preferred stock dividends of subsidiaries	—			534		381		—		—		—		915
Net income (loss) attributable to HECO	80,526			15,761		10,224		(11	)	(149	)	(25,825	)	80,526
Preferred stock dividends of HECO	1,080			—		—		—		—		—		1,080
Net income (loss) for common stock	$	79,446		15,761		10,224		(11	)	(149	)	(25,825	)	$	79,446

41

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
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		)
	33,627			9,546		9,761		—		—		(1,918	)	51,016
Net income (loss)	93,055			20,175		18,173		(77	)	(347	)	(37,009	)	93,970
Preferred stock of subsidiaries	—			534		381		—		—		—		915
Net income (loss) attributable to HECO	93,055			19,641		17,792		(77	)	(347	)	(37,009	)	93,055
Preferred stock dividends of HECO	1,080			—		—		—		—		—		1,080
Net income (loss) for common stock	$	91,975		19,641		17,792		(77	)	(347	)	(37,009	)	$	91,975

42

Consolidating Statements of Changes in Common Stock Equity

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and Eliminations		HECO consolidated
Balance, December 31, 2007	$	1,110,462		201,820		208,521		182		388		(410,911	)	$	1,110,462
Comprehensive income:
Net income (loss) for common stock	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 credit 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 assets, net of tax benefits 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
Comprehensive income:
Net income (loss) for common stock	79,446			15,761		10,224		(11	)	(149	)	(25,825	)	79,446
Retirement benefit plans:
Net transition asset arising during the period, net of taxes of $4,172	6,549			—		—		—		—		—		6,549
Prior service credit arising during the period, net of taxes of $922	1,446			—		—		—		—		—		1,446
Net gains arising during the period, net of taxes of $36,990	58,081			9,942		6,928		—		—		(16,870	)	58,081
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 $6,250	9,811			1,601		1,325		—		—		(2,926	)	9,811
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,251	(75,756		)	(11,531	)	(8,276	)	—		—		19,807		(75,756		)
Comprehensive income (loss)	79,577			15,773		10,201		(11	)	(149	)	(25,814	)	79,577
Issuance of common stock, net of expenses	92,989			3,398		—		—		25		(3,423	)	92,989
Common stock dividends	(55,000		)	—		(4,264	)	—		—		4,264		(55,000		)
Balance, December 31, 2009	1,306,408			240,576		221,319		94		17		(462,006	)	1,306,408
Comprehensive income:
Net income (loss) for common stock	76,589			16,608		9,012		(8	)	(12	)	(25,600	)	76,589
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of $3,001	4,712			2,679		2,033		—		—		(4,712	)	4,712
Net gains arising during the period, net of tax benefits of $27,408	(43,031		)	(6,131	)	(5,601	)	—		—		11,732		(43,031		)
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 $2,387	3,747			759		566		—		—		(1,325	)	3,747
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $21,336	33,499			2,617		2,959		—		—		(5,576	)	33,499
Comprehensive income (loss)	75,516			16,532		8,969		(8	)	(12	)	(25,481	)	75,516
Issuance of common stock, net of expenses	4,243			22,948		2,850		—		—		(25,798	)	4,243
Common stock dividends	(48,769		)	(9,483	)	(3,001	)	—		—		12,484		(48,769		)
Balance, December 31, 2010	$	1,337,398		270,573		230,137		86		5		(500,801	)	$	1,337,398

43

Consolidating statement of cash flows

	Year ended December 31, 2010
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	77,669		17,142		9,393		(8	)	(12	)	(25,600	)[2]	$	78,584
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings	(25,700		)	—		—		—		—		25,600	[2]	(100		)
Common stock dividends received from subsidiaries	12,584			—		—		—		—		(12,484	)[2]	100
Depreciation of property, plant and equipment	86,932			36,483		26,293		—		—		—		149,708
Other amortization	4,958			3,410		(643	)	—		—		—		7,725
Changes in deferred income taxes	62,089			20,939		12,657		—		—		—		95,685
Changes in tax credits, net	2,796			100		(55	)	—		—		—		2,841
Allowance for equity funds used during construction	(4,956		)	(507	)	(553	)	—		—		—		(6,016		)
Decrease in cash overdraft	—			—		(141	)	—		—		—		(141		)
Changes in assets and liabilities:
Increase in accounts receivable	(9,678		)	(7	)	(1,145	)	—		—		5,018	[1]	(5,812		)
Increase in accrued unbilled revenues	(13,690		)	(2,370	)	(4,048	)	—		—		—		(20,108		)
Decrease (increase) in fuel oil stock	(71,433		)	(3,111	)	500		—		—		—		(74,044		)
Decrease (increase) in materials and supplies	(512		)	(492	)	195		—		—		—		(809		)
Increase in regulatory assets	(812		)	(1,652	)	(472	)	—		—		—		(2,936		)
Increase in accounts payable	21,378			1,438		2,576		—		—		—		25,392
Changes in prepaid and accrued income taxes and revenue taxes	(8,647		)	(22	)	(1,501	)	—		—		—		(10,170		)
Changes in other assets and liabilities	17,006			(4,919	)	824		(1	)	(2	)	(5,018	)[2]	7,890
Net cash provided by (used in) operating activities	149,984			66,432		43,880		(9	)	(14	)	(12,484	)	247,789
Cash flows from investing activities:
Capital expenditures	(112,448		)	(35,146	)	(26,750	)	—		—		—		(174,344		)
Contributions in aid of construction	14,030			6,359		2,166		—		—		—		22,555
Advances from (to) affiliates	20,100			(30,950	)	(18,500	)	—		—		29,350	[1]	—
Other	1,327			—		—		—		—		—		1,327
Investment in consolidated subsidiary	(25,800		)	—		—		—		—		25,800	[2]	—
Net cash used in investing activities	(102,791		)	(59,737	)	(43,084	)	—		—		55,150		(150,462		)
Cash flows from financing activities:
Common stock dividends	(48,769		)	(9,483	)	(3,001	)	—		—		12,484	[2]	(48,769		)
Preferred stock dividends of HECO and subsidiaries	(1,080		)	(534	)	(381	)	—		—		—		(1,995		)
Proceeds from issuance of common stock	4,250			22,950		2,850		—		—		(25,800	)[2]	4,250
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	49,450			(20,100	)	—		—		—		(29,350	)[1]	—
Other	(1,006		)	(305	)	(144	)	—		—		—		(1,455		)
Net cash provided by (used in) financing activities	2,845			(7,472	)	(676	)	—		—		(42,666	)	(47,969		)
Net increase (decrease) in cash and cash equivalents	50,038			(777	)	120		(9	)	(14	)	—		49,358
Cash and cash equivalents, beginning of year	70,981			2,006		474		98		19		—		73,578
Cash and cash equivalents, end of year	$	121,019		1,229		594		89		5		—		$	122,936

44

Consolidating statement of cash flows

	Year ended December 31, 2009
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income	$	80,526		16,295		10,605		(11	)	(149	)	(25,825	)[2]	$	81,441
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings	(25,925		)	—		—		—		—		25,825	[2]	(100		)
Common stock dividends received from subsidiaries	4,364			—		—		—		—		(4,264	)[2]	100
Depreciation of property, plant and equipment	82,031			33,005		29,497		—		—		—		144,533
Other amortization	4,177			3,421		2,447		—		—		—		10,045
Changes in deferred income taxes	6,539			6,236		1,987		—		—		—		14,762
Changes in tax credits, net	(464		)	(443	)	(425	)	—		—		—		(1,332		)
Allowance for equity funds used during construction	(9,945		)	(1,621	)	(656	)	—		—		—		(12,222		)
Changes in assets and liabilities:
Decrease in accounts receivable	18,375			7,529		4,997		—		11		1,693	[1]	32,605
Decrease in accrued unbilled revenues	16,635			4,228		1,405		—		—		—		22,268
Decrease (increase) in fuel oil stock	3,699			(2,314	)	(2,331	)	—		—		—		(946		)
Decrease (increase) in materials and supplies	(1,795		)	360		59		—		—		—		(1,376		)
Increase in regulatory assets	(9,542		)	(3,860	)	(4,195	)	—		—		—		(17,597		)
Increase (decrease) in accounts payable	18,835			(10,426	)	1,308		—		—		—		9,717
Changes in prepaid and accrued income taxes and revenue taxes	(43,210		)	(6,759	)	(11,982	)	—		—		—		(61,951		)
Changes in other assets and liabilities	15,730			(12,028	)	(4,562	)	(14	)	(4	)	(1,693	)[2]	(2,571		)
Net cash provided by (used in) operating activities	160,030			33,623		28,154		(25	)	(142	)	(4,264	)	217,376
Cash flows from investing activities:
Capital expenditures	(208,904		)	(65,976	)	(27,447	)	—		—		—		(302,327		)
Contributions in aid of construction	5,348			7,061		1,761		—		—		—		14,170
Advances from (to) affiliates	38,500			—		1,000		—		—		(39,500	)[1]	—
Other	221			—		—		—		119		—		340
Investment in consolidated subsidiary	(25		)	—		—		—		—		25	[2]	—
Net cash provided by (used in) investing activities	(164,860		)	(58,915	)	(24,686	)	—		119		(39,475	)	(287,817		)
Cash flows from financing activities:
Common stock dividends	(55,000		)	—		(4,264	)	—		—		4,264	[2]	(55,000		)
Preferred stock dividends of HECO and subsidiaries	(1,080		)	(534	)	(381	)	—		—		—		(1,995		)
Proceeds from issuance of long-term debt	90,000			63,186		—		—		—		—		153,186
Proceeds from issuance of common stock	61,914			—		—		—		25		(25	)[2]	61,914
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	(11,464		)	(38,500	)	—		—		—		39,500	[1]	(10,464		)
Increase (decrease) in cash overdraft	(9,847		)	—		302		—		—		—		(9,545		)
Other	(976		)	(2	)	—		—		—		—		(978		)
Net cash provided by (used in) financing activities	73,547			24,150		(4,343	)	—		25		43,739		137,118
Net increase (decrease) in cash and cash equivalents	68,717			(1,142	)	(875	)	(25	)	2		—		66,677
Cash and cash equivalents, January 1	2,264			3,148		1,349		123		17		—		6,901
Cash and cash equivalents, December 31	$	70,981		2,006		474		98		19		—		$	73,578

45

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:
Net income	$	93,055		20,175		18,173		(77	)	(347	)	(37,009	)[2]	$	93,970
Adjustments to reconcile net income 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
Changes in deferred income taxes	3,457			1,866		(1,441	)	—		—		—		3,882
Change in 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 taxes and 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	)	(10,965	)	245,008
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 of HECO and subsidiaries	(1,080		)	(534	)	(381	)	—		—		—		(1,995		)
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 decrease 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
Increase (decrease) in cash overdraft	1,266			—		(1	)	—		—		—		1,265
Net cash provided by (used in) financing activities	23,263			27,054		(8,667	)	—		100		(24,535	)	17,215
Net increase (decrease) in cash and cash equivalents	2,061			79		576		(75	)	(418	)	—		2,223
Cash and cash equivalents, beginning of year	203			3,069		773		198		435		—		4,678
Cash and cash equivalents, end of year	$	2,264		3,148		1,349		123		17		—		$	6,901

46

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 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.

17.  Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2010 and 2009 follows:

	Quarters ended								Year ended
2010	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues	$	546,712	$	582,094	$	622,223	$	616,412	$	2,367,441
Operating income	30,407		30,850		36,114		22,470		119,841
Net income for common stock (1)	18,052		17,642		21,980		18,915		76,589

	Quarters ended								Year ended
2009	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues	$	459,285	$	447,836	$	546,502	$	573,049	$	2,026,672
Operating income	20,249		21,023		36,650		36,486		114,408
Net income for common stock	14,132		15,495		26,514		23,305		79,446

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

(1)The fourth quarter of 2010 includes $6 million of interest income (net of taxes), due to a federal tax settlement.

47