HECO Exhibit 99.2

This report is filed as an exhibit to the Annual Report on Form 10-K filed by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) on February 19, 2013 (Form 10-K) and contains information concerning HECO and its subsidiaries that is incorporated by reference into the Form 10-K.  This report should be read in conjunction with the information in the Form 10-K and, by virtue of its incorporation by reference into the Form 10-K, is an integral part of the Form 10-K.

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Company, Inc. (HECO) and its subsidiaries (collectively, the Company) 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 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 described 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, defense and construction industries, decisions concerning the extent of the presence of the federal government and military in Hawaii, the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, unrest, conflict and the overthrow of governmental regimes in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);

·weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming, such as more severe storms and rising sea levels), including their impact on Company operations and the economy;

·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 the Company’s 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;

·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 (and potential disapproval of actual or proposed) 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 cables, 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 or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

·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 continued availability to the electric utilities of other cost recovery mechanisms, including the purchased power adjustment clauses (PPACs), revenue adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales;

·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 energy 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 its competitors;

·cyber security risks and the potential for cyber incidents, including potential incidents at the Company (including at the power plants) and incidents at data processing centers it uses, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls;

·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 (including resulting compliance costs and risks of fines and penalties), the regulation of greenhouse gas (GHG) emissions, 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 as a result of adverse regulatory audit reports or otherwise);

1

·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));

·ability to recover increasing costs and earn a reasonable return on 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 possible 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 the Company and the results of financing efforts;

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

·the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the Company’s transmission and distribution system and losses from business interruption) or underinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits); and

·other risks or uncertainties described elsewhere in this report (e.g., Item 1A. Risk Factors) and in other reports 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.

2

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

This section supplements, and must be read in conjunction with, 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) (HEI’s MD&A) included in the Form 10-K and in conjunction with HECO’s consolidated financial statements and accompanying notes (HECO’s Notes to Consolidated Financial Statements) set forth below.

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

December 31, 2012	Payments due by period
(in millions)	Less than 1 year	1-3 years	3-5 years	More than 5 years	Total
Long-term debt	$      -	$     11	$    -	$1,137	$1,148
Interest on long-term debt	59	116	116	799	1,090
Operating leases	7	14	9	16	46
Open purchase order obligations ¹	84	17	9	-	110
Fuel oil purchase obligations (estimatebased on December 31, 2012 fuel oil prices)	921	1,315	407	-	2,643
Purchase power obligations– minimum fixed capacity charges	118	249	195	693	1,255
Liabilities for uncertain tax positions	-	1	-	-	1
Total (estimated)	$1,189	$1,723	$736	$2,645	$6,293

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, 2012, 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, but retirement benefit plan obligations, including estimated minimum required contributions for 2013 are discussed in the section “Retirement benefits” in HEI’s MD&A in the Form 10-K and Note 10 (“Retirement benefits”) of HECO’s “Notes to Consolidated Financial Statements” (included below in this report).

See Note 11 of HECO’s Notes to Consolidated Financial Statements for a discussion of fuel and power purchase commitments.

Management believes that HECO’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retirement benefits 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, 2012.

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 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.

3

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.

See the section “Other than bank interest rate risk” in HEI’s “Quantitative and Qualitative Disclosures about Market Risk,” included in the Form 10-K 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	2012		2011		2010		2009		2008
(in thousands)
Results of operations
Operating revenues	$3,101,998		$2,973,764		$2,367,441		$2,026,672		$2,853,639
Operating expenses	2,930,021		2,818,529		2,247,600		1,912,264		2,723,702
Operating income	171,977		155,235		119,841		114,408		129,937
Other income (deductions)	(13,006	)	4,279		17,695		19,709		15,049
Interest and other charges	57,700		57,533		58,952		52,676		51,016
Net income	101,271		101,981		78,584		81,441		93,970
Preferred stock dividends of subsidiaries	915		915		915		915		915
Net income attributable to HECO	100,356		101,066		77,669		80,526		93,055
Preferred stock dividends of HECO	1,080		1,080		1,080		1,080		1,080
Net income for common stock	$    99,276		$    99,986		$    76,589		$    79,446		$   91,975
At December 31	2012		2011		2010		2009		2008
(in thousands)
Financial position*
Utility plant	$5,567,346		$5,242,379		$5,049,900		$4,881,767		$4,586,668
Accumulated depreciation	(2,040,789	)	(1,966,894	)	(1,941,059	)	(1,848,416	)	(1,741,453	)
Net utility plant	$3,526,557		$3,275,485		$3,108,841		$3,033,351		$2,845,215
Total assets	$5,108,793		$4,674,007		$4,287,745		$3,980,457		$3,858,174
Capitalization:1
Short-term borrowings
from non-affiliates and affiliate	$             –		$              –		$              –		$             –		$     41,550
Current portion of long-term debt	–		57,500		–		–		–
Long-term debt, net	1,147,872		1,000,570		1,057,942		1,057,815		904,501
Common stock equity	1,472,136		1,402,841		1,334,155		1,303,165		1,185,599
Cumulative preferred stock–notsubject to mandatory redemption	34,293		34,293		34,293		34,293		34,293
Total capitalization	$2,654,301		$2,495,204		$2,426,390		$2,395,273		$2,165,943
Capital structure ratios (%)1
Debt	43.2		42.4		43.6		44.2		43.7
Cumulative preferred stock	1.3		1.4		1.4		1.4		1.6
Common stock equity	55.5		56.2		55.0		54.4		54.7

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

* The Company has revised its previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years prior to 2008.  See “Reclassifications and revisions” in Note 1 of HECO’s “Notes to Consolidated Financial Statements.”

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 in HEI’s MD&A in the Form 10-K 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.

4

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 sheets and statements of capitalization as of December 31, 2012 and 2011 and the related consolidated statements of income, comprehensive income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2012 present fairly, in all material respects, the financial position of Hawaiian Electric Company and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 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 audits.  We conducted our audits 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 audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 19, 2013

5

Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2012		2011		2010
(in thousands)
Operating revenues	$3,101,998		$2,973,764		$2,367,441
Operating expenses
Fuel oil	1,297,419		1,265,126		900,408
Purchased power	724,240		689,652		548,800
Other operation	272,117		257,065		251,027
Maintenance	122,312		121,219		127,487
Depreciation	144,498		142,975		149,708
Taxes, other than income taxes	292,841		276,504		222,117
Income taxes	76,594		65,988		48,053
	2,930,021		2,818,529		2,247,600
Operating income	171,977		155,235		119,841
Other income (deductions)
Allowance for equity funds used during construction	7,007		5,964		6,016
Impairment of assets	(40,000	)	(9,215	)	–
Other, net	4,441		3,126		10,494
Income tax benefits	15,546		4,404		1,185
	(13,006	)	4,279		17,695
Interest and other charges
Interest on long-term debt	59,014		57,532		57,532
Amortization of net bond premium and expense	2,905		3,081		2,975
Other interest charges	136		(582	)	1,003
Allowance for borrowed funds used during construction	(4,355	)	(2,498	)	(2,558	)
	57,700		57,533		58,952
Net income	101,271		101,981		78,584
Preferred stock dividends of subsidiaries	915		915		915
Net income attributable to HECO	100,356		101,066		77,669
Preferred stock dividends of HECO	1,080		1,080		1,080
Net income for common stock	$    99,276		$     99,986		$    76,589

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

6

Consolidated Statements of Comprehensive Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2012			2011			2010
(in thousands)
Net income for common stock	$	99,276		$	99,986		$	76,589
Other comprehensive income (loss) net of taxes;
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of nil, $4,408 and $3,001 for 2012, 2011 and 2010, respectively	-			6,921			4,712
Net losses arising during the period, net of tax benefits of $57,375, $74,346 and $27,408 for 2012, 2011 and 2010, respectively	(90,082		)	(116,726		)	(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 $8,709, $5,332 and $2,387 for 2012, 2011 and 2010, respectively	13,673			8,372			3,747
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,069, $64,134 and $21,336 for 2012, 2011 and 2010, respectively	75,471			100,692			33,499
Other comprehensive loss, net of tax benefits	(938		)	(741		)	(1,073		)
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	98,338		$	99,245		$	75,516

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

7

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2012			2011
(in thousands)
Assets
Utility plant, at cost
Land	$	51,568		$	51,514
Plant and equipment	5,364,400			5,052,027
Less accumulated depreciation	(2,040,789		)	(1,966,894		)
Construction in progress	151,378			138,838
Net utility plant	3,526,557			3,275,485
Current assets
Cash and equivalents	17,159			48,806
Customer accounts receivable, net	210,779			183,328
Accrued unbilled revenues, net	134,298			137,826
Other accounts receivable, net	28,176			8,623
Fuel oil stock, at average cost	161,419			171,548
Materials and supplies, at average cost	51,085			43,188
Prepayments and other	32,865			36,667
Regulatory assets	51,267			20,283
Total current assets	687,048			650,269
Other long-term assets
Regulatory assets	813,329			649,106
Unamortized debt expense	10,554			12,786
Other	71,305			86,361
Total other long-term assets	895,188			748,253
	$	5,108,793		$	4,674,007
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,472,136		$	1,402,841
Cumulative preferred stock – not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (see Note 11)
Long-term debt, net	1,147,872			1,000,570
Total capitalization	2,654,301			2,437,704
Current liabilities
Current portion of long-term debt	–			57,500
Accounts payable	186,824			188,580
Interest and preferred dividends payable	21,092			19,483
Taxes accrued	251,066			230,076
Other	62,879			69,353
Total current liabilities	521,861			564,992
Deferred credits and other liabilities
Deferred income taxes	417,611			337,863
Regulatory liabilities	322,074			315,466
Unamortized tax credits	66,584			60,614
Retirement benefits liability	620,205			494,753
Other	100,637			106,412
Total deferred credits and other liabilities	1,527,111			1,315,108
Contributions in aid of construction	405,520			356,203
	$	5,108,793		$	4,674,007

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

8

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2012			2011			2010
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding:
2012, 14,665,264 shares, 2011, 14,233,723 shares,and 2010, 13,830,823 shares	$	97,788		$	94,911		$	92,224
Premium on capital stock	468,045			426,921			389,609
Retained earnings	907,273			881,041			851,613
Accumulated other comprehensive income (loss), net of taxes - retirement benefit plans	(970		)	(32		)	709
Common stock equity	1,472,136			1,402,841			1,334,155
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		ParValue	SharesoutstandingDecember 31,2012 and 2011	2012		2011
(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.

9

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2012		2011
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds (subsidiary obligationsunconditionally 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, paid in 2012	–		40,000
HECO, 5.70%, refunding series 2000, paid in 2012	–		46,000
MECO, 5.70%, refunding series 2000, paid in 2012	–		20,000
HECO, 6.15%, refunding series 1999D, paid in 2012	–		16,000
HELCO, 6.15%, refunding series 1999D, paid in 2012	–		3,000
MECO, 6.15%, refunding series 1999D, paid in 2012	–		1,000
HECO, 6.20%, series 1999C, paid in 2012	–		35,000
HECO, 5.75%, refunding series 1999B, paid in 2012	–		30,000
HELCO, 5.75%, refunding series 1999B, paid in 2012	–		11,000
MECO, 5.75%, refunding series 1999B, paid in 2012	–		9,000
HELCO, 5.50%, refunding series 1999A, due 2014	11,400		11,400
HECO, 4.95%, refunding series 1998A, paid in 2012	–		42,580
HELCO, 4.95%, refunding series 1998A, paid in 2012	–		7,200
MECO, 4.95%, refunding series 1998A, paid in 2012	–		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, paid in 2012	–		50,000
HELCO, 5.45%, series 1993, paid in 2012	–		20,000
MECO, 5.45%, series 1993, paid in 2012	–		30,000
Total obligations to the State of Hawaii	639,400		1,007,900
Other long-term debt – unsecured:
Taxable unsecured senior notes	457,000		–
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034	51,546		51,546
Total long-term debt	1,147,946		1,059,446
Less unamortized discount	74		1,376
Less current portion long-term debt	–		57,500
Long-term debt, net	1,147,872		1,000,570
Total capitalization	$	2,654,301	$	2,437,704

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

10

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, 2009	13,787	$91,931	$385,659	$823,793		$  1,782		$1,303,165
Net income for common stock	–	–	–	76,589		–		76,589
Other comprehensive loss, net of taxes	–	–	–	–		(1,073	)	(1,073	)
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	851,613		709		1,334,155
Net income for common stock	–	–	–	99,986		–		99,986
Other comprehensive loss, net of taxes	–	–	–	–		(741	)	(741	)
Issuance of common stock, net of expenses	403	2,687	37,312	–		–		39,999
Common stock dividends	–	–	–	(70,558	)	–		(70,558	)
Balance, December 31, 2011	14,234	94,911	426,921	881,041		(32	)	1,402,841
Net income for common stock	–	–	–	99,276		–		99,276
Other comprehensive loss, net of taxes	–	–	–	–		(938	)	(938	)
Issuance of common stock, net of expenses	431	2,877	41,124	–		–		44,001
Common stock dividends	–	–	–	(73,044	)	–		(73,044	)
Balance, December 31, 2012	14,665	$97,788	$468,045	$907,273		$   (970	)	$1,472,136

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

11

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2012		2011		2010
(in thousands)
Cash flows from operating activities
Net income	$101,271		$101,981		$ 78,584
Adjustments to reconcile net income to net cash provided byoperating activities
Depreciation of utility plant	144,498		142,975		149,708
Other amortization	6,998		17,378		7,725
Impairment of assets	40,000		9,215		–
Change in deferred income taxes	86,878		69,091		95,685
Change in tax credits, net	6,075		2,087		2,841
Allowance for equity funds used during construction	(7,007	)	(5,964	)	(6,016	)
Change in cash overdraft	–		(2,688	)	(141	)
Changes in assets and liabilities
Increase in accounts receivable	(47,004	)	(44,404	)	(5,812	)
Decrease (increase) in accrued unbilled revenues	3,528		(33,442	)	(20,108	)
Decrease (increase) in fuel oil stock	10,129		(18,843	)	(74,044	)
Increase in materials and supplies	(7,897	)	(6,471	)	(809	)
Increase in regulatory assets	(72,401	)	(40,132	)	(2,936	)
Increase (decrease) in accounts payable	(38,913	)	(35,815	)	25,392
Change in prepaid and accrued income taxes and revenue taxes	25,239		69,736		(10,170	)
Contributions to defined benefit pension and other postretirement benefit plans	(63,075	)	(73,176	)	(31,068	)
Change in other assets and liabilities	(11,088	)	9,866		38,958
Net cash provided by operating activities	177,231		161,394		247,789
Cash flows from investing activities
Capital expenditures	(310,091	)	(226,022	)	(174,344	)
Contributions in aid of construction	45,982		23,534		22,555
Other	–		77		1,327
Net cash used in investing activities	(264,109	)	(202,411	)	(150,462	)
Cash flows from financing activities
Common stock dividends	(73,044	)	(70,558	)	(48,769	)
Preferred stock dividends of HECO and subsidiaries	(1,995	)	(1,995	)	(1,995	)
Proceeds from issuance of common stock	44,000		40,000		4,250
Proceeds from issuance of long-term debt	457,000		–		–
Repayment of long-term debt	(368,500	)	–		–
Other	(2,230	)	(560	)	(1,455	)
Net cash provided by (used in) financing activities	55,231		(33,113	)	(47,969	)
Net increase (decrease) in cash and cash equivalents	(31,647	)	(74,130	)	49,358
Cash and cash equivalents, January 1	48,806		122,936		73,578
Cash and cash equivalents, December 31	$17,159		$48,806		$122,936

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

12

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 public electric 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) when 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 Company expects that its 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 also evaluated for OTTI. Also see Note 3 below.

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

13

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 88 years for production plant, from 25 to 65 years for transmission and distribution plant and from 5 to 50 years for general plant.  The composite annual depreciation rate, which includes a component for cost of removal, was 3.1% in 2012, 3.2% in 2011 and 3.5% in 2010.

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 $8 million, $6 million and $6 million in 2012, 2011 and 2010, respectively. Future minimum lease payments are $7 million, $8 million, $7 million, $5 million, $3 million and $16 million for 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

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. As of December 31, 2012 and 2011, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $2 million.

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 greater of the minimum level required under the law or net periodic pension cost less pension asset, until its pension asset (existing at the time of the PUC decision and determined based on the cumulative contributions to the plans 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 greater of the minimum level required under the law or net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions and the amortization of the regulatory asset for postretirement benefits other than pensions (OPEB), while maximizing the use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The Company must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC. 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.

14

Financing costs.  The Company uses the straight-line method, which approximates the effective interest 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 to 55 years as an offset against depreciation expense.

Electric utility revenues.  Electric utility revenues are based on rates authorized by the PUC. Prior to the implementation of decoupling, revenues related to the sale of energy were generally recorded when service was rendered or energy was delivered to customers and included revenues applicable to energy consumed in the accounting period but not yet billed to the customers.

The rate schedules of the electric utilities include energy cost adjustment clauses (ECACs) under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules also include purchased power adjustment clauses (PPACs) under which the remaining purchase power expenses are recovered through surcharge mechanisms. The amounts collected through the ECACs and PPACs are required to be reconciled quarterly.

Upon the implementation of decoupling (HECO on March 1, 2011, HELCO on April 9, 2012 and MECO on May 4, 2012), the electric utilities: (1) recognize monthly revenue balancing account (RBA) revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales, (2) recognize a revenue escalation component via a revenue adjustment mechanism (RAM) for certain O&M expenses and rate base changes, and (3) recognize (when applicable) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility’s ratemaking ROACE exceeds the ROACE allowed in its most recent rate case.

The Company’s operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. However, the Company’s revenue tax payments to the taxing authorities in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For 2012, 2011 and 2010, the Company included approximately $280 million, $264 million and $211 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 Accounting Standards Codification (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 are 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, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery.

15

The weighted-average AFUDC rate was 7.6% in 2012, 8.0% in 2011 and 8.1% in 2010, and reflected quarterly compounding.

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.  Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

Federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits, in accordance with Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”

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 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 costs to sell.

Recent accounting pronouncements and interpretations

Offsetting assets and liabilities.  In December 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities,” which requires disclosures about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement to enable financial statement users to understand the effect of those arrangements on the entity’s financial position. The Company believes that the adoption of ASU No 2011-11 will not have a material impact on its financial statement disclosures.

Reporting of Amounts Reclassified Out of AOCI.  In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires companies to provide information about the amounts reclassified out of AOCI by component and to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that

16

are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The Company will include the disclosures required by ASU No. 2013-02 its financial statement for the first quarter of 2013.

Reclassifications and revisions.  Certain reclassifications have been made to prior years’ financial statements to conform to the 2012 presentation, which did not affect previously reported results of operations.

The Company has revised its previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years prior to 2010. The Company determined the cumulative impact for periods prior to 2010 to be a charge to its earnings of $3.2 million. These adjustments were not considered to be material individually or in the aggregate to previously issued financial statements. The table below illustrates the effects of this revision on the Company’s Consolidated Financial Statements for those line items affected (these revisions have no impact on the Company’s Consolidated Statements of Income and Cash Flows for the periods reported):

(dollars in thousands)	As previously filed	As revised	Difference
December 31, 2011
Consolidated Balance Sheet
Prepayments and other	$     34,602	$      36,667	$ 2,065
Total current assets	648,204	650,269	2,065
Total assets	4,671,942	4,674,007	2,065
Retained earnings	884,284	881,041	(3,243)
Common stock equity	1,406,084	1,402,841	(3,243)
Total capitalization	2,440,947	2,437,704	(3,243)
Taxes accrued	224,768	230,076	5,308
Total current liabilities	559,684	564,992	5,308
Total capitalization and liabilities	4,671,942	4,674,007	2,065
Consolidated Statement of Changes in Common Stock Equity
Retained earnings	884,284	881,041	(3,243)
Common stock equity	1,406,084	1,402,841	(3,243)
December 31, 2010
Consolidated Statement of Changes in Common Stock Equity
Retained earnings	854,856	851,613	(3,243)
Common stock equity	1,337,398	1,334,155	(3,243)
December 31, 2009
Consolidated Statement of Changes in Common Stock Equity
Retained earnings	827,036	823,793	(3,243)
Common stock equity	1,306,408	1,303,165	(3,243)

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, 2012	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.

17

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 HELCO and MECO each in the principal amount 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.  Taken together, HECO’s obligations under the HECO debentures, the HECO indenture, the subsidiary guarantees, the trust agreement, the expense agreement and trust guarantee provide, in aggregate, a full, irrevocable and unconditional guarantee of payments of amounts due on the Trust Preferred Securities. 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, 2012 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 2012 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Power purchase agreements.  As of December 31, 2012, the Company had six PPAs for 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 90% of firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPower. Purchases from all IPPs for 2012 totaled $724 million with purchases from AES Hawaii, Kalaeloa, HEP and HPower totaling $146 million, $310 million, $65 million and $65 million, respectively.

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”, 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 2012, the Company sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its 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 remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Company’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on the Company’s

18

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 the Company determines it is required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Company 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 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.  As of December 31, 2012, HECO’s accounts payable to Kalaeloa amounted to $23 million.

4.  Long-term debt

On April 19, 2012, HECO, MECO and HELCO issued through a private placement taxable unsecured senior notes (the HECO Notes, MECO Notes and HELCO Notes, and together, the Notes) in the aggregate principal amounts of $327 million, $59 million and $31 million, respectively, as follows:

(in thousands)
Long-term debt
HECO, 3.79%, series 2012A, due 2018	$	30,000
HELCO, 3.79%, series 2012A, due 2018	11,000
MECO, 3.79%, series 2012A, due 2018	9,000
HECO, 4.03%, series 2012B, due 2020	62,000
MECO, 4.03%, series 2012B, due 2020	20,000
HECO, 4.55%, series 2012C, due 2023	50,000
HELCO, 4.55%, series 2012B, due 2023	20,000
MECO, 4.55%, series 2012C, due 2023	30,000
HECO, 4.72%, series 2012D, due 2029	35,000
HECO, 5.39%, series 2012E, due 2042	150,000
Long-term debt	$	417,000

All proceeds of the Notes, except the Series 2012E of the HECO Notes, have been applied ($267 million in the aggregate), together with such additional funds as are required, to redeem special purpose revenue bonds and refunding special purpose revenue bonds issued by the Department of Budget and Finance (DBF) of the State of

19

Hawaii for the benefit of the utilities, which outstanding bonds have an aggregate principal amount of $271 million and stated interest rates ranging from 5.45% to 6.20%.

On September 13, 2012 HECO entered into a Note Purchase Agreement (the Note Agreement), pursuant to which HECO issued, through a private placement, its 4.53% Senior Notes, Series 2012F (to mature September 1, 2032), in the principal amount of $40 million.  The notes are unsecured and interest payable on the notes is taxable.  All proceeds of the notes have been applied, together with additional funds provided by HECO to redeem the $40 million aggregate principal amount 5.10% Series 2002A (year of maturity 2032) SPRBs issued by the DBF for the benefit of HECO.

The Company’s senior notes contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes of each and all of the utilities then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HECO, and each of HELCO and MECO, of certain financial ratios generally consistent with those in HECO’s existing amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million.

At December 31, 2012, the aggregate payments of principal required on long-term debt are nil in 2013, $11 million in 2014, and nil in 2015, 2016, and 2017.

5.  Short-term borrowings

There were no short-term borrowings from non-affiliates at December 31, 2012 and 2011.

At December 31, 2012 and 2011, the Company maintained syndicated credit facilities of $175 million.  HECO had no borrowings under its facilities in 2012 or 2011. The facility is not collateralized. See Note 13, “Related-party transactions,” concerning borrowings from affiliates.

Credit agreement.  Effective December 5, 2011, HECO and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of HECO’s $175 million line of credit facility (with a letter of credit sub-facility). The credit agreement, as amended, has a term which expires on December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 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 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. 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 contains customary conditions that must be met in order to draw on the credit facility, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for HELCO and 43% for MECO as of December 31, 2012, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 55% as of December 31, 2012, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

The 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 expenditures, working capital and general corporate purposes.

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

20

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 financial condition, results of operations and/or liquidity may result if regulatory assets have to be charged to expense 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, 2012, if different.

Regulatory assets were as follows:

December 31	2012	2011
(in thousands)
Retirement benefit plans (balance primarily varies with plans’ funded statuses)	$660,835	$523,640
Income taxes, net (1 to 55 years)	84,931	83,386
Decoupling revenue balancing account (1 to 2 years)	66,076	20,780
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 2 to 20 years remaining)	17,130	12,267
Vacation earned, but not yet taken (1 year)	8,493	8,161
Postretirement benefits other than pensions (18 years; 1 year remaining)	249	1,861
Other (1 to 50 years; 1 to 47 years remaining)	26,882	19,294
	$864,596	$669,389
Included in:
Current assets	51,267	20,283
Long-term assets	813,329	649,106
	$864,596	$669,389

Regulatory liabilities were as follows:

December 31	2012	2011
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$305,978	$294,817
Retirement benefit plans (5 years beginning with respective utility’s next rate case; primarily 5 years remaining)	15,563	20,000
Other (5 years; 1 to 2 years remaining)	533	649
	$322,074	$315,466

The regulatory asset and liability relating to retirement benefit plans was recorded 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).

21

7.  Income taxes

The components of income taxes attributable to net income were as follows:

Years ended December 31	2012		2011		2010
(in thousands)
Federal:
Current	$(26,965	)	$(10,819	)	$(40,780	)
Deferred	79,437		64,645		83,472
Deferred tax credits, net	186		–		(901	)
	52,658		53,826		41,791
State:
Current	(4,940	)	1,226		(10,879	)
Deferred	7,441		4,445		13,114
Deferred tax credits, net	5,889		2,087		2,840
	8,390		7,758		5,075
Total	$61,048		$61,584		$46,866

Total income tax expense incorporates the income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income. These tax benefits amounted to $15.5 million, $4.4 million and $1.2 million for 2012, 2011 and 2010, respectively.

A reconciliation of 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	2012			2011			2010
(in thousands)
Amount at the federal statutory income tax rate	$	56,812		$	57,248		$	43,908
Increase (decrease) resulting from:
State income taxes on operating income, net of effect on federal income taxes	5,453			5,042			3,300
Other	(1,217		)	(706		)	(342		)
Total	$	61,048		$	61,584		$	46,866
Effective income tax rate	37.6		%	37.7		%	37.4		%

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

December 31	2012		2011
(in thousands)
Deferred tax assets:
Other	$	20,399	$	13,295
	20,399		13,295
Deferred tax liabilities:
Property, plant and equipment	315,409		254,105
Change in accounting method related to repairs	69,514		48,566
Regulatory assets, excluding amounts attributable to property, plant and equipment	33,071		32,343
Retirement benefits	8,688		2,976
Other	11,328		13,168
	438,010		351,158
Net deferred income tax liability	$	417,611	$	337,863

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 substantially all of the benefits of the deferred tax assets. In 2012, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation (resulting from the 2010 Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act).

22

HECO and subsidiaries are included in the consolidated federal and Hawaii income tax returns of HEI and are subject to the provisions of HEI’s tax sharing agreement, which determines each subsidiary’s (or subgroup) income tax return liabilities and refunds on a standalone basis as if it filed a separate return (or subgroup consolidated return).  Consequently, although HEI consolidated does not expect any unutilized net operating loss (NOL) as of December 31, 2012, standalone HECO consolidated expects an $18 million NOL for federal tax purposes in accordance with the HEI tax sharing agreement. The deferred tax asset associated with this NOL is included in “Deferred tax assets-Other.”

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 Internal Revenue Service (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 2012, 2011 and 2010, credit adjustments to interest expense on income taxes was reflected in “Interest and other charges” in the amount of $0.5 million, $1.0 million and $1.3 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 2012 and 2011, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and preferred dividends payable” was de minimis and $0.3 million, respectively.

As of December 31, 2012 and 2011, the total amount of liability for uncertain tax positions of $0.4 million and $3.7 million, respectively, if recognized, would not affect the Company’s effective tax rate. The Company’s unrecognized tax benefits are primarily the result of temporary differences relating to the deductibility of costs incurred to repair generation property.  The Company believes that it is reasonably possible that the IRS may issue guidance on the deductibility of these repair costs and this guidance will eliminate much of the uncertainty in 2013.

The changes in total unrecognized tax benefits were as follows:

Years ended December 31	2012		2011
(in millions)
Unrecognized tax benefits, January 1	$ 3.7		$ 14.2
Additions based on tax positions taken during the year	0.3		–
Reductions based on tax positions taken during the year	–		(0.6	)
Reductions for tax positions of prior years	(3.6	)	(8.8	)
Settlements	–		–
Lapses of statute of limitations	–		(1.1	)
Unrecognized tax benefits, December 31	$ 0.4		$  3.7

The 2012 reduction in unrecognized tax benefits was primarily due to the IRS’s acceptance of the deductibility of cost of repairs to utility generation property for tax years 2007-2009.  The 2011 reduction in unrecognized tax benefits was primarily due to the IRS’s issuance of guidance (Revenue Procedure 2011-43, issued in August 2011) on the deductibility of costs of repairs to utility transmission and distribution (T&D) property, including a “safe harbor” method under which taxpayers could transition and minimize the uncertainty of the repairs expense deduction for T&D property.  The Company elected the “safe harbor” method in its 2011 tax return, which resulted in the reduction of associated unrecognized tax benefits for 2011.

The IRS is currently auditing tax years 2010 to 2011. Tax years 2007 to 2011 remain subject to examination by the Department of Taxation of the State of Hawaii.

As of December 31, 2012, 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 liquidity.

23

8.  Cash flows

(in millions)	2012		2011		2010
Supplemental disclosures of cash flow information
Interest paid to non-affiliates	$57		$58		$56
Income taxes paid/(refunded)	(3	)	(23	)	(7	)
Supplemental disclosures of noncash activities
AFUDC-equity	7		6		6
Estimated fair value of noncash contributions in aid of construction	10		7		7
Unpaid invoices and other	37		45		21

9.  Major customers

HECO and its subsidiaries received approximately 11% ($349 million), 11% ($316 million) and 10% ($242 million) of their operating revenues from the sale of electricity to various federal government agencies in 2012, 2011 and 2010, 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 Supplemental Plan for directors 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). Eligibility of employees and dependents are based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility  for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible to receive benefits from the HEI/HECO Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.

The executive death benefit plan was frozen on September 10, 2009 to participants and benefit levels as of that date. The electric discount was eliminated for management employees and retirees of HECO in August 2009,

24

HELCO in November 2010, and MECO in August 2010, and for bargaining unit employees and retirees on January 31, 2011 per the collective bargaining agreement. 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.

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 each of 2012 and 2011) 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 Company has reclassified to a regulatory asset charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge to AOCI of $124 million pretax and $165 million pretax for 2012 and 2011, respectively).

In 2007, 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 2007, the PUC declined to 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 (and has been, in the case of MECO) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2012 HECO’s pension asset had been reduced to $2 million.

The OPEB tracking mechanisms generally require the Company 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 2012, 2011 and 2010 was $32 million, $34 million and $39 million, respectively.

Retirement benefit plan changes.  On March 11, 2011, the Company’s bargaining unit employees ratified a new benefit agreement, which included changes to retirement benefits. Changes to retirement benefits for employees commencing employment after April 30, 2011 include a modified defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries) (with a lower payment formula than the formula in the plan for employees hired before May 1, 2011) and the addition of a 50% match by the applicable employer on the first 6% of employee elective deferrals by such employees through the defined contribution plan

25

(under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP)). In addition, new eligibility rules and contribution levels applicable to existing and new employees were adopted for postretirement welfare benefits.In general, defined pension benefits are based on the employees’ years of service and compensation.

Defined benefit 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 2012 and 2011 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, 2012 and 2011 were as follows:

	2012		2011
(in thousands)	Pension benefits	Other benefits	Pension benefits	Other benefits
Benefit obligation, January 1	$1,203,943	$184,240	$1,072,404	$174,745
Service cost	41,603	4,014	33,627	4,238
Interest cost	61,453	8,703	59,077	9,228
Amendments	–	–	–	(11,329)
Actuarial losses (gains)	197,718	(2,301)	91,539	16,137
Benefits paid and expenses	(55,272)	(7,546)	(52,704)	(8,779)
Benefit obligation, December 31	1,449,445	187,110	1,203,943	184,240
Fair value of plan assets, January 1	752,285	140,764	742,080	148,868
Actual return (loss) on plan assets	103,941	18,206	(8,711)	(2,286)
Employer contributions	60,442	2,634	71,246	1,930
Benefits paid and expenses	(54,890)	(7,418)	(52,330)	(7,748)
Fair value of plan assets, December 31	861,778	154,186	752,285	140,764
Accrued benefit liability, December 31	(587,667)	(32,924)	(451,658)	(43,476)
AOCI, January 1 (excluding impact of PUC D&Os)	488,556	27,390	341,697	8,209
Recognized during year – net recognized transition asset	–	9	–	8
Recognized during year – prior service credit	689	1,803	747	1,505
Recognized during year – net actuarial losses	(23,428)	(1,455)	(15,752)	(212)
Occurring during year – prior service cost	–	–	–	(11,329)
Occurring during year – net actuarial losses (gains)	157,771	(10,315)	161,864	29,209
	623,588	17,432	488,556	27,390
Cumulative impact of PUC D&Os	(621,310)	(18,123)	(486,710)	(29,183)
AOCI, December 31	2,278	(691)	1,846	(1,793)
Net actuarial loss	623,904	35,141	489,561	46,911
Prior service gain	(316)	(17,709)	(1,005)	(19,513)
Net transition obligation	–	–	–	(8)
	623,588	17,432	488,556	27,390
Cumulative impact of PUC D&Os	(621,310)	(18,123)	(486,710)	(29,183)
AOCL(AOCI), December 31	2,278	(691)	1,846	(1,793)
Income taxes (benefits)	(886)	269	(719)	698
AOCL(AOCI), net of taxes (benefits), December 31	$    1,392	$    (422)	$    1,127	$  (1,095)

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2012, 2011 and 2010.

The defined benefit pension plans with accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), in excess of plan assets as of December 31, 2012 and 2011, had aggregate ABOs of $1.2 billion and $1.1 billion, respectively, and plan assets of $862 million and $752 million, respectively.

On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding and administration of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to apply MAP-21 for 2012, which reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1,

26

2011 to September 30, 2012) for HECO and its subsidiaries. If the Adjusted Funding Target Attainment Percentage falls below 80% in the future, the restrictions on accelerated distribution options may apply again.

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. The HEI Retirement Plan fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

The Company estimates that the cash funding for the qualified defined benefit pension plan in 2013 will be $83 million, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanisms and the Plan’s funding policy. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2013 is $84 million.

As of December 31, 2012, the benefits expected to be paid under all retirement benefit plans in 2013, 2014, 2015, 2016, 2017 and 2018 through 2022 amounted to $65 million, $67 million, $69 million, $71 million, $74 million and $420 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 NPBC.

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	2012		2011		Target		Range	2012		2011		Target		Range
Asset category
Equity securities	69	%	68	%	70	%	65-75%	70	%	69	%	70	%	65-75%
Fixed income	31		32		30		25-35%	30		31		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	2012	2011	2010	2012	2011	2010
Benefit obligationDiscount rate	4.13%	5.19%	5.68%	4.07%	4.90%	5.60%
Rate of compensation increase	3.5	3.5	3.5	NA	NA	NA
Net periodic benefit cost (years ended)Discount rate	5.19	5.68	6.50	4.90	5.60	6.50
Expected return on plan assets	7.75	8.00	8.25	7.75	8.00	8.25
Rate of compensation increase	3.5	3.5	3.5	NA	NA	NA

NA Not applicable

The Company based its selection of an assumed discount rate for 2012 NPBC and December 31, 2011 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, 2011. In selecting the expected rate of return on plan assets of 7.75% for 2012 NPBC, the Company considered economic forecasts for the types of

27

investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations, industry and corporate surveys and the past performance of the plans’ assets.

As of December 31, 2012, the assumed health care trend rates for 2013 and future years were as follows: medical, 8%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2011, the assumed health care trend rates for 2012 and future years were as follows: medical, 8.5%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%.  Medicare Advantage reimbursements are expected to phase out by 2016; therefore, post age 65 medical trends are adjusted to reflect anticipated increases above the ordinary medical trend rates.  For post age 65, the medical trend is 4% higher than pre-65 for 2012 through 2014 and 3% higher in 2015.

The components of NPBC were as follows:

	Pension benefits			Other benefits
(in thousands)	2012	2011	2010	2012	2011	2010
Service cost	$41,603	$33,627	$27,576	$4,014	$4,238	$4,584
Interest cost	61,453	59,077	58,868	8,703	9,228	10,080
Expected return on plan assets	(64,004)	(61,615)	(61,491)	(10,195)	(10,508)	(10,960)
Amortization of net transition obligation	–	–	–	(9)	(8)	(8)
Amortization of net prior service gain	(689)	(747)	(747)	(1,803)	(1,505)	(409)
Amortization of net actuarial loss	23,428	15,752	7,300	1,455	212	–
Net periodic benefit cost	61,791	46,094	31,506	2,165	1,657	3,287
Impact of PUC D&Os	(15,754)	(3,516)	10,207	(2,227)	2,674	5,400
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$46,037	$42,578	$41,713	$(62)	$4,331	$8,687

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 2013 are $(0.5) million, $35.2 million and nil, respectively. The estimated prior service cost/(gain), net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI or regulatory assets into net periodic other than pension benefit cost during 2013 are $(1.8) million, $2.0 million and nil, respectively.

The Company recorded pension expense of $32 million, $31 million and $32 million and OPEB expense of $.4 million, $3 million and $7 million in 2012, 2011 and 2010, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans and other benefit plans had ABO exceeding plan assets as of December 31, 2012 and 2011.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2012, 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 accumulated postretirement benefit obligation (APBO) by $5.6 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the APBO by $5.7 million.

Defined contribution plans information.  Changes to retirement benefits for employees commencing employment after April 30, 2011 include a reduction of benefits provided through the defined benefit plan and the addition of a 50% match by the applicable employer on the first 6% of employee deferrals through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan).

The Company’s expense for its defined contribution pension plan under the HEIRSP Plan for 2012 and 2011 was de minimis.

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, 2016. 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. West Coast and U.S. Midwest. Based on the average price per barrel as of December 31, 2012, the estimated cost of minimum purchases under the fuel supply contracts is $0.9 billion in 2013, $0.9 billion in 2014, $0.4 billion in 2015 and $0.4 billion in 2016. The actual cost of purchases

28

in 2013 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 $1.3 billion, $1.3 billion and $1.0 billion of fuel under contractual agreements in 2012, 2011 and 2010, respectively.

HECO and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to an amended contract for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on April 30, 2013. A successor agreement between the parties for the supply of LSFO commences May 1, 2013 with an initial term ending December 31, 2016 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC issued an interim approval for the recovery of cost incurred under this contract on December 31, 2012.

HECO and Tesoro Hawaii Corp. (Tesoro) are parties to an amended LSFO supply contract (LSFO contract), which runs through April 30, 2013. A successor agreement between the parties for the supply of LSFO commences May 1, 2013 with an initial term ending December 31, 2014 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC issued an interim approval for the recovery of cost incurred under this contract on December 31, 2012. On January 8, 2013, Tesoro announced the April 2013 closure of its Kapolei refinery on Oahu. Tesoro stated that it will continue operations as a terminal for imported fuel while its Hawaii assets remain for sale. Tesoro has also stated it will honor all existing contracts.

HECO, MECO and HELCO are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Tesoro, respectively, which end December 31, 2014. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.

The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for LSFO under a Facility Fuel Supply Contract (fuel contract) between them. The fuel contract between Kalaeloa and Tesoro term ends May 31, 2016 and may be extended for terms thereafter unless terminated by one of the parties.

The costs incurred under the utilities’ fuel contracts are included in their respective ECACs, to the extent such costs are not recovered through the utilities’ base rates.

Power purchase agreements.  As of December 31, 2012, HECO and its subsidiaries had six firm capacity PPAs for a total of 545 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion, $0.7 billion and $0.5 billion for 2012, 2011 and 2010, 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 as amended) 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 2013 through 2017 and a total of $0.7 billion in the period from 2018 through 2033.

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.

Purchase power adjustment clause. The PUC has approved purchased power adjustment clauses (PPACs) for the utilities. Purchased power capacity, operation and maintenance (O&M) and other non-energy costs previously recovered through base rates are now recovered in the PPACs, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACs outside of a rate case. Purchased energy costs will continue to be recovered through the ECAC to the extent they are not recovered through base rates.

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 Hawaii Clean Energy Initiative (HCEI). In October

29

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 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.

Renewable energy projects.  HECO and its subsidiaries continue to negotiate with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others. This includes HECO’s plan to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a large windfarm proposed to be built on the island of Lanai.

In December 2009, the PUC allowed HECO to defer the costs of studies for the large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the stage 1 studies through the REIP surcharge. A decision from the PUC is pending.

In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between HECO and MECO) also through the REIP surcharge for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) and if doing so would be operationally beneficial and cost-effective. In August 2012, the PUC allowed HECO and MECO to defer the outside service costs for the additional studies for later review of prudence and reasonableness. The specific amount to be recovered, as well as the recovery mechanism and the terms of the recovery mechanism, will be determined at a later date.

A revised draft Request for Proposals (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands has been posted on the HECO website prior to the issuance of a proposed final RFP. In February 2012, the PUC granted HECO’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, HELCO filed an application to defer 2012 costs related to the Geothermal RFP. HELCO filed the Proposed Final Geothermal RFP with the PUC in January 2013 and is seeking PUC approval to issue the Geothermal RFP.

Interim increases.As of December 31, 2012, HECO and its subsidiaries had recognized $7 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.

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 HECO’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 those described below.

In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. The PUC subsequently eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the project cost issues. As part of a settlement agreement with the Consumer Advocate, subject to PUC approval, the parties agreed that the regulatory audits for the CIP CT-1 and CIS projects would be eliminated (see Note 16 below).

Campbell Industrial Park combustion turbine No. 1 and transmission line.  HECO’s incurred costs for this project, which was placed in service in 2009, were $195 million, including $9 million of AFUDC. HECO’s current

30

rates reflect recovery of $163 million of project costs. In July 2011, the PUC allowed HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s CIP CT-1 project ($32 million) until completion of an independently conducted regulatory audit. The PUC also approved the accrual of a carrying charge on the cost of the project not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory audit is completed and allowed the remaining project costs that were not deferred to be included in electric rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is collected in electric rates. Management believes no adjustment to project costs is required as of December 31, 2012.

East Oahu Transmission Project. 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 2007, the PUC approved HECO’s request to expend funds for a revised EOTP in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2).

Phase 1 was placed in service in June 2010. The interim D&O issued in July 2011 in HECO’s 2011 test year rate case reflected approximately $16 million of Phase 1 costs and related depreciation expense in determining revenue requirements. In that D&O, the PUC ordered that a regulatory audit was to be conducted before the PUC determined the recoverability of the remaining Phase 1 costs.

In March 2012, the PUC approved a settlement agreement reached among HECO, the Consumer Advocate and the Department of Defense, under which, in lieu of a regulatory audit, HECO would write off $9.5 million of Phase 1 gross plant in service and associated adjustments. This resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million and the elimination of the requirement for a Phase 1 regulatory audit. The PUC also provided for an additional increase of approximately $5 million in HECO’s 2011 test year rate case for the additional revenue requirements reflecting all remaining Phase 1 costs not previously included in rates or agreed to be written off.

In October 2010, the PUC approved HECO’s proposed modification request for Phase 2 of the EOTP using smart grid technology. Phase 2 was placed in service in August 2012. As of December 31, 2012, HECO’s incurred costs for the Modified Phase 2 project amounted to $10 million (total cost of $15 million, less $5 million received in Smart Grid Investment Grant funding). Management believes that no adjustment to project costs of EOTP Modified Phase 2 is required as of December 31, 2012.

Customer Information System Project.  In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million (including $18 million for capital and deferred costs) 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.

The CIS project’s new software system became operational in May 2012. In February 2012 and May 2012, the PUC granted HECO’s and MECO’s requests, respectively, to defer CIS project operation and maintenance expenses (limited to $2.3 million per year in 2011 and 2012 for HECO and limited to $0.6 million in 2012 for MECO) that are to be subject to a regulatory audit. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses) until the completion of the regulatory audit and begin amortization of such costs when the amortization is included in rates. For accounting purposes, the utilities will recognize the equity portion of the carrying charge when it is collected in electric rates.

As of December 31, 2012, the utilities’ total deferred and capital costs for the CIS project were $20 million (after the write-off of $40 million of project costs—see Note 16 below). Management believes no further adjustment to project costs is required as of December 31, 2012.

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, regulatory and governmental

31

activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at HECO’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual O&M expenditures. On June 11, 2012, the EPA published additional information on the section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule until June 2013.

On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at HECO’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, HECO has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs, avoid the reduction in operational flexibility imposed by emissions control equipment, achieve timely compliance with the MATS and provide flexibility for optimizing the combined compliance strategies for MATS and the tightening of the National Ambient Air Quality Standards.

On September 14, 2012, the EPA Administrator signed the final action for the Hawaii Regional Haze Federal Implementation Plan (FIP), which became effective on November 8, 2012. The plan establishes an annual limit for sulfur dioxide emissions from five HELCO steam generating units, with compliance required commencing December 31, 2018. No specific control technologies are required for any HECO or MECO generating units.

Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, and the implementation of more stringent National Ambient Air Quality Standards, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire certain generating units earlier than anticipated.

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. HECO and its subsidiaries believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on HECO’s consolidated results of operations, financial condition or liquidity.

Former Molokai Electric Company generation site.  In 1989, MECO acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the Hawaii Department of Health (DOH), MECO agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a MECO contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, MECO is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, MECO accrued an additional $3.1 million (reserve balance of $3.6 million as of December 31, 2012) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation.

Global climate change and greenhouse gas emissions reduction.  National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of

32

fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.

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 electric utilities participated in a Task Force established under Act 234, which was 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 being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities. Both the federal and state regulations create certain exclusions for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of the proposed regulations; compliance costs could be significant.

Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted.

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The utilities have submitted the required reports for 2010 and 2011 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ generating units.

In June 2010, the EPA issued its GHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, 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. In January 2011, the EPA announced 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. On March 27, 2012, the Federal Register published the EPA’s proposed New Source Performance Standard regulating carbon dioxide emissions from affected new fossil fuel-fired generating units. As proposed, the rule does not apply to non-continental units (i.e., in Hawaii and U.S. Territories) and therefore does not apply to the utilities.

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, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generating units, and testing biofuel blends in other HECO and MECO generating units. The utilities are also working with the State of Hawaii and other entities to pursue the use of liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. Management is unable to evaluate the ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ 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 and liquidity of the electric utilities. For example, severe weather could cause significant harm to the electric utilities’ physical facilities.

33

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 their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

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

(in thousands)	2012		2011
Balance, January 1	$ 50,871		$ 48,630
Accretion expense	1,563		2,202
Liabilities incurred	–		256
Liabilities settled	(4,003	)	(835	)
Revisions in estimated cash flows	–		618
Balance, December 31	$ 48,431		$ 50,871

Collective bargaining agreements. As of December 31, 2012, approximately 52% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities. On November 1, 2012, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement that both expire on October 31, 2018. The collective bargaining agreement provides for general non-compounded wage increases of 3% for 2014, 2015, 2017 and 2018, and 3.25% for 2016. (A general 3% non-compounded wage increase has been provided to bargaining unit employees for 2013 under the collective bargaining agreement ratified in March 2011). The agreement also includes wage adjustments for certain trades and crafts positions and different wage rates for new bargaining unit office and clerical positions. The new benefit agreement provides for an escalating percentage of employee contributions without caps for medical premiums throughout the term of the agreement.

12.  Regulatory restrictions on distributions to parent

As of December 31, 2012, net assets (assets less liabilities and preferred stock) of approximately $637 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 $6.1million, $4.9 million and $5.0 million for general management and administrative services in 2012, 2011 and 2010, 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, 2012 and 2011.  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 plus 0.15%.

Borrowings among HECO and its subsidiaries are eliminated in consolidation. Interest charged by HEI to HECO was nil in 2012, de minimis in 2011 and nil in 2010.

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.

34

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. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates but have not been considered in making such estimates.

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:

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

The estimated fair values of certain of the Company’s financial instruments were as follows:

December 31	2012		2011
(in thousands)	Carrying amount	Estimated fair value (Level 2)	Carrying amount	Estimated fair value (Level 2)
Financial liabilities:
Long-term debt, net, including amounts due within one year	$1,147,872	$1,181,631	$1,058,070	$1,095,133

Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with 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).

Retirement benefit plans.

Assets held in various trusts for the retirement benefit plans (Plans) are measured at fair value on a recurring basis and were as follows:

35

	Pension benefits					Other benefits
			Fair value measurements using					Fair value measurements using
(in millions)	December 31		Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobserv- able inputs (Level 3)	December 31,		Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobserv- able inputs (Level 3)
2012
Equity securities	$513		$513	$    –	$ –	$ 83		$ 83	$  –	$ –
Equity index funds	95		95	–	–	15		15	–	–
Fixed income securities	338		125	213	–	47		41	6	–
Pooled and mutual fundsand other	78		1	76	1	13		–	13	–
Total	1,024		$734	$289	$ 1	158		$139	$ 19	$ –
Receivables andpayables, net	(53	)				(1	)
Fair value of plan assets	$971					$157
2011
Equity securities	$425		$425	$    –	$ –	$ 73		$ 73	$  –	$ –
Equity index funds	82		82	–	–	15		15	–	–
Fixed income securities	283		98	185	–	43		37	6	–
Pooled and mutual fundsand other	87		1	86	–	13		–	13	–
Total	877		$606	$271	$ –	144		$125	$ 19	$ –
Receivables andpayables, net	(37	)				(1	)
Fair value of plan assets	$840					$143

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.

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, 2012 and 2011.

Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds (Level 1).  Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds are valued at the closing price reported on the active market on which the individual securities or funds 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, using observable inputs.

Other (Level 3).  Venture capital interest is valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.

36

For 2012 and 2011, the changes in Level 3 assets were as follows:

	2012				2011
(in thousands)	Pension benefits		Other benefits		Pension benefits		Other benefits
Balance, January 1	$217		$7		$141		$ 5
Realized and unrealized gains (losses)	(24	)	(1	)	92		3
Purchases and settlements, net	388		12		(16	)	(1	)
Balance, December 31	$581		$18		$217		$ 7

16.  Subsequent event

On January 28, 2013, HECO, HELCO and MECO signed a settlement agreement with the Consumer Advocate (Agreement), subject to approval by the PUC, to write off $40 million of CIS project costs, in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects. An after-tax charge to net income of $24 million ($18 million for HECO, $3 million for HELCO, and $3 million for MECO) was recorded in the fourth quarter of 2012 for the write-off of the project costs. In accordance with the Agreement, the remaining recoverable costs for CIP CT-1 and CIS of $52 million have been included in rate base as of December 31, 2012.

As part of the Agreement, the parties also agreed that HELCO would withdraw its 2013 test year rate case and will not file a rate case until its next turn in the 3-year cycle, which will be for a 2016 test year, but HELCO will make annual RBA and RAM rate adjustment filings to roll forward the base year information from its prior rate case. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case, until no earlier than January 2, 2014. The parties also agree that starting in 2014, HECO will be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting January 1 of each year through 2016. The cash collection of RAM revenues will remain unchanged, starting June 1 of each year through May 31 of the following year.

In deciding to enter into the Agreement, HECO, HELCO, and MECO took into account a number of considerations, including (1) the significant passage of time since the initial costs for the CIP CT-1 and CIS projects were incurred, (2) the uncertain timing and significant resources that would be required by the PUC, HECO and other parties to conduct a fair and meaningful regulatory audit of project costs for CIP CT-1 and CIS, (3) the additional carrying charges that would be accrued to the project cost for both CIP CT-1 and CIS, (4) resolving the regulatory audits, (5) the need to allow the PUC, the Consumer Advocate, HECO, HELCO and MECO to focus their resources on the numerous priorities they face in improving customer service and transforming the electric utility industry in Hawaii from one based on oil-fired generation to one based on energy efficiency and Hawaii’s indigenous renewable energy resources, and (6) the concern for the current high electric bills due to the high fuel costs.

Management cannot predict or provide any assurances concerning the approval or timing of approval of the Agreement by the PUC.

17.  Consolidating financial information (unaudited)

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

HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) under their respective private placement note agreements and the HELCO notes and MECO notes issued thereunder (see Note 4 above) and (c) relating to the trust preferred securities of Trust III (see Note 3 above). HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.

37

Consolidating statement of income

	Year ended December 31, 2012
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consolidated
Operating revenues	$2,221,929		440,343		439,726		–		–		–		$3,101,998
Operating expenses
Fuel oil	945,246		116,866		235,307		–		–		–		1,297,419
Purchased power	540,802		145,386		38,052		–		–		–		724,240
Other operation	183,935		40,970		47,212		–		–		–		272,117
Maintenance	79,588		19,247		23,477		–		–		–		122,312
Depreciation	90,783		33,337		20,378		–		–		–		144,498
Taxes, other than income taxes	209,943		41,370		41,528		–		–		–		292,841
Income taxes	54,587		12,213		9,794		–		–		–		76,594
	2,104,884		409,389		415,748		–		–		–		2,930,021
Operating income	117,045		30,954		23,978		–		–		–		171,977
Other income (deductions)
Allowance for equity funds usedduring construction	5,735		585		687		–		–		–		7,007
Equity in earnings of subsidiaries	28,836		–		–		–		–		(28,836	)  [2]	–
Impairment of asset	(29,000	)	(5,500	)	(5,500	)	–		–		–		(40,000	)
Other, net	3,619		440		462		(2	)	(1	)	(77	)  [1]	4,441
Income tax benefits	11,321		2,098		2,127		–		–		–		15,546
	20,511		(2,377	)	(2,224	)	(2	)	(1	)	(28,913	)	(13,006	)
Interest and other charges
Interest on long-term debt	39,203		11,399		8,412		–		–		–		59,014
Amortization of net bond premiumand expense	1,950		479		476		–		–		–		2,905
Other interest charges	(311	)	188		336		–		–		(77	)  [1]	136
Allowance for borrowed funds usedduring construction	(3,642	)	(235	)	(478	)	–		–		–		(4,355	)
	37,200		11,831		8,746		–		–		(77	)	57,700
Net income (loss)	100,356		16,746		13,008		(2	)	(1	)	(28,836	)	101,271
Preferred stock of subsidiaries	–		534		381		–		–		–		915
Net income (loss) attributable to HECO	100,356		16,212		12,627		(2	)	(1	)	(28,836	)	100,356
Preferred stock dividends of HECO	1,080		–		–		–		–		–		1,080
Net income (loss) for common stock	$     99,276		16,212		12,627		(2	)	(1	)	(28,836	)	$     99,276

Consolidating statement of comprehensive income

	Year ended December 31, 2012
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$99,276		16,212		12,627		(2	)	(1	)	(28,836	)	$99,276
Other comprehensive (loss), net of taxes: Retirement benefit plans:
Net gains arising during the period, net of tax benefits	(90,082	)	(13,577	)	(10,935	)	–		–		24,512	[1]	(90,082	)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	13,673		2,101		1,771		–		–		(3,872	)  [1]	13,673
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	75,471		11,442		9,093		–		–		(20,535	)  [1]	75,471
Other comprehensive loss, net of tax benefits	(938	)	(34	)	(71	)	–		–		105		(938	)
Comprehensive income attributable to common shareholder	$98,338		16,178		12,556		(2	)	(1	)	(28,731	)	$98,338

38

Consolidating statement of income

	Year ended December 31, 2011
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consolidated
Operating revenues	$2,110,249		444,266		419,249		–		–		–		$2,973,764
Operating expenses
Fuel oil	909,172		121,839		234,115		–		–		–		1,265,126
Purchased power	522,503		137,453		29,696		–		–		–		689,652
Other operation	183,633		36,318		37,114		–		–		–		257,065
Maintenance	81,583		19,668		19,968		–		–		–		121,219
Depreciation	89,324		32,767		20,884		–		–		–		142,975
Taxes, other than income taxes	196,170		41,028		39,306		–		–		–		276,504
Income taxes	37,652		16,863		11,473		–		–		–		65,988
	2,020,037		405,936		392,556		–		–		–		2,818,529
Operating income	90,212		38,330		26,693		–		–		–		155,235
Other income (deductions)
Allowance for equity funds usedduring construction	4,572		592		800		–		–		–		5,964
Equity in earnings of subsidiaries	44,616		–		–		–		–		(44,616	)  [2]	–
Impairment of asset	(9,215	)	–		–		–		–		–		(9,215	)
Other, net	2,226		545		391		(5	)	(4	)	(27	)  [1]	3,126
Income tax benefits	4,338		24		42		–		–		–		4,404
	46,537		1,161		1,233		(5	)	(4	)	(44,643	)	4,279
Interest and other charges
Interest on long-term debt	36,522		11,938		9,072		–		–		–		57,532
Amortization of net bond premiumand expense	2,023		554		504		–		–		–		3,081
Other interest charges	(921	)	62		304		–		–		(27	)  [1]	(582	)
Allowance for borrowed funds usedduring construction	(1,941	)	(248	)	(309	)	–		–		–		(2,498	)
	35,683		12,306		9,571		–		–		(27	)	57,533
Net income (loss)	101,066		27,185		18,355		(5	)	(4	)	(44,616	)	101,981
Preferred stock of subsidiaries	–		534		381		–		–		–		915
Net income (loss) attributable to HECO	101,066		26,651		17,974		(5	)	(4	)	(44,616	)	101,066
Preferred stock dividends of HECO	1,080		–		–		–		–		–		1,080
Net income (loss) for common stock	$    99,986		26,651		17,974		(5	)	(4	)	(44,616	)	$     99,986

Consolidating statement of comprehensive income

	Year ended December 31, 2011
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$99,986		26,651		17,974		(5	)	(4	)	(44,616	)	$99,986
Other comprehensive (loss), net of taxes: Retirement benefit plans:
Prior service credit arising during the period, net of taxes	6,921		1,419		1,239		–		–		(2,658	)  [1]	6,921
Net gains arising during the period, net of tax benefits	(116,726	)	(18,224	)	(16,816	)	–		–		35,040	[1]	(116,726	)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	8,372		1,324		1,158		–		–		(2,482	)  [1]	8,372
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	100,692		15,436		14,366		–		–		(29,802	)  [1]	100,692
Other comprehensive loss, net of tax benefits	(741	)	(45	)	(53	)	–		–		98		(741	)
Comprehensive income attributable to common shareholder	$99,245		26,606		17,921		(5	)	(4	)	(44,518	)	$99,245

39

Consolidating statement of income

	Year ended December 31, 2010
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		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 usedduring construction	4,956		507		553		–		–		–		6,016
Equity in earnings of subsidiaries	25,600		–		–		–		–		(25,600	)  [2]	–
Other, net	8,121		2,328		143		(8	)	(12	)	(78	)  [1]	10,494
Income tax benefits	1,069		28		88		–		–		–		1,185
	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 premiumand expense	1,942		537		496		–		–		–		2,975
Other interest charges	553		65		463		–		–		(78	)  [1]	1,003
Allowance for borrowed funds usedduring 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

Consolidating statement of comprehensive income

	Year ended December 31, 2010
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$76,589		16,608		9,012		(8	)	(12	)	(25,600	)	$76,589
Other comprehensive (loss), net of taxes:
Retirement benefit plans:
Prior service credit arising during the period, net of taxes	4,712		2,679		2,033		–		–		(4,712	)  [1]	4,712
Net gains arising during the period, net of tax benefits	(43,031	)	(6,131	)	(5,601	)	–		–		11,732	[1]	(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	3,747		759		566		–		–		(1,325	)  [1]	3,747
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	33,499		2,617		2,959		–		–		(5,576	)  [1]	33,499
Other comprehensive loss, net of tax benefit	(1,073	)	(76	)	(43	)	–		–		119		(1,073	)
Comprehensive income attributable to common shareholder	$75,516		16,532		8,969		(8	)	(12	)	(25,481	)	$75,516

40

Consolidating balance sheet

	December 31, 2012
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Consolidating adjustments		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,370		5,182		3,016		–	–	–		$	51,568
Plant and equipment	3,325,862			1,086,048		952,490		–	–	–		5,364,400
Less accumulated depreciation	(1,185,899		)	(433,531	)	(421,359	)	–	–	–		(2,040,789		)
Construction in progress	130,143			12,126		9,109		–	–	–		151,378
Net utility plant	2,313,476			669,825		543,256		–	–	–		3,526,557
Investment in wholly owned subsidiaries,at equity	497,939			–		–		–	–	(497,939	)  [2]	–
Current assets
Cash and equivalents	8,265			5,441		3,349		79	25	–		17,159
Advances to affiliates	9,400			18,050		–		–	–	(27,450	)  [1]	–
Customer accounts receivable, net	154,316			29,772		26,691		–	–	–		210,779
Accrued unbilled revenues, net	100,600			14,393		19,305		–	–	–		134,298
Other accounts receivable, net	33,313			1,122		3,016		–	–	(9,275	)  [1]	28,176
Fuel oil stock, at average cost	123,176			15,485		22,758		–	–	–		161,419
Materials & supplies, at average cost	31,779			5,336		13,970		–	–	–		51,085
Prepayments and other	21,708			5,146		6,011		–	–	–		32,865
Regulatory assets	42,675			4,056		4,536		–	–	–		51,267
Total current assets	525,232			98,801		99,636		79	25	(36,725	)	687,048
Other long-term assets
Regulatory assets	601,451			109,815		102,063		–	–	–		813,329
Unamortized debt expense	7,042			2,066		1,446		–	–	–		10,554
Other	46,586			9,871		14,848		–	–	–		71,305
Total other long-term assets	655,079			121,752		118,357		–	–	–		895,188
	$	3,991,726		890,378		761,249		79	25	(534,664	)	$	5,108,793
Capitalization and liabilities
Capitalization
Common stock equity	$	1,472,136		268,908		228,927		79	25	(497,939	)  [2]	$	1,472,136
Cumulative preferred stock–notsubject to mandatory redemption	22,293			7,000		5,000		–	–	–		34,293
Long-term debt, net	780,546			201,326		166,000		–	–	–		1,147,872
Total capitalization	2,274,975			477,234		399,927		79	25	(497,939	)	2,654,301
Current liabilities
Current portion of long-term debt	–			–		–		–	–	–		–
Short-term borrowings-affiliate	18,050			–		9,400		–	–	(27,450	)  [1]	–
Accounts payable	134,651			27,457		24,716		–	–	–		186,824
Interest and preferred dividends payable	14,479			4,027		2,593		–	–	(7	) [1]	21,092
Taxes accrued	174,477			38,778		37,811		–	–	–		251,066
Other	47,203			10,310		14,634		–	–	(9,268	)  [1]	62,879
Total current liabilities	388,860			80,572		89,154		–	–	(36,725	)	521,861
Deferred credits and other liabilities
Deferred income taxes	302,569			68,479		46,563		–	–	–		417,611
Regulatory liabilities	218,437			67,359		36,278		–	–	–		322,074
Unamortized tax credits	39,827			13,450		13,307		–	–	–		66,584
Retirement benefits liability	459,765			80,686		79,754		–	–	–		620,205
Other	68,783			17,799		14,055		–	–	–		100,637
Total deferred credits and other liabilities	1,089,381			247,773		189,957		–	–	–		1,527,111
Contributions in aid of construction	238,510			84,799		82,211		–	–	–		405,520
	$	3,991,726		890,378		761,249		79	25	(534,664	)	$	5,108,793

41

Consolidating balance sheet

	December 31, 2011
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Consolidating adjustments		HECOConsolidated
Assets
Utility plant, at cost
Land	$	43,316		5,182		3,016		–	–	–		$	51,514
Plant and equipment	3,091,908			1,048,599		911,520		–	–	–		5,052,027
Less accumulated depreciation	(1,141,839		)	(414,769	)	(410,286	)	–	–	–		(1,966,894		)
Construction in progress	117,625			8,144		13,069		–	–	–		138,838
Net utility plant	2,111,010			647,156		517,319		–	–	–		3,275,485
Investment in wholly owned subsidiaries,at equity	516,143			–		–		–	–	(516,143	)  [2]	–
Current assets
Cash and equivalents	44,819			3,383		496		82	26	–		48,806
Advances to affiliates	–			46,150		18,500		–	–	(64,650	)  [1]	–
Customer accounts receivable, net	130,190			28,602		24,536		–	–	–		183,328
Accrued unbilled revenues, net	103,328			18,499		15,999		–	–	–		137,826
Other accounts receivable, net	8,987			1,186		3,008		–	–	(4,558	)  [1]	8,623
Fuel oil stock, at average cost	128,037			19,217		24,294		–	–	–		171,548
Materials & supplies, at average cost	25,096			4,700		13,392		–	–	–		43,188
Prepayments and other	22,517			6,948		7,343		–	–	(141	)  [3]	36,667
Regulatory assets	18,038			1,115		1,130		–	–	–		20,283
Total current assets	481,012			129,800		108,698		82	26	(69,349	)	650,269
Other long-term assets
Regulatory assets	478,851			86,394		83,861		–	–	–		649,106
Unamortized debt expense	8,446			2,464		1,876		–	–	–		12,786
Other	58,672			11,843		15,846		–	–	–		86,361
Total other long-term assets	545,969			100,701		101,583		–	–	–		748,253
	$	3,654,134		877,657		727,600		82	26	(585,492	)	$	4,674,007
Capitalization and liabilities
Capitalization
Common stock equity	$	1,402,841		280,468		235,568		81	26	(516,143	)  [2]	$	1,402,841
Cumulative preferred stock–notsubject to mandatory redemption	22,293			7,000		5,000		–	–	–		34,293
Long-term debt, net	629,757			204,110		166,703		–	–	–		1,000,570
Total capitalization	2,054,891			491,578		407,271		81	26	(516,143	)	2,437,704
Current liabilities
Current portion of long-term debt	42,580			7,200		7,720		–	–	–		57,500
Short-term borrowings-affiliate	64,650			–		–		–	–	(64,650	)  [1]	–
Accounts payable	140,044			29,616		18,920		–	–	–		188,580
Interest and preferred dividends payable	12,648			4,074		2,762		–	–	(1	)  [1]	19,483
Taxes accrued	155,867			38,598		35,752		–	–	(141	)  [3]	230,076
Other	50,828			9,478		13,603		1	–	(4,557	)  [1]	69,353
Total current liabilities	466,617			88,966		78,757		1	–	(69,349	)	564,992
Deferred credits and other liabilities
Deferred income taxes	236,890			61,044		39,929		–	–	–		337,863
Regulatory liabilities	215,401			62,049		38,016		–	–	–		315,466
Unamortized tax credits	34,877			12,951		12,786		–	–	–		60,614
Retirement benefits liability	367,877			62,036		64,840		–	–	–		494,753
Other	72,786			22,391		11,235		–	–	–		106,412
Total deferred credits and other liabilities	927,831			220,471		166,806		–	–	–		1,315,108
Contributions in aid of construction	204,795			76,642		74,766		–	–	–		356,203
	$	3,654,134		877,657		727,600		82	26	(585,492	)	$	4,674,007

42

Consolidating statements of changes in common stock equity

(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consoli- dated
Balance, December 31, 2011	$1,402,841		280,468		235,568		81		26		(516,143	)	$1,402,841
Net income (loss) for common stock	99,276		16,212		12,627		(2	)	(1	)	(28,836	)	99,276
Other comprehensive income (loss)	(938	)	(34	)	(71	)	–		–		105		(938	)
Issuance of common stock, net of expenses	44,001		–		–		–		–		–		44,001
Common stock dividends	(73,044	)	(27,738	)	(19,197	)	–		–		46,935		(73,044	)
Balance, December 31, 2012	$1,472,136		268,908		228,927		79		25		(497,939	)	$1,472,136
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consoli- dated
Balance, December 31, 2010	$1,334,155		269,986		229,651		86		5		(499,728	)	$1,334,155
Net income (loss) for common stock	99,986		26,651		17,974		(5	)	(4	)	(44,616	)	99,986
Other comprehensive income (loss)	(741	)	(45	)	(53	)	–		–		98		(741	)
Issuance of common stock, net of expenses	39,999		–		–		–		25		(25	)	39,999
Common stock dividends	(70,558	)	(16,124	)	(12,004	)	–		–		28,128		(70,558	)
Balance, December 31, 2011	$1,402,841		280,468		235,568		81		26		(516,143	)	$1,402,841
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECO Consoli- dated
Balance, December 31, 2009	$1,303,165		239,989		220,833		94		17		(460,933	)	$1,303,165
Net income (loss) for common stock	76,589		16,608		9,012		(8	)	(12	)	(25,600	)	76,589
Other comprehensive income (loss)	(1,073	)	(76	)	(43	)	–		–		119		(1,073	)
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	$1,334,155		269,986		229,651		86		5		(499,728	)	$1,334,155

43

Consolidating statement of cash flows

	Year ended December 31, 2012
(in thousands)	HECO		HELCO		MECO		RHI		UBC		Consolidating adjustments		HECOConsolidated
Cash flows from operating activities:
Net income (loss)	$100,356		16,746		13,008		(2	)	(1	)	(28,836	)  [2]	$101,271
Adjustments to reconcile net income to net cashprovided by operating activities:
Equity in earnings	(28,936	)	–		–		–		–		28,836	[2]	(100	)
Common stock dividends receivedfrom subsidiaries	47,035		–		–		–		–		(46,935	)  [2]	100
Depreciation of property,plant and equipment	90,783		33,337		20,378		–		–		–		144,498
Other amortization	1,508		3,252		2,238		–		–		–		6,998
Impairment of assets	29,000		5,500		5,500		–		–		–		40,000
Changes in deferred income taxes	66,968		7,457		12,453		–		–		–		86,878
Changes in tax credits, net	5,006		522		547		–		–		–		6,075
Allowance for equity funds usedduring construction	(5,735	)	(585	)	(687	)	–		–		–		(7,007	)
Changes in assets and liabilities:
Increase in accounts receivable	(48,451	)	(1,106	)	(2,164	)	–		–		4,717	[1]	(47,004	)
Decrease (increase) in accrued unbilled revenues	2,728		4,106		(3,306	)	–		–		–		3,528
Decrease in fuel oil stock	4,861		3,732		1,536		–		–		–		10,129
Increase in materials and supplies	(6,683	)	(636	)	(578	)	–		–		–		(7,897	)
Increase in regulatory assets	(55,605	)	(9,649	)	(7,147	)	–		–		–		(72,401	)
Increase (decrease) in accounts payable	(31,743	)	(8,110	)	940		–		–		–		(38,913	)
Changes in prepaid and accrued income taxes and revenue taxes	19,871		1,935		3,433		–		–		–		25,239
Contributions to defined benefit pension and other postretirement benefit plans	(46,329	)	(8,368	)	(8,378	)	–		–		–		(63,075	)
Changes in other assets and liabilities	1,015		(2,966	)	(4,419	)	(1	)	–		(4,717	)  [1]	(11,088	)
Net cash provided by (used in) operating activities	145,649		45,167		33,354		(3	)	(1	)	(46,935	)	177,231
Cash flows from investing activities:
Capital expenditures	(233,792	)	(41,060	)	(35,239	)	–		–		–		(310,091	)
Contributions in aid of construction	32,285		8,184		5,513		–		–		–		45,982
Advances from (to) affiliates	(9,400	)	28,100		18,500		–		–		(37,200	)  [1]	–
Net cash used in investing activities	(210,907	)	(4,776	)	(11,226	)	–		–		(37,200	)	(264,109	)
Cash flows from financing activities:
Common stock dividends	(73,044	)	(27,738	)	(19,197	)	–		–		46,935	[2]	(73,044	)
Preferred stock dividends of HECO and subsidiaries	(1,080	)	(534	)	(381	)	–		–		–		(1,995	)
Proceeds from the issuance of long-term debit	367,000		31,000		59,000		–		–		–		457,000
Proceeds from issuance of common stock	44,000				–		–		–		–		44,000
Repayment of long-term debt	(259,580	)	(41,200	)	(67,720	)	–		–		–		(368,500	)
Net increase (decrease) in short-term borrowingsfrom non-affiliates and affiliate with originalmaturities of three months or less	(46,600	)	–		9,400		–		–		37,200	[2]	–
Other	(1,992	)	139		(377	)	–		–		–		(2,230	)
Net cash provided by (used in) financing activities	28,704		(38,333	)	(19,275	)	–		–		84,135		55,231
Net increase (decrease) in cash and cash equivalents	(36,554	)	2,058		2,853		(3	)	(1	)	–		(31,647	)
Cash and cash equivalents, January 1	44,819		3,383		496		82		26		–		48,806
Cash and cash equivalents, December 31	$8,265		5,441		3,349		79		25		–		$17,159

44

Consolidating statement of cash flows

	Year ended December 31, 2011
(in thousands)	HECO			HELCO		MECO		RHI		UBC	Consolidating adjustments		HECOConsolidated
Cash flows from operating activities:
Net income (loss)	$	101,066		27,185		18,355		(5	)	(4)	(44,616)	[2]	$ 101,981
Adjustments to reconcile net income to net cashprovided by operating activities:
Equity in earnings	(44,716		)	–		–		–		–	44,616	[2]	(100)
Common stock dividends receivedfrom subsidiaries	28,228			–		–		–		–	(28,128)	[2]	100
Depreciation of property,plant and equipment	89,324			32,767		20,884		–		–	–		142,975
Other amortization	9,890			2,528		4,960		–		–	–		17,378
Impairment of utility plant	9,215			–		–		–		–	–		9,215
Changes in deferred income taxes	38,548			16,101		14,442		–		–	–		69,091
Changes in tax credits, net	1,464			117		506		–		–	–		2,087
Allowance for equity funds usedduring construction	(4,572		)	(592	)	(800	)	–		–	–		(5,964)
Decrease in cash overdraft	–			(2,527	)	(161	)	–		–	–		(2,688)
Changes in assets and liabilities:
Increase in accounts receivable	(34,167		)	(2,985	)	(5,663	)	–		–	(1,589)	[1]	(44,404)
Decrease (Increase) in accrued unbilled revenues	(31,616		)	(2,481	)	655		–		–	–		(33,442)
Increase in fuel oil stock	(6,757		)	(3,466	)	(8,620	)	–		–	–		(18,843)
Increase in materials and supplies	(6,206		)	(202	)	(63	)	–		–	–		(6,471)
Increase in regulatory assets	(31,774		)	(2,025	)	(6,333	)	–		–	–		(40,132)
Increase (decrease) in accounts payable	(34,515		)	4,391		(5,691	)	–		–	–		(35,815)
Changes in prepaid and accrued income taxes and revenue taxes	51,593			9,641		8,502		–		–	–		69,736
Contributions to defined benefit pension and other postretirement benefit plans	(54,183		)	(9,191	)	(9,802	)	–		–	–		(73,176)
Changes in other assets and liabilities	16,312			(7,174	)	(859	)	(2	)	–	1,589	[1]	9,866
Net cash provided by (used in) operating activities	97,134			62,087		30,312		(7	)	(4)	(28,128)		161,394
Cash flows from investing activities:
Capital expenditures	(160,528		)	(34,230	)	(31,264	)	–		–	–		(226,022)
Contributions in aid of construction	15,003			6,271		2,260		–		–	–		23,534
Advances from (to) affiliates	–			(15,200	)	11,000		–		–	4,200	[1]	–
Other	77			–		–		–		–	–		77
Investment in consolidated subsidiary	(25		)	–		–		–		–	25	[2]	–
Net cash used in investing activities	(145,473		)	(43,159	)	(18,004	)	–		–	4,225		(202,411)
Cash flows from financing activities:
Common stock dividends	(70,558		)	(16,124	)	(12,004	)	–		–	28,128	[2]	(70,558)
Preferred stock dividends of HECO and subsidiaries	(1,080		)	(534	)	(381	)	–		–	–		(1,995)
Proceeds from issuance of common stock	40,000			–		–		–		25	(25)	[2]	40,000
Net increase in short-term borrowingsfrom non-affiliates and affiliate with originalmaturities of three months or less	4,200			–		–		–		–	(4,200)	[1]	–
Other	(423		)	(116	)	(21	)	–		–	–		(560)
Net cash provided by (used in) financing activities	(27,861		)	(16,774	)	(12,406	)	–		25	23,903		(33,113)
Net increase (decrease) in cash and cash equivalents	(76,200		)	2,154		(98	)	(7	)	21	–		(74,130)
Cash and cash equivalents, January 1	121,019			1,229		594		89		5	–		122,936
Cash and cash equivalents, December 31	$	44,819		3,383		496		82		26	–		$   48,806

45

Consolidating statement of cash flows

	Year ended December 31, 2010
(in thousands)	HECO			HELCO		MECO		RHI		UBC	Consolidating adjustments		HECOConsolidated
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 cashprovided by operating activities:
Equity in earnings	(25,700		)	–		–		–		–	25,600	[2]	(100)
Common stock dividends receivedfrom 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 usedduring 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)
Contributions to defined benefit pension and other postretirement benefit plans	(21,003		)	(4,981	)	(5,084	)	–		–	–		(31,068)
Changes in other assets and liabilities	38,009			62		5,908		(1	)	(2)	(5,018)	[1]	38,958
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 borrowingsfrom non-affiliates and affiliate with originalmaturities 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

46

Explanation of consolidating adjustments 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.

18.  Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information was as follows:

	Quarters ended				Years ended
(in thousands)	March 31	June 30	Sept. 30	Dec. 31	Dec. 31
2012
Operating revenues	$747,938	$787,685	$799,203	$767,172	$3,101,998
Operating income	38,581	41,507	51,379	40,510	171,977
Net income for common stock 1	27,300	29,376	38,375	4,225	99,276
2011
Operating revenues 2	644,301	727,652	818,907	782,904	2,973,764
Operating income 2	32,719	30,540	49,999	41,977	155,235
Net income for common stock 2,3	19,189	17,024	37,959	25,814	99,986

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

1In the fourth quarter of 2012, as part of a settlement agreement with the Consumer Advocate, the Company recorded a writedown of $24 million (net of taxes) of CIS project costs in lieu of conducting regulatory audits of the CIP CT-1 and CIS projects.

2In the fourth quarter of 2011, HECO recorded an adjustment of $6 million to revenues related to the third quarter of 2011, which decreased net income for the fourth quarter of 2011 by $3 million.

3In the fourth quarter of 2011 HECO recorded an impairment charge of $6 million (net of taxes) relating to a transmission project.

47