Hawaiian Electric Company, Inc. PFD SER E 5% (HAWEL) 10-Q 2013 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2013

OR

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

Exact Name of Registrant as	Commission	I.R.S. Employer
Specified in Its Charter	File Number	Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC.	1-8503	99-0208097
and Principal Subsidiary
HAWAIIAN ELECTRIC COMPANY, INC.	1-4955	99-0040500

State of Hawaii

(State or other jurisdiction of incorporation or organization)

Hawaiian Electric Industries, Inc. – 1001 Bishop Street, Suite 2900, Honolulu, Hawaii  96813

Hawaiian Electric Company, Inc. – 900 Richards Street, Honolulu, Hawaii  96813

(Address of principal executive offices and zip code)

Hawaiian Electric Industries, Inc. –(808) 543-5662

Hawaiian Electric Company, Inc. – (808) 543-7771

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Hawaiian Electric Industries, Inc. Yes x No o Hawaiian Electric Company, Inc. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Hawaiian Electric Industries, Inc. Yes x No o Hawaiian Electric Company, Inc. Yes x No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Hawaiian Electric Industries, Inc. Yes o No x Hawaiian Electric Company, Inc. Yes o No x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Hawaiian Electric Industries, Inc.	Large accelerated filer  x	Hawaiian Electric Company, Inc.	Large accelerated filer o
	Accelerated filer o		Accelerated filer o
	Non-accelerated filer o		Non-accelerated filer  x
	(Do not check if a smaller reporting company)		(Do not check if a smaller reporting company)
	Smaller reporting company o		Smaller reporting company o

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

Class of Common Stock	Outstanding July 31, 2013
Hawaiian Electric Industries, Inc. (Without Par Value)	99,128,257 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)	14,665,264 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2013

INDEX

Page No.
ii	Glossary of Terms
iv	Forward-Looking Statements
	PART I. FINANCIAL INFORMATION
1	Item 1.	Financial Statements
		Hawaiian Electric Industries, Inc. and Subsidiaries
1		Consolidated Statements of Income - three and six months ended June 30, 2013 and 2012
2		Consolidated Statements of Comprehensive Income - three and six months ended June 30, 2013 and 2012
3		Consolidated Balance Sheets - June 30, 2013 and December 31, 2012
4		Consolidated Statements of Changes in Shareholders’ Equity - six months ended June 30, 2013 and 2012
5		Consolidated Statements of Cash Flows - six months ended June 30, 2013 and 2012
6		Notes to Consolidated Financial Statements
		Hawaiian Electric Company, Inc. and Subsidiaries
30		Consolidated Statements of Income - three and six months ended June 30, 2013 and 2012
30		Consolidated Statements of Comprehensive Income - three and six months ended June 30, 2013 and 2012
31		Consolidated Balance Sheets - June 30, 2013 and December 31, 2012
32		Consolidated Statements of Changes in Common Stock Equity - six months ended June 30, 2013 and 2012
33		Consolidated Statements of Cash Flows - six months ended June 30, 2013 and 2012
34		Notes to Consolidated Financial Statements
54	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
54		HEI Consolidated
59		Electric Utilities
68		Bank
78	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
79	Item 4.	Controls and Procedures
	PART II.	OTHER INFORMATION
80	Item 1.	Legal Proceedings
80	Item 1A.	Risk Factors
80	Item 5.	Other Information
81	Item 6.	Exhibits
82	Signatures

i

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2013

GLOSSARY OF TERMS

Terms	Definitions
AFTAP	Adjusted Funding Target Attainment Percentage
AFUDC	Allowance for funds used during construction
AOCI	Accumulated other comprehensive income/(loss)
ARO	Asset retirement obligation
ASB	American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc.
ASHI	American Savings Holdings, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
ASU	Accounting Standards Update
CIP CT-1	Campbell Industrial Park 110 MW combustion turbine No. 1
CIS	Customer Information System
Company	Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); American Savings Holdings, Inc. and its subsidiary, American Savings Bank, F.S.B.; HEI Properties, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
Consumer Advocate	Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
DBEDT	State of Hawaii Department of Business, Economic Development and Tourism
D&O	Decision and order
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOH	Department of Health of the State of Hawaii
DRIP	HEI Dividend Reinvestment and Stock Purchase Plan
DSM	Demand-side management
ECAC	Energy cost adjustment clauses
EIP	2010 Equity and Incentive Plan
EGU	Electrical generating unit
Energy Agreement	Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI
EPA	Environmental Protection Agency — federal
EPS	Earnings per share
ERISA	Employee Retirement Income Security Act of 1974, as amended
EVE	Economic value of equity
Exchange Act	Securities Exchange Act of 1934
FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
federal	U.S. Government
FHLB	Federal Home Loan Bank
FHLMC	Federal Home Loan Mortgage Corporation
FNMA	Federal National Mortgage Association
FRB	Federal Reserve Board

ii

GLOSSARY OF TERMS, continued

Terms	Definitions
GAAP	U.S. generally accepted accounting principles
GHG	Greenhouse gas
GNMA	Government National Mortgage Association
HCEI	Hawaii Clean Energy Initiative
HECO	Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated financing subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.
HEI	Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., HEI Properties, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.)
HEIRSP	Hawaiian Electric Industries Retirement Savings Plan
HELCO	Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER	City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP	Independent power producer
IRP	Integrated resource planning
Kalaeloa	Kalaeloa Partners, L.P.
KW	Kilowatt
KWH	Kilowatthour
LTIP	Long-term incentive plan
MAP-21	Moving Ahead for Progress in the 21st Century Act
MECO	Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
MW	Megawatt/s (as applicable)
NII	Net interest income
NQSO	Nonqualified stock option
O&M	Other operation and maintenance
OCC	Office of the Comptroller of the Currency
OPEB	Postretirement benefits other than pensions
PPA	Power purchase agreement
PPAC	Purchased power adjustment clause
PUC	Public Utilities Commission of the State of Hawaii
RAM	Revenue adjustment mechanism
RBA	Revenue balancing account
RFP	Request for proposal
REIP	Renewable Energy Infrastructure Program
RHI	Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.
ROACE	Return on average common equity
RORB	Return on average rate base
RPS	Renewable portfolio standard
SAR	Stock appreciation right
SEC	Securities and Exchange Commission
See	Means the referenced material is incorporated by reference
SOIP	1987 Stock Option and Incentive Plan, as amended
TDR	Troubled debt restructuring
UBC	Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc.
VIE	Variable interest entity

iii

FORWARD-LOOKING STATEMENTS

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects 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 HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those 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, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB), which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii (including the effects of sequestration), 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 climate change, such as more severe storms and rising sea levels), including their impact on Company operations and the economy;

·the timing and extent of changes in interest rates and the shape of the yield curve;

·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 to access capital markets to issue HEI common stock under volatile and challenging market conditions, 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 and ASB’s securities available for sale;

·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 impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) and of the rules and regulations that the Dodd-Frank Act requires to be promulgated;

·increasing competition in the banking industry (e.g., increased price competition for deposits, or an outflow of deposits to alternative investments, which may have an adverse impact on ASB’s cost of funds);

·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), and the fulfillment by the electric utilities of their 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 such as the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, 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, 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 electric utilities of their 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 utilities;

iv

·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 electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

·new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB) or their competitors;

·cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and HECO and their subsidiaries (including at ASB branches and at the electric utility plants) and incidents at data processing centers they use, 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 existing, new and changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (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 and/or liabilities), the regulation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), 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);

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

·potential enforcement actions by the Office of the Comptroller of the Currency, the Federal Reserve Board (FRB), the Federal Deposit Insurance Corporation (FDIC) and/or other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under existing or new banking and consumer protection laws and regulations or with respect to capital adequacy);

·the ability of the electric utilities 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 HEI’s businesses and ASB’s loans, ASB’s concentration in a single product type (i.e., first mortgages) and ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers);

·changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, 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 HEI and HECO and the results of financing efforts;

·faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage-servicing assets of ASB;

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

·changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;

·the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;

·the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the utilities’ 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 and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

v

PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months						Six months
	ended June 30						ended June 30
(in thousands, except per share amounts)	2013			2012			2013			2012
Revenues
Electric utility	$	730,688		$	789,552		$	1,449,961		$	1,539,162
Bank	66,027			64,721			130,783			129,973
Other	15			(5		)	50			(7		)
Total revenues	796,730			854,268			1,580,794			1,669,128
Expenses
Electric utility	669,550			728,056			1,335,870			1,420,412
Bank	41,322			42,847			84,327			85,187
Other	3,488			3,959			7,570			8,307
Total expenses	714,360			774,862			1,427,767			1,513,906
Operating income (loss)
Electric utility	61,138			61,496			114,091			118,750
Bank	24,705			21,874			46,456			44,786
Other	(3,473		)	(3,964		)	(7,520		)	(8,314		)
Total operating income	82,370			79,406			153,027			155,222
Interest expense—other than on deposit liabilities and other bank borrowings	(19,613		)	(20,199		)	(39,401		)	(38,738		)
Allowance for borrowed funds used during construction	398			893			1,128			1,763
Allowance for equity funds used during construction	1,560			1,997			2,775			3,937
Income before income taxes	64,715			62,097			117,529			122,184
Income taxes	23,654			22,824			42,316			44,122
Net income	41,061			39,273			75,213			78,062
Preferred stock dividends of subsidiaries	473			473			946			946
Net income for common stock	$	40,588		$	38,800		$	74,267		$	77,116
Basic earnings per common share	$	0.41		$	0.40		$	0.75		$	0.80
Diluted earnings per common share	$	0.41		$	0.40		$	0.75		$	0.80
Dividends per common share	$	0.31		$	0.31		$	0.62		$	0.62
Weighted-average number of common shares outstanding	98,660			96,693			98,399			96,430
Net effect of potentially dilutive shares	589			286			562			389
Adjusted weighted-average shares	99,249			96,979			98,961			96,819

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

1

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012
Net income for common stock	$	40,588		$	38,800		$	74,267		$	77,116
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits of $5,485 and ($721) for the three months ended June 30, 2013 and 2012 and $6,032 and ($572) for the six months ended June 30, 2013 and 2012, respectively	(8,307		)	1,093			(9,135		)	867
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $488 and $53 for the three months ended June 30, 2013 and 2012 and $488 and $53 for the six months ended June 30, 2013 and 2012, respectively	(738		)	(81		)	(738		)	(81		)
Derivatives qualified as cash flow hedges:
Less: reclassification adjustment to net income, net of tax benefits of $38 for the three months ended June 30, 2013 and 2012 and $75 for the six months ended June 30, 2013 and 2012	59			59			118			118
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,630 and $2,405 for the three months ended June 30, 2013 and 2012 and $7,476 and $4,878 for the six months ended June 30, 2013 and 2012, respectively	5,680			3,768			11,701			7,641
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,184 and $2,095 for the three months ended June 30, 2013 and 2012 and $6,568 and $4,257 for the six months ended June 30, 2013 and 2012, respectively	(4,999		)	(3,289		)	(10,312		)	(6,684		)
Other comprehensive income (loss), net of taxes	(8,305		)	1,550			(8,366		)	1,861
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	32,283		$	40,350		$	65,901		$	78,977

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

2

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands)	June 30, 2013						December 31, 2012
Assets
Cash and cash equivalents				$	153,712					$	219,662
Accounts receivable and unbilled revenues, net				359,259						362,823
Available-for-sale investment and mortgage-related securities				560,172						671,358
Investment in stock of Federal Home Loan Bank of Seattle				94,281						96,022
Loans receivable held for investment, net				3,912,630						3,737,233
Loans held for sale, at lower of cost or fair value				34,073						26,005
Property, plant and equipment, net of accumulated depreciation of $2,161,681 in 2013 and $2,125,286 in 2012				3,701,905						3,594,829
Regulatory assets				885,025						864,596
Other				454,898						494,414
Goodwill				82,190						82,190
Total assets				$	10,238,145					$	10,149,132
Liabilities and shareholders’ equity
Liabilities
Accounts payable				$	175,038					$	212,379
Interest and dividends payable				25,503						26,258
Deposit liabilities				4,276,243						4,229,916
Short-term borrowings—other than bank				125,786						83,693
Other bank borrowings				187,884						195,926
Long-term debt, net—other than bank				1,422,877						1,422,872
Deferred income taxes				474,197						439,329
Regulatory liabilities				336,065						322,074
Contributions in aid of construction				419,337						405,520
Defined benefit pension and other postretirement benefit plans liability				639,898						656,394
Other				496,375						526,613
Total liabilities				8,579,203						8,520,974
Preferred stock of subsidiaries - not subject to mandatory redemption				34,293						34,293
Commitments and contingencies (Notes 3 and 4)
Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none				—						—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 99,044,053 shares in 2013 and 97,928,403 shares in 2012				1,429,371						1,403,484
Retained earnings				230,067						216,804
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains on securities	$	888					$	10,761
Unrealized losses on derivatives	(642		)				(760		)
Retirement benefit plans	(35,035		)	(34,789		)	(36,424		)	(26,423		)
Total shareholders’ equity				1,624,649						1,593,865
Total liabilities and shareholders’ equity				$	10,238,145					$	10,149,132

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

3

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Shareholders’ Equity (unaudited)

	Common stock			Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount		Earnings			loss			Total
Balance, December 31, 2012	97,928	$	1,403,484	$	216,804		$	(26,423	)	$	1,593,865
Net income for common stock	—	—		74,267			—			74,267
Other comprehensive loss, net of tax benefits	—	—		—			(8,366		)	(8,366		)
Issuance of common stock, net	1,116	25,887		—			—			25,887
Common stock dividends ($0.62 per share)	—	—		(61,004		)	—			(61,004		)
Balance, June 30, 2013	99,044	$	1,429,371	$	230,067		$	(34,789	)	$	1,624,649
Balance, December 31, 2011	96,038	$	1,349,446	$	198,397		$	(19,137	)	$	1,528,706
Net income for common stock	—	—		77,116			—			77,116
Other comprehensive income, net of taxes	—	—		—			1,861			1,861
Issuance of common stock, net	985	27,980		—			—			27,980
Dividend equivalents paid on equity-classified awards	—	—		(96		)	—			(96		)
Common stock dividends ($0.62 per share)	—	—		(59,791		)	—			(59,791		)
Balance, June 30, 2012	97,023	$	1,377,426	$	215,626		$	(17,276	)	$	1,575,776

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

4

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Six months ended June 30	2013			2012
(in thousands)
Cash flows from operating activities
Net income	$	75,213		$	78,062
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment	79,843			75,517
Other amortization	2,868			2,999
Provision for loan losses	899			5,924
Loans receivable originated and purchased, held for sale	(128,276		)	(161,344		)
Proceeds from sale of loans receivable, held for sale	148,243			161,713
Change in deferred income taxes	40,403			41,541
Change in excess tax benefits from share-based payment arrangements	(445		)	(40		)
Allowance for equity funds used during construction	(2,775		)	(3,937		)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net	3,564			(42,428		)
Decrease (increase) in fuel oil stock	43,974			(35,893		)
Increase in regulatory assets	(37,586		)	(35,476		)
Increase (decrease) in accounts, interest and dividends payable	(43,384		)	3,578
Change in prepaid and accrued income taxes and utility revenue taxes	(33,822		)	(12,998		)
Contributions to defined benefit pension and other postretirement benefit plans	(41,521		)	(53,356		)
Other increase in defined benefit pension and other postretirement benefit plans liability	41,191			31,204
Change in other assets and liabilities	(17,597		)	(58,638		)
Net cash provided by (used in) operating activities	130,792			(3,572		)
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(39,721		)	(93,808		)
Principal repayments on available-for-sale investment and mortgage-related securities	62,819			75,407
Proceeds from sale of available-for-sale investment and mortgage-related securities	71,367			3,548
Net increase in loans held for investment	(201,184		)	(61,214		)
Proceeds from sale of real estate acquired in settlement of loans	5,712			6,036
Capital expenditures	(158,830		)	(145,263		)
Contributions in aid of construction	17,188			26,981
Other	2,364			—
Net cash used in investing activities	(240,285		)	(188,313		)
Cash flows from financing activities
Net increase in deposit liabilities	46,326			66,709
Net increase in short-term borrowings with original maturities of three months or less	42,093			27,419
Net decrease in retail repurchase agreements	(8,054		)	(14,556		)
Proceeds from other bank borrowings	25,000			—
Repayments of other bank borrowings	(25,000		)	—
Proceeds from issuance of long-term debt	50,000			417,000
Repayment of long-term debt	(50,000		)	(328,500		)
Change in excess tax benefits from share-based payment arrangements	445			40
Net proceeds from issuance of common stock	11,994			11,909
Common stock dividends	(48,921		)	(47,851		)
Preferred stock dividends of subsidiaries	(946		)	(946		)
Other	606			(2,055		)
Net cash provided by financing activities	43,543			129,169
Net decrease in cash and cash equivalents	(65,950		)	(62,716		)
Cash and cash equivalents, beginning of period	219,662			270,265
Cash and cash equivalents, end of period	$	153,712		$	207,549

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

5

Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s Form 10-K for the year ended December 31, 2012 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2013.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of June 30, 2013 and December 31, 2012, the results of its operations for the three and six months ended June 30, 2013 and 2012 and its cash flows for the six months ended June 30, 2013 and 2012. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

6

2 · Segment financial information

(in thousands)	Electric utility		Bank		Other			Total
Three months ended June 30, 2013
Revenues from external customers	$	730,682	$	66,027	$	21		$	796,730
Intersegment revenues (eliminations)	6		—		(6		)	—
Revenues	730,688		66,027		15			796,730
Income (loss) before income taxes	47,517		24,705		(7,507		)	64,715
Income taxes (benefit)	18,325		8,786		(3,457		)	23,654
Net income (loss)	29,192		15,919		(4,050		)	41,061
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	28,693		15,919		(4,024		)	40,588
Six months ended June 30, 2013
Revenues from external customers	$	1,449,949	$	130,783	$	62		$	1,580,794
Intersegment revenues (eliminations)	12		—		(12		)	—
Revenues	1,449,961		130,783		50			1,580,794
Income (loss) before income taxes	86,839		46,457		(15,767		)	117,529
Income taxes (benefit)	32,719		16,383		(6,786		)	42,316
Net income (loss)	54,120		30,074		(8,981		)	75,213
Preferred stock dividends of subsidiaries	998		—		(52		)	946
Net income (loss) for common stock	53,122		30,074		(8,929		)	74,267
Assets (at June 30, 2013)	5,161,819		5,068,771		7,555			10,238,145
Three months ended June 30, 2012
Revenues from external customers	$	789,539	$	64,721	$	8		$	854,268
Intersegment revenues (eliminations)	13		—		(13		)	—
Revenues	789,552		64,721		(5		)	854,268
Income (loss) before income taxes	48,501		21,873		(8,277		)	62,097
Income taxes (benefit)	18,626		7,684		(3,486		)	22,824
Net income (loss)	29,875		14,189		(4,791		)	39,273
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	29,376		14,189		(4,765		)	38,800
Six months ended June 30, 2012
Revenues from external customers	$	1,539,113	$	129,973	$	42		$	1,669,128
Intersegment revenues (eliminations)	49		—		(49		)	—
Revenues	1,539,162		129,973		(7		)	1,669,128
Income (loss) before income taxes	93,708		45,337		(16,861		)	122,184
Income taxes (benefit)	36,034		15,271		(7,183		)	44,122
Net income (loss)	57,674		30,066		(9,678		)	78,062
Preferred stock dividends of subsidiaries	998		—		(52		)	946
Net income (loss) for common stock	56,676		30,066		(9,626		)	77,116
Assets (at December 31, 2012)	5,108,793		5,041,673		(1,334		)	10,149,132

Intercompany electricity sales of the electric utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.

Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income for common stock.

3 · Electric utility subsidiary

For consolidated HECO financial information, including its commitments and contingencies, see HECO’s consolidated financial statements beginning on page 30 through Note 10 on page 44.

7

4 · Bank subsidiary

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data

	Three months ended June 30					Six months ended June 30
(in thousands)	2013			2012		2013		2012
Interest income
Interest and fees on loans	$	43,624		$	44,473	$	86,227	$	89,361
Interest on investment and mortgage-related securities	3,234			3,297		6,698		7,102
Total interest income	46,858			47,770		92,925		96,463
Interest expense
Interest on deposit liabilities	1,296			1,696		2,608		3,475
Interest on other borrowings	1,178			1,214		2,342		2,475
Total interest expense	2,474			2,910		4,950		5,950
Net interest income	44,384			44,860		87,975		90,513
Provision (credit) for loan losses	(959		)	2,378		899		5,924
Net interest income after provision (credit) for loan losses	45,343			42,482		87,076		84,589
Noninterest income
Fees from other financial services	7,996			7,463		15,639		14,800
Fee income on deposit liabilities	4,433			4,322		8,747		8,600
Fee income on other financial products	1,780			1,532		3,574		3,081
Mortgage banking income	2,003			2,185		5,349		4,220
Gain on sale of securities	1,226			134		1,226		134
Other income	1,731			1,315		3,323		2,675
Total noninterest income	19,169			16,951		37,858		33,510
Noninterest expense
Compensation and employee benefits	20,063			18,696		40,151		37,342
Occupancy	4,219			4,241		8,342		8,466
Data processing	2,827			2,489		5,814		4,600
Services	2,328			2,221		4,431		4,004
Equipment	1,870			1,807		3,644		3,537
Other expense	8,500			8,106		16,095		14,813
Total noninterest expense	39,807			37,560		78,477		72,762
Income before income taxes	24,705			21,873		46,457		45,337
Income taxes	8,786			7,684		16,383		15,271
Net income	$	15,919		$	14,189	$	30,074	$	30,066

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data

	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012
Net income	$	15,919		$	14,189		$	30,074		$	30,066
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits, of $5,485 and ($721) for the three months ended June 30, 2013 and 2012 and $6,032 and ($572) for the six months ended June 30, 2013 and 2012, respectively	(8,307		)	1,093			(9,135		)	867
Less: reclassification adjustment for net realized gains, included in net income , net of taxes, of $488 and $53 for the three months ended June 30, 2013 and 2012 and $488 and $53 for the six months ended June 30, 2013 and 2012, respectively	(738		)	(81		)	(738		)	(81		)
Retirement benefit plans:
Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $308 and $168 for the three months ended June 30, 2013 and 2012 and $1,732 and $332 for the six months ended June 30, 2013 and 2012, respectively	466			255			2,623			503
Other comprehensive income (loss), net of taxes	(8,579		)	1,267			(7,250		)	1,289
Comprehensive income	$	7,340		$	15,456		$	22,824		$	31,355

8

American Savings Bank, F.S.B.

Balance Sheets Data

(in thousands)	June 30, 2013						December 31, 2012
Assets
Cash and cash equivalents				$	143,912					$	184,430
Available-for-sale investment and mortgage-related securities				560,172						671,358
Investment in stock of Federal Home Loan Bank of Seattle				94,281						96,022
Loans receivable held for investment				3,953,634						3,779,218
Allowance for loan losses				(41,004		)				(41,985		)
Loans receivable held for investment, net				3,912,630						3,737,233
Loans held for sale, at lower of cost or fair value				34,073						26,005
Other				241,513						244,435
Goodwill				82,190						82,190
Total assets				$	5,068,771					$	5,041,673
Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing				$	1,168,937					$	1,164,308
Deposit liabilities—interest-bearing				3,107,306						3,065,608
Other borrowings				187,884						195,926
Other				102,516						117,752
Total liabilities				4,566,643						4,543,594
Commitments and contingencies (see “Litigation” below)
Common stock				334,937						333,712
Retained earnings				189,837						179,763
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains on securities	$	888					$	10,761
Retirement benefit plans	(23,534		)	(22,646		)	(26,157		)	(15,396		)
Total shareholder’s equity				502,128						498,079
Total liabilities and shareholder’s equity				$	5,068,771					$	5,041,673
Other assets
Bank-owned life insurance				$	127,851					$	125,726
Premises and equipment, net				68,124						62,458
Prepaid expenses				4,064						13,199
Accrued interest receivable				13,472						13,228
Mortgage-servicing rights				11,363						10,818
Real estate acquired in settlement of loans, net				2,987						6,050
Other				13,652						12,956
				$	241,513					$	244,435
Other liabilities
Accrued expenses				$	15,456					$	17,103
Federal and state income taxes payable				30,932						35,408
Cashier’s checks				22,737						23,478
Advance payments by borrowers				10,300						9,685
Other				23,091						32,078
				$	102,516					$	117,752

Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.

9

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $138 million and $50 million, respectively, as of June 30, 2013 and $146 million and $50 million, respectively, as of December 31, 2012.

Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the balance sheet. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:

(in millions)	Gross amount of recognized liabilities		Gross amount offset in the Balance Sheet		Net amount of liabilities presented in the Balance Sheet
Repurchase agreements
June 30, 2013	$	138	$	—	$	138
December 31, 2012	146		—		146

	Gross amount not offset in the Balance Sheet
(in millions)	Net amount of liabilities presented in the Balance Sheet		Financial instruments		Cash collateral pledged		Net amount
June 30, 2013
Financial institution	$	50	$	50	$	—	$	—
Commercial account holders	88		88		—		—
Total	$	138	$	138	$	—	$	—
December 31, 2012
Financial institution	$	50	$	50	$	—	$	—
Commercial account holders	96		96		—		—
Total	$	146	$	146	$	—	$	—

Investment and mortgage-related securities portfolio.

Available-for-sale securities.  The book value (amortized cost), gross unrealized gains and losses, estimated fair value and gross unrealized losses (fair value and amount by duration of time in which positions have been held in a continuous loss position) for securities held in ASB’s “available-for-sale” portfolio by major security type were as follows:

			Gross		Gross			Estimated		Gross unrealized losses
	Amortized		unrealized		unrealized			fair		Less than 12 months					12 months or longer
(in thousands)	cost		gains		losses			value		Fair value		Amount			Fair value		Amount
June 30, 2013
Federal agency obligations	$	99,963	$	561	$	(1,460	)	$	99,064	$	30,383	$	(1,460	)	$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	381,281		6,257		(5,494		)	382,044		178,144		(5,494		)	—		—
Municipal bonds	77,455		1,929		(320		)	79,064		26,561		(320		)	—		—
	$	558,699	$	8,747	$	(7,274	)	$	560,172	$	235,088	$	(7,274	)	$	—	$	—
December 31, 2012
Federal agency obligations	$	168,324	$	3,167	$	—		$	171,491	$	—	$	—		$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	407,175		10,412		(204		)	417,383		32,269		(204		)	—		—
Municipal bonds	77,993		4,491		—			82,484		—		—			—		—
	$	653,492	$	18,070	$	(204	)	$	671,358	$	32,269	$	(204	)	$	—	$	—

The unrealized losses on ASB’s investments in mortgage-related securities and obligations issued by federal agencies were caused by interest rate movements. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost basis of the investments. Because ASB does

10

not intend to sell the securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of their amortized costs basis, which may be at maturity, ASB did not consider these investments to be other-than-temporarily impaired at June 30, 2013.

The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.

The following table details the contractual maturities of available-for-sale securities. All positions with variable maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual maturities will likely differ from these contractual maturities because borrowers have the right to prepay obligations with or without prepayment penalties.

June 30, 2013	Amortized cost		Fair value
(in thousands)
Due in one year or less	$	28,120	$	28,192
Due after one year through five years	34,885		35,220
Due after five years through ten years	89,055		90,477
Due after ten years	25,358		24,239
	177,418		178,128
Mortgage-related securities-FNMA,FHLMC and GNMA	381,281		382,044
Total available-for-sale securities	$	558,699	$	560,172

Allowance for loan losses.  ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio. The allowance for loan losses consists of an allocated portion, which estimates credit losses for specifically identified loans and pools of loans, and an unallocated portion.

The allowance for loan losses (balances and changes) and financing receivables were as follows:

	Residential			Commercial real		Home equity line			Residential			Commercial		Residential		Commercial			Consumer
(in thousands)	1-4 family			estate		of credit			land			construction		construction		loans			loans			Unallocated		Total
Six months ended June 30, 2013
Allowance for loan losses:
Beginning balance	$	6,068		$	2,965	$	4,493		$	4,275		$	2,023	$	9	$	15,931		$	4,019		$	2,202	$	41,985
Charge-offs	(1,056		)	—		(738		)	(235		)	—		—		(1,350		)	(1,404		)	—		(4,783		)
Recoveries	1,225			—		256			500			—		—		612			310			—		2,903
Provision	120			1,152		998			(2,353		)	282		5		1,114			(526		)	107		899
Ending balance	$	6,357		$	4,117	$	5,009		$	2,187		$	2,305	$	14	$	16,307		$	2,399		$	2,309	$	41,004
Ending balance: individually evaluated for impairment	$	944		$	820	$	—		$	1,641		$	—	$	—	$	3,367		$	—		$	—	$	6,772
Ending balance: collectively evaluated for impairment	$	5,413		$	3,297	$	5,009		$	546		$	2,305	$	14	$	12,940		$	2,399		$	2,309	$	34,232
Financing Receivables:
Ending balance	$	2,001,035		$	382,735	$	673,727		$	21,836		$	50,114	$	9,664	$	719,519		$	104,759		$	—	$	3,963,389
Ending balance: individually evaluated for impairment	$	21,417		$	3,811	$	837		$	16,041		$	—	$	—	$	21,431		$	20		$	—	$	63,557
Ending balance: collectively evaluated for impairment	$	1,979,618		$	378,924	$	672,890		$	5,795		$	50,114	$	9,664	$	698,088		$	104,739		$	—	$	3,899,832
Year ended December 31, 2012
Allowance for loan losses:
Beginning balance	$	6,500		$	1,688	$	4,354		$	3,795		$	1,888	$	4	$	14,867		$	3,806		$	1,004	$	37,906
Charge-offs	(3,183		)	—		(716		)	(2,808		)	—		—		(3,606		)	(2,517		)	—		(12,830		)
Recoveries	1,328			—		108			1,443			—		—		649			498			—		4,026
Provision	1,423			1,277		747			1,845			135		5		4,021			2,232			1,198		12,883
Ending balance	$	6,068		$	2,965	$	4,493		$	4,275		$	2,023	$	9	$	15,931		$	4,019		$	2,202	$	41,985
Ending balance: individually evaluated for impairment	$	384		$	535	$	—		$	3,221		$	—	$	—	$	2,659		$	—		$	—	$	6,799
Ending balance: collectively evaluated for impairment	$	5,684		$	2,430	$	4,493		$	1,054		$	2,023	$	9	$	13,272		$	4,019		$	2,202	$	35,186
Financing Receivables:
Ending balance	$	1,866,450		$	375,677	$	630,175		$	25,815		$	43,988	$	6,171	$	721,349		$	121,231		$	—	$	3,790,856
Ending balance: individually evaluated for impairment	$	25,279		$	6,751	$	1,560		$	18,563		$	—	$	—	$	20,298		$	22		$	—	$	72,473
Ending balance: collectively evaluated for impairment	$	1,841,171		$	368,926	$	628,615		$	7,252		$	43,988	$	6,171	$	701,051		$	121,209		$	—	$	3,718,383

11

Credit quality.  ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial and industrial, commercial real estate and commercial construction loans.

A dual ten-point risk rating system is used to reflect the probability of default (borrower risk rating) and loss given default (transaction risk rating). The borrower risk rating addresses risk presented by the individual borrower and is based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting quality and industry/economic factors. Separately, the transaction risk rating addresses risk in the transaction and is a function of the type of collateral control exercised over the collateral, loan structure, guarantees, and other structural support or enhancements to the loan.

The numerical representation of the risk categories are:

1- Substantially risk free

2- Minimal risk

3- Modest risk

4- Better than average risk

5- Average risk

6- Acceptable risk

7- Special mention

8- Substandard

9- Doubtful

10- Loss

Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral.

The credit risk profile by internally assigned grade for loans was as follows:

	June 30, 2013						December 31, 2012
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	319,751	$	44,703	$	629,293	$	314,182	$	39,063	$	638,854
Special mention	36,141		—		19,655		25,437		4,925		24,511
Substandard	23,032		5,411		66,925		29,308		—		53,538
Doubtful	3,811		—		3,646		6,750		—		4,446
Loss	—		—		—		—		—		—
Total	$	382,735	$	50,114	$	719,519	$	375,677	$	43,988	$	721,349

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The credit risk profile based on payment activity for loans was as follows:

(in thousands)	30-59 days past due		60-89 days past due		Greater than 90 days		Total past due		Current		Total financing receivables		Recorded investment> 90 days and accruing
June 30, 2013
Real estate loans:
Residential 1-4 family	$	2,656	$	580	$	17,899	$	21,135	$	1,979,900	$	2,001,035	$	—
Commercial real estate	—		—		3,811		3,811		378,924		382,735		—
Home equity line of credit	923		126		975		2,024		671,703		673,727		—
Residential land	167		852		9,493		10,512		11,324		21,836		2,187
Commercial construction	—		—		—		—		50,114		50,114		—
Residential construction	—		—		—		—		9,664		9,664		—
Commercial loans	577		834		5,528		6,939		712,580		719,519		—
Consumer loans	408		161		136		705		104,054		104,759		—
Total loans	$	4,731	$	2,553	$	37,842	$	45,126	$	3,918,263	$	3,963,389	$	2,187
December 31, 2012
Real estate loans:
Residential 1-4 family	$	6,353	$	1,741	$	24,054	$	32,148	$	1,834,302	$	1,866,450	$	—
Commercial real estate	85		—		6,750		6,835		368,842		375,677		—
Home equity line of credit	1,077		142		1,319		2,538		627,637		630,175		—
Residential land	2,851		75		7,788		10,714		15,101		25,815		—
Commercial construction	—		—		—		—		43,988		43,988		—
Residential construction	—		—		—		—		6,171		6,171		—
Commercial loans	3,052		2,814		1,098		6,964		714,385		721,349		131
Consumer loans	598		348		424		1,370		119,861		121,231		242
Total loans	$	14,016	$	5,120	$	41,433	$	60,569	$	3,730,287	$	3,790,856	$	373

The credit risk profile based on nonaccrual loans and accruing loans 90 days or more past due was as follows:

	June 30, 2013				December 31, 2012
(in thousands)	Nonaccrual loans		Accruing loans 90 days or more past due		Nonaccrual loans		Accruing loans 90 days or more past due
Real estate loans:
Residential 1-4 family	$	21,392	$	—	$	26,721	$	—
Commercial real estate	3,811		—		6,750		—
Home equity line of credit	2,160		—		2,349		—
Residential land	7,565		2,187		8,561		—
Commercial construction	—		—		—		—
Residential construction	—		—		—		—
Commercial loans	21,935		—		20,222		131
Consumer loans	263		—		284		242
Total	$	57,126	$	2,187	$	64,887	$	373

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The total carrying amount and the total unpaid principal balance of impaired loans, with and without recorded allowance for loan losses and combined, were as follows:

	June 30, 2013						Three months ended June 30, 2013				Six months ended June 30, 2013
(in thousands)	Recorded investment		Unpaid principal balance		Related Allowance		Average recorded investment		Interest income recognized*		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	10,921	$	14,527	$	—	$	12,380	$	98	$	13,568	$	232
Commercial real estate	—		—		—		—		—		1,604		—
Home equity line of credit	536		1,077		—		637		—		646		—
Residential land	8,429		9,809		—		8,502		122		8,167		219
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	4,306		6,408		—		4,393		1		4,306		1
Consumer loans	20		20		—		20		—		21		—
	24,212		31,841		—		25,932		221		28,312		452
With an allowance recorded
Real estate loans:
Residential 1-4 family	7,172		7,193		944		7,069		75		6,039		176
Commercial real estate	3,811		3,834		820		8,341		151		7,221		151
Home equity line of credit	—		—		—		—		—		—		—
Residential land	6,229		6,356		1,641		6,379		89		7,632		202
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	17,125		18,427		3,367		15,073		—		15,147		5
Consumer loans	—		—		—		—		—		—		—
	34,337		35,810		6,772		36,862		315		36,039		534
Total
Real estate loans:
Residential 1-4 family	18,093		21,720		944		19,449		173		19,607		408
Commercial real estate	3,811		3,834		820		8,341		151		8,825		151
Home equity line of credit	536		1,077		—		637		—		646		—
Residential land	14,658		16,165		1,641		14,881		211		15,799		421
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	21,431		24,835		3,367		19,466		1		19,453		6
Consumer loans	20		20		—		20		—		21		—
	$	58,549	$	67,651	$	6,772	$	62,794	$	536	$	64,351	$	986

14

	December 31, 2012						Year ended December 31, 2012
(in thousands)	Recorded investment		Unpaid principal balance		Related allowance		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	14,633	$	20,247	$	—	$	16,688	$	294
Commercial real estate	2,929		2,929		—		7,771		237
Home equity line of credit	581		1,374		—		632		1
Residential land	7,691		10,624		—		21,589		1,185
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	4,265		6,994		—		24,605		986
Consumer loans	21		21		—		23		—
	30,120		42,189		—		71,308		2,703
With an allowance recorded
Real estate loans:
Residential 1-4 family	4,803		4,803		384		4,204		250
Commercial real estate	3,821		3,840		535		1,295		—
Home equity line of credit	—		—		—		26		—
Residential land	9,984		10,364		3,221		7,428		575
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	16,033		16,912		2,659		8,429		23
Consumer loans	—		—		—		—		—
	34,641		35,919		6,799		21,382		848
Total
Real estate loans:
Residential 1-4 family	19,436		25,050		384		20,892		544
Commercial real estate	6,750		6,769		535		9,066		237
Home equity line of credit	581		1,374		—		658		1
Residential land	17,675		20,988		3,221		29,017		1,760
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	20,298		23,906		2,659		33,034		1,009
Consumer loans	21		21		—		23		—
	$	64,761	$	78,108	$	6,799	$	92,690	$	3,551

*Since loan was classified as impaired.

Troubled debt restructurings.  A loan modification is deemed to be a troubled debt restructuring (TDR) when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty. When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.

ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period, and temporary deferral of principal payments. ASB does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.

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All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment:  (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell, or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.

Loan modifications that occurred were as follows for the indicated periods:

	Three months ended June 30, 2013					Six months ended June 30, 2013
	Number of	Outstanding recorded investment				Number of	Outstanding recorded investment
(dollars in thousands)	contracts	Pre-modification		Post-modification		contracts	Pre-modification		Post-modification
Troubled debt restructurings
Real estate loans:
Residential 1-4 family	14	$	4,645	$	4,775	18	$	5,767	$	5,838
Commercial real estate	—	—		—		—	—		—
Home equity line of credit	—	—		—		4	462		215
Residential land	4	1,116		1,163		7	2,040		2,031
Commercial loans	3	714		714		3	714		714
Consumer loans	—	—		—		—	—		—
	21	$	6,475	$	6,652	32	$	8,983	$	8,798

	Three months ended June 30, 2012					Six months ended June 30, 2012
	Number of	Outstanding recorded investment				Number of	Outstanding recorded investment
(dollars in thousands)	contracts	Pre-modification		Post-modification		contracts	Pre-modification		Post-modification
Troubled debt restructurings
Real estate loans:
Residential 1-4 family	15	$	3,056	$	2,872	22	$	4,469	$	4,282
Commercial real estate	—	—		—		—	—		—
Home equity line of credit	—	—		—		—	—		—
Residential land	8	1,774		1,580		15	3,508		3,021
Commercial loans	8	1,869		1,869		14	2,029		2,029
Consumer loans	—	—		—		—	—		—
	31	$	6,699	$	6,321	51	$	10,006	$	9,332

ASB did not have any loans modified in TDRs that experienced a payment default of 90 or more days in 2013, and for which the payment default occurred within one year of the modification. Loans modified in TDRs that experienced a payment default of 90 days or more in 2012, and for which the payment default occurred within one year of the modification, were as follows:

	Three months ended June 30, 2012			Six months ended June 30, 2012
(dollars in thousands)	Number of contracts	Recorded investment		Number of contracts	Recorded investment
Troubled debt restructurings that  subsequently defaulted
Real estate loans:
Residential 1-4 family	—	$	—	—	$	—
Commercial real estate	—	—		—	—
Home equity line of credit	—	—		—	—
Residential land	—	—		—	—
Commercial loans	—	—		3	847
Consumer loans	—	—		—	—
	—	$	—	3	$	847

The three commercial loans that subsequently defaulted were modified by temporarily lowering the monthly payments and deferring principal payments for a short period of time. There are no commitments to lend additional funds to borrowers whose loan terms have been impaired or modified in TDRs as of June 30, 2013.

Litigation.  In March 2011, a purported class action lawsuit was filed in the First Circuit Court of the State of Hawaii by a customer who claimed that ASB had improperly charged overdraft fees on debit card transactions. The lawsuit

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is still in its preliminary stage, thus, the probable outcome and range of reasonably possible loss are not determinable at this time.

ASB is subject in the normal course of business to pending and threatened legal proceedings. Management does not anticipate that the aggregate ultimate liability arising out of these pending or threatened legal proceedings will be material to its financial position. However, ASB cannot rule out the possibility that such outcomes could have a material adverse effect on the results of operations or liquidity for a particular reporting period in the future.

5 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information.  For the first six months of 2013, the Company contributed $42 million (primarily by the utilities) to its pension and other postretirement benefit plans, compared to $53 million (primarily by the utilities) in the first six months of 2012. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2013 is $83 million ($81 million by the utilities, $2 million by HEI and nil by ASB), compared to $78 million ($63 million by the utilities, $2 million by HEI and $13 million by ASB) in 2012. In addition, the Company expects to pay directly $2 million ($1 million each by the utilities and HEI) of benefits in 2013, compared to $1 million paid in 2012.

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 improved the plans’ Adjusted Funding Target Attainment Percentage (AFTAP) for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HEI and HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under Employee Retirement Income Security Act of 1974, as amended (ERISA) to be less than the net periodic cost for 2013 and 2014; therefore, the Company expects to contribute the net periodic cost for these years. If the AFTAP 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. However, the HEI Retirement Plan met the threshold requirements in each of 2012 and 2013 so that the more conservative assumptions do not apply for either the 2013 or 2014 valuation of plan liabilities for purposes of calculating the minimum required contribution. Other factors could cause changes to the required contribution levels.

The components of net periodic benefit cost for consolidated HEI were as follows:

	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	14,121		$	11,397		$	1,103		$	1,008		$	28,210		$	21,588		$	2,152		$	2,104
Interest cost	16,307			16,973			1,855			2,223			32,413			33,744			3,786			4,504
Expected return on plan assets	(18,182		)	(17,736		)	(2,521		)	(2,557		)	(36,267		)	(35,592		)	(5,083		)	(5,178		)
Amortization of prior service gain	(25		)	(82		)	(449		)	(449		)	(49		)	(163		)	(897		)	(897		)
Amortization of net actuarial loss	9,499			6,403			284			299			19,318			12,826			805			752
Net periodic benefit cost	21,720			16,955			272			524			43,625			32,403			763			1,285
Impact of PUC D&Os	(5,286		)	(4,977		)	(187		)	(416		)	(12,722		)	(8,834		)	(584		)	(1,096		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	16,434		$	11,978		$	85		$	108		$	30,903		$	23,569		$	179		$	189

Consolidated HEI recorded retirement benefits expense of $23 million and $17 million in the first six months of 2013 and 2012, respectively, and charged the remaining amounts primarily to electric utility plant.

The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with

17

GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

Defined contribution plans information.  For the first six months of 2013 and 2012, the Company’s expense for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan was $2.0 million and $1.8 million, respectively, and cash contributions were $3.0 million and $2.7 million, respectively.

6 · Share-based compensation

Under the 2010 Equity and Incentive Plan (EIP), HEI can issue an aggregate of 4 million shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted stock units, performance shares and other share-based and cash-based awards.

As of June 30, 2013, there were 3.6 million shares remaining available for future issuance under the EIP of which an estimated 2.6 million shares could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals under long-term incentive plans (based on the assumption that long-term incentive plan (LTIP) awards are achieved at maximum levels).

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 1,000 shares of common stock (based on the June 30, 2013 market price of shares as the price on the exercise dates) were outstanding as of June 30, 2013 to selected employees in the form of stock appreciation rights (SARs) and dividend equivalents. As of May 11, 2010 (when the EIP became effective), no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered under the SOIP will be deregistered and delisted.

The Company’s share-based compensation expense and related income tax benefit were as follows:

	Three months ended June 30				Six months ended June 30
(in millions)	2013		2012		2013		2012
Share-based compensation expense (1)	$	1.1	$	1.7	$	3.0	$	3.5
Income tax benefit	0.4		0.6		1.1		1.2

(1)The Company has not capitalized any share-based compensation cost.

Nonqualified stock options.  As of December 31, 2012, nonqualified stock options (NQSOs) outstanding totaled 14,000 (representing the same number of underlying shares), with a weighted-average exercise price of $20.49. As of June 30, 2013, there were no NQSOs outstanding.

NQSO activity and statistics were as follows:

	Three months ended  June 30				Six months ended June 30
(dollars in thousands, except prices)	2013		2012		2013		2012
Shares exercised	12,000		21,500		14,000		33,500
Weighted-average exercise price	$	20.49	$	20.93	$	20.49	$	21.20
Cash received from exercise	$	246	$	450	$	287	$	710
Intrinsic value of shares exercised (1)	$	113	$	174	$	128	$	265
Tax benefit realized for the deduction of exercises	$	44	$	68	$	50	$	103

(1)Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

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Stock appreciation rights.  Information about HEI’s SARs was as follows:

June 30, 2013		Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices	Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price
2004	$26.02	62,000	0.8	$	26.02
2005	26.18	102,000	1.8	26.18
	$26.02 –26.18	164,000	1.4	$	26.12

As of December 31, 2012, the shares underlying SARs outstanding totaled 164,000, with a weighted-average exercise price of $26.12. As of June 30, 2013, all SARs outstanding were exercisable and had no aggregate intrinsic value.

SARs activity and statistics were as follows:

	Three months ended June 30			Six months ended June 30
(dollars in thousands, except prices)	2013	2012		2013	2012
Shares underlying SARS exercised	—	112,000		—	112,000
Weighted-average price of shares exercised	—	$	26.17	—	$	26.17
Intrinsic value of shares exercised (1)	—	$	194	—	$	194
Tax benefit realized for the deduction of exercises	—	$	76	—	$	76

(1)Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalent rights exceeds the exercise price of the right.

Restricted shares and restricted stock awards.  Information about HEI’s grants of restricted shares and restricted stock awards was as follows:

	Three months ended June 30							Six months ended June 30
	2013			2012				2013			2012
	Shares	(1)		Shares		(1)		Shares	(1)		Shares		(1)
Outstanding, beginning of period	9,005	$	22.21	38,107		$	23.83	9,005	$	22.21	46,807		$	24.45
Granted	—	—		—		—		—	—		—		—
Vested	—	—		(23,300	)	24.71		—	—		(32,000	)	25.38
Forfeited	—	—		—		—		—	—		—		—
Outstanding, end of period	9,005	$	22.21	14,807		$	22.45	9,005	$	22.21	14,807		$	22.45

(1) Weighted-average grant-date fair value per share based on the closing or average price of HEI common stock on the date of grant.

As of June 30, 2013, there was $0.1 million of total unrecognized compensation cost related to nonvested restricted shares and restricted stock awards. The cost is expected to be recognized over a weighted-average period of 1.4 years.

For the first six months of 2012, total restricted stock vested had a grant-date fair value of $0.8 million and the tax benefits realized for tax deductions related to restricted stock awards were $0.2 million.

Restricted stock units.  Information about HEI’s grants of restricted stock units was as follows:

	Three months ended June 30								Six months ended June 30
	2013				2012				2013				2012
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, beginning of period	301,145		$	25.15	318,551		$	22.80	315,094		$	22.82	247,286		$	21.80
Granted	—		—		2,334	(2)	26.75		107,231	(3)	26.89		94,846	(4)	26.00
Vested	(832	)	26.60		(250	)	26.25		(114,044	)	20.34		(21,497	)	24.97
Forfeited	—		—		(1,564	)	25.53		(7,968	)	25.26		(1,564	)	25.53
Outstanding, end of period	300,313		$	25.15	319,071		$	22.81	300,313		$	25.15	319,071		$	22.81

(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

(2)Total weighted-average grant-date fair value of $62,000.

(3)Total weighted-average grant-date fair value of $2.9 million.

(4)Total weighted average grant date fair value of $2.5 million.

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As of June 30, 2013, there was $4.9 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.8 years.

For the first six months of 2013 and 2012, total restricted stock units that vested and related dividends had a grant-date fair value of $3.5 million and $0.6 million, respectively, and the related tax benefits were $1.0 million and $0.2 million, respectively.

LTIP payable in stock.  The 2011-2013 LTIP, 2012-2014 LTIP and the 2013-2015 LTIP provide for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2011-2013 LTIP, the 2012-2014 LTIP and the 2013-2015 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on common equity (ROACE), HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on the applicable three-year averages.

LTIP linked to TRS.  Information about HEI’s LTIP grants linked to TRS was as follows:

	Three months ended June 30							Six months ended June 30
	2013			2012				2013				2012
	Shares	(1)		Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, beginning of period	235,064	$	32.87	239,470		$	29.12	239,256		$	29.12	197,385		$	25.94
Granted	—	—		1,442		30.71		89,533		32.69		78,924	(2)	30.71
Vested	—	—		—		—		(87,753	)	22.45		(35,397	)	14.85
Forfeited	—	—		(1,505	)	30.39		(5,972	)	32.96		(1,505	)	30.39
Outstanding, end of period	235,064	$	32.87	239,407		$	29.12	235,064		$	32.87	239,407		$	29.12

(1)Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.

(2)Total weighted-average grant-date fair value of $2.4 million.

On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 89,533 shares of HEI common stock (based on the grant date price of $26.89 and target TRS performance levels) with a weighted-average grant date fair value of $2.9 million based on the weighted-average grant date fair value per share of $32.69.

The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:

	2013	2012
Risk-free interest rate	0.38%	0.33%
Expected life in years	3	3
Expected volatility	19.4%	25.3%
Range of expected volatility for Peer Group	12.4% to 25.3%	15.5% to 34.5%
Grant date fair value (per share)	$32.69	$30.71

For the six months ended June 30, 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $2.2 million and $0.6 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively.

As of June 30, 2013, there was $3.6 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.6 years.

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LTIP awards linked to other performance conditions.  Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:

	Three months ended June 30								Six months ended June 30
	2013				2012				2013				2012
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, beginning of period	341,824		$	26.00	297,602		$	23.92	247,175		$	25.04	182,498		$	22.63
Granted	—		—		3,600	(2)	26.75		118,895		26.89		118,704	(3)	26.00
Vested	—		—		—		—		(18,275	)	18.95		—		—
Cancelled	(37,351	)	24.96		—		—		(37,351	)	24.96		—		—
Forfeited	—		—		(6,018	)	24.23		(5,971	)	25.94		(6,018	)	24.23
Outstanding, end of period	304,473		$	26.12	295,184		$	23.95	304,473		$	26.12	295,184		$	23.95

(1)Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

(2)Total weighted-average grant-date fair value of $0.1 million (at target performance levels).

(3)Total weighted-average grant-date fair value of $3.1 million (at target performance levels).

On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 118,895 shares of HEI common stock (based on the grant date price of $26.89 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.2 million based on the weighted-average grant date fair value per share of $26.89.

For the six months ended June 30, 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.

As of June 30, 2013, there was $4.5 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.7 years.

7 · Earnings per share and shareholders’ equity

Earnings per share.  Under the two-class method of computing earnings per share (EPS), EPS was comprised as follows for both participating securities and unrestricted common stock:

	Three months ended June 30				Six months ended June 30
	2013		2012		2013		2012
	Basic and diluted		Basic and diluted		Basic and diluted		Basic and diluted
Distributed earnings	$	0.31	$	0.31	$	0.62	$	0.62
Undistributed earnings (loss)	0.10		0.09		0.13		0.18
	$	0.41	$	0.40	$	0.75	$	0.80

As of June 30, 2013, the antidilutive effects of SARs of 102,000 shares of HEI common stock for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of dilutive EPS. As of June 30, 2012, there were no shares that were antidilutive.

Shareholders’ equity.

Equity forward transaction.  On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering on that date of 6.1 million shares of HEI common stock at $26.75 per share. On March 19, 2013, HEI common stock closed at $27.01 per share. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with the resulting additional 0.9 million shares of HEI common stock.

The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans. Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of

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the equity forward transactions, to the extent that the transactions are physically settled, HEI would be required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transactions. The equity forward transactions must be settled fully by March 25, 2015. Except in specified circumstances or events that would require physical settlement, HEI is able to elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to March 25, 2015.

The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled, and at that time HEI will record the proceeds, if any, in equity. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in ASC 480 and ASC 815 and that they qualified for an exception from derivative accounting under ASC 815 because the forward sale transactions were indexed to its own stock. HEI anticipates settling the equity forward transactions through physical settlement.

At June 30, 2013, the equity forward transactions could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $178 million. At June 30, 2013, the equity forward transactions could also have been cash settled, with delivery of cash of approximately $8 million (which amount includes $7 million of underwriting discount) to the forward counterparty, or net share settled with delivery of approximately 282,000 shares of common stock to the forward counterparty.

Prior to their settlement, the equity forward transactions will be reflected in HEI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of HEI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transactions less the number of shares that could be purchased by HEI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transactions (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transactions are outstanding.

Accordingly, before physical or net share settlement of the equity forward transactions, and subject to the occurrence of certain events, HEI anticipates that the forward sale agreement and additional forward sale agreement will have a dilutive effect on HEI’s earnings per share only during periods when the applicable average market price per share of HEI’s common stock is above the per share adjusted forward sale price, as described above. However, if HEI decides to physically or net share settle the forward sale agreement and additional forward sale agreement, any delivery by HEI of shares upon settlement could result in dilution to HEI’s earnings per share.

For the six months ended June 30, 2013, the equity forward transactions did not have a material dilutive effect on HEI’s earnings per share.

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Accumulated other comprehensive income.  Reclassifications out of accumulated other comprehensive income/(loss) (AOCI) were as follows:

	Amount reclassified from AOCI
	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012			Affected line item in the Statement of Income
Net realized gains on securities	$	(738	)	$	(81	)	$	(738	)	$	(81	)	Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	59			59			118			118			Interest expense
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	5,680			3,768			11,701			7,641			See Note 5 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(4,999		)	(3,289		)	(10,312		)	(6,684		)	See Note 5 for additional details
Total reclassifications	$	2		$	457		$	769		$	994

8 · Commitments and contingencies

See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.

9 · 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 is 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.

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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:

Short term borrowings—other than bank.  The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities.  To determine the fair value of investment securities held in ASB’s available-for-sale portfolio, independent third-party vendor or broker pricing is used on an unadjusted basis. Prices for investments and mortgage-related securities are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA (to be announced) prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security.  The pricing vendor corroborates its finding on an on-going basis by monitoring market activity and events.

Third party pricing services provide security prices in good faith using rigorous methodologies; however, they do not warrant or guarantee the adequacy or accuracy of their information. Therefore, ASB utilizes a separate third party pricing vendor to corroborate security pricing of the first pricing vendor. If the pricing differential between the two pricing sources exceeds an established threshold, a pricing inquiry will be sent to both vendors or to an independent broker to determine a price that can be supported based on observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.

Loans receivable.  The estimated fair value of loans receivable is determined based on characteristics such as loan category, repricing features and remaining maturity, and includes prepayment estimates.

For residential real estate loans, fair values were estimated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics and remaining maturity.

For other types of loans, fair values were estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.

The fair value of all loans was adjusted to reflect current assessments of loan collectability. Also see “Fair value measurements on a nonrecurring basis” below.

Deposit liabilities.  The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

Other bank borrowings.  Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

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 and from discounting the future cash flows using the current rates offered for debt of the same or similar remaining maturities.

Derivative financial instruments.  See “Fair value measurements on a recurring basis” below.

Off-balance sheet financial instruments.  The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new

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commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements.

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

	Carrying or notional		Estimated fair value
(in thousands)	amount		Level 1		Level 2		Level 3		Total
June 30, 2013
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment and mortgage-related securities	560,172		—		560,172		—		560,172
Investment in stock of Federal Home Loan Bank of Seattle	94,281		—		94,281		—		94,281
Loans receivable, net	3,946,703		—		—		4,075,387		4,075,387
Derivative assets	54,192		625		538		—		1,163
Financial liabilities
Deposit liabilities	4,276,243		—		4,279,284		—		4,279,284
Short-term borrowings—other than bank	125,786		—		125,786		—		125,786
Other bank borrowings	187,884		—		200,813		—		200,813
Long-term debt, net—other than bank	1,422,877		—		1,450,844		—		1,450,844
Derivative liabilities	19,350		—		525		—		525
December 31, 2012
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment and mortgage-related securities	671,358		—		671,358		—		671,358
Investment in stock of Federal Home Loan Bank of Seattle	96,022		—		96,022		—		96,022
Loans receivable, net	3,763,238		—		—		3,957,752		3,957,752
Financial liabilities
Deposit liabilities	4,229,916		—		4,235,527		—		4,235,527
Short-term borrowings—other than bank	83,693		—		83,693		—		83,693
Other bank borrowings	195,926		—		212,163		—		212,163
Long-term debt, net—other than bank	1,422,872		—		1,481,004		—		1,481,004

As of June 30, 2013 and December 31, 2012, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.6 billion and $1.5 billion, respectively, and their estimated fair value on such dates were $0.1 million and $1.2 million, respectively. As of June 30, 2013 and December 31, 2012, loans serviced by ASB for others had notional amounts of $1.3 billion and the estimated fair value of the servicing rights for such loans was $14.0 million and $11.9 million, respectively.

Fair value measurements on a recurring basis.

Securities.  While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.

Derivative financial instruments.  ASB enters into interest rate lock commitments (IRLC) for residential mortgage loans, which commit ASB to lend funds to a potential borrower at a specific interest rate and within a specified period of time. The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.

ASB utilizes forward commitments as economic hedges against potential changes in the values of the IRLCs and loans held for sale. To reduce the impact of price fluctuations of IRLC and mortgage loans held for sale, ASB will purchase to be announced (TBA) mortgage-backed securities forward commitments, mandatory and best effort

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commitments. These commitments help protect our loan sale profit margin from fluctuations in interest rates.  The changes in the fair value of these commitments are recognized as part of mortgage banking income on the consolidated statements of income. TBA forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined similarly to the IRLCs using quoted prices in the market place that are observable and are classified as Level 2 measurements.

Assets measured at fair value on a recurring basis were as follows:

	Fair value measurements using
	Quoted prices in		Significant other		Significant
	active markets for identical		observable  inputs		unobservable inputs
(in thousands)	assets (Level 1)		(Level 2)		(Level 3)
June 30, 2013
Money market funds (“other” segment)	$	—	$	10	$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	382,044	$	—
Federal agency obligations	—		99,064		—
Municipal bonds	—		79,064		—
	$	—	$	560,172	$	—
Derivative assets (1)
Interest rate lock commitments	$	—	$	211	$	—
Forward commitments	625		327		—
	$	625	$	538	$	—
Derivative liabilities (1)
Interest rate lock commitments	$	—	$	473	$	—
Forward commitments	—		52		—
	$	—	$	525	$	—
December 31, 2012
Money market funds (“other” segment)	$	—	$	10	$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	417,383	$	—
Federal agency obligations	—		171,491		—
Municipal bonds	—		82,484		—
	$	—	$	671,358	$	—

(1)  Derivatives are carried at fair value with changes in value reflected in the balance sheet in other assets or other liabilities and included in mortgage banking income.

Fair value measurements on a nonrecurring basis.  From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments based on the current appraised value of the collateral securing the loans or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. During the first six months of 2013, it was not required that a measurement of the fair value of goodwill be calculated and goodwill was not measured at fair value.

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Assets measured at fair value on a nonrecurring basis were as follows:

			Fair value measurements
(in millions)	Balance		Level 1		Level 2		Level 3
Loans
June 30, 2013	$	17	$	—	$	—	$	17
December 31, 2012	21		—		—		21
Real estate acquired in settlement of loans
June 30, 2013	$	2	—		—		$	2
December 31, 2012	3		—		—		3

For the first six months of 2013 and 2012, there were no adjustments to fair value for ASB’s loans held for sale.

Residential loans.  The fair value of ASB’s residential loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

Home equity lines of credit.  The fair value of ASB’s home equity lines of credit that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

Commercial loans.  The fair value of ASB’s commercial loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, the value placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.

Real estate acquired in settlement of loans.  The fair value of ASB’s real estate acquired in settlement of loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

For loans and real estate acquired in settlement of loans classified as Level 3 as of June 30, 2013, the significant unobservable inputs used in the fair value measurement were as follows:

($ in thousands)	Fair value at June 30, 2013		Valuation technique	Significant unobservable input	Significant unobservable  input value
Residential loans	$	13,840	Fair value of property or collateral	Appraised value	13 - 96%
Home equity lines of credit	536		Fair value of property or collateral	Appraised value	25 - 82%
Commercial loan	220		Fair value of property or collateral	Insurance proceeds	59%
Commercial loans	892		Fair value of property or collateral	Fair value of business assets	37 - 92%
Commercial loan	1,739		Discounted cash flow	Present value of expected future cash flows based on anticipated debt restructuring Discount rate	Paydown of loan — 59% 4.5%
Total commercial loans	2,851
Real estate acquired in settlement of loans	2,036		Fair value of property or collateral	Appraised value	81 — 100%

Significant increases (decreases) in any of those inputs in isolation would result in significantly higher (lower) fair value measurement.

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10 · Cash flows

Six months ended June 30	2013		2012
(in millions)
Supplemental disclosures of cash flow information
Interest paid to non-affiliates	$	43	$	42
Income taxes paid	1		6
Supplemental disclosures of noncash activities
Common stock dividends reinvested in HEI common stock (1)	12		12
Increases in common stock related to director and officer compensatory plans	1		4
Additions to electric utility property, plant and equipment - Unpaid invoices and other	5		12
Real estate acquired in settlement of loans	3		5
Loans transferred from held-for-investment to held-for-sale	25		—

(1)The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions.

11 · Recent accounting pronouncements

Obligations resulting from joint and several liability.  In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.

The Company will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.

Unrecognized tax benefit.  In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which clarifies that a liability for an unrecognized tax benefit should be presented as a reduction of a deferred tax asset when settlement of the liability with the taxing authority results in the reduction of a net operating loss or tax credit carryforward. ASU No. 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.

The Company will prospectively adopt ASU No. 2013-11 in the first quarter of 2014 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.

12 · Credit agreement and long-term debt

Credit agreement.  HEI maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.

Changes in long-term debt.

March 6, 2013 notes.  On March 6, 2013, HEI entered into a First Supplement (the First Supplement) to the Master Note Purchase Agreement dated March 24, 2011 (the Note Agreement). Under the First Supplement, HEI issued $50 million of its unsecured, 3.99% Series 2013A Senior Notes, due March 6, 2023, via a private placement with The Prudential Insurance Company of America, Prudential Arizona Reinsurance Captive Company and The Lincoln National Life Insurance Company.

The Note Agreement, as modified by the First Supplement (which includes representations that supersede and supplement the representations in the Note Agreement), contains customary representations and warranties,

28

affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the Notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s existing amended revolving noncollateralized credit agreement described above and in HEI’s Form 10-K for the year ended December 31, 2012. For example, under the Note Agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less (actual ratio of 18% as of June 30, 2013, as calculated under the agreement) or “Consolidated Net Worth” of at least $975 million (actual Net Worth of $1.7 billion as of June 30, 2013, as calculated under the agreement).

The net proceeds from the issuance of the Notes were used by HEI to refinance $50 million of its unsecured, 5.25% Medium-Term Notes, Series D, which matured on March 7, 2013.

29

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012
Operating revenues	$	728,793		$	787,685		$	1,444,990		$	1,535,623
Operating expenses
Fuel oil	289,278			331,064			594,378			658,903
Purchased power	178,444			188,352			331,808			353,141
Other operation	66,184			64,516			137,607			126,365
Maintenance	27,340			31,235			57,042			61,273
Depreciation	38,590			36,133			76,870			72,615
Taxes, other than income taxes	68,759			76,304			136,446			147,299
Income taxes	18,333			18,574			32,428			35,939
Total operating expenses	686,928			746,178			1,366,579			1,455,535
Operating income	41,865			41,507			78,411			80,088
Other income
Allowance for equity funds used during construction	1,560			1,997			2,775			3,937
Other, net	940			1,414			3,252			2,723
Income tax benefit (expense)	8			(51		)	(291		)	(95		)
Total other income	2,508			3,360			5,736			6,565
Interest and other charges
Interest on long-term debt	14,614			15,323			29,228			29,706
Amortization of net bond premium and expense	647			661			1,294			1,406
Other interest charges (credits)	318			(99		)	633			(370		)
Allowance for borrowed funds used during construction	(398		)	(893		)	(1,128		)	(1,763		)
Total interest and other charges	15,181			14,992			30,027			28,979
Net income	29,192			29,875			54,120			57,674
Preferred stock dividends of subsidiaries	229			229			458			458
Net income attributable to HECO	28,963			29,646			53,662			57,216
Preferred stock dividends of HECO	270			270			540			540
Net income for common stock	$	28,693		$	29,376		$	53,122		$	56,676

HEI owns all of the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012
Net income for common stock	$	28,693		$	29,376		$	53,122		$	56,676
Other comprehensive income, net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $3,195 and $2,142 for the three months ended June 30, 2013 and 2012 and $6,590 and $4,354 for the six months ended June 30, 2013 and 2012, respectively	5,016			3,364			10,347			6,836
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,184 and $2,095 for the three months ended June 30, 2013 and 2012 and $6,568 and $4,257 for the six months ended June 30, 2013 and 2012, respectively	(4,999		)	(3,289		)	(10,312		)	(6,684		)
Other comprehensive income, net of taxes	17			75			35			152
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	28,710		$	29,451		$	53,157		$	56,828

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

30

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands, except par value)	June 30, 2013			December 31, 2012
Assets
Utility plant, at cost
Land	$	51,622		$	51,568
Plant and equipment	5,492,118			5,364,400
Less accumulated depreciation	(2,082,532		)	(2,040,789		)
Construction in progress	166,902			151,378
Net utility plant	3,628,110			3,526,557
Current assets
Cash and cash equivalents	8,617			17,159
Customer accounts receivable, net	196,643			210,779
Accrued unbilled revenues, net	139,187			134,298
Other accounts receivable, net	10,059			28,176
Fuel oil stock, at average cost	117,445			161,419
Materials and supplies, at average cost	58,224			51,085
Prepayments and other	38,301			32,865
Regulatory assets	63,672			51,267
Total current assets	632,148			687,048
Other long-term assets
Regulatory assets	821,353			813,329
Unamortized debt expense	9,948			10,554
Other	70,260			71,305
Total other long-term assets	901,561			895,188
Total assets	$	5,161,819		$	5,108,793
Capitalization and liabilities
Capitalization
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 14,665,264 shares)	$	97,788		$	97,788
Premium on capital stock	468,045			468,045
Retained earnings	919,606			907,273
Accumulated other comprehensive loss, net of income tax benefits-retirement benefit plans	(935		)	(970		)
Common stock equity	1,484,504			1,472,136
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,147,877			1,147,872
Total capitalization	2,666,674			2,654,301
Commitments and contingencies (Note 5)
Current liabilities
Short-term borrowings from nonaffiliates	53,992			—
Accounts payable	150,877			186,824
Interest and preferred dividends payable	20,325			21,092
Taxes accrued	218,850			251,066
Other	77,895			62,879
Total current liabilities	521,939			521,861
Deferred credits and other liabilities
Deferred income taxes	456,952			417,611
Regulatory liabilities	327,254			322,074
Unamortized tax credits	69,526			66,584
Defined benefit pension and other postretirement benefit plans liability	605,026			620,205
Other	95,111			100,637
Total deferred credits and other liabilities	1,553,869			1,527,111
Contributions in aid of construction	419,337			405,520
Total capitalization and liabilities	$	5,161,819		$	5,108,793

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

31

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)

	Common stock			Premium on capital		Retained			Accumulated other comprehensive
(in thousands)	Shares	Amount		stock		earnings			income (loss)			Total
Balance, December 31, 2012	14,665	$	97,788	$	468,045	$	907,273		$	(970	)	$	1,472,136
Net income for common stock	—	—		—		53,122			—			53,122
Other comprehensive income, net of taxes	—	—		—		—			35			35
Common stock dividends	—	—		—		(40,789		)	—			(40,789		)
Balance, June 30, 2013	14,665	$	97,788	$	468,045	$	919,606		$	(935	)	$	1,484,504
Balance, December 31, 2011	14,234	$	94,911	$	426,921	$	881,041		$	(32	)	$	1,402,841
Net income for common stock	—	—		—		56,676			—			56,676
Other comprehensive income, net of taxes	—	—		—		—			152			152
Common stock dividends	—	—		—		(36,522		)	—			(36,522		)
Common stock issue expense	—	—		1		—			—			1
Balance, June 30, 2012	14,234	$	94,911	$	426,922	$	901,195		$	120		$	1,423,148

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

32

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Six months ended June 30	2013			2012
(in thousands)
Cash flows from operating activities
Net income	$	54,120		$	57,674
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation of property, plant and equipment	76,870			72,615
Other amortization	2,884			2,770
Change in deferred income taxes	38,780			42,524
Change in tax credits, net	2,997			2,880
Allowance for equity funds used during construction	(2,775		)	(3,937		)
Changes in assets and liabilities
Decrease (increase) in accounts receivable	32,253			(10,958		)
Increase in accrued unbilled revenues	(4,889		)	(32,053		)
Decrease (increase) in fuel oil stock	43,974			(35,893		)
Increase in materials and supplies	(7,139		)	(7,599		)
Increase in regulatory assets	(37,586		)	(35,476		)
Increase (decrease) in accounts payable	(41,234		)	5,931
Change in prepaid and accrued income taxes and utility revenue taxes	(38,123		)	(21,141		)
Contributions to defined benefit pension and other postretirement benefit plans	(40,586		)	(52,086		)
Other increase in defined benefit pension and other postretirement benefit plans liability	41,575			31,166
Change in other assets and liabilities	(9,419		)	(37,942		)
Net cash provided by (used in) operating activities	111,702			(21,525		)
Cash flows from investing activities
Capital expenditures	(150,251		)	(141,618		)
Contributions in aid of construction	17,188			26,981
Other	623			—
Net cash used in investing activities	(132,440		)	(114,637		)
Cash flows from financing activities
Common stock dividends	(40,789		)	(36,522		)
Preferred stock dividends of HECO and subsidiaries	(998		)	(998		)
Proceeds from issuance of long-term debt	—			417,000
Repayment of long-term debt	—			(328,500		)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	53,992			44,242
Other	(9		)	(1,929		)
Net cash provided by financing activities	12,196			93,293
Net decrease in cash and cash equivalents	(8,542		)	(42,869		)
Cash and cash equivalents, beginning of period	17,159			48,806
Cash and cash equivalents, end of period	$	8,617		$	5,937

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

33

Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2012 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2013.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of June 30, 2013 and December 31, 2012, the results of their operations for the three and six months ended June 30, 2013 and 2012 and their cash flows for the six months ended June 30, 2013 and 2012. All such adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

2 · 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 Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (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 the 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 variable interest entities (VIEs). Trust III’s balance sheets as of June 30, 2013 and December 31, 2012 each 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 statements for the six months ended June 30, 2013 and 2012 each consisted of $1.7 million of interest income received from the 2004 Debentures, $1.6 million of distributions to holders of the Trust Preferred Securities, and $0.1 million of common dividends on the trust common securities to HECO. As 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

34

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 June 30, 2013, HECO and its subsidiaries had six PPAs for firm capacity and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 91% of the 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 were as follows:

	Three months ended June 30				Six months ended June 30
(in millions)	2013		2012		2013		2012
AES Hawaii	$	37	$	37	$	60	$	72
Kalaeloa	79		83		143		152
HEP	9		15		20		29
HPOWER	12		15		27		31
Other IPPs	41		38		82		69
Total IPPs	$	178	$	188	$	332	$	353

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. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.

An enterprise with an interest in a VIE or potential VIE created before December 31, 2003, and not thereafter materially modified, is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information from two firm capacity producers and other small IPPs who entered into their PPAs prior to December 31, 2003 and have not provided such information, but have been unsuccessful to date as it was not a contractual requirement to provide such information prior to 2004. 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. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and the potential recognition of losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.

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

35

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 June 30, 2013, HECO’s accounts payable to Kalaeloa amounted to $23 million.

3 · Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, HECO and its subsidiaries’ 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 the six months ended June 30, 2013 and 2012, HECO and its subsidiaries included approximately $129 million and $140 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

4 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information.  For the first six months of 2013, HECO and its subsidiaries contributed $41 million to their pension and other postretirement benefit plans, compared to $52 million in the first six months of 2012. HECO and its subsidiaries’ current estimate of contributions to their pension and other postretirement benefit plans in 2013 is $81 million, compared to contributions of $63 million in 2012. In addition, HECO and its subsidiaries expect to pay directly $1.0 million of benefits in 2013, compared to $0.5 million paid in 2012.

On July 6, 2012, President Obama signed the MAP-21, which included provisions related to the funding and administration of pension plans. This law does not affect the utilities’ accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The utilities elected to apply MAP-21 for 2012, which improved the plan’s AFTAP for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under ERISA to be less than the net periodic cost for 2013 and 2014; therefore, the utilities expect to contribute the net periodic cost for these years as they did for 2012. If the AFTAP 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. However, the HEI Retirement Plan met the threshold requirements in each of 2012 and 2013 so that the more conservative assumptions do not apply for either the 2013 or 2014 valuation of plan liabilities for purposes of calculating the minimum required contribution. Other factors could cause changes to the required contribution levels.

36

The components of net periodic benefit cost were as follows:

	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2013			2012			2013			2012			2013			2012			2013			2012
Service cost	$	13,638		$	11,000		$	1,067		$	959		$	27,241		$	20,802		$	2,081		$	2,007
Interest cost	14,883			15,465			1,783			2,147			29,559			30,726			3,644			4,352
Expected return on plan assets	(16,185		)	(15,942		)	(2,480		)	(2,519		)	(32,275		)	(32,002		)	(5,000		)	(5,098		)
Amortization of net transition obligation	—			—			—			(2		)	—			—			—			(4		)
Amortization of net prior service gain	(116		)	(172		)	(451		)	(451		)	(232		)	(344		)	(902		)	(902		)
Amortization of net actuarial loss	8,509			5,845			268			288			17,299			11,714			772			728
Net periodic benefit cost	20,729			16,196			187			422			41,592			30,896			595			1,083
Impact of PUC D&Os	(5,286		)	(4,977		)	(187		)	(416		)	(12,722		)	(8,834		)	(584		)	(1,096		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	15,443		$	11,219		$	—		$	6		$	28,870		$	22,062		$	11		$	(13	)

HECO and its subsidiaries recorded retirement benefits expense of $21 million and $15 million for the first six months of 2013 and 2012, respectively. The electric utilities charged a portion of the net periodic benefit cost to electric utility plant.

The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

Accumulated other comprehensive income.  Reclassifications out of AOCI were as follows:

	Amount reclassified from AOCI
	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	$	5,016		$	3,364		$	10,347		$	6,836		See above
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(4,999		)	(3,289		)	(10,312		)	(6,684		)	See above
Total reclassifications	$	17		$	75		$	35		$	152

Defined contribution plan information.  For the first six months of 2013 and 2012, the utilities’ expense for its defined contribution pension plan was $0.3 million and de minimis, respectively.

5 · Commitments and contingencies

Utility 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.

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. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the EOTP

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Phase I project cost issues and, in March 2013, the PUC eliminated the requirement for an audit of the CIP CT-1 and CIS project costs as described below.

On January 28, 2013, HECO and its subsidiaries and the Consumer Advocate, signed a settlement agreement (2013 Agreement), subject to PUC approval, to write-off $40 million of costs in lieu of conducting the regulatory audits of the CIP CT-1 project and the CIS project. Based on the 2013 Agreement, as of December 31, 2012, the utilities recorded an after-tax charge to net income of approximately $24 million—$17.1 million for HECO, $3.4 million for HELCO, and $3.2 million for MECO. The remaining recoverable costs of $52 million were included in rate base as of December 31, 2012.

As part of the 2013 Agreement, HELCO would withdraw its 2013 test year rate case, and delay filing a new rate case until a 2016 test year. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. For both utilities, the existing terms of the last rate case decisions would continue. HECO would also be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting on January 1 of 2014, 2015 and 2016. The cash collection of RAM revenues would remain unchanged, starting June 1 of each year through May 31 of the following year.

On March 19, 2013, the PUC issued a decision and order (2013 D&O) approving the 2013 Agreement, with the following clarifications, none of which changed the financial impact recorded as of December 31, 2012: (1) the PUC reiterated its authority to examine and ascertain what post go-live CIS costs would be subject to regulatory review in future rate cases; (2) the PUC discouraged requesting single issue cost deferral accounting and/or cost recovery mechanisms during the period of rate case deferral by HECO and HELCO; (3) the PUC approved the agreed-upon recovery of CIP CT-1 and CIS project costs through the RAM, as set forth in the 2013 Agreement, however not setting a precedent for future projects; and (4) the PUC reaffirmed its right to rule on the substance of the MECO 2012 test year rate case in its ongoing rate case proceeding. On May 31, 2013, the PUC issued a final D&O in the MECO 2012 test year rate case. See “MECO 2012 test year rate case” below.

Renewable energy projects.  HECO and its subsidiaries are committed to achieving or exceeding the State’s Renewable Portfolio Standard (RPS) goal of 40% renewable energy by 2030 and to meeting their commitments relating to decreasing the State’s dependence on imported fossil fuels under their 2008 Energy Agreement with the Governor, the State Department of Business, Economic Development and Tourism and the Consumer Advocate (Energy Agreement). The utilities continue to evaluate and pursue opportunities 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. 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. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.

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, were to 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 was posted on HECO’s 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. On July 11, 2013, the PUC issued orders related to the 200 MW RFP. First, it issued an order that HECO shall amend its current draft of the Oahu 200 MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order. Second, it initiated an investigative proceeding to review the progress of the Lanai Wind Project stating that there was an uncertainty whether the

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project developer retained an equivalent ability to develop the project as when it submitted its bid in 2008 and its term sheet in 2011. The PUC also stated that it will review the PPA (if one is completed) and, as part of that process, determine whether the Lanai Wind Project should be developed taking into account potential as-available renewable energy projects and grid infrastructure options. The PUC stated it intends to evaluate the project as a combined resources proposal (i.e., wind project and generation tie transmission cable between the islands of Oahu and Lanai). Third, it initiated a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui.

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. In February 2013, HELCO issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.

In June 2013, HECO filed an application to seek PUC approval of Waivers from the Framework for Competitive Bidding for five projects (4 photovoltaic and 1 wind) selected as part of HECO’s “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.”

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 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 other operation and maintenance (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 November 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 and avoid the reduction in operational flexibility imposed by emissions control equipment. As provided in the MATS regulations, HECO will be requesting a one-year extension resulting in a MATS compliance date of April 16, 2016. On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour sulfur dioxide NAAQS implementation plans. HECO will work with the Hawaii Department of Health (DOH) and the EPA in the rulemaking process for these implementation plans to insure development of cost-effective strategies for NAAQS compliance. Based on the February 6, 2013 EPA guidance document, current estimates of the compliance date for the one-hour sulfur dioxide NAAQS is in the 2022 or later timeframe.

Depending upon the final outcome of the CWA 316(b) regulations, the specific measures required for MATS compliance, and the rules and guidance developed for 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 or deactivate certain generating units earlier than anticipated.

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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.

Potential Clean Air Act Enforcement.  On July 1, 2013, HELCO and MECO received a letter from the U.S. Department of Justice (DOJ) asserting potential violations of the Prevention of Significant Deterioration (PSD) and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The EPA referred the matter to the DOJ for enforcement based on HELCO’s and MECO’s responses to information requests in 2010 and 2012. The letter expresses an interest in resolving the matter without the issuance of a notice of violation, and invites HELCO and MECO to engage in settlement negotiations. HELCO and MECO are in contact with the DOJ to seek additional information and to begin making arrangements for settlement discussions. HELCO and MECO cannot currently estimate the amount or effect of a settlement, if any. Neither HELCO nor MECO has identified at this time any projects or work relating to the information requests that may have been noncompliant with PSD or Title V requirements, and continue to investigate the potential bases for the DOJ’s claims.

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 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 June 30, 2013) 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. A revised draft site investigation work plan for site characterization was submitted to the DOH and EPA in June 2013.

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 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. HECO submitted comments on the proposed regulations in January 2013. HECO continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.

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.

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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, 2011 and 2012 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’ EGUs.

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. 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. On June 25, 2013, President Obama directed the EPA Administrator to issue a new proposal no later than September 20, 2013. In addition, the President directed the Administrator to issue proposed standards, regulations, or guidelines for GHG emissions from existing power plants by no later than June 1, 2014, and final standards no later than June 1, 2015. HECO will participate in the federal GHG rulemaking process and support an exclusion for both new and existing non-continental sources.

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.

MECO 2012 test year rate case.  On May 31, 2013, the PUC issued a final D&O in the MECO 2012 test year rate case. Final rates became effective August 1, 2013. The final D&O approved an increase in annual revenues of $5.3 million, which is $7.8 million less than the interim increase that had been in effect since June 1, 2012. Reductions from the interim D&O relate primarily to:

(in millions)
Lower ROACE	$	4.0
Customer Information System expenses	0.3
Pension and OPEB expense based on 3-year average	1.5
Integrated resource planning expenses	0.9
Operational and Renewable Energy Integration study costs	1.1
Total adjustment	$	7.8

According to the PUC, the reduction in the allowed ROACE from the stipulated 10% to the final approved 9% is composed of 0.5% allocation due to updated economic and financial market conditions manifested in lower interest rates in the 2012 test year and 0.5% for system inefficiencies reflected in over curtailment of renewable energy produced by independent power producers.

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The PUC found that the record did not sufficiently support the normalization of 2013 and 2014 Customer Information System costs into the 2012 test year and ordered a downward adjustment to remove these costs from the test year.

The reduction in the pension and OPEB expense is due to applying a three-year average in the calculation of pension costs for the purpose of the 2012 test year. This is not a PUC decision to change the pension and OPEB tracking mechanisms, although the PUC emphasizes the need to evaluate alternatives to decrease or limit the growth in employee benefits costs.

The PUC removed integrated resource planning (IRP) expenses from the test year as it could not determine whether these expenses have been reasonably incurred for the 2012 test year as required by the PUC’s IRP Framework and stated that it will determine the appropriate level and method of cost recovery for MECO’s IRP expenses in the pending IRP proceeding.

The PUC reduced operational and renewable energy integration study costs because of the uncertainty regarding the scope of work and actual costs of these studies.

The PUC also continued MECO’s existing energy cost adjustment clause (ECAC) and power purchase adjustment clause (PPAC) design. The PUC stated that it will consider HECO, HELCO and MECO’s future actions to reduce fuel costs and increase use of renewable energy as it continues to review the design of the ECAC in the future.

On June 12, 2013, MECO filed a motion for partial reconsideration and partial clarification of the final D&O in the MECO 2012 test year rate case. The motion primarily requested reconsideration of the findings and conclusions concerning MECO’s 9% ROACE for the test year and also addressed other matters identified in the D&O, including treatment of IRP costs pending PUC determinations on such costs in a separate IRP proceeding. MECO requested a panel evidentiary hearing on ROACE, curtailment and technical studies, and pension expense. MECO also requested to partially stay the implementation of the final D&O, pending the presentation at the evidentiary hearing on its motion for partial reconsideration of the final D&O related to the ROACE reduction from 10.0% to 9.0% and the PUC’s final decision following the hearing. On July 2, 2013, the PUC issued an order denying MECO’s requests for an evidentiary hearing and for partial reconsideration, and dismissed MECO’s motion for partial stay. The order granted MECO’s motion for partial clarification to allow MECO to defer IRP costs incurred since June 2012, which through June 30, 2013 totaled approximately $0.7 million, until the level of costs are determined and a method of recovery is decided in the IRP proceeding.

Since the final rate increase was lower than the interim increase previously in effect, MECO recorded a charge, net of revenue taxes, of $7.6 million in the second quarter and will be refunding to customers approximately $9.7 million (which includes interest accrued since June 1, 2012) between September 2013 and October 2013. As a result of the D&O, in the second quarter MECO also recorded adjustments to reduce expenses by reducing employee benefits expenses by $1.8 million for adjustments to pension and OPEB costs, and to reclassify $0.7 million of IRP costs to deferred accounts.

As directed by the PUC, in June 2013, MECO filed documentation regarding the re-setting of its target heat rate to take into account the operation of the Auwahi wind farm and made its curtailment information available to the public on its website. In addition, as required by the final D&O, MECO will be filing by September 3, 2013, a System Improvement and Curtailment Reduction Plan. Management cannot predict any actions by the PUC as a result of these filings.

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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:

	Six months ended June 30
(in thousands)	2013			2012
Balance, beginning of period	$	48,431		$	50,871
Accretion expense	363			862
Liabilities incurred	—			—
Liabilities settled	(1,506		)	(2,217		)
Revisions in estimated cash flows	(916		)	—
Balance, end of period	$	46,372		$	49,516

6 · Cash flows

Six months ended June 30	2013			2012
(in millions)
Supplemental disclosures of cash flow information
Interest paid	$	30		$	29
Income taxes paid/(refunded)	(26		)	3
Supplemental disclosures of noncash activities
Additions to electric utility property, plant and equipment - Unpaid invoices and other	5			12

7 · Fair value measurements

See Note 9 “Fair value measurements,” of HEI’s “Notes to Consolidated Financial Statements” for discussions of fair value estimates, grouping of financial instruments and methods and assumptions used to estimate the fair value of short-term borrowings and long-term debt.

The estimated fair values of certain of the electric utilities’ financial instruments were as follows:

	June 30, 2013				December 31, 2012
(in thousands)	Carrying amount		Estimated fair value (Level 2)		Carrying amount		Estimated fair value (Level 2)
Financial liabilities
Short-term borrowings - nonaffiliates	$	53,992	$	53,992	$	—	$	—
Long-term debt, net, including amounts due within one year	1,147,877		1,164,470		1,147,872		1,181,631

Fair value measurements on a nonrecurring basis.  From time to time, the utilities may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of the utilities ARO (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 “Asset retirement obligations” in Note 5.

8 · Recent accounting pronouncements

Obligations resulting from joint and several liability.  In February 2013, the FASB issued ASU No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the

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amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.

HECO and its subsidiaries will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on HECO and its subsidiaries’ results of operations, financial condition or liquidity.

Unrecognized tax benefit.  In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which clarifies that a liability for an unrecognized tax benefit should be presented as a reduction of a deferred tax asset when settlement of the liability with the taxing authority results in the reduction of a net operating loss or tax credit carryforward. ASU No. 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.

HECO and its subsidiaries will prospectively adopt ASU No. 2013-11 in the first quarter of 2014 and does not expect it to have a material impact on the utilities’ results of operations, financial condition or liquidity.

9 · Credit agreement

HECO maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. 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.

10 · Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income

	Three months ended June 30						Six months ended June 30
(in thousands)	2013			2012			2013			2012
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	61,138		$	61,496		$	114,091		$	118,750
Deduct:
Income taxes on regulated activities	(18,333		)	(18,574		)	(32,428		)	(35,939		)
Revenues from nonregulated activities	(1,895		)	(1,867		)	(4,971		)	(3,539		)
Add: Expenses from nonregulated activities	955			452			1,719			816
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	41,865		$	41,507		$	78,411		$	80,088

11·Consolidating financial information

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, (b) under their respective private placement note agreements and the HELCO notes and MECO notes issued thereunder and (c) relating to the trust preferred securities of Trust III (see Note 2 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.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Operating revenues	$	521,730		106,374		100,689		—		—		$	728,793
Operating expenses
Fuel oil	203,379			33,569		52,330		—		—		289,278
Purchased power	135,271			29,278		13,895		—		—		178,444
Other operation	48,084			10,146		7,954		—		—		66,184
Maintenance	19,651			4,301		3,388		—		—		27,340
Depreciation	25,001			8,547		5,042		—		—		38,590
Taxes, other than income taxes	49,287			9,960		9,512		—		—		68,759
Income taxes	12,886			3,060		2,387		—		—		18,333
Total operating expenses	493,559			98,861		94,508		—		—		686,928
Operating income	28,171			7,513		6,181		—		—		41,865
Other income (loss)
Allowance for equity funds used during construction	1,247			192		121		—		—		1,560
Equity in earnings of subsidiaries	8,667			—		—		—		(8,667	)	—
Other, net	702			167		111		(1	)	(39	)	940
Income tax benefits (expense)	41			(18	)	(15	)	—		—		8
Total other income (loss)	10,657			341		217		(1	)	(8,706	)	2,508
Interest and other charges
Interest on long-term debt	9,901			2,751		1,962		—		—		14,614
Amortization of net bond premium and expense	411			117		119		—		—		647
Other interest charges (credits)	(105		)	16		446		—		(39	)	318
Allowance for borrowed funds used during construction	(342		)	(43	)	(13	)	—		—		(398		)
Total interest and other charges	9,865			2,841		2,514		—		(39	)	15,181
Net income (loss)	28,963			5,013		3,884		(1	)	(8,667	)	29,192
Preferred stock dividend of subsidiaries	—			133		96		—		—		229
Net income (loss) attributable to HECO	28,963			4,880		3,788		(1	)	(8,667	)	28,963
Preferred stock dividends of HECO	270			—		—		—		—		270
Net income (loss) for common stock	$	28,693		4,880		3,788		(1	)	(8,667	)	$	28,693

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$	28,693		4,880		3,788		(1	)	(8,667	)	$	28,693
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	5,016			681		622		—		(1,303	)	5,016
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(4,999		)	(680	)	(623	)	—		1,303		(4,999		)
Other comprehensive income (loss), net of taxes	17			1		(1	)	—		—		17
Comprehensive income (loss) attributable to common shareholder	$	28,710		4,881		3,787		(1	)	(8,667	)	$	28,710

45

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Operating revenues	$	567,527		111,741		108,417		—		—		$	787,685
Operating expenses
Fuel oil	241,393			30,616		59,055		—		—		331,064
Purchased power	141,136			37,395		9,821		—		—		188,352
Other operation	44,621			9,948		9,947		—		—		64,516
Maintenance	20,542			4,885		5,808		—		—		31,235
Depreciation	22,737			8,301		5,095		—		—		36,133
Taxes, other than income taxes	55,440			10,423		10,441		—		—		76,304
Income taxes	13,361			2,831		2,382		—		—		18,574
Total operating expenses	539,230			104,399		102,549		—		—		746,178
Operating income	28,297			7,342		5,868		—		—		41,507
Other income (loss)
Allowance for equity funds used during construction	1,654			160		183		—		—		1,997
Equity in earnings of subsidiaries	8,250			—		—		—		(8,250	)	—
Other, net	1,173			117		144		(1	)	(18	)	1,415
Income tax benefits (expense)	(36		)	(18	)	2		—		—		(52		)
Total other income (loss)	11,041			259		329		(1	)	(8,268	)	3,360
Interest and other charges
Interest on long-term debt	10,190			2,913		2,220		—		—		15,323
Amortization of net bond premium and expense	429			108		124		—		—		661
Other interest charges	(167		)	20		66		—		(18	)	(99		)
Allowance for borrowed funds used during construction	(760		)	(64	)	(69	)	—		—		(893		)
Total interest and other charges	9,692			2,977		2,341		—		(18	)	14,992
Net income (loss)	29,646			4,624		3,856		(1	)	(8,250	)	29,875
Preferred stock dividend of subsidiaries	—			133		96		—		—		229
Net income (loss) attributable to HECO	29,646			4,491		3,760		(1	)	(8,250	)	29,646
Preferred stock dividends of HECO	270			—		—		—		—		270
Net income (loss) for common stock	$	29,376		4,491		3,760		(1	)	(8,250	)	$	29,376

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$	29,376		4,491		3,760		(1	)	(8,250	)	$	29,376
Other comprehensive income, net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	3,364			518		412		—		(930	)	3,364
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(3,289		)	(511	)	(406	)	—		917		(3,289		)
Other comprehensive income, net of taxes	75			7		6		—		(13	)	75
Comprehensive income (loss) attributable to common shareholder	$	29,451		4,498		3,766		(1	)	(8,263	)	$	29,451

46

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Six months ended June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Operating revenues	$	1,027,559		212,390		205,041		—		—		$	1,444,990
Operating expenses
Fuel oil	425,346			66,505		102,527		—		—		594,378
Purchased power	246,426			59,400		25,982		—		—		331,808
Other operation	98,195			21,210		18,202		—		—		137,607
Maintenance	41,303			8,107		7,632		—		—		57,042
Depreciation	49,708			17,094		10,068		—		—		76,870
Taxes, other than income taxes	97,372			19,646		19,428		—		—		136,446
Income taxes	20,197			5,774		6,457		—		—		32,428
Total operating expenses	978,547			197,736		190,296		—		—		1,366,579
Operating income	49,012			14,654		14,745		—		—		78,411
Other income (loss)
Allowance for equity funds used during construction	2,230			330		215		—		—		2,775
Equity in earnings of subsidiaries	19,652			—		—		—		(19,652	)	—
Other, net	2,723			309		288		(1	)	(67	)	3,252
Income tax expense	(189		)	(41	)	(61	)	—		—		(291		)
Total other income (loss)	24,416			598		442		(1	)	(19,719	)	5,736
Interest and other charges
Interest on long-term debt	19,803			5,501		3,924		—		—		29,228
Amortization of net bond premium and expense	821			234		239		—		—		1,294
Other interest charges	52			85		563		—		(67	)	633
Allowance for borrowed funds used during construction	(910		)	(135	)	(83	)	—		—		(1,128		)
Total interest and other charges	19,766			5,685		4,643		—		(67	)	30,027
Net income (loss)	53,662			9,567		10,544		(1	)	(19,652	)	54,120
Preferred stock dividend of subsidiaries	—			267		191		—		—		458
Net income (loss) attributable to HECO	53,662			9,300		10,353		(1	)	(19,652	)	53,662
Preferred stock dividends of HECO	540			—		—		—		—		540
Net income (loss) for common stock	$	53,122		9,300		10,353		(1	)	(19,652	)	$	53,122

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Six months ended June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$	53,122		9,300		10,353		(1	)	(19,652	)	$	53,122
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	10,347			1,440		1,279		—		(2,719	)	10,347
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(10,312		)	(1,441	)	(1,279	)	—		2,720		(10,312		)
Other comprehensive income (loss), net of taxes	35			(1	)	—		—		1		35
Comprehensive income (loss) attributable to common shareholder	$	53,157		9,299		10,353		(1	)	(19,651	)	$	53,157

47

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Operating revenues	$	1,098,140		224,068		213,415		—		—		$	1,535,623
Operating expenses
Fuel oil	476,419			63,026		119,458		—		—		658,903
Purchased power	265,916			71,303		15,922		—		—		353,141
Other operation	84,569			18,963		22,833		—		—		126,365
Maintenance	41,378			9,134		10,761		—		—		61,273
Depreciation	45,308			16,737		10,570		—		—		72,615
Taxes, other than income taxes	105,993			20,886		20,420		—		—		147,299
Income taxes	25,324			7,054		3,561		—		—		35,939
Total operating expenses	1,044,907			207,103		203,525		—		—		1,455,535
Operating income	53,233			16,965		9,890		—		—		80,088
Other income (loss)
Allowance for equity funds used during construction	3,235			285		417		—		—		3,937
Equity in earnings of subsidiaries	16,740			—		—		—		(16,740	)	—
Other, net	2,266			232		255		(2	)	(28	)	2,723
Income tax benefits	(65		)	(32	)	2		—		—		(95		)
Total other income (loss)	22,176			485		674		(2	)	(16,768	)	6,565
Interest and other charges
Interest on long-term debt	19,320			5,898		4,488		—		—		29,706
Amortization of net bond premium and expense	912			245		249		—		—		1,406
Other interest charges	(554		)	53		159		—		(28	)	(370		)
Allowance for borrowed funds used during construction	(1,485		)	(115	)	(163	)	—		—		(1,763		)
Total interest and other charges	18,193			6,081		4,733		—		(28	)	28,979
Net income (loss)	57,216			11,369		5,831		(2	)	(16,740	)	57,674
Preferred stock dividend of subsidiaries	—			267		191		—		—		458
Net income (loss) attributable to HECO	57,216			11,102		5,640		(2	)	(16,740	)	57,216
Preferred stock dividends of HECO	540			—		—		—		—		540
Net income (loss) for common stock	$	56,676		11,102		5,640		(2	)	(16,740	)	$	56,676

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Net income (loss) for common stock	$	56,676		11,102		5,640		(2	)	(16,740	)	$	56,676
Other comprehensive income, net of taxes:
Retirement benefit plans:
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	6,836			1,050		885		—		(1,935	)	6,836
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(6,684		)	(1,037	)	(873	)	—		1,910		(6,684		)
Other comprehensive income, net of taxes	152			13		12		—		(25	)	152
Comprehensive income (loss) attributable to common shareholder	$	56,828		11,115		5,652		(2	)	(16,765	)	$	56,828

48

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	Consolidating adjustments		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,424		5,182		3,016		—	—		$	51,622
Plant and equipment	3,423,045			1,095,425		973,648		—	—		5,492,118
Less accumulated depreciation	(1,208,090		)	(445,035	)	(429,407	)	—	—		(2,082,532		)
Construction in progress	131,745			21,635		13,522		—	—		166,902
Net utility plant	2,390,124			677,207		560,779		—	—		3,628,110
Investment in wholly owned subsidiaries, at equity	503,388			—		—		—	(503,388	)	—
Current assets
Cash and cash equivalents	4,914			3,401		199		103	—		8,617
Advances to affiliates	18,000			9,600		—		—	(27,600	)	—
Customer accounts receivable, net	137,171			30,867		28,605		—	—		196,643
Accrued unbilled revenues, net	102,695			17,241		19,251		—	—		139,187
Other accounts receivable, net	15,027			2,308		1,420		—	(8,696	)	10,059
Fuel oil stock, at average cost	84,748			9,673		23,024		—	—		117,445
Materials and supplies, at average cost	35,848			6,816		15,560		—	—		58,224
Prepayments and other	26,194			5,805		6,385		—	(83	)	38,301
Regulatory assets	51,214			5,815		6,643		—	—		63,672
Total current assets	475,811			91,526		101,087		103	(36,379	)	632,148
Other long-term assets
Regulatory assets	606,971			110,163		104,219		—	—		821,353
Unamortized debt expense	6,655			1,943		1,350		—	—		9,948
Other	45,995			9,281		14,984		—	—		70,260
Total other long-term assets	659,621			121,387		120,553		—	—		901,561
Total assets	$	4,028,944		890,120		782,419		103	(539,767	)	$	5,161,819
Capitalization and liabilities
Capitalization
Common stock equity	$	1,484,504		271,013		232,272		103	(503,388	)	$	1,484,504
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	780,546			201,331		166,000		—	—		1,147,877
Total capitalization	2,287,343			479,344		403,272		103	(503,388	)	2,666,674
Current liabilities
Short-term borrowings from nonaffiliates	53,992			—		—		—	—		53,992
Short-term borrowings from affiliate	9,600			—		18,000		—	(27,600	)	—
Accounts payable	101,725			23,747		25,405		—	—		150,877
Interest and preferred dividends payable	13,805			4,105		2,427		—	(12	)	20,325
Taxes accrued	152,905			33,299		32,646		—	—		218,850
Other	51,807			9,564		25,291		—	(8,767	)	77,895
Total current liabilities	383,834			70,715		103,769		—	(36,379	)	521,939
Deferred credits and other liabilities
Deferred income taxes	330,551			74,285		52,116		—	—		456,952
Regulatory liabilities	222,193			70,171		34,890		—	—		327,254
Unamortized tax credits	42,396			13,508		13,622		—	—		69,526
Defined benefit pension and other postretirement benefit plans liability	449,039			78,265		77,722			—		605,026
Other	65,242			16,146		13,723		—	—		95,111
Total deferred credits and other liabilities	1,109,421			252,375		192,073		—	—		1,553,869
Contributions in aid of construction	248,346			87,686		83,305		—	—		419,337
Total capitalization and liabilities	$	4,028,944		890,120		782,419		103	(539,767	)	$	5,161,819

49

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries	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	)	—
Current assets
Cash and cash equivalents	8,265			5,441		3,349		104	—		17,159
Advances to affiliates	9,400			18,050		—		—	(27,450	)	—
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	)	28,176
Fuel oil stock, at average cost	123,176			15,485		22,758		—	—		161,419
Materials and 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		104	(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
Total assets	$	3,991,726		890,378		761,249		104	(534,664	)	$	5,108,793
Capitalization and liabilities
Capitalization
Common stock equity	$	1,472,136		268,908		228,927		104	(497,939	)	$	1,472,136
Cumulative preferred stock—not subject 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		104	(497,939	)	2,654,301
Current liabilities
Current portion of long-term debt	—			—		—		—	—		—
Short-term borrowings from affiliate	18,050			—		9,400		—	(27,450	)	—
Accounts payable	134,651			27,457		24,716		—	—		186,824
Interest and preferred dividends payable	14,479			4,027		2,593		—	(7	)	21,092
Taxes accrued	174,477			38,778		37,811		—	—		251,066
Other	47,203			10,310		14,634		—	(9,268	)	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
Defined benefit pension and other postretirement benefit plans 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
Total capitalization and liabilities	$	3,991,726		890,378		761,249		104	(534,664	)	$	5,108,793

50

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Balance, December 31, 2012	$	1,472,136		268,908		228,927		104		(497,939	)	$	1,472,136
Net income (loss) for common stock	53,122			9,300		10,353		(1	)	(19,652	)	53,122
Other comprehensive income (loss), net of taxes	35			(1	)	—		—		1		35
Common stock dividends	(40,789		)	(7,194	)	(7,008	)	—		14,202		(40,789		)
Balance, June 30, 2013	1,484,504			271,013		232,272		103		(503,388	)	1,484,504

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Balance, December 31, 2011	$	1,402,841		280,468		235,568		107		(516,143	)	$	1,402,841
Net income (loss) for common stock	56,676			11,102		5,640		(2	)	(16,740	)	56,676
Other comprehensive income, net of taxes	152			13		12		—		(25	)	152
Common stock dividends	(36,522		)	(6,569	)	(4,373	)	—		10,942		(36,522		)
Common stock issue expenses	1			—		—		—		—		1
Balance, June 30, 2012	$	1,423,148		285,014		236,847		105		(521,966	)	$	1,423,148

51

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2013

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	53,662		9,567		10,544		(1	)	(19,652	)	$	54,120
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(19,702		)	—		—		—		19,652		(50		)
Common stock dividends received from subsidiaries	14,227			—		—		—		(14,202	)	25
Depreciation of property, plant and equipment	49,708			17,094		10,068		—		—		76,870
Other amortization	(160		)	716		2,328		—		—		2,884
Change in deferred income taxes	27,560			5,584		5,636		—		—		38,780
Change in tax credits, net	2,598			70		329		—		—		2,997
Allowance for equity funds used during construction	(2,230		)	(330	)	(215	)	—		—		(2,775		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	35,431			(2,281	)	(318	)	—		(579	)	32,253
Decrease (increase) in accrued unbilled revenues	(2,095		)	(2,848	)	54		—		—		(4,889		)
Decrease (increase) in fuel oil stock	38,428			5,812		(266	)	—		—		43,974
Increase in materials and supplies	(4,069		)	(1,480	)	(1,590	)	—		—		(7,139		)
Increase in regulatory assets	(25,647		)	(4,852	)	(7,087	)	—		—		(37,586		)
Decrease in accounts payable	(36,971		)	(2,513	)	(1,750	)	—		—		(41,234		)
Change in prepaid and accrued income and utility revenue taxes	(25,831		)	(6,171	)	(6,121	)	—		—		(38,123		)
Contributions to defined benefit pension and other postretirement benefit plans	(29,766		)	(5,389	)	(5,431	)	—		—		(40,586		)
Other increase in defined benefit pension and other postretirement benefit plans liability	30,929			5,261		5,385		—		—		41,575
Change in other assets and liabilities	(12,731		)	(3,171	)	5,929		—		579		(9,394		)
Net cash provided by (used in) operating activities	93,341			15,069		17,495		(1	)	(14,202	)	111,702
Cash flows from investing activities:
Capital expenditures	(104,846		)	(22,367	)	(23,038	)	—		—		(150,251		)
Contributions in aid of construction	11,924			4,270		994		—		—		17,188
Other	623			—		—		—		—		623
Advances from (to) affiliates	(8,600		)	8,450		—		—		150		—
Net cash used in investing activities	(100,899		)	(9,647	)	(22,044	)	—		150		(132,440		)
Cash flows from financing activities:
Common stock dividends	(40,789		)	(7,194	)	(7,008	)	—		14,202		(40,789		)
Preferred stock dividends of HECO and subsidiaries	(540		)	(267	)	(191	)	—		—		(998		)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	45,542			—		8,600		—		(150	)	53,992
Other	(6		)	(1	)	(2	)	—		—		(9		)
Net cash provided by (used in) financing activities	4,207			(7,462	)	1,399		—		14,052		12,196
Net decrease in cash and cash equivalents	(3,351		)	(2,040	)	(3,150	)	(1	)	—		(8,542		)
Cash and cash equivalents, beginning of period	8,265			5,441		3,349		104		—		17,159
Cash and cash equivalents, end of period	$	4,914		3,401		199		103		—		$	8,617

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2012

(in thousands)	HECO			HELCO		MECO		Other subsidiaries		Consolidating adjustments		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	57,216		11,369		5,831		(2	)	(16,740	)	$	57,674
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(16,790		)	—		—		—		16,740		(50		)
Common stock dividends received from subsidiaries	10,967			—		—		—		(10,942	)	25
Depreciation of property, plant and equipment	45,308			16,737		10,570		—		—		72,615
Other amortization	347			1,418		1,005		—		—		2,770
Change in deferred income taxes	31,673			5,857		4,994		—		—		42,524
Change in tax credits, net	2,641			125		114		—		—		2,880
Allowance for equity funds used during construction	(3,235		)	(285	)	(417	)	—		—		(3,937		)
Changes in assets and liabilities:
Increase in accounts receivable	(17,653		)	(137	)	(702	)	—		7,534		(10,958		)
Increase in accrued unbilled revenues	(21,274		)	(6,456	)	(4,323	)	—		—		(32,053		)
Increase in fuel oil stock	(28,905		)	(514	)	(6,474	)	—		—		(35,893		)
Increase in materials and supplies	(6,172		)	(1,022	)	(405	)	—		—		(7,599		)
Increase in regulatory assets	(28,190		)	(3,234	)	(4,052	)	—		—		(35,476		)
Increase (decrease) in accounts payable	12,843			(6,938	)	26		—		—		5,931
Change in prepaid and accrued income and utility revenue taxes	(9,994		)	(6,347	)	(4,800	)	—		—		(21,141		)
Contributions to defined benefit pension and other postretirement benefit plans	(38,693		)	(6,536	)	(6,857	)	—		—		(52,086		)
Other increase in defined benefit pension and other postretirement benefit plans liability	22,947			4,089		4,130				—		31,166
Change in other assets and liabilities	(26,968		)	(3,432	)	18		(1	)	(7,534	)	(37,917		)
Net cash provided by (used in) operating activities	(13,932		)	4,694		(1,342	)	(3	)	(10,942	)	(21,525		)
Cash flows from investing activities:
Capital expenditures	(111,011		)	(17,405	)	(13,202	)	—		—		(141,618		)
Contributions in aid of construction	23,693			2,327		961		—		—		26,981
Advances from (to) affiliates	(8,700		)	26,800		18,500		—		(36,600	)	—
Net cash provided by (used in) investing activities	(96,018		)	11,722		6,259		—		(36,600	)	(114,637		)
Cash flows from financing activities:
Common stock dividends	(36,522		)	(6,569	)	(4,373	)	—		10,942		(36,522		)
Preferred stock dividends of HECO and subsidiaries	(540		)	(267	)	(191	)	—		—		(998		)
Proceeds from issuance of long-term debt	327,000			31,000		59,000		—		—		417,000
Repayment of long-term debt	(219,580		)	(41,200	)	(67,720	)	—		—		(328,500		)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	(1,058		)	—		8,700		—		36,600		44,242
Other	(1,746		)	171		(354	)	—		—		(1,929		)
Net cash provided by (used in) financing activities	67,554			(16,865	)	(4,938	)	—		47,542		93,293
Net decrease in cash and cash equivalents	(42,396		)	(449	)	(21	)	(3	)	—		(42,869		)
Cash and cash equivalents, beginning of period	44,819			3,383		496		108		—		48,806
Cash and cash equivalents, end of period	$	2,423		2,934		475		105		—		$	5,937

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and HECO’s Form 10-K for 2012 and should be read in conjunction with the 2012 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI’s and HECO’s 2012 Form 10-K, as well as the quarterly (as of and for the three and six months ended June 30, 2013) financial statements and notes thereto included in this Form 10-Q.

HEI Consolidated

RESULTS OF OPERATIONS

(in thousands, except per	Three months ended June 30				%		Primary reason(s) for
share amounts)	2013		2012		change		significant change*
Revenues	$	796,730	$	854,268	(7	)	Decrease for the electric utility segment, partly offset by increase in bank segment
Operating income	82,370		79,406		4		Increase for the electric utility and bank segments and a reduced operating loss for the “other” segment
Net income for common stock	40,588		38,800		5		Higher operating income and lower “interest expense—other than on deposit liabilities and other bank borrowings” partly offset by lower AFUDC
Basic earnings per common share	$	0.41	$	0.40	2		Higher net income, partly offset by higher weighted average shares outstanding
Weighted-average number of common shares outstanding	98,660		96,693		2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans

(in thousands, except per	Six months ended June 30				%		Primary reason(s) for
share amounts)	2013		2012		change		significant change*
Revenues	$	1,580,794	$	1,669,128	(5	)	Decrease for the electric utility segment, partly offset by increase in bank segment
Operating income	153,027		155,222		(1	)	Decrease for the electric utility segment, partly offset by an increase in the bank segment and a reduced operating loss for the “other” segment
Net income for common stock	74,267		77,116		(4	)	Lower operating income, higher “interest expense—other than on deposit liabilities and other bank borrowings” and lower AFUDC, partly offset by lower income taxes
Basic earnings per common share	$	0.75	$	0.80	(6	)	Lower net income and higher weighted average shares outstanding
Weighted-average number of common shares outstanding	98,399		96,430		2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans

*Also, see segment discussions which follow.

Notes:  The Company’s effective tax rates (combined federal and state) for the second quarters of 2013 and 2012 were 37%. The Company’s effective tax rates (combined federal and state) for the first six months of 2013 and 2012 were 36%.

HEI’s consolidated ROACE was 8.5% for the twelve months ended June 30, 2013 and 10.4% for the twelve months ended June 30, 2012.

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Dividends.  The payout ratios for the first six months of 2013 and full year 2012 were 82% and 87%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.

Economic conditions.

Note: The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS®; Bureau of Economic Analysis and national and local newspapers).

Hawaii’s tourism industry, a significant driver of Hawaii’s economy, set new records in 2012 and continues to grow in 2013, although at a slower pace. State visitor arrivals grew by 5.6% in the first half of 2013 over 2012. State visitor expenditures also grew, increasing by 6.9% in the first half of 2013 over 2012. Average daily hotel room rates also continued to rise, but hotel occupancies were weaker. The outlook for the visitor industry remains positive, but is expected to expand at a slower pace. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the third quarter of 2013 to increase by 1.4% over the third quarter of 2012.

Hawaii’s unemployment rate continues to decline, falling to 4.6% in June 2013, lower than the state’s 6.0% rate in June 2012 and the June 2013 national unemployment rate of 7.6%.

Hawaii real estate activity, as indicated by the home resale market, strengthened in the first half of 2013. The median sales price for single family residential homes on Oahu increased by 0.8% and closed sales increased 11.6% in the first half of 2013 as compared to the same period in 2012. Oahu condominiums maintained strong momentum with median sales prices rising 6.8% and closed sales increasing 18.8% for the first half of 2013 as compared to the first half of 2012. The announcements of several new planned condominium projects in Honolulu were met with immediate interest, and several projects generated strong pre-sale demand.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011 increased regional demand for energy supplies, including petroleum, and the prices of the utilities’ fuels have accordingly remained at the elevated 2011 level through 2012 and into 2013.

At its meeting on June 18-19, 2013, the Federal Open Market Committee (FOMC) announced that it expects to continue to hold the federal funds rate target at 0% to 0.25% for as long as the unemployment rate is above 6.5% and the inflation outlook remains no more than 0.5 percentage point above a longer-run 2% goal. The FOMC stated it will continue purchases of Treasury and agency mortgage-backed securities and employ other policy tools as appropriate to support progress toward the FOMC’s statutory mandate of maximum employment and price stability. In June 2013, however, Chairman Ben Bernanke indicated that if the economy continues improving, the Fed may slow its bond-buying program later this year and possibly end it in mid-2014, thereby putting upward pressure on interest rates.

Overall, Hawaii’s economy is expected to see increased growth in 2013 and 2014 with local economic growth supported by continued expansion of the visitor industry and recovery in the construction industry. U.S. budget cuts, continued uncertainty in global economies, heightened tensions in Asia and potential pandemics pose possible risks to local economic growth.

Despite economic improvement, the electric utilities’ KWH sales declined in 2012 and continued to decline in 2013. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the electric utilities’ 2013 and 2014 KWH sales are expected to further decline below 2012 levels.

Recent tax developments.  The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that impacted the Company through 2012, including the 50% and 100% bonus depreciation provisions for qualified property that resulted in an estimated net increase in federal tax depreciation of $116 million for 2012 over depreciation to which the Company would otherwise be entitled without the bonus provisions. The additional depreciation is attributable to the utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and provided a one year extension of 50% bonus depreciation, which is estimated to increase the Company’s federal tax depreciation for 2013 by $120 million, primarily attributable to the utilities.

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The Internal Revenue Service (IRS) issued proposed and temporary regulations that provide a general framework for determining whether expenditures are deductible as repairs, effective January 1, 2014. The IRS plans to issue final regulations related to repairs deductions in 2013. In the interim, the IRS has directed its examination teams to discontinue the current examination of these repairs issues and withdraw any proposed adjustments previously made in the examination of tax years prior to 2012. Once final regulations are issued, the Company will review the regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for the current and future years.

The IRS recently released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. The utilities have begun to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when the election should be made.

Health care reform.  On June 28, 2012, the US Supreme Court upheld the Patient Protection and Affordable Care Act, the 2010 health care reform law. Currently, Hawaii’s Prepaid Health Care Act generally provides greater benefits to employees and dependents because of cost sharing limitations. The Company will continue to comply with its obligations under these laws and to monitor the interaction of the state and federal laws.

Retirement benefits.  For the first six month of 2013, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a gain, after investment management fees, of 7.1%. The market value of these assets as of June 30, 2013 was $1.2 billion (including $1.1 billion for the utilities) compared to $1.1 billion at December 31, 2012 (including $1.0 billion for the utilities).

The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2013 will be $83 million ($81 million by the utilities, $2 million by HEI and nil by ASB), which is expected to fully satisfy the minimum contribution requirements, including requirements of the utilities’ pension and other postretirement benefits tracking mechanisms and the plans’ funding policies.

Commitments and contingencies.  See Note 4, “Bank subsidiary,” of HEI’s “Notes to Consolidated Financial Statements” and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements.  See Note 11, “Recent accounting pronouncements,” of HEI’s “Notes to Consolidated Financial Statements.”

“Other” segment.

	Three months ended June 30						Six months ended June 30						Primary reason(s) for
(in thousands)	2013			2012			2013			2012			significant change
Revenues	$	15		$	(5	)	$	50		$	(7	)
Operating loss	(3,473		)	(3,964		)	(7,520		)	(8,314		)	Lower administrative and general expenses
Net loss	(4,024		)	(4,765		)	(8,929		)	(9,626		)	Lower operating loss and interest expense

The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; HEI Properties, Inc., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.

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FINANCIAL CONDITION

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

The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:

(dollars in millions)	June 30, 2013				December 31, 2012
Short-term borrowings—other than bank	$	126	4	%	$	84	3	%
Long-term debt, net—other than bank	1,423		44		1,423		45
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,625		51		1,594		51
	$	3,208	100	%	$	3,135	100	%

HEI’s short-term borrowings and HEI’s line of credit facility were as follows:

	Six months ended June 30, 2013		Balance
(in millions)	Average balance		June 30, 2013		December 31, 2012
Short-term borrowings(1)
Commercial paper	$	81	$	72	$	84
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility (expiring December 5, 2016)			125		125

(1)This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources.” The maximum amount of HEI’s external short-term borrowings during the first six months of 2013 was $96 million. At July 31, 2013, HEI had $70 million in outstanding commercial paper and its line of credit facility was undrawn.

HEI has a line of credit facility of $125 million (see Note 12 of HEI’s “Notes to Consolidated Financial Statements”). There are customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in the credit agreement, or meet other requirements may result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 18% as of June 30, 2013, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of June 30, 2013, as calculated under the agreement), or if HEI no longer owns HECO. The commitment fee and interest charges on drawn amounts under the credit agreement are subject to adjustment in the event of a change in HEI’s long-term credit ratings.

The Company raised $25 million through the issuance of approximately 0.9 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first six months of 2013.

In March 2013, HEI entered into equity forward transactions in which a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and such borrowed shares were sold pursuant to an HEI registered public offering. At June 30, 2013, the equity forward transactions could have been settled with physical delivery by HEI of 7 million newly-issued shares to the forward counterparty in exchange for cash of $178 million. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled. HEI anticipates physical settlement of the equity forward transactions before March 25, 2015, but the transactions may also be cash settled or net share settled.

On March 6, 2013, HEI issued $50 million of 3.99% Senior Notes due March 6, 2023 via a private placement.  HEI used the net proceeds from the issuance of the Senior Notes to refinance $50 million of its 5.25% medium-term notes that matured on March 7, 2013. The Senior Notes contain customary representation and warranties, affirmative

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and negative covenants, and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement. For example, see discussion of “Capitalization Ratio” and “Consolidated Net Worth” above.

For the first six months of 2013, net cash provided by operating activities of consolidated HEI was $131 million. Net cash used by investing activities for the same period was $240 million, due to HECO’s consolidated capital expenditures, a net increase in ASB’s loans held for investment and purchases of investment and mortgage-related securities, partly offset by repayments of investment and mortgage-related securities, proceeds from sale of investment securities and HECO’s contributions in aid of construction. Net cash provided by financing activities during this period was $44 million as a result of several factors, including net increases in deposit liabilities and short-term borrowings and proceeds from the issuance of common stock under HEI plans, partly offset by the payment of common stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), HECO’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition—Liquidity and capital resources” sections below.) During the first six months of 2013, HECO and ASB (via ASHI) paid cash dividends to HEI of $41 million and $20 million, respectively.

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 48 to 49, 64 to 67, and 78 to 80 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.

Additional factors that may affect future results and financial condition are described on pages iv and v under “Forward-Looking Statements.”

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

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

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments.

For information about these material estimates and critical accounting policies, see pages 49 to 50, 67 to 68, and 80 to 81 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.

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Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.

Electric utility

RESULTS OF OPERATIONS

Utility strategic progress.  In 2012 and the first six months of 2013, the utilities continued to make significant progress in implementing their renewable energy strategies to support Hawaii’s efforts to reduce its dependence on oil. The PUC issued several important regulatory decisions during the period, including a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below).

The utilities are committed to achieving or exceeding the State’s Renewable Portfolio Standard goal of 40% renewable energy by 2030 (see “Renewable energy strategy” below). In addition, while it will not take precedence over the utilities’ work to increase their use of renewable energy, the utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used for the remaining generation.

Regulatory.  In January 2013, the utilities and Consumer Advocate signed a settlement agreement (2013 Agreement), which the PUC approved with clarifications in March 2013 (2013 D&O). See “Utility projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” and the discussion under “Most recent rate proceedings” below.

With PUC approval, decoupling was implemented by HECO on March 1, 2011, by HELCO on April 9, 2012 and by MECO on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual revenue adjustments for certain O&M expenses and rate base changes. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a RAM and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. The implementation of decoupling has resulted in an improvement in the utilities’ under-earning situation that has existed over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been well below PUC-allowed returns.

Under decoupling, the most significant drivers for improving earnings are:

1.completing major capital projects within PUC approved amounts and on schedule;

2.managing O&M expenses relative to authorized O&M adjustments; and

3.regulatory outcomes that cover O&M requirements and rate base items not included in the RAMs.

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for HECO, the PUC opened an investigative docket to review whether the decoupling mechanism is functioning as intended. The PUC affirmed its support for the continuation of the sales decoupling (RBA) mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency and whether the current interest rate applied to the outstanding RBA balance is reasonable. HECO, HELCO, MECO and the Consumer Advocate are named as parties to this proceeding and filed a joint statement of position that any material changes to the current decoupling mechanism should be made prospectively after 2016 unless the utilities and the Consumer Advocate mutually agree to the change in this proceeding. Several parties have filed motions to intervene.

The utilities’ five-year 2013-2017 forecast reflects net capital expenditures of $2.9 billion and a compounded near-term annual rate base growth rate in the range of 5% to 10%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise approximately 35% of the 5-year plan include projects relating to: (1) environmental compliance; (2) fuel infrastructure investments; (3) new generation; and (4) infrastructure investments to integrate more energy from renewables into the system. Estimates for these initiatives could change over time, based on external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation.

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Actual and PUC-allowed (as of June 30, 2013) returns were as follows:

%	Return on rate base (RORB)*						ROACE**						Rate-making ROACE***
Twelve months ended June 30, 2013	HECO		HELCO		MECO		HECO		HELCO		MECO		HECO	HELCO		MECO
Utility returns	7.73		6.54		7.01		6.80		5.18		7.39		10.05	7.02		8.60
PUC-allowed returns	8.11		8.31		7.34		10.00		10.00		9.00		10.00	10.00		9.00
Difference	(0.38	)	(1.77	)	(0.33	)	(3.20	)	(4.82	)	(1.61	)	0.05	(2.98	)	(0.40	)

*Based on recorded operating income and average rate base, both adjusted for items not included in determining electric rates.

**Recorded net income divided by average common equity.

***ROACE adjusted to remove items not included by the PUC in establishing rates, such as the write-off of $40 million of CIS project costs, executive bonuses and advertising.

The approval of decoupling by the PUC has helped the utilities to gradually improve their ROACEs, which in turn will facilitate the utilities’ ability to effectively raise capital for needed infrastructure investments. However, the utilities continue to expect an ongoing structural gap between their PUC-allowed ROACEs and the ROACEs they actually achieve due to the following:

1) the timing of general rate case decisions,

2) the effective date of the RAMs,

3) the 5-year historical average for baseline plant additions, and

4) the PUC’s consistent exclusion of certain expenses from rates.

The structural gap in 2014 to 2016 is expected to be 80 to 110 basis points, an improvement of 40 basis points from management’s prior expectations. The improvement is due to the change in the timing of the recognition of the RAM revenues in 2014 to 2016 as defined in the 2013 Agreement. For 2013, the expected structural gap remains unchanged at 120 to 150 basis points. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the utilities (primarily investments in software projects, changes in fuel inventory and O&M in excess of indexed escalations). The specific magnitude of the impact will depend on various factors, including the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.

Management expects the earned ROACE to gradually improve from 2014 to 2016.

As part of decoupling, HECO also tracks its rate-making ROACE as calculated under the earnings sharing mechanism and which includes only items considered in establishing rates. Earnings over and above the ROACE allowed by the PUC are shared between HECO and its ratepayers on a tiered basis. For 2012, HECO’s rate-making ROACE was 10.70%, which was above the PUC allowed 10% ROACE and triggered its earnings sharing mechanism. As a result, HECO will credit its customers $2.6 million for their portion of the earnings sharing. HECO’s 2012 rate-making ROACE of 10.70% included various adjustments to HECO’s actual ROACE of 7.57% such as the exclusion of the $40 million of CIS project costs pursuant to the 2013 Agreement, and of other expenses not considered in establishing electric rates (e.g., executive bonuses and advertising). HELCO’s rate-making ROACE was 7.79% and MECO’s rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.

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Annual decoupling filings.  On May 31, 2013, the PUC approved the revised annual decoupling filings for tariffed rates for HECO, HELCO and MECO that will be effective from June 1, 2013 through May 31, 2014. The amounts approved as noted below reflect the electric utilities’ agreements with the position of the Consumer Advocate. The revised tariffed rates include:

(in millions)	HECO			HELCO		MECO
Annual incremental RAM adjusted revenues
Operations and maintenance	$	3.9		$	0.9	$	1.0
Invested capital	27.5			1.2		2.4
Total annual incremental RAM adjusted revenues	$	31.4		$	2.1	$	3.4
Accrued earnings sharing credits to be refunded	$	(2.6	)	$	—	$	—
Accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected	$	55.4		$	4.9	$	5.8

Results.

Three months ended June 30				Increase
2013		2012		(decrease)			(in millions)
$	731	$	790	$	(59	)	Revenues. Decrease largely due to:
				$	(56	)	Lower fuel prices and lower KWH sales adjusted for decoupling mechanisms and revenue taxes
				2			Interim rate increase granted to MECO in its 2012 test year rate case
				(8		)	MECO test year 2012 final (refund)
				1			Interim and final rate increases granted to HECO in its 2011 test year rate case
289		331		(42		)	Fuel oil expense. Decrease largely due to lower fuel costs and less KWHs generated
178		188		(10		)	Purchased power expense. Decrease largely due to lower purchased power energy costs, partially offset by higher KWH purchased
94		96		(2		)	Other operation and maintenance expenses. Decrease largely due to:
				4			Higher customer service expenses
				2			Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012
				(3		)	MECO final decision adjustments for deferral of pension/OPEB and IRP expenses
				(4		)	Decrease due to timing of overhauls
109		113		(4		)	Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions
61		62		(1		)	Operating income. Slight decrease due to MECO 2012 test year refund, partially offset by lower O&M, MECO interim and HECO rate increases
29		29		—			Net income for common stock. Slight decrease largely due to lower operating income
2,247		2,257		(10		)	Kilowatthour sales (millions)
69.3		68.0		1.3			Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,114		1,150		(36		)	Cooling degree days (Oahu)
$	129.94	$	145.27	$	(15.33	)	Average fuel oil cost per barrel

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Six months ended June 30				Increase
2013		2012		(decrease)			(in millions)
$	1,450	$	1,539	$	(89	)	Revenues. Decrease largely due to:
				$	(93	)	Lower fuel prices and lower KWH sales adjusted for decoupling mechanisms and revenue taxes
				5			Interim rate increase granted to MECO in its 2012 test year rate case
				(8		)	MECO test year 2012 final (refund)
				2			Interim and final rate increases granted to HECO in its 2011 test year rate case
594		659		(65		)	Fuel oil expense. Decrease largely due to lower fuel costs and less KWHs generated
332		353		(21		)	Purchased power expense. Decrease largely due to lower purchased power energy costs, less KWH purchased and lower purchase capacity/non-fuel charges
195		188		7			Other operation and maintenance expenses. Increase largely due to:
				9			Higher customer service expenses
				3			Higher employee benefit costs
				2			Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012
				(3		)	2012 increase in general liability reserve for an environmental matter
				(3		)	MECO final decision adjustments for deferral of pension/OPEB and IRP expenses
				(4		)	Decrease due to timing of overhauls
215		220		(5		)	Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions
114		119		(5		)	Operating income. Decrease largely due to MECO 2012 test year refund, higher O&M, partly offset by MECO interim and HECO rate increases
53		57		(4		)	Net income for common stock. Decrease largely due to lower operating income
4,370		4,508		(138		)	Kilowatthour sales (millions)
67.6		67.6		—			Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,903		2,011		(108		)	Cooling degree days (Oahu)
$	131.49	$	139.63	$	(8.14	)	Average fuel oil cost per barrel
450,455		448,001		2,472			Customer accounts (end of period)

Note:  The electric utilities had effective tax rates for the second quarters of 2013 and 2012 of 39% and 38%, respectively, and for the first six months of 2013 and 2012 of 38%.

HECO’s consolidated ROACE was 6.6% for the twelve months ended June 30, 2013 and 8.7% for the twelve months ended June 30, 2012.

Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be flat to approximately 1% over prior year, as the electric utilities expect to manage expenses to near-2012 levels.

See “Economic conditions” in the “HEI Consolidated” section above.

Most recent rate proceedings.  Unless otherwise agreed or ordered, each electric utility shall initiate a rate proceeding every third year (on a staggered basis) to allow the PUC and the Consumer Advocate to regularly evaluate decoupling and the utility to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

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The following table summarizes certain details of each utility’s most recent rate cases, including the details of the increases requested, whether the utility and the Consumer Advocate reached a settlement that they proposed to the PUC, the details of any granted interim and final PUC D&O increases, and whether an interim or final PUC D&O remains pending.

Test year (dollars in millions)	Date (applied/ implemented)	Amount		% over  rates in  effect	ROACE (%)	RORB (%)	Rate base		Common equity %	Stipulated  agreement  reached with Consumer Advocate
HECO
2011 (1)
Request	7/30/10	$	113.5	6.6	10.75	8.54	$	1,569	56.29	Yes
Interim increase	7/26/11	53.2		3.1	10.00	8.11	1,354		56.29
Interim increase (adjusted)	4/2/12	58.2		3.4	10.00	8.11	1,385		56.29
Interim increase (adjusted)	5/21/12	58.8		3.4	10.00	8.11	1,386		56.29
Final increase	9/1/12	58.1		3.4	10.00	8.11	1,386		56.29
HELCO
2010 (2)
Request	12/9/09	$	20.9	6.0	10.75	8.73	$	487	55.91	Yes
Interim increase	1/14/11	6.0		1.7	10.50	8.59	465		55.91
Interim increase (adjusted)	1/1/12	5.2		1.5	10.50	8.59	465		55.91
Final increase	4/9/12	4.5		1.3	10.00	8.31	465		55.91
2013 (3)
Request	8/16/12	$	19.8	4.2	10.25	8.30	$	455	57.05
Closed	3/27/13
MECO
2012 (4)
Request	7/22/11	$	27.5	6.7	11.00	8.72	$	393	56.85	Yes
Interim increase	6/1/12	13.1		3.2	10.00	7.91	393		56.86
Final increase	8/1/13	5.3		1.3	9.00	7.34	393		56.86

Note:  The “Request Date” reflects the application filing date for the rate proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of PUC-approved increases.

(1)HECO filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. HECO’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.

The $53.2 million, $58.2 million, and $58.8 million interim increases, and the $58.1 million final increase, include the $15 million in annual revenues that were being recovered through the decoupling RAM prior to the first interim increase.

(2)HELCO’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and increasing O&M expenses. On February 8, 2012, the PUC issued a final D&O, which reflected the approval of decoupling and cost-recovery mechanisms, and on February 21, 2012, HELCO filed its revised tariffs to reflect the increase in rates. On April 4, 2012, the PUC issued an order approving the revised tariffs, which became effective April 9, 2012. HELCO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. HELCO also reset the heat rates and implemented heat rate deadbands and the PPAC, which provides a surcharge mechanism that more closely aligns cost recovery with costs incurred. The revised tariffs reflect a lower increase in annual revenue requirement compared to the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund to customers was required.

(3)HELCO’s request was required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. As a result of the 2013 Agreement and 2013 D&O (described below), the rate case was withdrawn and the docket has been closed.

(4)MECO’s request was required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation. See discussion on final D&O, including the refund to customers in September and October 2013 required as a result of the final D&O, in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

HECO 2011 test year rate case.  In the HECO 2011 test year rate case, the PUC had granted HECO’s request to defer CIS project operation and maintenance (O&M) expenses (limited to $2,258,000 per year in 2011 and 2012) that were to be subject to a regulatory audit of project costs, and allowed HECO to accrue AFUDC on these deferred costs until the completion of the regulatory audit.

On January 28, 2013, HECO, HELCO, MECO and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the

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CIP CT-1 and the CIS projects, with the remaining recoverable costs for the projects of $52 million to be included in rate base as of December 31, 2012. The parties agreed that HELCO would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that, starting in 2014, HECO will be allowed to record RAM revenues starting on January 1 of 2014, 2015 and 2016. On March 19, 2013, the PUC issued its 2013 D&O approving the 2013 Agreement, with clarifications. See “Utility projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for additional information on the 2013 Agreement and the 2013 D&O and their effects.

MECO 2012 test year rate case.  See “MECO 2012 test year rate case” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for information on the PUC’s final D&O.

Integrated Resource Planning.  In June 2013, HECO, HELCO and MECO filed their 2013 integrated resource planning (IRP) report and five-year action plans detailing plans to meet future electricity needs for the islands of Oahu, Maui, Molokai, Lanai and Hawaii. IRP aims to develop long-range 20-year resource plans for meeting energy needs under various scenarios and then to develop near-term actions for implementation over the next five years. The 2013 IRP process was the first IRP to employ scenario planning, as well as an independent entity that facilitated and provided oversight of the process, since the PUC revised the IRP Framework in March 2012. The IRP process included input from a community advisory group established by the PUC of almost 70 business, community, and government, environmental and other leaders. The utilities also held two rounds of public meetings on the islands of Oahu, Maui, Molokai, Lanai and Hawaii to seek comments from the general public, in addition to 17 meetings with the advisory group.

The overarching goals of the action plans filed are lowering costs to customers, replacing expensive oil with cleaner sources of energy, modernizing the electric grid, and looking out for the interests of all customers. Significant action plan items include:

·Lowering costs to customers by accelerating the development of low-cost, fast-track, utility-scale renewable energy projects, including solar and wind facilities.

·Deactivating (i.e., removing from service with the possibility of reactivating in the future in a major emergency for example) older, less efficient oil-fired power plant units, to help lower costs and increase the use of renewable energy generation. This includes Honolulu Power Plant and two of four generating units at Maui’s Kahului Power Plant by 2014, as well as two generators at Oahu’s Waiau Power Plant by 2016. In addition, all units at Kahului Power Plant would be fully retired by 2019. Hawaii Island’s Shipman Plant is already deactivated and will be retired in 2014.

·Converting or replacing power plants that are not deactivated to use cost-effective, cleaner fuels, including renewable biomass or biofuel and liquefied natural gas.

·Supporting the state’s efforts to procure cheaper, cleaner, liquefied natural gas to replace the use of oil in making electricity.

·Increasing the capability of utility grids to accept additional customer-sited renewable generation, especially roof-top photovoltaic systems, while protecting safety, reliability and fairness of electric service for all customers.

·Developing “smart” grids for all three companies to improve customer service, integrate more renewable energy, and enable customers to better control their electric bills. Major components of the smart grid include installing smart meters for all customers (with opt-out provisions) in the 2017-2018 timeframe, automating the grid, and developing utility energy storage systems.

In July 2013, the Independent Entity, the person selected by the PUC to provide unbiased oversight of the IRP, filed a report to the PUC documenting his evaluation of the IRP process. The evaluation recognizes that the IRP report and action plans are compliant with many IRP Framework requirements and provides substantial analysis addressing the Principal Issues, which were issues and questions identified by the PUC to be addressed in the IRP process. However, the Independent Entity did not certify that the IRP process was conducted consistent with all provisions of the IRP Framework or that it fully addressed the Principal Issues. Under the IRP Framework, the PUC should issue a decision (with approval, partial approval, rejection, modifications and/or other directives) on the action plans within six months after the utilities’ IRP filing, unless the PUC determines that an evidentiary hearing is warranted.

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Renewable energy strategy.  The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel. The utilities’ renewable energy strategy will also allow them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. For 2012, HECO achieved an RPS without DSM energy savings of 13.9%, primarily through a comprehensive portfolio of renewable energy power purchase agreements, net energy metering programs and biofuels. The utilities believe they are on track to meet the 2015 RPS.

Recent developments in the utilities’ renewable energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”):

·In February 2011, the PUC opened dockets related to HECO’s and MECO’s plans to proceed with competitive bidding processes to acquire up to approximately 300 MW and 50 MW, respectively, of new, renewable firm dispatchable capacity generation resources. In July 2013, the PUC closed the HECO and MECO RFPs, stating that the RFPs and related proceedings appear to be premature. The PUC will consider future requests by HECO or MECO to open another proceeding to conduct an RFP for generation upon demonstration of need and a plan focused on customer needs.

·In July 2011, the PUC directed HECO to submit a draft RFP for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, HECO filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200 MW RFP (see Note 5 of HECO’s “Notes to Consolidated Financial Statements” for additional information).

·In August 2011, HECO signed a 20-year contract, subject to PUC approval, with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant to begin within five years of PUC approval. In 2011, HECO also signed other contracts, subject to PUC approval, for lesser amounts of biocrude and for biodiesel for testing or operations.

·In September 2011, the PUC denied the utilities’ requested approval of HELCO’s contract with Aina Koa Pono-Ka’u LLC (AKP) citing the higher cost of the biofuel over the cost of petroleum diesel. In August 2012, HELCO signed a new 20-year contract with AKP, subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption expected to begin in 2017 or later. HELCO filed an application for approval of this contract in August 2012.

·In May 2012, the PUC approved HECO’s 3-year biodiesel supply contract with Renewable Energy Group for continued biodiesel supply to CT-1 of 3 million to 7 million gallons per year.

·In May 2012, MECO began purchasing wind energy from the 21 MW Kaheawa Wind Power II, LLC facility, which went into commercial operation in July 2012.

·In May 2012, HECO signed a contract, which was approved by the PUC, with the City and County of Honolulu to purchase an additional 27 MW of capacity and energy from an expanded waste-to-energy HPower facility, which was placed in service in April 2013.

·In May 2012, HELCO signed a power purchase agreement, subject to PUC approval, with Hu Honua Bioenergy for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii.

·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. In February 2013, HELCO issued the Final Geothermal RFP. Six bids were received in April 2013 and are being evaluated.

·In August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire and HECO has not purchased wind energy from the wind farm since then.

·In August 2012, the PUC approved a waiver from the competitive bidding process to allow HECO to negotiate with the U.S. Army for construction of a 50 MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu and expected to be placed in service in 2017.

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·In September 2012, HECO began purchasing test wind energy from the 69 MW Kawailoa Wind, LLC facility. The wind farm was placed into full commercial operation in November 2012.

·In December 2012, the PUC approved a 3-year biodiesel supply contract with Pacific Biodiesel to supply 250,000 to 1 million gallons of biodiesel at the Honolulu International Airport Emergency Power Facility beginning in 2013.

·In December 2012, the 21 MW Auwahi Wind Energy LLC facility was placed into commercial operation, selling power to MECO under a 20-year contract.

·In December 2012, the 5 MW Kalaeloa Solar Two, LLC photovoltaic facility was placed into commercial operation, selling power to HECO under a 20-year contract.

·HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of June 30, 2013, there were 9 MW, 1 MW and 2 MW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.

·As of June 30, 2013, there were approximately 127 MW, 26 MW and 30 MW of installed net energy metering capacity from renewable energy technologies (mainly photovoltaic) at HECO, HELCO and MECO, respectively. Net energy metering continues to proceed at a record pace. The amount of net energy metering capacity installed in the first half of 2013 was more than twice the amount installed during the first half of 2012.

·In February 2013, HECO issued an “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.” The invitation for waiver projects seeks to lower the cost of electricity for customers in the near term with qualified renewable energy projects on Oahu that can be quickly placed into service at a low cost per KWH. Proposals were received and, in June 2013, HECO filed a waiver request from the PUC Competitive Bidding Framework for five projects that meet these goals.

Commitments and contingencies.  See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements.  See Note 8, “Recent accounting pronouncements,” of HECO’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources.  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.

HECO’s consolidated capital structure was as follows:

(dollars in millions)	June 30, 2013				December 31, 2012
Short-term borrowings	$	54	2	%	$	—	—	%
Long-term debt, net	1,148		42		1,148		43
Preferred stock	34		1		34		1
Common stock equity	1,485		55		1,472		56
	$	2,721	100	%	$	2,654	100	%

Information about HECO’s short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows:

	Average balance		Balance
(in millions)	Six months ended June 30, 2013		June 30, 2013		December 31,  2012
Short-term borrowings(1)
Commercial paper	$	37	$	54	$	—
Line of credit draws	—		—		—
Borrowings from HEI	—		—		—
Undrawn capacity under line of credit facility (expiring December 5, 2016)			175		175

(1)The maximum amount of HECO’s external short-term borrowings during the first six months of 2013 was $71.0 million. At June 30, 2013, HECO had $9.6 million of short-term borrowings from HELCO, and MECO had $18 million of short-term borrowings from HECO. At July 31, 2013, HECO had $37 million of outstanding commercial paper, no draws under its line of credit facility, no borrowings from HEI and $10 million of short-term borrowings from HELCO. Also, at July 31, 2013, MECO had $22 million of short-term borrowings from HECO. Intercompany borrowings are eliminated in consolidation.

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HECO has a line of credit facility of $175 million (see Note 9 of HECO’s “Notes to Consolidated Financial Statements”). There are customary conditions that must be met in order to draw on it, 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 44% for MECO as of June 30, 2013, 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 June 30, 2013, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of HECO and its subsidiaries, but the sources of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the DBF, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on Special Purpose Revenue Bonds currently outstanding and issued prior to 2009 are insured by one of the following bond insurers: Ambac Assurance Corporation; Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012 (with a plan of rehabilitation approved on June 11, 2013); MBIA Insurance Corporation (which bonds have been reinsured by National Public Finance Guarantee Corp.); or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The Standard & Poor’s (S&P’s) and Moody’s Investor Service’s ratings of each of these insurers, which at the time the insured obligations were issued were higher than the ratings of the utilities, are currently either lower than the ratings of the utilities or have been withdrawn.

The PUC has approved the use of an expedited approval procedure for the approval of long-term debt financings or refinancings (including the issuance of taxable debt) by HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions. New long-term debt authorizations of $150 million (HECO $100 million, HELCO $25 million and MECO $25 million) can be requested under the expedited approval procedure through 2015.

In January 2013, HECO, HELCO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $90 million, $56 million and $20 million, respectively, of unsecured obligations bearing taxable interest to refinance select series of outstanding revenue bonds. In February 2013, HECO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $50 million and $20 million, respectively, of unsecured obligations bearing taxable interest. The proceeds are expected to be used to fund capital expenditures, including repaying short-term indebtedness incurred to fund capital expenditures. By orders issued on June 28 and July 24, 2013, the PUC approved both requests.

Operating activities provided $112 million in net cash during the first six months of 2013. Investing activities for the same period used net cash of $132 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $12 million, primarily due to the increase in short-term borrowings, partly offset by payment of $42 million of common and preferred dividends.

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Bank

RESULTS OF OPERATIONS

	Three months ended June 30					Increase
(in millions)	2013			2012		(decrease)			Primary reason(s) for significant change
Interest income	$	47		$	48	$	(1	)	The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for the second quarter of 2013 was $180 million higher than for the second quarter of 2012 as the average home equity lines of credit, residential, commercial real estate and consumer loan balances increased by $89 million, $81 million, $25 million and $24 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix target and loan growth strategy. The loan portfolio yields were impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yield.
Noninterest income	19			17		2			Higher gain on sale of securities as ASB sold $70 million of agency obligations during the second quarter of 2013.
Revenues	66			65		1
Interest expense	2			3		(1		)	Lower funding costs as a result of the low interest rate environment. Average deposit balances for the second quarter of 2013 increased by $184 million compared to the second quarter of 2012 due to an increase in core deposits of $252 million, partly offset by a decrease in term certificates of $68 million. The other borrowings average balance decreased by $30 million due to lower retail repurchase agreements.
Provision (credit) for loan losses	(1		)	2		(3		)	The credit for loan losses in the second quarter of 2013 was due to the $1 million release of reserves as a result of an agreement to sell ASB’s credit card portfolio. No additional provision expense was incurred as increases in the provision for loan losses to cover loan growth and charge-offs were offset by the release of commercial real estate loan portfolio reserves due to paydowns, recoveries of previously charged off consumer loans and the ongoing improvement in the quality of ASB’s loan portfolio.
Noninterest expense	40			38		2			Higher compensation and benefits expenses due to targeted staffing increases to support increased business volumes, information technology (IT) and risk management capabilities.
Expenses	41			43		(2		)
Operating income	25			22		3			Higher noninterest income and lower provision for loan losses, partially offset by lower net interest income and higher noninterest expenses.
Net income	16			14		2			Higher operating income.

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	Six months ended June 30				Increase
(in millions)	2013		2012		(decrease)			Primary reason(s) for significant change
Interest income	$	93	$	96	$	(3	)	The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for the six months ended June 30, 2013 was $144 million higher than for the same period in 2012 as the average home equity lines of credit, commercial real estate, residential and consumer loan balances increased by $89 million, $30 million, $27 million and $26 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix target and loan growth strategy. Loan portfolio yields were impacted by the low interest rate environment as new loan production yields were lower than the average portfolio yields. The average investment and mortgage-related securities portfolio balance increased by $23 million as ASB used its excess liquidity to purchase securities.
Noninterest income	38		34		4			Higher gain on sale of securities due to the sale of $70 million of agency obligations and higher mortgage banking income due to higher gain on sale of loans.
Revenues	131		130		1
Interest expense	5		6		(1		)	Lower funding costs as a result of the low interest rate environment. Average deposit balances for the six months ended June 30, 2013 increased by $161 million compared to the same period in 2012 due to an increase in core deposits of $230 million, partly offset by a decrease in term certificates of $70 million. The other borrowings average balance decreased by $35 million due to lower retail repurchase agreements.
Provision for loan losses	1		6		(5		)	The 2013 provision for loan losses declined due in part to the improved credit quality associated with the continuing improvement in Hawaii’s economy, lower net charge-offs in the higher risk land loan portfolios and purchased mortgage portfolio and $1.0 million release of the allowance on credit card loans due to the upcoming portfolio sale.
Noninterest expense	79		73		6			Higher compensation and benefits expenses due to targeted staffing increases to support increased business volumes, IT and risk management capabilities.
Expenses	85		85		—
Operating income	46		45		1			Lower provision for loan losses and higher noninterest income, partially offset by lower net interest income and higher noninterest expenses.
Net income	30		30		—

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Details of ASB’s other noninterest income and other noninterest expense were as follows:

	Three months ended June 30				Six months ended June 30
(in thousands)	2013		2012		2013		2012
Bank-owned life insurance	$	985	$	993	$	1,952	$	1,972
Other	746		456		1,371		837
Total other income	$	1,731	$	1,449	$	3,323	$	2,809
FDIC insurance premium	$	848	$	854	$	1,688	$	1,707
Marketing	824		554		1,362		1,104
Office supplies, printing and postage	1,026		919		1,899		1,909
Communication	424		430		895		866
Reversal of interest expense—tax	—		—		—		(552		)
Other	5,378		5,349		10,251		9,779
Total other expense	$	8,500	$	8,106	$	16,095	$	14,813

See Note 4 of HEI’s “Notes to Consolidated Financial Statements” and “Economic conditions” in the “HEI Consolidated” section above.

Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base and lower-risk profile to continue to deliver strong performance compared to industry peers.

ASB’s return on average assets, net interest margin and efficiency ratio were as follows:

	Three months ended		Six months ended
	June 30		June 30
(percent)	2013	2012	2013	2012
Return on average assets	1.25	1.15	1.19	1.22
Net interest margin	3.79	3.97	3.79	4.01
Efficiency ratio	62	60	62	58

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Average balance sheet and net interest margin.  The following tables set forth average balances, together with interest earned and accrued, and resulting yields and costs:

	2013						2012
Three months ended June 30 (dollars in thousands)	Average balance			Interest		Yield/ rate (%)	Average balance			Interest		Yield/ rate (%)
Assets:
Other investments (1)	$	164,374		$	44	0.11	$	201,812		$	66	0.13
Securities purchased under resale agreements	26,154			25		0.38	—			—		—
Available-for-sale investment and mortgage-related securities	617,942			3,386		2.19	624,581			3,435		2.20
Loans (2)
Residential 1-4 family	1,964,140			23,503		4.79	1,882,701			24,802		5.27
Commercial real estate	429,409			4,973		4.64	404,542			4,649		4.60
Home equity line of credit	665,879			4,840		2.92	576,655			3,914		2.73
Residential land	22,607			335		5.93	37,453			598		6.39
Commercial loans	699,023			7,347		4.21	723,995			7,916		4.40
Consumer loans	123,601			2,626		8.52	99,261			2,594		10.51
Total loans (2), (3)	3,904,659			43,624		4.47	3,724,607			44,473		4.79
Total interest-earning assets (4)	4,713,129			47,079		4.00	4,551,000			47,974		4.22
Allowance for loan losses	(43,372		)				(39,295		)
Non-interest-earning assets	429,924						429,258
Total assets	$	5,099,681					$	4,940,963
Liabilities and shareholder’s equity:
Savings	$	1,811,157		263		0.06	$	1,725,034		304		0.07
Interest-bearing checking	659,790			25		0.02	613,370			30		0.02
Money market	176,812			56		0.13	187,455			73		0.16
Time certificates	462,762			952		0.83	530,896			1,289		0.97
Total interest-bearing deposits	3,110,521			1,296		0.17	3,056,755			1,696		0.22
Advances from Federal Home Loan Bank	51,264			542		4.18	50,000			541		4.28
Securities sold under agreements to repurchase	144,496			636		1.74	175,745			673		1.52
Total interest-bearing liabilities	3,306,281			2,474		0.30	3,282,500			2,910		0.35
Non-interest bearing liabilities:
Deposits	1,182,244						1,052,275
Other	104,372						106,125
Total liabilities	4,592,897						4,440,900
Shareholder’s equity	506,784						500,063
Total liabilities and shareholder’s equity	$	5,099,681					$	4,940,963
Net interest income				$	44,605					$	45,064
Net interest margin (%) (5)						3.79						3.97

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	2013						2012
Six months ended June 30 (dollars in thousands)	Average balance			Interest		Yield/ rate (%)	Average balance			Interest		Yield/ rate (%)
Assets:
Other investments (1)	$	181,195		$	108	0.12	$	226,714		$	162	0.14
Securities purchased under resale agreements	13,149			25		0.38	—			—		—
Available-for-sale investment and mortgage-related securities	633,232			7,005		2.21	609,826			7,315		2.40
Loans (2)
Residential 1-4 family	1,923,389			46,859		4.87	1,896,188			50,412		5.32
Commercial real estate	425,473			9,606		4.53	395,229			9,235		4.68
Home equity line of credit	653,086			9,302		2.87	563,723			7,684		2.74
Residential land	23,801			591		4.97	39,661			1,153		5.81
Commercial loans	705,330			14,816		4.23	718,297			15,875		4.44
Consumer loans	123,624			5,053		8.23	97,240			5,002		10.34
Total loans (2), (3)	3,854,703			86,227		4.49	3,710,338			89,361		4.83
Total interest-earning assets (4)	4,682,279			93,365		4.00	4,546,878			96,838		4.27
Allowance for loan losses	(42,992		)				(38,741		)
Non-interest-earning assets	432,009						430,929
Total assets	$	5,071,296					$	4,939,066
Liabilities and shareholder’s equity:
Savings	$	1,793,415		517		0.06	$	1,711,941		614		0.07
Interest-bearing checking	650,044			49		0.02	609,448			60		0.02
Money market	186,136			119		0.13	218,571			194		0.18
Time certificates	466,261			1,923		0.83	536,113			2,607		0.98
Total interest-bearing deposits	3,095,856			2,608		0.17	3,076,073			3,475		0.23
Advances from Federal Home Loan Bank	50,635			1,077		4.23	50,000			1,082		4.28
Securities sold under agreements to repurchase	145,888			1,265		1.73	181,535			1,393		1.52
Total interest-bearing liabilities	3,292,379			4,950		0.30	3,307,608			5,950		0.36
Non-interest bearing liabilities:
Deposits	1,166,993						1,026,187
Other	107,594						108,519
Total liabilities	4,566,966						4,442,314
Shareholder’s equity	504,330						496,752
Total liabilities and shareholder’s equity	$	5,071,296					$	4,939,066
Net interest income				$	88,415					$	90,888
Net interest margin (%) (5)						3.79						4.01

(1)Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.

(2)Includes loans held for sale.

(3)Includes loan fees of $1.4 million and $1.3 million for the three months ended June 30, 2013 and 2012, respectively, and $2.9 million and $2.5 million for the six months ended June 30, 2013 and 2012, together with interest accrued prior to suspension of interest accrual on nonaccrual loans, includes nonaccrual loans.

(4)Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million for the three months ended June 30, 2013 and 2012, and $0.4 million for the six months ended June 30, 2013 and 2012.

(5)Defined as net interest income as a percentage of average earning assets.

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Earning assets, costing liabilities and other factors.  Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The interest rate environment has been impacted by disruptions in the financial markets and these conditions have continued to have a negative impact on ASB’s net interest margin.

Loan originations and mortgage-related securities are ASB’s primary sources of earning assets.

Loan portfolio.  ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. The composition of ASB’s loan portfolio was as follows:

	June 30, 2013				December 31, 2012
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate loans:
Residential 1-4 family	$	2,001,035		50.5	$	1,866,450		49.2
Commercial real estate	382,735			9.7	375,677			9.9
Home equity line of credit	673,727			17.0	630,175			16.6
Residential land	21,836			0.5	25,815			0.7
Commercial construction	50,114			1.3	43,988			1.2
Residential construction	9,664			0.2	6,171			0.2
Total real estate loans, net	3,139,111			79.2	2,948,276			77.8
Commercial loans	719,519			18.2	721,349			19.0
Consumer loans	104,759			2.6	121,231			3.2
	3,963,389			100.0	3,790,856			100.0
Less: Deferred fees and discounts	(9,755		)		(11,638		)
Allowance for loan losses	(41,004		)		(41,985		)
Total loans, net	$	3,912,630			$	3,737,233

The increase in the total loan portfolio during the first six months of 2013 compared to the same period in 2012 was primarily due to an increase in originated ASB’s residential 1-4 family, home equity lines of credit and commercial real estate loan portfolios and is in line with ASB’s portfolio mix target and loan growth strategy.

In May 2013, ASB entered into an agreement with First Bankcard, a division of First National Bank of Omaha, to sell ASB’s credit card portfolio to First Bankcard. As part of the agreement, through First Bankcard, ASB will be able to offer ASB customers a greater variety of business and consumer credit card products, an enhanced rewards program, and regular marketing support. First Bankcard supports more than 500 partners with 5,700 retail branches, owning over 4 million credit card accounts. ASB transferred the $25 million credit card portfolio to held for sale and carried it at lower of cost or market. On August 1, 2013, ASB completed the sale of its credit card portfolio to First Bankcard.

Home equity — key credit statistics.

	June 30, 2013			December 31, 2012
Outstanding balance (in thousands)	$	673,727		$	630,175
Percent of portfolio in first lien position	35.0		%	29.9		%
Net charge-off ratio	0.14		%	0.10		%
Delinquency ratio	0.30		%	0.40		%

							End of draw period – interest only									Current
June 30, 2013	Total			Interest only			2013-2014			2015-2017			Thereafter			amortizing
Outstanding balance (in thousands)	$	673,727		$	524,775		$	132		$	12,153		$	512,490		$	148,952
% of total	100		%	78		%	—		%	2		%	76		%	22		%

The home equity line of credit (HELOC) portfolio makes up 17% of the total loan portfolio and is generally an interest-only revolving loan for a 10-year period, after which time the HELOC outstanding balance converts to a fully amortizing variable rate term loan with a 20-year amortization period. This product type comprises 89% of the total HELOC portfolio and is the current product offering. Within this product type, borrowers also have a “Fixed Rate Loan Option” to convert a part of their available line of credit into a 5, 7 or 10-year fully amortizing fixed rate loan with level

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principal and interest payments. As of June 30, 2013, approximately 11% of the portfolio balances are amortizing loans under the Fixed Rate Loan Option. Nearly all originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period.   These older vintage equity lines represent 11% of the portfolio and are included in the amortizing balances identified in the table above.

Loan portfolio risk elements.  See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

Investment and mortgage-related securities.  ASB’s investment portfolio was comprised as follows:

	June 30, 2013				December 31, 2012
(dollars in thousands)	Balance		% of total		Balance		% of total
Federal agency obligations	$	99,064	18	%	$	171,491	26	%
Mortgage-related securities — FNMA, FHLMC and GNMA	382,044		68		417,383		62
Municipal bonds	79,064		14		82,484		12
	$	560,172	100	%	$	671,358	100	%

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. The decrease in federal agency obligations was due to the sale of $70 million of agency obligations in the second quarter of 2013. The decrease in mortgage-related securities was due to paydowns in the portfolio.

Deposits and other borrowings.  Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth will remain challenging in the current environment due to competition for deposits and the low level of short-term interest rates. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be additional sources of funds. Advances from the FHLB of Seattle have remained at $50 million from December 31, 2012 to June 30, 2013. As of June 30, 2013 and December 31, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. The weighted average cost of deposits for the first six months of 2013 was 0.12%, compared to 0.17% for the first six months of 2012.

Other factors.  Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in the fair value of those instruments, respectively. In addition, changes in credit spreads also impact the fair values of those instruments.

As of June 30, 2013 and December 31, 2012, ASB had unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $1 million and $11 million, respectively. The decrease in AOCI was due to the impact of rising interest rates on the fair value of ASB’s investment and mortgage-related securities. See “Item 3. Quantitative and qualitative disclosures about market risk.”

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During the first six months of 2013, ASB recorded a provision for loan losses of $0.9 million primarily due to net charge-offs during the year for consumer, commercial and HELOC loans, and growth in the loan portfolio, partly offset by the release of reserves for the credit card and commercial real estate loan portfolios. During the first six months of 2012, ASB recorded a provision for loan losses of $5.9 million primarily due to charge-offs during the year for 1-4 family, residential land, commercial and consumer loans. Continued financial stress on ASB’s customers may result in higher levels of delinquencies and losses.

	Six months ended June 30						Year ended December 31
(in thousands)	2013			2012			2012
Allowance for loan losses, January 1	$	41,985		$	37,906		$	37,906
Provision for loan losses	899			5,924			12,883
Less: net charge-offs	1,880			4,367			8,804
Allowance for loan losses, end of period	$	41,004		$	39,463		$	41,985
Ratio of allowance for loan losses, end of period, to end of period loans outstanding	1.04		%	1.06		%	1.11		%
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.10		%	0.24		%	0.24		%

Legislation and regulation.  ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corporation (FDIC). Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.”

Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act).  Regulation of the financial services industry, including regulation of HEI, ASHI and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI, ASHI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASHI, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, OCC and the Bureau. In addition, HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.

More stringent affiliate transaction rules now apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards were raised with respect to the ability of ASB to merge with or acquire another institution. In reviewing a potential merger or acquisition, the approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. banking or financial system.”

The Dodd-Frank Act established the Bureau. It has authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have to have sufficient assets or income to pay back the loan, and (iii) lenders will have to determine the consumer’s ability to repay both the principal and the interest over the long term - not just during an introductory period when the rate may be lower.

On May 22, 2012, the Bureau issued the Final Remittance Rule (an amendment to Regulation E). For international wires, the rule now provides flexibility regarding the disclosure of foreign taxes, as well as fees imposed by a designated recipient’s institution for receiving a remittance transfer in an account. Second, the rule limits a remittance transfer provider’s obligation to disclose foreign taxes to those imposed by a country’s central government. And third, the rule revises the error resolution provisions that apply when a remittance transfer is not

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delivered to a designated recipient because the sender provided incorrect or insufficient information, and, in particular, when a sender provides an incorrect account number and that incorrect account number results in the funds being deposited in the wrong account.

ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank may be subject to state regulation and allows federal law to preempt a state consumer financial law on a “case by case” basis only when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state; (2) the state law prevents or significantly interferes with a bank’s exercise of its power; or (3) the state law is preempted by another federal law.

The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms.

The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. Financial institutions and their affiliates that have less than $10 billion in assets are exempt from this Amendment; however, as of July 1, 2013, ASB is not exempt. For the second quarter of 2013, ASB had earned an average of 49 cents per electronic debit transaction. ASB estimates debit card interchange fees to be lower by approximately $3 million after tax for the remainder of 2013 and approximately $6 million after tax if it continues to be non-exempt in 2014.

Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective.

Final Capital Rule.  On July 2, 2013, the FRB finalized its rule implementing the Basel III regulatory capital framework. The final rule would apply to banking organizations of all sizes and types regulated by the FRB and the OCC, except bank holding companies subject to the FRB’s Small Bank Holding Company Policy Statement and Savings & Loan Holding Companies (SLHCs) substantially engaged in insurance underwriting or commercial activities. HEI currently meets the requirements of the exemption as a top-tier grandfathered unitary SLHC that derived, as of June 30 of the previous calendar year, either 50% or more of its total consolidated assets or 50% or more of its total revenues on an enterprise-wide basis (calculated under GAAP) from activities that are not financial in nature pursuant to Section 4(k) of the Bank Holding Company Act. The FRB is temporarily excluding these SLHCs from the final rule while it considers a proposal relating to capital and other requirements for SLHC intermediate holding companies. The FRB anticipates that it will release a proposal on intermediate holding companies in the near term that would specify the criteria for establishing and transferring activities to intermediate holding companies and propose to apply the FRB’s capital requirements to such intermediate holding companies.

Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would be subject to the following minimum regulatory capital requirements: a common equity tier 1 capital ratio of 4.5%, a tier 1 capital ratio of 6%, a total capital ratio of 8% of risk-weighted assets and a leverage ratio of 4%. In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, the final rule requires a banking organization to hold a buffer of common equity tier 1 capital above its minimum risk-based capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer). In addition, a countercyclical capital buffer would expand the capital conservation buffer by up to 2.5% of a banking organization’s total risk-weighted assets for advanced approaches banking organizations. The final rule would establish qualification criteria for common equity, additional tier 1 and tier 2 capital instruments that help to ensure their ability to absorb losses. All banking organizations would be required to calculate risk-weighted assets under the standardized approach, which harmonizes the banking agencies’ calculation of risk-weighted assets and address shortcomings in risk-based capital requirements identified by the agencies.

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Minimum Capital Requirements

Effective dates	1/1/15		1/1/16		1/1/17		1/1/18		1/1/19
Capital conservation buffer			0.625	%	1.25	%	1.875	%	2.50	%
Common equity ratio + conservation buffer	4.50	%	5.125	%	5.75	%	6.375	%	7.00	%
Tier 1 capital ratio + conservation buffer	6.00	%	6.625	%	7.25	%	7.875	%	8.50	%
Total capital ratio + conservation buffer	8.00	%	8.625	%	9.25	%	9.875	%	10.50	%
Tier 1 leverage ratio	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Countercyclical capital buffer — not applicable to ASB			0.625	%	1.25	%	1.875	%	2.50	%

The final rule is effective January 1, 2015 for ASB. Subject to the timing and final outcome of the FRB’s SLHC intermediate holding company proposal, HEI anticipates that the capital requirements in the final rule will be effective for HEI or ASHI on January 1, 2015 as well. HEI and ASB have reviewed the final rule and the impact to capital ratios. If the final rules were currently applicable to HEI and ASB, management believes HEI and ASB would satisfy the new capital requirements, including the fully phased-in capital conservation buffer.

Commitments and contingencies.  See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources.

(dollars in millions)	June 30, 2013		December 31, 2012		% change
Total assets	$	5,069	$	5,042	1
Available-for-sale investment and mortgage-related securities	560		671		(17	)
Loans receivable held for investment, net	3,913		3,737		5
Deposit liabilities	4,276		4,230		1
Other bank borrowings	188		196		(4	)

As of June 30, 2013, ASB was one of Hawaii’s largest financial institutions based on assets of $5.1 billion and deposits of $4.3 billion.

As of June 30, 2013, ASB’s unused FHLB borrowing capacity was approximately $0.9 billion. As of June 30, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first six months of 2013, net cash provided by ASB’s operating activities was $48 million. Net cash used during the same period by ASB’s investing activities was $108 million, primarily due to purchases of investment and mortgage-related securities of $40 million, a net increase in loans receivable of $201 million and additions to premises and equipment of $8 million, partly offset by proceeds from the sale of investment securities of $71 million, repayments of investment and mortgage-related securities of $63 million, proceeds from the sale of real estate acquired in settlement of loans of $6 million and redemption of stock from FHLB of Seattle of $2 million. Net cash provided in financing activities during this period was $19 million, primarily due to net increases in deposit liabilities of $46 million and a net increase in mortgage escrow deposits of $1 million, partly offset by a net decrease in retail repurchase agreements of $8 million and the payment of $20 million in common stock dividends to HEI (through ASHI).

FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of June 30, 2013, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.3% (5.0%), a Tier-1 risk-based capital ratio of 11.5% (6.0%) and a total risk-based capital ratio of 12.5% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity. For additional quantitative and qualitative information about the Company’s market risks, see pages 82 to 84, HEI’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2012 Form 10-K and HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 2012 Form 10-K by reference to Exhibit 99.2.

ASB’s interest-rate risk sensitivity measures as of June 30, 2013 and December 31, 2012 constitute “forward-looking statements” and were as follows:

	Change in NII (gradual change in interest rates)				Change in EVE (instantaneous change in interest rates)
Change in interest rates (basis points)	June 30, 2013		December 31, 2012		June 30, 2013		December 31, 2012
+300	1.8	%	1.6	%	(9.8	)%	(9.4	)%
+200	0.6		0.5		(6.0	)	(4.9	)
+100	0.1		0.1		(2.7	)	(1.9	)
-100	(0.2	)	(0.2	)	(0.2	)	(1.7	)

Management believes that ASB’s interest rate risk position as of June 30, 2013 represents a reasonable level of risk. Net interest income (NII) sensitivity as of June 30, 2013 was slightly more asset sensitive for larger increases in rates compared to December 31, 2012 due to changes in assumptions about the rate sensitivity of certain non-maturity or core deposits.

ASB’s base economic value of equity (EVE) increased to $868 million as of June 30, 2013 compared to $767 million as of December 31, 2012 due to the decrease in the discount of core deposits resulting from the rise in interest rates.

The change in EVE was more sensitive to rising rate scenarios as of June 30, 2013 compared to December 31, 2012 due to the increase and steepening of the yield curve and changes in the asset mix as the residential portfolio grew and short duration securities were sold.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

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Item 4. Controls and Procedures

HEI:

Changes in Internal Control over Financial Reporting

During the second quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of June 30, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of June 30, 2013. Based on their evaluations, as of June 30, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:

(1)is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2)is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

HECO:

Changes in Internal Control over Financial Reporting

During the second quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of June 30, 2013 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Richard M. Rosenblum, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of June 30, 2013. Based on their evaluations, as of June 30, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

(1)is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2)is accumulated and communicated to HECO management, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Note 4 of HEI’s “Notes to Consolidated Financial Statements” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

Item 1A. Risk Factors

For information about Risk Factors, see pages 70 to 79 of HEI’s Form 10-Q for the quarter ended March 31, 2013, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on pages v and vi of HEI’s 2012 Form 10-K, as updated on pages iv and v herein.

Item 5. Other Information

A.Ratio of earnings to fixed charges.

	Six months ended June 30		Years ended December 31
	2013	2012	2012	2011	2010	2009	2008
HEI and Subsidiaries
Excluding interest on ASB deposits	3.50	3.59	3.28	3.22	2.89	2.29	2.06
Including interest on ASB deposits	3.36	3.41	3.14	3.03	2.64	1.95	1.71
HECO and Subsidiaries	3.57	3.79	3.37	3.52	2.88	2.99	3.48

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

B.James A. Ajello, HEI Executive Vice President and Chief Financial Officer, has been appointed HEI principal accounting officer effective August 2, 2013, in addition to his existing responsibilities. With respect to the principal accounting officer role, Mr. Ajello succeeds Jennifer B. Loo, HEI Manager, Financial Reporting and Accounting and Assistant Controller, who served as Interim principal accounting officer from March 8 to August 1, 2013, in addition to her ongoing duties. Mr. Ajello will not receive any additional compensation in connection with his appointment as principal accounting officer.

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Item 6. Exhibits

HEI Exhibit 12.1	Hawaiian Electric Industries, Inc. and Subsidiaries
	Computation of ratio of earnings to fixed charges, six months ended June 30, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008
HEI Exhibit 31.1	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)
HEI Exhibit 31.2	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer)
HEI Exhibit 32.1	HEI Certification Pursuant to 18 U.S.C. Section 1350
HEI Exhibit 101.INS	XBRL Instance Document
HEI Exhibit 101.SCH	XBRL Taxonomy Extension Schema Document
HEI Exhibit 101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
HEI Exhibit 101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
HEI Exhibit 101.LAB	XBRL Taxonomy Extension Label Linkbase Document
HEI Exhibit 101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
HECO Exhibit 12.2	Hawaiian Electric Company, Inc. and Subsidiaries
	Computation of ratio of earnings to fixed charges, six months ended June 30, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008
HECO Exhibit 31.3	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer)
HECO Exhibit 31.4	Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)
HECO Exhibit 32.2	HECO Certification Pursuant to 18 U.S.C. Section 1350

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.

HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
(Registrant)		(Registrant)
By	/s/ Constance H. Lau	By	/s/ Richard M. Rosenblum
	Constance H. Lau		Richard M. Rosenblum
	President and Chief Executive Officer		President and Chief Executive Officer
	(Principal Executive Officer of HEI)		(Principal Executive Officer of HECO)
By	/s/ James A. Ajello	By	/s/ Tayne S. Y. Sekimura
	James A. Ajello		Tayne S. Y. Sekimura
	Executive Vice President and		Senior Vice President
	Chief Financial Officer		and Chief Financial Officer
	(Principal Financial and Accounting		(Principal Financial Officer of HECO)
	Officer of HEI)
		By	/s/ Cathlynn L. Yoshida
			Cathlynn L. Yoshida
			Controller
			(Principal Accounting Officer of HECO)
Date: August 8, 2013		Date: August 8, 2013

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