HAWAIIAN ELECTRIC CO INC - Quarter Report: 2015 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2015

o TRANSITION 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 April 30, 2015
Hawaiian Electric Industries, Inc. (Without Par Value)		107,417,644 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		15,805,327 Shares (not publicly traded)

Hawaiian Electric Industries, Inc. (HEI) is the sole holder of Hawaiian Electric Company, Inc. (Hawaiian Electric) common stock.

This combined Form 10-Q is separately filed by HEI and Hawaiian Electric. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to the other registrant, except that information relating to Hawaiian Electric is also attributed to HEI.

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2015

TABLE OF CONTENTS



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 months ended March 31, 2015 and 2014
2		Consolidated Statements of Comprehensive Income - three months ended March 31, 2015 and 2014
3		Consolidated Balance Sheets - March 31, 2015 and December 31, 2014
4		Consolidated Statements of Changes in Shareholders’ Equity - three months ended March 31, 2015 and 2014
5		Consolidated Statements of Cash Flows - three months ended March 31, 2015 and 2014
		Hawaiian Electric Company, Inc. and Subsidiaries
6		Consolidated Statements of Income - three months ended March 31, 2015 and 2014
6		Consolidated Statements of Comprehensive Income - three months ended March 31, 2015 and 2014
7		Consolidated Balance Sheets - March 31, 2015 and December 31, 2014
8		Consolidated Statements of Changes in Common Stock Equity - three months ended March 31, 2015 and 2014
9		Consolidated Statements of Cash Flows - three months ended March 31, 2015 and 2014
10		Notes to Consolidated Financial Statements
57	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
57		HEI consolidated
60		Electric Utilities
70		Bank
76	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
77	Item 4.	Controls and Procedures

	PART II.	OTHER INFORMATION
77	Item 1.	Legal Proceedings
78	Item 1A.	Risk Factors
78	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds
78	Item 5.	Other Information
79	Item 6.	Exhibits
80	Signatures

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2015

GLOSSARY OF TERMS



Terms		Definitions
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 ASB Hawaii, Inc.
ASB Hawaii		ASB Hawaii, Inc. (formerly American Savings Holdings, Inc.), a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
ASC		Accounting Standards Codification
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 Hawaiian Electric); ASB Hawaii, 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
DG		Distributed generation
Dodd-Frank Act		Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
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 clause
EGU		Electrical generating unit
EIP		2010 Equity and Incentive Plan, as amended and restated
Energy Agreement		Agreement, dated October 20, 2008, 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 Hawaiian Electric, 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. In September 2014, the parties to the Energy Agreement concluded that the agreements and policy directives in the Energy Agreement had been advanced or superseded by subsequent events, as well as by decisions and orders issued by the PUC, and accordingly ended the Energy Agreement as of September 14, 2014.
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
GAAP		Accounting principles generally accepted in the United States of America
GHG		Greenhouse gas

GLOSSARY OF TERMS, continued



Terms		Definitions
GNMA		Government National Mortgage Association
HCEI		Hawaii Clean Energy Initiative
Hawaii Electric Light		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
Hawaiian Electric		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., ASB Hawaii, 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
HELOC		Home equity line of credit
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/s (as applicable)
KWH		Kilowatthour/s (as applicable)
LTIP		Long-term incentive plan
LGD		Loss given default
Maui Electric		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
Merger		As provided in the Merger Agreement, merger of Merger Sub I with and into HEI, with HEI surviving, and then merger of HEI with and into Merger Sub II, with Merger Sub II surviving as a wholly owned subsidiary of NEE
Merger Agreement		Agreement and Plan of Merger by and among HEI, NEE, Merger Sub II and Merger Sub I, dated December 3, 2014
Merger Sub I		NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE
Merger Sub II		NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE
MOU		Memorandum of understanding
MW		Megawatt/s (as applicable)
NEE		NextEra Energy, Inc.
NII		Net interest income
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
PV		Photovaltaic
RAM		Rate adjustment mechanism
RBA		Revenue balancing account
RFP		Request for proposals
ROACE		Return on average common equity
RORB		Return on rate base
RPS		Renewable portfolio standards
SAR		Stock appreciation right
SEC		Securities and Exchange Commission
See		Means the referenced material is incorporated by reference
Spin-Off		The distribution to HEI shareholders of all of the common stock of ASB Hawaii immediately prior to the Merger
TDR		Troubled debt restructuring
Trust III		HECO Capital Trust III
Utilities		Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited
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. (Hawaiian Electric) 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:

•

the successful and timely completion of the proposed Merger with NextEra Energy, Inc. (NEE), which could be materially and adversely affected by, among other things, resolving the litigation brought in connection with the proposed Merger, the timing and terms and conditions of required governmental and regulatory approvals, the ability to obtain the required shareholder approval and the ability to maintain relationships with employees, customers or suppliers, as well as the ability to integrate the businesses;


•	the ability of ASB to operate successfully after the Spin-Off of its parent ASB Hawaii;

•

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, 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, ongoing conflicts in North Africa and the Middle East, terrorist acts, potential conflict or crisis with North Korea or Iran, developments in the Ukraine and potential pandemics);


•	the effects of future actions or inaction of the U.S. government or related agencies, including those related to the U.S. debt ceiling and monetary policy;


•	weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes, lava flows and the potential effects of climate change, such as more severe storms and rising sea levels), including their impact on the Company's and Utilities' 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 and the Utilities to access the credit and capital markets (e.g., to obtain commercial paper and other short-term and long-term debt financing, including lines of credit, and, in the case of HEI, to issue 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 PUC’s potential delay in considering (and potential disapproval of actual or proposed) Hawaii Clean Energy Initiative (HCEI)-related costs; reliance by the Utilities 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);

•

the ability of the Utilities to develop, implement and recover the costs of implementing the Utilities’ action plans and business model changes that are being developed in response to the four orders that the Public Utilities Commission of the State of Hawaii (PUC) issued in April 2014, in which the PUC: directed the Utilities to develop, among other things, Power Supply Improvement Plans, a Demand Response Portfolio Plan and a Distributed Generation Interconnection Plan; described the PUC’s inclinations on the future of Hawaii’s electric utilities and the vision, business strategies and regulatory policy changes required to align the Utilities’ business model with customer interests and the state’s public policy goals; and emphasized the need to “leap ahead” of other states in creating a 21st century generation system and modern transmission and distribution grids;


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


•	fuel oil price changes, delivery of adequate fuel by suppliers 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), rate adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales to mitigate the effects of declining kilowatthour sales;


•	the impact of fuel price volatility on customer satisfaction and political and regulatory support for the Utilities;


•	the risks associated with increasing reliance on renewable energy, 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 growing risk that energy production from renewable generating resources may be curtailed and the interconnection of additional resources will be constrained as more generating resources are added to the Utilities' electric systems and as customers reduce their energy usage;


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


•	the potential that, as IPP contracts near the end of their terms, there may be less economic incentive for the IPPs to make investments in their units to ensure the availability of their units;


•	the ability of the Utilities to negotiate, periodically, favorable agreements for significant resources such as fuel supply contracts and collective bargaining agreements;


•	new technological developments that could affect the operations and prospects of HEI and ASB or their competitors;


•	new technological developments, such as the commercial development of energy storage and microgrids, that could affect the operations of the Utilities;


•	cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and the Utilities (including at ASB branches and 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, the Utilities and ASB (including changes in taxation, increases in capital requirements, regulatory policy changes, 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);


•	developments in laws, regulations, and policies governing protections for historic, archaeological, and cultural sites, and plant and animal species and habitats, as well as developments in the implementation and enforcement of such laws, regulations, and policies;


•	discovery of conditions that may be attributable to historical chemical releases, including any necessary investigation and remediation, and any associated enforcement, litigation, or regulatory oversight;


•	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 (OCC), 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 Utilities to recover increasing costs and earn a reasonable return on capital investments not covered by RAMs;


•	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, the Utilities and ASB, including the adoption of 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 Hawaiian Electric 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 provision for loan losses, 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, the Utilities and ASB;


•	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 Hawaiian Electric 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, Hawaiian Electric, 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.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)



	Three months ended March 31
(in thousands, except per share amounts)	2015			2014
Revenues
Electric utility	$	573,442		$	720,062
Bank	64,348			63,619
Other	72			68
Total revenues	637,862			783,749
Expenses
Electric utility	515,806			649,396
Bank	43,717			41,088
Other	8,833			4,051
Total expenses	568,356			694,535
Operating income (loss)
Electric utility	57,636			70,666
Bank	20,631			22,531
Other	(8,761		)	(3,983		)
Total operating income	69,506			89,214
Interest expense, net—other than on deposit liabilities and other bank borrowings	(19,100		)	(19,456		)
Allowance for borrowed funds used during construction	499			614
Allowance for equity funds used during construction	1,413			1,609
Income before income taxes	52,318			71,981
Income taxes	19,979			25,721
Net income	32,339			46,260
Preferred stock dividends of subsidiaries	473			473
Net income for common stock	$	31,866		$	45,787
Basic earnings per common share	$	0.31		$	0.45
Diluted earnings per common share	$	0.31		$	0.45
Dividends per common share	$	0.31		$	0.31
Weighted-average number of common shares outstanding	103,281			101,382
Net effect of potentially dilutive shares	286			783
Adjusted weighted-average shares	103,567			102,165

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)



	Three months ended March 31
(in thousands)	2015			2014
Net income for common stock	$	31,866		$	45,787
Other comprehensive income, net of taxes:
Net unrealized gains on available-for-sale investment securities:
Net unrealized gains on available-for-sale investment securities arising during the period, net of tax benefits of $2,278 and $1,664 for the respective periods	3,451			2,520
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil and $1,132 for the respective periods	—			(1,715		)
Derivatives qualified as cash flow hedges:
Less: reclassification adjustment to net income, net of tax benefits of $37 for both periods	59			59
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 $3,486 and $1,796 for the respective periods	5,459			2,813
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,127 and $1,598 for the respective periods	(4,911		)	(2,510		)
Other comprehensive income, net of taxes	4,058			1,167
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	35,924		$	46,954

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)



(dollars in thousands)	March 31, 2015			December 31, 2014
Assets
Cash and cash equivalents	$	292,168		$	175,542
Accounts receivable and unbilled revenues, net	255,365			313,696
Available-for-sale investment securities, at fair value	590,648			550,394
Stock in Federal Home Loan Bank of Seattle, at cost	63,711			69,302
Loans receivable held for investment, net	4,401,504			4,389,033
Loans held for sale, at lower of cost or fair value	9,906			8,424
Property, plant and equipment, net of accumulated depreciation of $2,258,065 and $2,250,950 at the respective dates	4,190,835			4,148,774
Regulatory assets	905,589			905,264
Other	481,531			542,523
Goodwill	82,190			82,190
Total assets	$	11,273,447		$	11,185,142
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	167,784		$	186,425
Interest and dividends payable	25,225			25,336
Deposit liabilities	4,751,328			4,623,415
Short-term borrowings—other than bank	30,500			118,972
Other bank borrowings	312,094			290,656
Long-term debt, net—other than bank	1,506,546			1,506,546
Deferred income taxes	640,778			633,570
Regulatory liabilities	351,712			344,849
Contributions in aid of construction	474,385			466,432
Defined benefit pension and other postretirement benefit plans liability	624,555			632,845
Other	456,338			531,230
Total liabilities	9,341,245			9,360,276
Preferred stock of subsidiaries - not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (Notes 4 and 5)
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: 107,417,644 shares and 102,565,266 shares at the respective dates	1,624,549			1,521,297
Retained earnings	296,680			296,654
Accumulated other comprehensive loss, net of tax benefits	(23,320		)	(27,378		)
Total shareholders’ equity	1,897,909			1,790,573
Total liabilities and shareholders’ equity	$	11,273,447		$	11,185,142

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

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			income (loss)			Total
Balance, December 31, 2014	102,565	$	1,521,297	$	296,654		$	(27,378	)	$	1,790,573
Net income for common stock	—	—		31,866			—			31,866
Other comprehensive income, net of taxes	—	—		—			4,058			4,058
Issuance of common stock, net	4,853	103,252		—			—			103,252
Common stock dividends ($0.31 per share)	—	—		(31,840		)	—			(31,840		)
Balance, March 31, 2015	107,418	$	1,624,549	$	296,680		$	(23,320	)	$	1,897,909
Balance, December 31, 2013	101,260	$	1,488,126	$	255,030		$	(16,750	)	$	1,726,406
Net income for common stock	—	—		45,787			—			45,787
Other comprehensive income, net of taxes	—	—		—			1,167			1,167
Issuance of common stock, net	218	3,212		—			—			3,212
Common stock dividends ($0.31 per share)	—	—		(31,448		)	—			(31,448		)
Balance, March 31, 2014	101,478	$	1,491,338	$	269,369		$	(15,583	)	$	1,745,124

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)



Three months ended March 31	2015			2014
(in thousands)
Cash flows from operating activities
Net income	$	32,339		$	46,260
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	45,865			43,181
Other amortization	1,362			1,609
Provision for loan losses	614			995
Loans receivable originated and purchased, held for sale	(79,070		)	(46,998		)
Proceeds from sale of loans receivable, held for sale	78,332			48,720
Increase in deferred income taxes	15,265			6,457
Excess tax benefits from share-based payment arrangements	(968		)	(164		)
Allowance for equity funds used during construction	(1,413		)	(1,609		)
Change in cash overdraft	—			(1,038		)
Changes in assets and liabilities
Decrease in accounts receivable and unbilled revenues, net	58,331			22,352
Decrease (increase) in fuel oil stock	20,731			(34,260		)
Increase in regulatory assets	(10,827		)	(9,258		)
Decrease in accounts, interest and dividends payable	(42,463		)	(9,307		)
Change in prepaid and accrued income taxes and utility revenue taxes	(61,397		)	(19,474		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	123			(818		)
Change in other assets and liabilities	19,826			(27,227		)
Net cash provided by operating activities	76,650			19,421
Cash flows from investing activities
Available-for-sale investment securities purchased	(63,370		)	(79,912		)
Principal repayments on available-for-sale investment securities	28,486			15,597
Proceeds from sale of available-for-sale investment securities	—			79,564
Redemption of stock from Federal Home Loan Bank of Seattle	5,590			5,848
Net increase in loans held for investment	(12,524		)	(37,887		)
Proceeds from sale of real estate acquired in settlement of loans	606			1,429
Capital expenditures	(59,011		)	(65,829		)
Contributions in aid of construction	9,145			6,958
Other	3,281			—
Net cash used in investing activities	(87,797		)	(74,232		)
Cash flows from financing activities
Net increase in deposit liabilities	127,913			105,510
Net increase (decrease) in short-term borrowings with original maturities of three months or less	(88,472		)	30,887
Net increase in retail repurchase agreements	21,451			141
Excess tax benefits from share-based payment arrangements	968			164
Net proceeds from issuance of common stock	104,468			3,054
Common stock dividends	(31,829		)	(31,435		)
Preferred stock dividends of subsidiaries	(473		)	(473		)
Other	(6,253		)	(3,953		)
Net cash provided by financing activities	127,773			103,895
Net increase in cash and cash equivalents	116,626			49,084
Cash and cash equivalents, beginning of period	175,542			220,036
Cash and cash equivalents, end of period	$	292,168		$	269,120

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)



	Three months ended March 31
(in thousands)	2015			2014
Revenues	$	573,442		$	720,062
Expenses
Fuel oil	176,806			286,300
Purchased power	136,007			164,916
Other operation and maintenance	104,002			88,606
Depreciation	44,243			41,603
Taxes, other than income taxes	54,748			67,971
Total expenses	515,806			649,396
Operating income	57,636			70,666
Allowance for equity funds used during construction	1,413			1,609
Interest expense and other charges, net	(16,325		)	(15,723		)
Allowance for borrowed funds used during construction	499			614
Income before income taxes	43,223			57,166
Income taxes	15,850			21,247
Net income	27,373			35,919
Preferred stock dividends of subsidiaries	229			229
Net income attributable to Hawaiian Electric	27,144			35,690
Preferred stock dividends of Hawaiian Electric	270			270
Net income for common stock	$	26,874		$	35,420

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)



	Three months ended March 31
(in thousands)	2015			2014
Net income for common stock	$	26,874		$	35,420
Other comprehensive income, net of taxes:
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 $3,141 and $1,605 for the respective periods	4,933			2,519
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,127 and $1,598 for the respective periods	(4,911		)	(2,510		)
Other comprehensive income, net of taxes	22			9
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	26,896		$	35,429

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)



(dollars in thousands, except par value)	March 31, 2015			December 31, 2014
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	52,022		$	52,299
Plant and equipment	6,066,523			6,009,482
Less accumulated depreciation	(2,189,090		)	(2,175,510		)
Construction in progress	164,851			158,616
Utility property, plant and equipment, net	4,094,306			4,044,887
Nonutility property, plant and equipment, less accumulated depreciation of $1,228 and $1,227 at respective dates	6,562			6,563
Total property, plant and equipment, net	4,100,868			4,051,450
Current assets
Cash and cash equivalents	8,120			13,762
Customer accounts receivable, net	124,995			158,484
Accrued unbilled revenues, net	109,494			137,374
Other accounts receivable, net	8,668			4,283
Fuel oil stock, at average cost	85,315			106,046
Materials and supplies, at average cost	58,607			57,250
Prepayments and other	43,355			66,383
Regulatory assets	102,745			71,421
Total current assets	541,299			615,003
Other long-term assets
Regulatory assets	802,844			833,843
Unamortized debt expense	8,216			8,323
Other	82,273			81,838
Total other long-term assets	893,333			924,004
Total assets	$	5,535,500		$	5,590,457
Capitalization and liabilities
Capitalization
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 15,805,327 shares)	$	105,388		$	105,388
Premium on capital stock	578,933			578,938
Retained earnings	1,002,046			997,773
Accumulated other comprehensive income, net of income taxes-retirement benefit plans	67			45
Common stock equity	1,686,434			1,682,144
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,206,546			1,206,546
Total capitalization	2,927,273			2,922,983
Commitments and contingencies (Note 4)
Current liabilities
Short-term borrowings from non-affiliates	30,000			—
Accounts payable	138,509			163,934
Interest and preferred dividends payable	24,257			22,316
Taxes accrued	182,872			250,402
Regulatory liabilities	1,174			632
Other	65,989			65,146
Total current liabilities	442,801			502,430
Deferred credits and other liabilities
Deferred income taxes	596,984			602,872
Regulatory liabilities	350,538			344,217
Unamortized tax credits	82,037			79,492
Defined benefit pension and other postretirement benefit plans liability	587,165			595,395
Other	74,317			76,636
Total deferred credits and other liabilities	1,691,041			1,698,612
Contributions in aid of construction	474,385			466,432
Total capitalization and liabilities	$	5,535,500		$	5,590,457

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

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, 2014	15,805	$	105,388	$	578,938		$	997,773		$	45	$	1,682,144
Net income for common stock	—	—		—			26,874			—		26,874
Other comprehensive income, net of taxes	—	—		—			—			22		22
Common stock dividends	—	—		—			(22,601		)	—		(22,601		)
Common stock issuance expenses	—	—		(5		)	—			—		(5		)
Balance, March 31, 2015	15,805	$	105,388	$	578,933		$	1,002,046		$	67	$	1,686,434
Balance, December 31, 2013	15,429	$	102,880	$	541,452		$	948,624		$	608	$	1,593,564
Net income for common stock	—	—		—			35,420			—		35,420
Other comprehensive income, net of taxes	—	—		—			—			9		9
Common stock dividends	—	—		—			(22,707		)	—		(22,707		)
Common stock issuance expenses	—	—		(3		)	—			—		(3		)
Balance, March 31, 2014	15,429	$	102,880	$	541,449		$	961,337		$	617	$	1,606,283

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)



Three months ended March 31	2015			2014
(in thousands)
Cash flows from operating activities
Net income	$	27,373		$	35,919
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	44,243			41,603
Other amortization	689			1,621
Increase in deferred income taxes	15,132			20,344
Change in tax credits, net	2,576			2,032
Allowance for equity funds used during construction	(1,413		)	(1,609		)
Change in cash overdraft	—			(1,038		)
Changes in assets and liabilities
Decrease in accounts receivable	29,104			8,804
Decrease in accrued unbilled revenues	27,880			12,260
Decrease (increase) in fuel oil stock	20,731			(34,260		)
Increase in materials and supplies	(1,357		)	(1,045		)
Increase in regulatory assets	(10,827		)	(9,258		)
Decrease in accounts payable	(49,136		)	(16,024		)
Change in prepaid and accrued income taxes and revenue taxes	(63,696		)	(47,526		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	110			(205		)
Change in other assets and liabilities	(8,522		)	(10,981		)
Net cash provided by operating activities	32,887			637
Cash flows from investing activities
Capital expenditures	(54,358		)	(64,462		)
Contributions in aid of construction	9,145			6,958
Net cash used in investing activities	(45,213		)	(57,504		)
Cash flows from financing activities
Common stock dividends	(22,601		)	(22,707		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(499		)	(499		)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	30,000			34,996
Other	(216		)	(389		)
Net cash provided by financing activities	6,684			11,401
Net decrease in cash and cash equivalents	(5,642		)	(45,466		)
Cash and cash equivalents, beginning of period	13,762			62,825
Cash and cash equivalents, end of period	$	8,120		$	17,359

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (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 and Hawaiian Electric’s Form 10-K for the year ended December 31, 2014.

In the opinion of HEI’s and Hawaiian Electric’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s and Hawaiian Electric’s financial position as of March 31, 2015 and December 31, 2014, the results of its operations and its cash flows for the three months ended March 31, 2015 and 2014. 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.

Prior period financial statements reflect the retrospective application of Accounting Standards Update (ASU) No. 2014-01, “Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which was adopted as of January 1, 2015 and did not have a material impact on the Company’s financial condition or results of operations. See “Investments in qualified affordable housing projects” in Note 11.

2 · Proposed Merger

On December 3, 2014, HEI, NextEra Energy, Inc., a Florida corporation (NEE), NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE (Merger Sub II) and NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE (Merger Sub I), entered into an Agreement and Plan of Merger (the Merger Agreement). The Merger Agreement provides for Merger Sub I to merge with and into HEI (the Initial Merger), with HEI surviving, and then for HEI to merge with and into Merger Sub II, with Merger Sub II surviving as a wholly owned subsidiary of NEE (the Merger). The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and be tax-free to HEI shareholders.

Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of HEI common stock will automatically be converted into the right to receive 0.2413 shares of common stock of NEE (the Exchange Ratio). No adjustment to the Exchange Ratio is made in the Merger Agreement for any changes in the market prices of either HEI or NEE common stock between December 3, 2014 and the closing of the Merger.

The Merger Agreement contemplates that, immediately prior to the closing of the Merger, HEI will distribute to its shareholders all of the issued and outstanding shares of common stock of ASB Hawaii, the direct parent company of ASB (such distribution referred to as the Spin-Off), with ASB Hawaii becoming a new public company. In addition, the Merger Agreement contemplates that, immediately prior to the closing of the Merger, HEI will pay its shareholders a special dividend of $0.50 per share.

The closing of the Merger is subject to various conditions, including, among others, (i) the approval of holders of 75%% of the outstanding shares of HEI common stock, (ii) effectiveness of the registration statement for the NEE common stock to be issued in the Initial Merger and the listing of such shares on the New York Stock Exchange, (iii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iv) receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission and the Hawaii Public Utilities Commission, (v) the absence of any law or judgment in effect or pending in which a governmental entity has imposed or is seeking to impose a legal restraint that would prevent or make illegal the closing of the Merger, (vi) the absence of any material adverse effect with respect to either HEI or NEE, (vii) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement, (viii) receipt by each of HEI and NEE of a tax opinion of its counsel regarding the tax treatment of the transactions contemplated by the Merger Agreement, (ix) effectiveness of the ASB Hawaii registration statement necessary to consummate the Spin-Off, and (x) the determination by each of HEI and NEE that, upon completion of the Spin-Off, HEI will no longer be a savings and loan holding company or be deemed to control ASB for purposes of the Home Owners' Loan Act. The Spin-Off will be subject to various conditions, including, among others, the approval of the Federal Reserve Board (FRB).

The Merger Agreement contains customary representations, warranties and covenants of HEI and NEE.

HEI is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals, provide information or engage in discussion with third parties, except under limited circumstances to permit HEI’s board of directors to comply with its fiduciary duties.

The Merger Agreement contains certain termination rights for both HEI and NEE, including the right of either party to terminate the Merger Agreement if the Merger has not been consummated by December 3, 2015 (subject to a 6-month extension if required to obtain necessary regulatory approvals), and further provides that upon termination of the Merger Agreement under specified circumstances, HEI or NEE, as the case may be, would be required to pay the other party a termination fee of $90 million and reimburse the other party for up to $5 million of its documented out-of-pocket expenses incurred in connection with the Merger Agreement.

On March 26, 2015, NEE’s Form S-4, which registers NEE common stock expected to be issued in the Initial Merger, was declared effective. Also on March 26, 2015, HEI filed its special meeting proxy statement for the vote on the merger proposal and related matters, which meeting is scheduled for May 12, 2015. On March 30, 2015, ASB Hawaii filed its Form 10, the registration statement for ASB Hawaii shares expected to be distributed in the Spin-Off.

PUC application. In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger of Hawaiian Electric. The application also requests modification of certain conditions agreed to by HEI and the PUC in 1982 for the merger and corporate restructuring of Hawaiian Electric, and confirmation that with approval of the Merger Agreement, the recommendations in the 1995 Dennis Thomas Report (resulting from a proceeding to review the relationship between HEI and Hawaiian Electric and any impact of HEI’s then diversified activities on the Utilities) will no longer be applicable. The application includes a commitment that, for at least four years following the completion of the transaction, Hawaiian Electric will not submit any applications seeking a general base rate increase and will forego recovery of the incremental operations and maintenance rate adjustment under decoupling during that period, which amounts to approximately $60 million in cumulative savings for customers, subject to certain exceptions and conditions, including that the following remain in effect: the RBA tariff provisions, the Rate Base RAM, the Renewable Energy Infrastructure Program, and Renewable Energy Infrastructure Surcharge, the IRP/DSM Recovery tariff provisions, the ECAC tariff provisions, the PPA tariff provision and the Pension and OPEB tracker mechanism. Various parties, including governmental, environmental and commercial interests, have been allowed to intervene in the proceeding. The PUC issued an initial procedural schedule governing the pre-filing of testimonies by the parties in the proceeding and the discovery on the pre-filed testimonies, and indicated the PUC will issue a further order concerning hearing dates and related matters after the Utilities and NEE file response testimonies on August 31, 2015.

Other requests. On January 29, 2015, HEI submitted its application to the FERC requesting all necessary authorization to consummate the transactions contemplated by the Merger Agreement. The FERC issued its order authorizing the proposed merger on March 27, 2015.

On February 1, 2015, HEI submitted a letter to FRB requesting deregistration as a Savings & Loan Holding Company (SLHC).

Pending litigation and other matters.

Litigation. HEI and its subsidiaries are subject to various legal proceedings that arise from time to time. Some of these proceedings may seek relief or damages in amounts that may be substantial. Because these proceedings are complex, many years may pass before they are resolved, and it is not feasible to predict their outcomes. Some of these proceedings involve claims HEI and Hawaiian Electric believe may be covered by insurance, and HEI and Hawaiian Electric have advised their insurance carriers accordingly.

Since the December 3, 2014 announcement of the merger agreement, eight purported class action complaints were filed in the Circuit Court of the First Circuit for the State of Hawaii by alleged stockholders of HEI against HEI, Hawaiian Electric (in one complaint), the individual directors of HEI, NEE and NEE's acquisition subsidiaries. The lawsuits are captioned as follows: Miller v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2531-12 KTN (December 15, 2014) (the Miller Action); Walsh v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2541-12 JHC (December 15, 2014) (the Walsh Action); Stein v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2555-12 KTN (December 17, 2014) (the Stein Action); Brown v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2643-12 RAN (December 30, 2014) (the Brown Action); Cohn v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2642-12 KTN (December 30, 2014) (the Cohn State Action); Guenther v. Watanabe, et al., Case No. 15-1-003-01 ECN (January 2, 2015) (the Guenther Action); Hudson v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0013-01 JHC (January 5, 2015) (the Hudson Action); Grieco v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0094-01 KKS (January 21, 2015) (the Grieco Action). On January 12, 2015, plaintiffs in the Miller Action, the Walsh Action, the Stein Action, the Brown Action, the Guenther Action, and the Hudson Action filed a

motion to consolidate their actions and to appoint co-lead counsel. The Court held a hearing on this motion on February 13, 2015 and granted consolidation and appointment of co-lead counsel on March 6, 2015. On March 10, 2015, plaintiffs in the consolidated state action filed an amended complaint, and added J.P. Morgan Securities, LLC (JP Morgan), which was HEI’s financial advisor for the Merger, as a defendant. On March 17, 2015, plaintiffs in the consolidated state action moved for limited expedited discovery. After limited discovery, the parties in the consolidated state action stipulated and the Court ordered that the deadline for defendants to respond to the amended complaint is extended indefinitely. On April 30, 2015, the Court consolidated the seven state actions under the caption, In re Consolidated HEI Shareholder Cases. On January 23, 2015, the Cohn State Action was voluntarily dismissed. Thereafter, the same alleged stockholder plaintiff filed a purported class action complaint in the United States District Court for the District of Hawaii against HEI, the individual directors of HEI, NEE and NEE's acquisition subsidiaries. The lawsuit is captioned as Cohn v. Hawaiian Electric Industries, Inc. et al., 15-cv-00029-JMS-KSC (January 27, 2015) (the Cohn Federal Action).

The actions allege, among other things, that members of HEI's Board breached their fiduciary duties in connection with the proposed transaction, and that the Merger Agreement involves an unfair price, was the product of an inadequate sales process, and contains unreasonable deal protection devices that purportedly preclude competing offers. The complaints further allege that HEI, NEE and/or its acquisition subsidiaries aided and abetted the purported breaches of fiduciary duty. The plaintiffs in these lawsuits seek, among other things, (i) a declaration that the Merger Agreement was entered into in breach of HEI's directors' fiduciary duties, (ii) an injunction enjoining the HEI Board from consummating the Merger, (iii) an order directing the HEI Board to exercise their duties to obtain a transaction which is in the best interests of HEI's stockholders, (iv) a rescission of the Merger to the extent that it is consummated, and/or (v) damages suffered as a result of the defendants' alleged actions. Plaintiffs in the consolidated state action also allege that JP Morgan had a conflict of interest in advising HEI because JP Morgan and its affiliates had business ties to and investments in NEE. The consolidated state action also alleges that the HEI board of directors violated its fiduciary duties by omitting material facts from the Registration Statement on Form S-4. In addition, the Cohn Federal Action alleges that the HEI board of directors violated its fiduciary duties and federal securities laws by omitting material facts from the Registration Statement on Form S-4.

HEI and Hawaiian Electric believe the allegations of the complaints are without merit and intend to defend these lawsuits vigorously.

Other matters. In January 2015, various clean energy and environmental groups filed a motion and applications with the PUC to delay consideration of the Company’s proposed Merger pending its decision on the Power Supply Improvement Plans, Distributed Generation Interconnection Plan, Integrated Demand Response Portfolio Plan, decoupling, and issues regarding customer-based distributed energy resources. The PUC issued its order on March 2, 2015, dismissing the motion and applications.

3 · Segment financial information



(in thousands)	Electric utility		Bank		Other			Total
Three months ended March 31, 2015
Revenues from external customers	$	573,431	$	64,348	$	83		$	637,862
Intersegment revenues (eliminations)	11		—		(11		)	—
Revenues	573,442		64,348		72			637,862
Income (loss) before income taxes	43,223		20,631		(11,536		)	52,318
Income taxes (benefit)	15,850		7,156		(3,027		)	19,979
Net income (loss)	27,373		13,475		(8,509		)	32,339
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	26,874		13,475		(8,483		)	31,866
Assets (at March 31, 2015)	5,535,500		5,724,877		13,070			11,273,447

Three months ended March 31, 2014
Revenues from external customers	$	720,056	$	63,619	$	74		$	783,749
Intersegment revenues (eliminations)	6		—		(6		)	—
Revenues	720,062		63,619		68			783,749
Income (loss) before income taxes	57,166		22,532		(7,717		)	71,981
Income taxes (benefit)	21,247		8,133		(3,659		)	25,721
Net income (loss)	35,919		14,399		(4,058		)	46,260
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	35,420		14,399		(4,032		)	45,787
Assets (at December 31, 2014)	5,590,457		5,566,222		28,463			11,185,142

Intercompany electricity sales of the 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 the Utilities, 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 Utilities 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.

4 · Electric utility segment

Revenue taxes. The Utilities’ revenues include amounts for the recovery of various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, the Utilities’ 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). The Utilities included in the three months ended March 31, 2015 and 2014 approximately $51 million and $65 million, respectively, of revenue taxes in “revenues” and in “taxes, other than income taxes” expense.

Recent tax developments. The Utilities adopted the safe harbor guidelines with respect to network assets in 2011 and, in June 2013, the IRS 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. Management intends to adopt a method consistent with this guidance in its 2014 tax return.

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 Hawaiian Electric, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by Hawaiian Electric in the principal amount of $31.5 million and issued by Hawaii Electric Light and Maui Electric 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 the Utilities under an expense agreement and Hawaiian Electric’s obligations under its trust guarantee and its guarantee of the obligations of Hawaii Electric Light and Maui Electric under their respective debentures, are the sole assets of Trust III. Taken together, Hawaiian Electric’s obligations under the Hawaiian Electric debentures, the Hawaiian Electric 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 Hawaiian Electric. Since Hawaiian Electric, as the holder of 100% of the trust common securities, does not absorb the majority of the variability of Trust III, Hawaiian Electric is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of VIEs. Trust III’s balance sheets as of March 31, 2015 and December 31, 2014 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 three months ended March 31, 2015 and 2014 each consisted of $0.8 million of interest income received from the 2004 Debentures; $0.8 million of distributions to holders of the Trust Preferred Securities; and $25,000 of common dividends on the trust common securities to Hawaiian Electric. As long as the 2004 Trust Preferred Securities are outstanding, Hawaiian Electric is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by Hawaiian Electric in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event any of the Utilities elect to defer payment of interest on any of their respective 2004 Debentures, then Hawaiian Electric 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 March 31, 2015, the Utilities had six purchase power agreements (PPAs) for firm capacity and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kilowatts (kWs) or less who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs. Approximately 90% of 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 March 31
(in millions)	2015		2014
AES Hawaii	$	34	$	33
Kalaeloa	44		67
HEP	11		12
HPOWER	16		16
Other IPPs	31		37
Total IPPs	$	136	$	165

Some of the IPPs provided sufficient information for Hawaiian Electric to determine that the IPP was not a VIE, or was either a “business” or “governmental organization,” and thus excluded from the scope of accounting standards for VIEs. Other IPPs, including the three largest, declined to provide the information necessary for Hawaiian Electric to determine the applicability of accounting standards for VIEs.

Since 2004, Hawaiian Electric has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2014, the Utilities sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as Hawaii Electric Light and Maui Electric do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities. If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Consolidated Financial Statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Utilities determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Utilities would retrospectively apply accounting standards for VIEs.

Kalaeloa Partners, L.P. In October 1988, Hawaiian Electric entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that Hawaiian Electric would purchase 180 megawatts (MW) of firm capacity for a period of 25 years beginning in May 1991. In October 2004, Hawaiian Electric 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 Hawaiian Electric 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 Hawaiian Electric 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, Hawaiian Electric is deemed to have a variable interest in Kalaeloa by reason of the provisions of Hawaiian Electric’s PPA with Kalaeloa. However, management has concluded that Hawaiian Electric is not the primary beneficiary of Kalaeloa because Hawaiian Electric does not have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, Hawaiian Electric has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses Hawaiian Electric could potentially absorb is the fact that Hawaiian Electric’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 Hawaiian Electric absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose Hawaiian Electric 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 Hawaiian Electric’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of March 31, 2015, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $13 million.

Commitments and contingencies.

Fuel contracts. The Utilities have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through October 2017. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. West Coast and U.S. Midwest.

Updates. On August 27, 2014, Chevron Products Company (Chevron) and Hawaiian Electric entered into a first amendment of their Low Sulfur Fuel Oil Supply Contract, which was approved by the PUC in March 2015. The Amendment reduces the price of fuel above certain volumes, allows for increases in the volume of fuel, and modifies the specification of certain petroleum products supplied under the contract. In addition, Chevron agreed to supply a blend of low sulfur fuel oil (LSFO) and diesel as soon as January 2016 (for supply through the end of the contract term, December 31, 2016) to help Hawaiian Electric meet more stringent EPA air emission requirements known as Mercury and Air Toxics Standards.

The Utilities are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Hawaii Independent Energy, LLC (HIE), respectively, which were scheduled to end December 31, 2015. In August 2014, Chevron and the Utilities entered into a third amendment to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract, which amendment extended the term of the contract through December 31, 2016 and provided for automatic renewal for annual terms thereafter unless earlier terminated by either party. In February 2015, Hawaiian Electric executed a similar extension, through December 31, 2016, of the corresponding Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract with HIE.

Liquefied natural gas. In August 2014, Hawaiian Electric entered into a 15-year agreement with Fortis BC Energy Inc. (Fortis) for liquefaction capacity for liquefied natural gas (LNG) under tariffed rates approved by the British Columbia Utilities Commission. The agreement, which is subject to Hawaii PUC approval, other regulatory approvals and permits, and other conditions precedent before it becomes effective, provides for LNG liquefaction capacity purchases of 800,000 tonnes per year for the first five years, 700,000 tonnes per year for the next five years, and 600,000 tonnes per year for the last five years. Fortis must also obtain regulatory and other approvals for the agreement to become effective. The Fortis agreement is assignable and can be assigned to the selected bidder in the Utilities’ request for proposal (RFP) for the supply of containerized LNG and will help ensure that liquefaction capacity is available at pricing that management believes will lower customer bills.

Environmental regulation. The Utilities 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 and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On August 14, 2014, the Environmental Protection Agency (EPA) published in the Federal Register the final 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 regulations were effective October 14, 2014 and apply to the cooling water systems for the steam generating units at Hawaiian Electric’s power plants on the island of Oahu. The regulations prescribe a process, including a number of required site-specific studies, for states to develop facility-specific entrainment and impingement controls to be incorporated in the facility’s National Pollutant Discharge Elimination System permit. In the case of Hawaiian Electric’s power plants, there are a number of studies that have yet to be completed before Hawaiian Electric and the Department of Health of the State of Hawaii (DOH) can determine what entrainment or impingement controls, if any, might be appropriate.

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 Hawaiian Electric’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, Hawaiian Electric 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. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date of April 16, 2016. Hawaiian Electric submitted to the EPA a Petition for Reconsideration and Stay dated April 16, 2012, and a Request for Expedited Consideration dated August 14, 2013. The submittals asked the EPA to revise an emissions standard for non-continental oil-fired EGUs on the grounds that the promulgated standard was incorrectly derived. The Petition and Request submittals to the EPA included additional data to demonstrate that the existing standard is erroneous. On April 21, 2015, the EPA issued a notice denying Hawaiian Electric's MATS Petition for Reconsideration along with all other pending MATS petitions. The EPA also issued a report dated March 2015 which presents the detailed rationale for the EPA’s denial of the petitions. Hawaiian Electric is currently reviewing the notice and report.

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 (SO₂) National Ambient Air Quality Standard (NAAQS) implementation plans. In May 2014, the EPA published a proposed data requirements rule for states to characterize their air quality in relation to the one-hour SO₂ NAAQS. Under the proposed rule, the EPA expects to designate areas as attaining, or not attaining, the one-hour SO₂ NAAQS in December 2017 or December 2020, depending on whether the area was

characterized through modeling or monitoring. Hawaiian Electric will work with the DOH in implementing the one-hour SO₂NAAQS and in developing cost-effective strategies for NAAQS compliance, if needed.

Depending upon the specific measures required for compliance with the CWA 316(b) regulations and MATS, and the rules and guidance developed for compliance with the more stringent NAAQS, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts and their timing 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.

Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases into the environment associated with current or previous operations and report and take action on these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.

Potential Clean Air Act Enforcement. On July 1, 2013, Hawaii Electric Light and Maui Electric 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 Hawaii Electric Light’s and Maui Electric’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. The parties had preliminary discussions in February 2014, and are continuing to negotiate toward a resolution of the DOJ’s claims. As part of the ongoing negotiations, the DOJ proposed in November 2014 entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities are currently reviewing the proposal, but are unable to estimate the amount or effect of a consent decree, if any, at this time.

Former Molokai Electric Company generation site. In 1989, Maui Electric 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 Maui Electric never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the DOH, Maui Electric 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 Maui Electric contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, Maui Electric is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, residual fuel oils, and other subsurface contaminants. In March 2012, Maui Electric accrued an additional $3.1 million (reserve balance of $3.6 million as of March 31, 2015) 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. Maui Electric received the DOH’s and EPA’s comments on a draft site investigation plan for site characterization in the fourth quarter of 2013. Management concluded that these comments did not require a change to the reserve balance. The site investigation plan was revised to address the EPA’s and DOH’s comments. The final site investigation plan was submitted to the DOH and EPA in December 2014 for their review and approval.

Pearl Harbor sediment study. The U.S. Navy is conducting a feasibility study for the remediation of contaminated sediment in Pearl Harbor. In the course of its study, the Navy identified elevated levels of PCBs in the sediment offshore from the Waiau Power Plant. The results of the Navy’s study to date, including sampling data and possible remediation approaches, are undergoing further federal review. Hawaiian Electric submitted comments on the Navy’s study, including the further investigation and analyses that are necessary to identify appropriate remedial options and actions.

In July 2014, the Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is responsible for cleanup of the area offshore of the Waiau Power Plant. The Navy has also requested that Hawaiian Electric reimburse the costs incurred by the Navy to date to investigate the area, and is asking Hawaiian Electric to engage in negotiations regarding the financing and undertaking of future response actions. The extent of the contamination, the appropriate remedial measures to address it, and Hawaiian Electric’s potential responsibility for any associated costs have not yet been determined. In December 2014, Hawaiian Electric recorded a reserve of $0.8 million for additional investigation of the PCBs in the sediment offshore from the Waiau Power Plant; however, final costs of remediation will depend on the results of the additional investigation. On March 23, 2015, Hawaiian Electric received from the EPA a letter requesting that Hawaiian Electric submit within 45 days a work plan to assess potential sources and extent of PCB contamination onshore at the Waiau Power Plant. The extent of the onshore contamination, the appropriate remedial measures to address it, and any associated costs have not yet been determined.

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

fossil fuels) to climate change 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. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 and the regulations went into effect on June 30, 2014. In general, the regulations will require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 16% below 2010 emission levels by 2020. The regulations will also assess affected sources an annual fee based on tons per year of GHG emissions commencing on the effective date of the regulations, estimated to be approximately $0.5 million annually for the Utilities. The DOH GHG regulations also track 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.

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

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The Utilities have submitted the required reports for 2010 through 2013 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 covering the permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds set forth in the rule, under the Prevention of Significant Deterioration program. On June 23, 2014, the U.S. Supreme Court issued a decision that invalidated the GHG Tailoring Rule, to the extent it regulated sources based solely on their GHG emissions. It also invalidated the GHG emissions threshold for regulation.

On December 19, 2014, the EPA released two memoranda outlining the Agency’s plan for addressing the U.S. Supreme Court’s decision. Hawaiian Electric, Hawaii Electric Light and Maui Electric are evaluating the potential impacts of the Agency’s plan on utility operations and permitting. On January 8, 2014, the EPA published in the Federal Register its new proposal for New Source Performance Standards for GHG from new generating units. The proposed rule on GHG from new EGUs does not apply to oil- fired combustion turbines or diesel engine generators, and is not otherwise expected to have significant impacts on the Utilities.

On June 18, 2014, the EPA published in the Federal Register its proposed rule for GHG emissions from existing power plants. The rule sets interim and final state-wide, state-specific emission performance goals, expressed as lb CO₂/MWh, that would apply to the state’s affected sources. The interim goal would apply as an average over the period 2020 through 2029, with the final goal to be met by 2030. On the same date, the EPA also published a separate rule for modified and reconstructed power plants. The EPA’s plan is to issue the final rules by mid-summer 2015. Hawaiian Electric is still evaluating the proposed rules for GHG emissions from existing, modified, and reconstructed sources, and how they might relate to the recently issued State GHG rules. Hawaiian Electric will participate in the federal GHG rulemaking process, and in the implementation of the State GHG rules, to try to reconcile federal GHG regulation, state GHG regulation, and any action the EPA may take as a result of the recent U.S. Supreme Court opinion, to facilitate clear and cost-effective compliance. The Utilities will continue to evaluate the impact of proposed GHG rules and regulations as they develop. Final regulations may impose significant compliance costs, and may require reductions in fossil fuel use and the addition of renewable energy resources in excess of the requirements of the RPS law.

The Utilities 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 Hawaiian Electric’s Campbell Industrial Park combustion turbine No. 1 (CIP CT-1), using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric 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 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 Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.

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. The Utilities’ 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 the Utilities relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

Hawaiian Electric has recorded estimated AROs related to removing retired generating units at its Honolulu and Waiau power plants. These removal projects are ongoing, with significant activity and expenditures occurring in 2014 in partial settlement of these liabilities. Both removal projects are expected to continue through 2015.

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



	Three months ended March 31
(in thousands)	2015			2014
Balance, beginning of period	$	29,419		$	43,106
Accretion expense	6			370
Liabilities incurred	—			—
Liabilities settled	(1,614		)	(2,240		)
Revisions in estimated cash flows	—			—
Balance, end of period	$	27,811		$	41,236

Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by Hawaiian Electric on March 1, 2011, by Hawaii Electric Light on April 9, 2012 and by Maui Electric 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 rate adjustments for certain other operation and maintenance (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 return on average common equity (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.

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for Hawaiian Electric, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. 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. In October 2013, the PUC issued orders that bifurcated the proceeding (into Schedule A and Schedule B issues). On February 7, 2014, the PUC issued a decision and order (D&O) on the Schedule A issues, which made certain modifications to the decoupling mechanism. Specifically, the D&O required:


•	An adjustment to the Rate Base RAM Adjustment to include 90% of the amount of the current RAM Period Rate Base RAM Adjustment that exceeds the Rate Base RAM Adjustment from the prior year, to be effective with the Utilities’ 2014 decoupling filing.


•	Effective March 1, 2014, the interest rate to be applied on the outstanding RBA balances to be the short term debt rate used in each Utilities last rate case (ranging from 1.25% to 3.25%), instead of the 6% that had been previously approved.

As required, the Utilities have made available to the public, on the Utilities’ websites, performance metrics identified by the PUC.

On March 31, 2015, the PUC issued an Order related to the Schedule B portion of the proceeding to make certain further modifications to the decoupling mechanism, and to establish a briefing schedule with respect to certain issues in the proceeding. The order modifies the RAM portion of the decoupling mechanism to be capped at the lesser of the RAM Revenue Adjustment as currently determined (adjusted to eliminate the 90% limitation on the current RAM Period Rate Base RAM adjustment that was ordered in the Schedule A portion of the proceeding) and a RAM Revenue Adjustment calculated based on the cumulative annual compounded increase in Gross Domestic Product Price Index (GDPPI) applied to the 2014 annualized target revenues (adjusted for certain items specified in the Order). The 2014 annualized target revenues represent the target revenues from the last rate case, and RAM revenues, offset by earnings sharing credits, if any, allowed under the decoupling mechanism through the 2014 decoupling filing. The Utilities may apply to the PUC for approval of recovery of revenues for Major Projects (including related baseline projects grouped together for consideration as Major Projects) through the RAM above the RAM cap or outside of the RAM through the Renewable Energy Infrastructure Program (REIP) surcharge or other adjustment mechanism. The Utilities and the Consumer Advocate are directed to develop standards and guidelines for eligibility of projects and determination of the amount of eligible cost recovery above the RAM cap for PUC approval. The RAM is amended on an interim basis pending the outcome of the PUC’s review of the Utilities’ Power Supply Improvement Plans. The triennial rate case cycle required under the decoupling mechanism continues to serve as the maximum period between the filing of general rate cases, and the amendments to the RAM do not limit or dilute the ordinary opportunities for the Utilities to seek rate relief according to conventional/traditional ratemaking procedures.

In making the modifications to the RAM Adjustment, the PUC stated the changes are designed to provide the PUC with control of and prior regulatory review over substantial additions to baseline projects between rate cases. It does not deprive the Utilities of the opportunity to recover any prudently incurred expenditure or limit orderly recovery for necessary expanded capital programs.

The RBA, which is the sales decoupling component, is retained, and the PUC made no change in the authorized return on common equity. Performance based ratemaking is not adopted at this time.

On April 15, 2015, the Utilities submitted revised annual decoupling filings for tariffed rates to be effective from June 1, 2015 through May 31, 2016 (unless the filings are modified or suspended by the PUC), and reflected revisions to the RAM based on the Order. The revised 2015 annual incremental RAM revenues for the three Utilities based on the Order amounted to $26.2 million, compared to the 2015 annual incremental revenues of $31.6 million filed on March 31, 2015 based on the methodology prior to the modification of the Order. The revised tariffs also include the collection or refund of the accrued revenue balancing account (RBA) balance and associated revenue taxes as of December 31, 2014 and any accrued earning sharing mechanism credits. The net annual incremental amount to be collected under the tariffs is $14.7 million for the three Utilities.



(in millions)	Hawaiian Electric			Hawaii Electric Light		Maui Electric
Annual incremental RAM adjusted revenues	$	20.3		$	2.4	$	3.4
Annual change in accrued earnings sharing credits to be refunded	$	—		$	—	$	(0.1	)
Annual change in accrued RBA balance as of December 31, 2014 (and associated revenue taxes) to be collected	$	(9.2	)	$	0.1	$	(2.2	)
Net annual incremental amount to be collected under the tariffs	$	11.1		$	2.5	$	1.1
Impact on typical residential customer monthly bill (in dollars) *	$	0.56		$	1.10	$	0.60

* Based on 600 KWH bill for Hawaiian Electric and Maui Electric and 500 KWH bill for Hawaii Electric Light.

The Consumer Advocate has submitted information requests to the Utilities and filed initial questions on the calculations of the RAM revenues based on the March 31, 2015 Order, and the Utilities have responded to an information request from the PUC regarding the tariff filings. The Consumer Advocate has until May 15, 2015 to submit its Statement of Position. The PUC is expected to issue a decision on the tariff filings prior to the June 1, 2015 effective date.

The March 31, 2015 Order directs the Parties to the proceeding to submit initial briefs within 60 days that address the following issues: (1) whether, and if so, how the conventional performance incentive mechanisms proposed in this proceeding should be refined and implemented in this docket; (2) what are the appropriate steps, processes and timing for determining measures to improve the efficiency and effectiveness of the general rate case filing and review process; and (3) what are the appropriate steps, processes, and timing to further consider the merits of the proposed changes to the energy cost adjustment clause (ECAC) identified in this proceeding. In identifying the issue on possible changes to the ECAC, the PUC stated that changes to the ECAC should be made with great care to avoid unintended consequences. Reply briefs are due within 75 days.

Management cannot predict the further outcome of this proceeding or the ultimate impact of the proceeding on the results of operation of the Utilities.

Potential impact of lava flows. In June 2014, lava from the Kilauea Volcano on the island of Hawaii began flowing toward the town of Pahoa. Hawaii Electric Light monitored utility property and equipment near the affected areas and protected that property and equipment to the extent possible (e.g., building barriers around poles). In March 2015 Hawaii Electric Light filed an application with the PUC requesting approval to defer costs incurred by the Company to monitor, prepare for, respond to, and take other actions necessary in connection with the June 2014 Kilauea lava flow such that the Company can request PUC approval to recover those costs in a future rate case.

April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively address certain key policy, resource planning and operational issues for the Utilities. The four orders are as follows:

Integrated Resource Planning. The PUC did not accept the Utilities’ Integrated Resource Plan and Action Plans submission, and, in lieu of an approved plan, has commenced other initiatives to enable resource planning. The PUC also terminated the Utilities’ integrated resource planning (IRP) cycle, including the filing of a mid-cycle evaluation report, and formally concluded the IRP advisory group. The PUC directed each of Hawaiian Electric and Maui Electric to file within 120 days its respective Power Supply Improvement Plans (PSIPs), and the PSIPs were filed in August 2014. The PUC also provided its inclinations on the future of Hawaii’s electric utilities in an exhibit to the order. The exhibit provides the PUC’s perspectives on the vision, business strategies and regulatory policy changes required to align the Utilities’ business model with customers’ interests and the state’s public policy goals.

Reliability Standards Working Group. The PUC ordered the Utilities (and in some cases the Kauai Island Utility Cooperative (KIUC)) to take timely actions intended to lower energy costs, improve system reliability and address emerging challenges to integrate additional renewable energy. In addition to the PSIPs mentioned above, the PUC ordered certain filing requirements which include the following:


•	Distributed Generation Interconnection Plan to be filed within 120 days. The Utilities’ Plan was filed in August 2014.


•	Plan to implement an on-going distribution circuit monitoring program to measure real-time voltage and other power quality parameters to be filed within 60 days. The plan shall achieve full implementation of the distribution circuit monitoring program within 180 days. The Utilities’ Plan was filed in June 2014.


•	Action Plan for improving efficiencies in the interconnection requirements studies to be filed within 30 days. The Utilities’ Plan was filed in May 2014.


•	The Utilities are to file monthly reports providing details about interconnection requirements studies.


•	Proposal to implement an integrated interconnection queue for each distribution circuit for each island grid to be filed within 120 days. The Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015.

The PUC also stated it would be opening new dockets to address (1) reliability standards, (2) the technical, economic and policy issues associated with distributed energy resources and (3) the Hawaii electricity reliability administrator, which is a third party position which the legislature has authorized the PUC to create by contract to provide support for the PUC in developing and periodically updating local grid reliability standards and procedures and interconnection requirements and overseeing grid access and operation.

Policy Statement and Order Regarding Demand Response Programs. The PUC provided guidance concerning the objectives and goals for demand response programs, and ordered the Utilities to develop within 90 days an integrated Demand Response Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. In August 2014, the PUC invited public comment on the Utilities’ Plan. The Utilities submitted a status update in October 2014, and a second status update was filed with the PUC in March 2015.

Maui Electric Company 2012 Test Year Rate Case. The PUC acknowledged the extensive analyses provided by Maui Electric in its System Improvement and Curtailment Reduction Plan (SICRP) filed in September 2013. The PUC stated that it is encouraged by the changes in Maui Electric’s operations that have led to a significant reduction in the curtailment of renewables, but stated that Maui Electric has not set forth a clearly defined path that addresses integration and curtailment of additional renewables. The PUC directed Maui Electric to present a PSIP within 120 days to address present and future system operations so as to not only reduce curtailment, but to optimize the operation of its system for its customers’ benefit. The Maui Electric PSIP was filed in August 2014, and will be reviewed by the PUC in a new docket along with the Hawaiian Electric and Hawaii Electric Light PSIPs. Maui Electric filed its first annual SICRP status update in September 2014.

Review of PSIPs. Collectively, the PUC’s April 2014 resource planning orders confirm the energy policy and operational priorities that will guide the Utilities’ strategies and plans going forward.

PSIPs for Hawaiian Electric, Maui Electric and Hawaii Electric Light (updating its Power Supply Plan filed in April 2014) were filed in August 2014. The PSIPs each include a tactical plan to transform how electric utility services will be offered to meet customer needs and produce higher levels of renewable energy. Each plan contains a diversified mix of technologies, including significant distributed and utility‑scale renewable resources, that is expected to result, on a consolidated basis, in over 65% of the Utilities’ energy being produced from renewable resources by 2030. Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), switch from high-priced oil to lower cost liquefied natural gas, retire higher-cost, less efficient existing oil-based steam generators, and lower full service residential customer bills in real dollars.

The PSIPs will be reviewed by the PUC in a new docket, and a number of parties have moved to intervene in the proceeding. In September 2014, the PUC invited the public to comment on the PSIPs. In October 2014, the Utilities filed responses to information requests on the PSIPs from the PUC.

Transitional Distributed Generation Tariff. Consistent with their Distributed Generation Interconnection Plan, on January 20, 2015, the Utilities filed a motion which requested the PUC in pertinent part to:

(1) Reinstitute a program capacity threshold for the Utilities' existing Net Energy Metering (NEM) program;

(2) Approve the Utilities’ proposal to address both existing NEM program participants and those customers presently awaiting interconnection approval under the existing NEM program;

(3) Approve a new Transitional Distributed Generation (TDG) tariff to be available to customers seeking interconnection after the NEM program capacity is reached, which tariff more fairly allocates fixed grid costs to DG customers and credits customers for the value of the excess energy produced by their systems; and

(4) Approve a new standard form TDG contract to allow for the advanced technical capabilities required to integrate higher levels of distributed generation.

Once the requests in the motion are approved, it is contemplated that the Utilities will be able to increase existing circuit penetration limits based upon daytime minimum load, and identify strategic and cost effective investments to circuits and the system to support increased levels of DG. Such investments would be made for the benefit of all customers rather than charging costs only to those installing DG systems on the circuit.

The Utilities had requested approval of their motion within 60 days of filing or by March 20, 2015. However, pursuant to the PUC order described in the following section, the PUC declined to rule on this request.

Distributed Energy Resources (DER) Investigative Proceeding. Consistent with the PUC’s plan to review the technical, economic and policy issues associated with distributed energy resources as noted in the Reliability Standards Working Group order, in March 2015, the PUC issued an order to address DER issues. The PUC order:


(1)	Allowed intervention to ten parties in the proceeding,


(2)	Consolidated portions of two other proceedings related to rules on interconnection of distributed generating facilities with the Utilities system,


(3)	Declined to rule on distributed generation interconnection plan filed in August 2014 as a result of the Reliability Standards Working Group order,


(4)	Declined to rule on Utilities’ TDG motion, filed on January 20, 2015, and instead, directed the parties to collaborate on a “Transition Plan” from existing DER programs, including NEM, to a longer-term DER market structure;


(5)	Ordered the parties to collaborate on issues through a series of bi-weekly technical sessions;


(6)	Issued a Statement of Issues and a Procedural Schedule for the docket that directs the parties to file stipulations on areas of agreement, or separate statements of positions on issues where agreement cannot be reached, by June 29, 2015; and


(7)	Ordered the Utilities to submit weekly reports documenting progress on clearing interconnection applications, and monthly reports on the status of key technical developments to enable DER market growth.

In addition, the PUC provided further clarifications and guidance from their Staff’s perspective on important issues relating to the growth of DER in the State.

Management cannot predict the outcome of the proceedings to review the Plans submitted in response to the PUC’s April 2014 resource planning orders, or the ultimate impact of the proceedings on the results of operations of the Utilities.

Consolidating financial information. Hawaiian Electric is not required to provide separate financial statements or other disclosures concerning Hawaii Electric Light and Maui Electric to holders of the 2004 Debentures issued by Hawaii Electric Light and Maui Electric 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 Hawaiian Electric. Consolidating information is provided below for Hawaiian Electric and each of its subsidiaries for the periods ended and as of the dates indicated.

Hawaiian Electric also unconditionally guarantees Hawaii Electric Light’s and Maui Electric’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 Hawaii Electric Light and Maui Electric, (b) under their respective private placement note agreements and the Hawaii Electric Light notes and Maui Electric notes issued thereunder and (c) relating to the trust preferred securities of Trust III. Hawaiian Electric is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on Hawaii Electric Light’s and Maui Electric’s preferred stock if the respective subsidiary is unable to make such payments.Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended March 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	399,741		88,055		85,674		—	(28	)	$	573,442
Expenses
Fuel oil	118,403			23,385		35,018		—	—		176,806
Purchased power	103,250			21,893		10,864		—	—		136,007
Other operation and maintenance	70,084			16,399		17,519		—	—		104,002
Depreciation	29,389			9,313		5,541		—	—		44,243
Taxes, other than income taxes	38,201			8,384		8,163		—	—		54,748
Total expenses	359,327			79,374		77,105		—	—		515,806
Operating income	40,414			8,681		8,569		—	(28	)	57,636
Allowance for equity funds used during construction	1,123			145		145		—	—		1,413
Equity in earnings of subsidiaries	7,692			—		—		—	(7,692	)	—
Interest expense and other charges, net	(11,238		)	(2,680	)	(2,435	)	—	28		(16,325		)
Allowance for borrowed funds used during construction	388			53		58		—	—		499
Income before income taxes	38,379			6,199		6,337		—	(7,692	)	43,223
Income taxes	11,235			2,277		2,338		—	—		15,850
Net income	27,144			3,922		3,999		—	(7,692	)	27,373
Preferred stock dividends of subsidiaries	—			134		95		—	—		229
Net income attributable to Hawaiian Electric	27,144			3,788		3,904		—	(7,692	)	27,144
Preferred stock dividends of Hawaiian Electric	270			—		—		—	—		270
Net income for common stock	$	26,874		3,788		3,904		—	(7,692	)	$	26,874

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Three months ended March 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	26,874		3,788		3,904		—	(7,692	)	$	26,874
Other comprehensive income, net of taxes:
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	4,933			651		600		—	(1,251	)	4,933
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(4,911		)	(651	)	(600	)	—	1,251		(4,911		)
Other comprehensive income, net of taxes	22			—		—		—	—		22
Comprehensive income attributable to common shareholder	$	26,896		3,788		3,904		—	(7,692	)	$	26,896

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended March 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	512,455		104,931		102,693		—	(17	)	$	720,062
Expenses
Fuel oil	203,547			31,500		51,253		—	—		286,300
Purchased power	123,969			29,491		11,456		—	—		164,916
Other operation and maintenance	58,515			14,047		16,044		—	—		88,606
Depreciation	27,301			8,975		5,327		—	—		41,603
Taxes, other than income taxes	48,184			9,763		10,024		—	—		67,971
Total expenses	461,516			93,776		94,104		—	—		649,396
Operating income	50,939			11,155		8,589		—	(17	)	70,666
Allowance for equity funds used during construction	1,472			65		72		—	—		1,609
Equity in earnings of subsidiaries	8,917			—		—		—	(8,917	)	—
Interest expense and other charges, net	(10,487		)	(2,748	)	(2,505	)	—	17		(15,723		)
Allowance for borrowed funds used during construction	559			25		30		—	—		614
Income before income taxes	51,400			8,497		6,186		—	(8,917	)	57,166
Income taxes	15,710			3,202		2,335		—	—		21,247
Net income	35,690			5,295		3,851		—	(8,917	)	35,919
Preferred stock dividends of subsidiaries	—			134		95		—	—		229
Net income attributable to Hawaiian Electric	35,690			5,161		3,756		—	(8,917	)	35,690
Preferred stock dividends of Hawaiian Electric	270			—		—		—	—		270
Net income for common stock	$	35,420		5,161		3,756		—	(8,917	)	$	35,420

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Three months ended March 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	35,420		5,161		3,756		—	(8,917	)	$	35,420
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	2,519			344		253		—	(597	)	2,519
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(2,510		)	(344	)	(253	)	—	597		(2,510		)
Other comprehensive income, net of taxes	9			—		—		—	—		9
Comprehensive income attributable to common shareholder	$	35,429		5,161		3,756		—	(8,917	)	$	35,429

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consoli- dating adjustments		Hawaiian Electric Consolidated
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	43,542		5,464		3,016		—	—		$	52,022
Plant and equipment	3,826,826			1,182,567		1,057,130		—	—		6,066,523
Less accumulated depreciation	(1,256,950		)	(478,692	)	(453,448	)	—	—		(2,189,090		)
Construction in progress	135,984			14,947		13,920		—	—		164,851
Utility property, plant and equipment, net	2,749,402			724,286		620,618		—	—		4,094,306
Nonutility property, plant and equipment, less accumulated depreciation	4,949			82		1,531		—	—		6,562
Total property, plant and equipment, net	2,754,351			724,368		622,149		—	—		4,100,868
Investment in wholly owned subsidiaries, at equity	540,032			—		—		—	(540,032	)	—
Current assets
Cash and cash equivalents	5,484			1,654		881		101	—		8,120
Advances to affiliates	12,600			—		—		—	(12,600	)	—
Customer accounts receivable, net	86,157			21,485		17,353		—	—		124,995
Accrued unbilled revenues, net	81,346			14,500		13,648		—	—		109,494
Other accounts receivable, net	13,582			1,571		3,285		—	(9,770	)	8,668
Fuel oil stock, at average cost	65,861			7,983		11,471		—	—		85,315
Materials and supplies, at average cost	34,269			6,589		17,749		—	—		58,607
Prepayments and other	31,970			230		12,534		—	(1,379	)	43,355
Regulatory assets	85,353			9,359		8,033		—	—		102,745
Total current assets	416,622			63,371		84,954		101	(23,749	)	541,299
Other long-term assets
Regulatory assets	598,535			104,663		99,749		—	(103	)	802,844
Unamortized debt expense	5,621			1,396		1,199		—	—		8,216
Other	53,370			15,689		13,214		—	—		82,273
Total other long-term assets	657,526			121,748		114,162		—	(103	)	893,333
Total assets	$	4,368,531		909,487		821,265		101	(563,884	)	$	5,535,500
Capitalization and liabilities
Capitalization
Common stock equity	$	1,686,434		283,129		256,802		101	(540,032	)	$	1,686,434
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	830,546			190,000		186,000		—	—		1,206,546
Total capitalization	2,539,273			480,129		447,802		101	(540,032	)	2,927,273
Current liabilities
Current portion of long-term debt	—			—		—		—	—		—
Short-term borrowings from non-affiliates	30,000			—		—		—	—		30,000
Short-term borrowings from affiliate	—			10,000		2,600		—	(12,600	)	—
Accounts payable	106,975			14,988		16,546		—	—		138,509
Interest and preferred dividends payable	16,678			3,560		4,029		—	(10	)	24,257
Taxes accrued	126,742			30,060		27,449		—	(1,379	)	182,872
Regulatory liabilities	681			—		493		—	—		1,174
Other	49,389			10,126		16,234		—	(9,760	)	65,989
Total current liabilities	330,465			68,734		67,351		—	(23,749	)	442,801
Deferred credits and other liabilities
Deferred income taxes	423,151			89,923		83,910		—	—		596,984
Regulatory liabilities	240,749			79,504		30,388		—	(103	)	350,538
Unamortized tax credits	52,093			15,096		14,848		—	—		82,037
Defined benefit pension and other postretirement benefit plans liability	443,249			68,989		74,927			—		587,165
Other	48,044			12,664		13,609		—	—		74,317
Total deferred credits and other liabilities	1,207,286			266,176		217,682		—	(103	)	1,691,041
Contributions in aid of construction	291,507			94,448		88,430		—	—		474,385
Total capitalization and liabilities	$	4,368,531		909,487		821,265		101	(563,884	)	$	5,535,500

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consoli- dating adjustments		Hawaiian Electric Consolidated
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	43,819		5,464		3,016		—	—		$	52,299
Plant and equipment	3,782,438			1,179,032		1,048,012		—	—		6,009,482
Less accumulated depreciation	(1,253,866		)	(473,933	)	(447,711	)	—	—		(2,175,510		)
Construction in progress	134,376			12,421		11,819		—	—		158,616
Utility property, plant and equipment, net	2,706,767			722,984		615,136		—	—		4,044,887
Nonutility property, plant and equipment, less accumulated depreciation	4,950			82		1,531		—	—		6,563
Total property, plant and equipment, net	2,711,717			723,066		616,667		—	—		4,051,450
Investment in wholly owned subsidiaries, at equity	538,639			—		—		—	(538,639	)	—
Current assets
Cash and cash equivalents	12,416			612		633		101	—		13,762
Advances to affiliates	16,100			—		—		—	(16,100	)	—
Customer accounts receivable, net	111,462			24,222		22,800		—	—		158,484
Accrued unbilled revenues, net	103,072			15,926		18,376		—	—		137,374
Other accounts receivable, net	9,980			981		2,246		—	(8,924	)	4,283
Fuel oil stock, at average cost	74,515			13,800		17,731		—	—		106,046
Materials and supplies, at average cost	33,154			6,664		17,432		—	—		57,250
Prepayments and other	44,680			8,611		13,567		—	(475	)	66,383
Regulatory assets	58,550			6,745		6,126		—	—		71,421
Total current assets	463,929			77,561		98,911		101	(25,499	)	615,003
Other long-term assets
Regulatory assets	623,784			107,454		102,788		—	(183	)	833,843
Unamortized debt expense	5,640			1,438		1,245		—	—		8,323
Other	53,106			15,366		13,366		—	—		81,838
Total other long-term assets	682,530			124,258		117,399		—	(183	)	924,004
Total assets	$	4,396,815		924,885		832,977		101	(564,321	)	$	5,590,457
Capitalization and liabilities
Capitalization
Common stock equity	$	1,682,144		281,846		256,692		101	(538,639	)	$	1,682,144
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	830,546			190,000		186,000		—	—		1,206,546
Total capitalization	2,534,983			478,846		447,692		101	(538,639	)	2,922,983
Current liabilities
Short-term borrowings from affiliate	—			10,500		5,600		—	(16,100	)	—
Accounts payable	122,433			23,728		17,773		—	—		163,934
Interest and preferred dividends payable	15,407			3,989		2,931		—	(11	)	22,316
Taxes accrued	176,339			37,548		36,807		—	(292	)	250,402
Regulatory liabilities	191			—		441		—	—		632
Other	48,282			9,866		16,094		—	(9,096	)	65,146
Total current liabilities	362,652			85,631		79,646		—	(25,499	)	502,430
Deferred credits and other liabilities
Deferred income taxes	429,515			90,119		83,238		—	—		602,872
Regulatory liabilities	236,727			77,707		29,966		—	(183	)	344,217
Unamortized tax credits	49,865			14,902		14,725		—	—		79,492
Defined benefit pension and other postretirement benefit plans liability	446,888			72,547		75,960		—	—		595,395
Other	52,446			10,658		13,532		—	—		76,636
Total deferred credits and other liabilities	1,215,441			265,933		217,421		—	(183	)	1,698,612
Contributions in aid of construction	283,739			94,475		88,218		—	—		466,432
Total capitalization and liabilities	$	4,396,815		924,885		832,977		101	(564,321	)	$	5,590,457

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Balance, December 31, 2014	$	1,682,144		281,846		256,692		101	(538,639	)	$	1,682,144
Net income for common stock	26,874			3,788		3,904		—	(7,692	)	26,874
Other comprehensive income, net of taxes	22			—		—		—	—		22
Common stock dividends	(22,601		)	(2,505	)	(3,794	)	—	6,299		(22,601		)
Common stock issuance expenses	(5		)	—		—		—	—		(5		)
Balance, March 31, 2015	$	1,686,434		283,129		256,802		101	(540,032	)	$	1,686,434

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Balance, December 31, 2013	$	1,593,564		274,802		248,771		101	(523,674	)	$	1,593,564
Net income for common stock	35,420			5,161		3,756		—	(8,917	)	35,420
Other comprehensive income, net of taxes	9			—		—		—	—		9
Common stock dividends	(22,707		)	(2,941	)	(3,629	)	—	6,570		(22,707		)
Common stock issuance expenses	(3		)	—		(1	)	—	1		(3		)
Balance, March 31, 2014	$	1,606,283		277,022		248,897		101	(526,020	)	$	1,606,283

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	27,144		3,922		3,999		—	(7,692	)	$	27,373
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries	(7,717		)	—		—		—	7,692		(25		)
Common stock dividends received from subsidiaries	6,324			—		—		—	(6,299	)	25
Depreciation of property, plant and equipment	29,389			9,313		5,541		—	—		44,243
Other amortization	590			500		(401	)	—	—		689
Increase in deferred income taxes	12,048			719		2,365		—	—		15,132
Change in tax credits, net	2,246			200		130		—	—		2,576
Allowance for equity funds used during construction	(1,123		)	(145	)	(145	)	—	—		(1,413		)
Change in cash overdraft	—			—		—		—	—		—
Changes in assets and liabilities:
Increase in accounts receivable	21,703			2,147		4,408		—	846		29,104
Decrease in accrued unbilled revenues	21,726			1,426		4,728		—	—		27,880
Decrease in fuel oil stock	8,654			5,817		6,260		—	—		20,731
Decrease (increase) in materials and supplies	(1,115		)	75		(317	)	—	—		(1,357		)
Increase in regulatory assets	(8,903		)	(1,522	)	(402	)	—	—		(10,827		)
Decrease in accounts payable	(35,128		)	(9,892	)	(4,116	)	—	—		(49,136		)
Change in prepaid and accrued income and utility revenue taxes	(52,273		)	(1,807	)	(9,616	)	—	—		(63,696		)
Increase in defined benefit pension and other postretirement benefit plans liability	—			—		110		—	—		110
Change in other assets and liabilities	(8,439		)	229		534		—	(846	)	(8,522		)
Net cash provided by operating activities	15,126			10,982		13,078		—	(6,299	)	32,887
Cash flows from investing activities
Capital expenditures	(40,594		)	(7,558	)	(6,206	)	—	—		(54,358		)
Contributions in aid of construction	8,121			758		266		—	—		9,145
Advances from affiliates	3,500			—		—		—	(3,500	)	—
Net cash used in investing activities	(28,973		)	(6,800	)	(5,940	)	—	(3,500	)	(45,213		)
Cash flows from financing activities
Common stock dividends	(22,601		)	(2,505	)	(3,794	)	—	6,299		(22,601		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(270		)	(134	)	(95	)	—	—		(499		)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	30,000			(500	)	(3,000	)	—	3,500		30,000
Other	(214		)	(1	)	(1	)	—	—		(216		)
Net cash provided by (used in) financing activities	6,915			(3,140	)	(6,890	)	—	9,799		6,684
Net increase (decrease) in cash and cash equivalents	(6,932		)	1,042		248		—	—		(5,642		)
Cash and cash equivalents, beginning of period	12,416			612		633		101	—		13,762
Cash and cash equivalents, end of period	$	5,484		1,654		881		101	—		$	8,120

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	35,690		5,295		3,851		—	(8,917	)	$	35,919
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(8,942		)	—		—		—	8,917		(25		)
Common stock dividends received from subsidiaries	6,595			—		—		—	(6,570	)	25
Depreciation of property, plant and equipment	27,301			8,975		5,327		—	—		41,603
Other amortization	235			501		885		—	—		1,621
Increase in deferred income taxes	17,123			862		2,359		—	—		20,344
Change in tax credits, net	1,741			217		74		—	—		2,032
Allowance for equity funds used during construction	(1,472		)	(65	)	(72	)	—	—		(1,609		)
Change in cash overdraft	—			—		(1,038	)	—	—		(1,038		)
Changes in assets and liabilities:
Decrease in accounts receivable	4,131			2,029		2,194		—	450		8,804
Decrease (increase) in accrued unbilled revenues	11,031			(230	)	1,459		—	—		12,260
Decrease (increase) in fuel oil stock	(35,060		)	1,166		(366	)	—	—		(34,260		)
Increase in materials and supplies	(330		)	(387	)	(328	)	—	—		(1,045		)
Increase in regulatory assets	(8,188		)	(881	)	(189	)	—	—		(9,258		)
Decrease in accounts payable	(837		)	(6,032	)	(9,155	)	—	—		(16,024		)
Change in prepaid and accrued income and utility revenue taxes	(39,581		)	(2,791	)	(5,154	)	—	—		(47,526		)
Decrease in defined benefit pension and other postretirement benefit plans liability	(103		)	—		(102	)	—	—		(205		)
Change in other assets and liabilities	(10,874		)	1,041		(698	)	—	(450	)	(10,981		)
Net cash provided by (used in) operating activities	(1,540		)	9,700		(953	)	—	(6,570	)	637
Cash flows from investing activities
Capital expenditures	(49,432		)	(7,530	)	(7,500	)	—	—		(64,462		)
Contributions in aid of construction	4,541			1,121		1,296		—	—		6,958
Advances from (to) affiliates	(12,661		)	900		—		—	11,761		—
Net cash used in investing activities	(57,552		)	(5,509	)	(6,204	)	—	11,761		(57,504		)
Cash flows from financing activities
Common stock dividends	(22,707		)	(2,941	)	(3,629	)	—	6,570		(22,707		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(270		)	(134	)	(95	)	—	—		(499		)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	34,096			—		12,661		—	(11,761	)	34,996
Other	(320		)	—		(69	)	—	—		(389		)
Net cash provided by (used in) financing activities	10,799			(3,075	)	8,868		—	(5,191	)	11,401
Net increase (decrease) in cash and cash equivalents	(48,293		)	1,116		1,711		—	—		(45,466		)
Cash and cash equivalents, beginning of period	61,245			1,326		153		101	—		62,825
Cash and cash equivalents, end of period	$	12,952		2,442		1,864		101	—		$	17,359

5 · Bank segment

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data



	Three months ended March 31
(in thousands)	2015		2014
Interest and dividend income
Interest and fees on loans	$	45,198	$	43,682
Interest and dividends on investment securities	3,051		3,035
Total interest and dividend income	48,249		46,717
Interest expense
Interest on deposit liabilities	1,260		1,225
Interest on other borrowings	1,466		1,405
Total interest expense	2,726		2,630
Net interest income	45,523		44,087
Provision for loan losses	614		995
Net interest income after provision for loan losses	44,909		43,092
Noninterest income
Fees from other financial services	5,355		5,128
Fee income on deposit liabilities	5,315		4,421
Fee income on other financial products	1,889		2,290
Bank-owned life insurance	983		963
Mortgage banking income	1,822		628
Gains on sale of investment securities	—		2,847
Other income, net	735		625
Total noninterest income	16,099		16,902
Noninterest expense
Compensation and employee benefits	21,766		20,286
Occupancy	4,113		3,953
Data processing	3,116		3,060
Services	2,341		2,273
Equipment	1,701		1,645
Office supplies, printing and postage	1,483		1,616
Marketing	841		711
FDIC insurance	811		796
Other expense	4,205		3,122
Total noninterest expense	40,377		37,462
Income before income taxes	20,631		22,532
Income taxes	7,156		8,133
Net income	$	13,475	$	14,399

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data



	Three months ended March 31
(in thousands)	2015		2014
Net income	$	13,475	$	14,399
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on available-for-sale investment securities:
Net unrealized gains losses on available-for-sale investment securities arising during the period, net of tax benefits of $2,278 and $1,664 for the respective periods	3,451		2,520
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil and $1,132 for the respective periods	—		(1,715		)
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 $259 and $144 for the respective periods	392		219
Other comprehensive income, net of taxes	3,843		1,024
Comprehensive income	$	17,318	$	15,423

American Savings Bank, F.S.B.

Balance Sheets Data



(in thousands)	March 31, 2015						December 31, 2014
Assets
Cash and due from banks				$	98,484					$	107,233
Interest-bearing deposits				172,517						54,230
Available-for-sale investment securities, at fair value				590,648						550,394
Stock in Federal Home Loan Bank of Seattle, at cost				63,711						69,302
Loans receivable held for investment				4,447,299						4,434,651
Allowance for loan losses				(45,795		)				(45,618		)
Net loans				4,401,504						4,389,033
Loans held for sale, at lower of cost or fair value				9,906						8,424
Other				305,917						305,416
Goodwill				82,190						82,190
Total assets				$	5,724,877					$	5,566,222

Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing				$	1,420,085					$	1,342,794
Deposit liabilities—interest-bearing				3,331,243						3,280,621
Other borrowings				312,094						290,656
Other				117,849						118,363
Total liabilities				5,181,271						5,032,434
Commitments and contingencies
Common stock				1						1
Additional paid in capital				338,411						338,411
Retained earnings				217,909						211,934
Accumulated other comprehensive loss, net of tax benefits
Net unrealized gains on securities	$	3,913					$	462
Retirement benefit plans	(16,628		)	(12,715		)	(17,020		)	(16,558		)
Total shareholder’s equity				543,606						533,788
Total liabilities and shareholder’s equity				$	5,724,877					$	5,566,222

Other assets
Bank-owned life insurance				$	135,141					$	134,115
Premises and equipment, net				85,174						92,407
Prepaid expenses				4,892						3,196
Accrued interest receivable				13,720						13,632
Mortgage-servicing rights				11,965						11,540
Low-income housing equity investments				32,140						33,438
Real estate acquired in settlement of loans, net				665						891
Other				22,220						16,197
				$	305,917					$	305,416
Other liabilities
Accrued expenses				$	29,670					$	37,880
Federal and state income taxes payable				36,010						28,642
Cashier’s checks				24,686						20,509
Advance payments by borrowers				5,904						9,652
Other				21,579						21,680
				$	117,849					$	118,363

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.

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $212 million and $100 million, respectively, as of March 31, 2015 and $191 million and $100 million, respectively, as of December 31, 2014.

Available-for-sale investment securities. The major components of investment securities were as follows:



	Amortized cost		Gross unrealized gains		Gross unrealized losses			Estimated fair value			Gross unrealized losses
										Less than 12 months						12 months or longer
(dollar in thousands)										Number of issues	Fair value		Amount			Number of issues	Fair value		Amount
March 31, 2015
Available-for-sale
U.S. Treasury and federal agency obligations	$	138,593	$	2,029	$	(395	)	$	140,227	1	$	9,973	$	(2	)	3	$	19,198	$	(393	)
Mortgage-related securities- FNMA, FHLMC and GNMA	445,559		7,149		(2,287		)	450,421		6	40,889		(89		)	26	147,722		(2,198		)
	$	584,152	$	9,178	$	(2,682	)	$	590,648	7	$	50,862	$	(91	)	29	$	166,920	$	(2,591	)
December 31, 2014
Available-for-sale
U.S. Treasury and federal agency obligations	$	119,507	$	1,092	$	(1,039	)	$	119,560	6	$	41,970	$	(361	)	5	$	29,168	$	(678	)
Mortgage-related securities- FNMA, FHLMC and GNMA	430,120		5,653		(4,939		)	430,834		6	47,029		(164		)	29	172,623		(4,775		)
	$	549,627	$	6,745	$	(5,978	)	$	550,394	12	$	88,999	$	(525	)	34	$	201,791	$	(5,453	)

The unrealized losses on ASB’s investments in mortgage-related securities and obligations issued by federal agencies were caused by interest rate movements. Because ASB does 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 cost basis, which may be at maturity, ASB did not consider these investments to be other-than-temporarily impaired at March 31, 2015.

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

U.S. Treasury and federal agency obligations have contractual terms to maturity. Mortgage-related securities have contractual terms to maturity, but require periodic payments to reduce principal. In addition, expected maturities will differ from contractual maturities because borrowers have the right to prepay the underlying mortgages.

The contractual maturities of available-for-sale investment securities were as follows:



March 31, 2015	Amortized cost		Fair value
(in thousands)
Due in one year or less	$	—	$	—
Due after one year through five years	29,958		30,296
Due after five years through ten years	71,811		73,188
Due after ten years	36,824		36,743
	138,593		140,227
Mortgage-related securities-FNMA,FHLMC and GNMA	445,559		450,421
Total available-for-sale securities	$	584,152	$	590,648

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



(in thousands)	Residential 1-4 family			Commercial real estate		Home equity line of credit			Residential land			Commercial construction			Residential construction			Commercial loans			Consumer loans			Unallocated			Total
Three months ended March 31, 2015
Allowance for loan losses:
Beginning balance	$	4,662		$	8,954	$	6,982		$	1,875		$	5,471		$	28		$	14,017		$	3,629		$	—		$	45,618
Charge-offs	(156		)	—		(3		)	—			—			—			(46		)	(942		)	—			(1,147		)
Recoveries	12			—		31			49			—			—			341			277			—			710
Provision	403			2,274		(487		)	362			(2,634		)	(7		)	268			435			—			614
Ending balance	$	4,921		$	11,228	$	6,523		$	2,286		$	2,837		$	21		$	14,580		$	3,399		$	—		$	45,795
Ending balance: individually evaluated for impairment	$	1,429		$	1,785	$	144		$	1,085		$	—		$	—		$	1,096		$	9					$	5,548
Ending balance: collectively evaluated for impairment	$	3,492		$	9,443	$	6,379		$	1,201		$	2,837		$	21		$	13,484		$	3,390		$	—		$	40,247
Financing Receivables:
Ending balance	$	2,039,099		$	561,189	$	814,265		$	18,155		$	77,164		$	20,804		$	803,545		$	119,310					$	4,453,531
Ending balance: individually evaluated for impairment	$	23,089		$	4,998	$	1,183		$	7,819		$	—		$	—		$	11,879		$	15					$	48,983
Ending balance: collectively evaluated for impairment	$	2,016,010		$	556,191	$	813,082		$	10,336		$	77,164		$	20,804		$	791,666		$	119,295					$	4,404,548
Three months ended March 31, 2014
Allowance for loan losses:
Beginning balance	$	5,534		$	5,059	$	5,229		$	1,817		$	2,397		$	19		$	15,803		$	2,367		$	1,891		$	40,116
Charge-offs	(266		)	—		—			(6		)	—			—			(124		)	(561		)	—			(957		)
Recoveries	341			—		11			86			—			—			100			231			—			769
Provision	(134		)	656		729			(322		)	666			5			(187		)	279			(697		)	995
Ending balance	$	5,475		$	5,715	$	5,969		$	1,575		$	3,063		$	24		$	15,592		$	2,316		$	1,194		$	40,923
Ending balance: individually evaluated for impairment	$	906		$	1,544	$	—		$	1,102		$	—		$	—		$	2,133		$	—					$	5,685
Ending balance: collectively evaluated for impairment	$	4,569		$	4,171	$	5,969		$	473		$	3,063		$	24		$	13,459		$	2,316		$	1,194		$	35,238
Financing Receivables:
Ending balance	$	1,985,812		$	452,303	$	764,483		$	15,906		$	66,578		$	16,474		$	786,611		$	108,202					$	4,196,369
Ending balance: individually evaluated for impairment	$	20,141		$	4,558	$	1,164		$	10,351		$	—		$	—		$	19,399		$	18					$	55,631
Ending balance: collectively evaluated for impairment	$	1,965,671		$	447,745	$	763,319		$	5,555		$	66,578		$	16,474		$	767,212		$	108,184					$	4,140,738

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, commercial real estate and commercial construction loans.

Each loan is assigned an Asset Quality Rating (AQR) reflecting the likelihood of repayment or orderly liquidation of that loan transaction pursuant to regulatory credit classifications: Pass, Special Mention, Substandard, Doubtful, and Loss. The AQR is a function of the PD Model rating, the LGD, and possible non-model factors which impact the ultimate collectability of the loan such as character of the business owner/guarantor, interim period performance, litigation, tax liens, and major changes

in business and economic conditions. 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. Special Mention loans have potential weaknesses that, if left uncorrected, could jeopardize the liquidation of the debt. Substandard loans have well-defined weaknesses that jeopardize the liquidation of the debt and are characterized by the distinct possibility that the Bank may sustain some loss. An asset classified Doubtful has the weaknesses of those classified Substandard, with the added characteristic that the weaknesses make collection or liquidation in full, on the basis of currently existing facts, conditions, and values, highly questionable and improbable.

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



	March 31, 2015						December 31, 2014
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	507,993	$	77,164	$	739,721	$	493,105	$	79,312	$	743,334
Special mention	5,203		—		31,863		5,209		—		16,095
Substandard	47,993		—		31,335		33,603		17,126		31,665
Doubtful	—		—		626		—		—		663
Loss	—		—		—		—		—		—
Total	$	561,189	$	77,164	$	803,545	$	531,917	$	96,438	$	791,757

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
March 31, 2015
Real estate:
Residential 1-4 family	$	6,074	$	2,718	$	12,231	$	21,023	$	2,018,076	$	2,039,099	$	—
Commercial real estate	—		—		—		—		561,189		561,189		—
Home equity line of credit	1,041		807		629		2,477		811,788		814,265		—
Residential land	422		—		—		422		17,733		18,155
Commercial construction	—		—		—		—		77,164		77,164		—
Residential construction	—		—		—		—		20,804		20,804		—
Commercial	680		238		532		1,450		802,095		803,545		—
Consumer	895		270		266		1,431		117,879		119,310		—
Total loans	$	9,112	$	4,033	$	13,658	$	26,803	$	4,426,728	$	4,453,531	$	—
December 31, 2014
Real estate:
Residential 1-4 family	$	6,124	$	1,732	$	12,632	$	20,488	$	2,023,717	$	2,044,205	$	—
Commercial real estate	—		—		—		—		531,917		531,917		—
Home equity line of credit	1,341		501		194		2,036		816,779		818,815		—
Residential land	—		—		—		—		16,240		16,240		—
Commercial construction	—		—		—		—		96,438		96,438		—
Residential construction	—		—		—		—		18,961		18,961		—
Commercial	699		145		569		1,413		790,344		791,757		—
Consumer	829		333		403		1,565		121,091		122,656		—
Total loans	$	8,993	$	2,711	$	13,798	$	25,502	$	4,415,487	$	4,440,989	$	—

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



(in thousands)	March 31, 2015		December 31, 2014
Real estate:
Residential 1-4 family	$	18,205	$	19,253
Commercial real estate	4,998		5,112
Home equity line of credit	1,701		1,087
Residential land	717		720
Commercial construction	—		—
Residential construction	—		—
Commercial	9,018		10,053
Consumer	542		661
Total nonaccrual loans	$	35,181	$	36,886
Real estate:
Residential 1-4 family	$	—	$	—
Commercial real estate	—		—
Home equity line of credit	—		—
Residential land	—		—
Commercial construction	—		—
Residential construction	—		—
Commercial	—		—
Consumer	—		—
Total accruing loans 90 days or more past due	$	—	$	—
Real estate:
Residential 1-4 family	$	14,334	$	13,525
Commercial real estate	—		—
Home equity line of credit	750		480
Residential land	7,102		7,130
Commercial construction	—		—
Residential construction	—		—
Commercial	2,720		2,972
Consumer	—		—
Total troubled debt restructured loans not included above	$	24,906	$	24,107

The total carrying amount and the total unpaid principal balance of impaired loans were as follows:



	March 31, 2015						Three months ended March 31, 2015
(in thousands)	Recorded investment		Unpaid principal balance		Related Allowance		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate:
Residential 1-4 family	$	11,168	$	12,460	$	—	$	11,552	$	89
Commercial real estate	547		609		—		555		—
Home equity line of credit	339		544		—		400		1
Residential land	3,265		4,121		—		2,637		52
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	6,289		8,089		—		7,295		2
Consumer	—		—		—		—		—
	$	21,608	$	25,823	$	—	$	22,439	$	144
With an allowance recorded
Real estate:
Residential 1-4 family	$	11,921	$	11,974	$	1,429	$	11,510	$	126
Commercial real estate	4,451		4,511		1,785		4,482		—
Home equity line of credit	844		900		144		626		6
Residential land	4,554		4,632		1,085		5,189		83
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	5,590		7,549		1,096		4,982		50
Consumer	15		15		9		15		—
	$	27,375	$	29,581	$	5,548	$	26,804	$	265
Total
Real estate:
Residential 1-4 family	$	23,089	$	24,434	$	1,429	$	23,062	$	215
Commercial real estate	4,998		5,120		1,785		5,037		—
Home equity line of credit	1,183		1,444		144		1,026		7
Residential land	7,819		8,753		1,085		7,826		135
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	11,879		15,638		1,096		12,277		52
Consumer	15		15		9		15		—
	$	48,983	$	55,404	$	5,548	$	49,243	$	409



	December 31, 2014						Year ended December 31, 2014
(in thousands)	Recorded investment		Unpaid principal balance		Related allowance		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate:
Residential 1-4 family	$	11,654	$	12,987	$	—	$	9,056	$	227
Commercial real estate	571		626		—		194		—
Home equity line of credit	363		606		—		402		5
Residential land	2,344		3,200		—		2,728		172
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	8,235		11,471		—		5,204		38
Consumer	—		—		—		8		—
	$	23,167	$	28,890	$	—	$	17,592	$	442
With an allowance recorded
Real estate:
Residential 1-4 family	$	11,327	$	11,347	$	951	$	8,822	$	419
Commercial real estate	4,541		4,541		1,845		3,415		478
Home equity line of credit	416		420		46		132		6
Residential land	5,506		5,584		1,057		6,415		484
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	4,873		5,211		760		12,089		438
Consumer	16		16		6		9		—
	$	26,679	$	27,119	$	4,665	$	30,882	$	1,825
Total
Real estate:
Residential 1-4 family	$	22,981	$	24,334	$	951	$	17,878	$	646
Commercial real estate	5,112		5,167		1,845		3,609		478
Home equity line of credit	779		1,026		46		534		11
Residential land	7,850		8,784		1,057		9,143		656
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	13,108		16,682		760		17,293		476
Consumer	16		16		6		17		—
	$	49,846	$	56,009	$	4,665	$	48,474	$	2,267


*	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 generally does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.

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:



	Three months ended March 31, 2015
	Number of	Outstanding recorded investment				Net increase in ALL
(dollars in thousands)	contracts	Pre-modification		Post-modification		(as of period end)
Troubled debt restructurings
Real estate:
Residential 1-4 family	5	$	877	$	895	$	47
Commercial real estate	—	—		—		—
Home equity line of credit	9	429		429		55
Residential land	—	—		—		—
Commercial construction	—	—		—		—
Residential construction	—	—		—		—
Commercial	1	92		92		—
Consumer	—	—		—		—
	15	$	1,398	$	1,416	$	102



	Three months ended March 31, 2014
	Number of	Outstanding recorded investment				Net increase in ALL
(dollars in thousands)	contracts	Pre-modification		Post-modification		(as of period end)
Troubled debt restructurings
Real estate:
Residential 1-4 family	5	$	921	$	935	$	44
Commercial real estate	—	—		—		—
Home equity line of credit	—	—		—		—
Residential land	7	1,133		1,133		175
Commercial construction	—	—		—		—
Residential construction	—	—		—		—
Commercial	3	473		473		14
Consumer	—	—		—		—
	15	$	2,527	$	2,541	$	233

There were no loans modified in TDRs that experienced a payment default of 90 days or more in the first quarter of 2015 and 2014, and for which the payment of default occurred within one year of the modification.

If loans modified in a TDR subsequently default, ASB evaluates the loan for further impairment. Based on its evaluation, adjustments may be made in the allocation of the allowance or partial charge-offs may be taken to further write-down the carrying value of the loan. There were no commitments to lend additional funds to borrowers whose loan terms have been impaired or modified in TDRs as of March 31, 2015.

Mortgage servicing rights. In its mortgage banking business, ASB sells residential mortgage loans to government-sponsored entities and other parties, who may issue securities backed by pools of such loans. ASB retains no beneficial interests in these sales, but may retain the servicing rights of the loans sold.

Mortgage servicing fees, a component of other income, net, were $0.9 million for the three months ended March 31, 2015 and 2014.

The carrying values of mortgage servicing assets were as follows:



(in thousands)	Gross carrying amount		Accumulated amortization			Valuation allowance			Net carrying amount
March 31, 2015	$	28,090	$	(16,084	)	$	(41	)	$	11,965
March 31, 2014	26,097		(14,138		)	(202		)	11,757

Changes related to mortgage servicing rights were as follows:



(in thousands)	2015			2014
Mortgage servicing rights
Balance, January 1	$	11,749		$	11,938
Amount capitalized	906			467
Amortization	(647		)	(432		)
Other-than-temporary impairment	(2		)	(14		)
Carrying amount before valuation allowance, March 31	12,006			11,959
Valuation allowance for mortgage servicing rights
Balance, January 1	209			251
Provision (recovery)	(166		)	(35		)
Other-than-temporary impairment	(2		)	(14		)
Balance, March 31	41			202
Net carrying value of mortgage servicing rights	$	11,965		$	11,757

ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing rights. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others, which increases the value of mortgage servicing rights, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing rights and increase the amortization of the mortgage servicing rights.

Key assumptions used in estimating the fair value of the bank’s mortgage servicing rights were as follows:



(dollars in thousands)	March 31, 2015			December 31, 2014
Unpaid principal balance	$	1,414,990		$	1,391,030
Weighted average note rate	4.06		%	4.07		%
Weighted average discount rate	9.6		%	9.6		%
Weighted average prepayment speed	10.6		%	9.5		%

The sensitivity analysis of fair value of MSR to hypothetical adverse changes of 25 and 50 basis points in certain key assumptions is as follows:



(dollars in thousands)	March 31, 2015			December 31, 2014
Prepayment rate:
25 basis points adverse rate change	$	(750	)	$	(757	)
50 basis points adverse change	(1,408		)	(1,524		)
Discount rate:
25 basis points adverse change	(129		)	(140		)
50 basis points adverse rate change	(256		)	(278		)

The effect of a variation in certain assumptions on fair value is calculated without changing any other assumptions. This analysis typically cannot be extrapolated because the relationship of a change in one key assumption to the changes in the fair value of MSRs typically is not linear.

Other borrowings. 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
March 31, 2015	$212	$—	$212
December 31, 2014	191	—	191



	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
March 31, 2015
Financial institution	$	50	$	50	$	—	$	—
Government entities	56		56		—		—
Commercial account holders	106		106		—		—
Total	$	212	$	212	$	—	$	—

December 31, 2014
Financial institution	$	50	$	50	$	—	$	—
Government entities	56		56		—		—
Commercial account holders	85		85		—		—
Total	$	191	$	191	$	—	$	—

Derivative financial instruments. ASB enters into interest rate lock commitments (IRLCs) with borrowers, and forward commitments to sell loans or to-be-announced mortgage-backed securities to investors to hedge against the inherent interest rate and pricing risk associated with selling loans.

ASB enters into IRLCs 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. IRLCs that relate to the origination of mortgage loans that will be held for sale are considered derivative financial instruments under applicable accounting guidance. Outstanding IRLCs expose ASB to the risk that the price of the mortgage loans underlying the commitments may decline due to increases in mortgage interest rates from inception of the rate lock to the funding of the loan. The IRLCs are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.

ASB enters into forward commitments to hedge the interest rate risk for rate locked mortgage applications in process and closed mortgage loans held for sale. These commitments are primarily forward sales of to-be-announced mortgage backed securities. Generally, when mortgage loans are closed, the forward commitment is liquidated and replaced with a mandatory delivery forward sale of the mortgage to a secondary market investor. In some cases, a best-efforts forward sale agreement is utilized as the forward commitment. These commitments are free-standing derivatives which are carried at fair value with changes recorded in mortgage banking income.

Changes in the fair value of IRLCs and forward commitments subsequent to inception are based on changes in the fair value of the underlying loan resulting from the fulfillment of the commitment and changes in the probability that the loan will fund within the terms of the commitment, which is affected primarily by changes in interest rates and the passage of time.

The notional amount and fair value of ASB’s derivative financial instruments were as follows:



	March 31, 2015					December 31, 2014
(in thousands)	Notional amount		Fair value			Notional amount		Fair value
Interest rate lock commitments	$	50,301	$	835		$	29,330	$	390
Forward commitments	46,489		(265		)	32,833		(106		)

ASB’s derivative financial instruments, their fair values, and balance sheet location were as follows:



Derivative Financial Instruments Not Designated as Hedging Instruments ¹	March 31, 2015				December 31, 2014
(in thousands)	Asset derivatives		Liability derivatives		Asset derivatives		Liability derivatives
Interest rate lock commitments	$	836	$	1	$	393	$	3
Forward commitments	15		280		5		111
	$	851	$	281	$	398	$	114

¹ Asset derivatives are included in other assets and liability derivatives are included in other liabilities in the balance sheets.

The following table presents ASB’s derivative financial instruments and the amount and location of the net gains or losses recognized in the statements of income:



Derivative Financial Instruments Not Designated as Hedging Instruments	Location of net gains (losses) recognized in the Statement of Income	Three months ended March 31
(in thousands)		2015			2014
Interest rate lock commitments	Mortgage banking income	$	445		$	(270	)
Forward commitments	Mortgage banking income	(159		)	(106		)
		$	286		$	(376	)

Commitments to fund Low-Income Housing Tax Credit (LIHTC). ASB’s unfunded commitments to fund its LIHTC investment partnerships were $12.5 million and $14.8 million at March 31, 2015 and December 31, 2014, respectively. These unfunded commitments were unconditional and legally binding and are recorded in other liabilities with a corresponding increase in other assets. As of March 31, 2015, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its LIHTC investment partnerships.

Contingencies. 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. ASB filed a motion to dismiss the lawsuit on the basis that ASB’s overdraft practices are governed by federal regulations established for federal savings banks which preempt the customer’s state law claims. In July 2011, the Circuit Court denied ASB's motion without prejudice and ASB appealed that decision. ASB's appeal is pending before the Hawaii Supreme Court. However, in December 2014, through a voluntary mediation process, ASB reached a tentative settlement of the claims. The tentative settlement, which remains subject to final court approval, provides for a payment of $2.0 million into a class settlement fund, the proceeds of which will be used to refund class members and pay attorneys’ fees and administrative and other costs, in exchange for a complete release of all claims asserted against ASB. As of March 2015, the $2.0 million tentative settlement amount was fully reserved by ASB.

6 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information. For the first three months of 2015, the Company contributed $21 million ($21 million by the Utilities) to its pension and other postretirement benefit plans, compared to $15 million ($14 million by the Utilities) in the first three months of 2014. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2015 is $86 million ($84 million by the Utilities, $2 million by HEI and nil by ASB), compared to $60 million ($59 million by the Utilities, $1 million by HEI and nil by ASB) in 2014. In addition, the Company expects to pay directly $2 million ($1 million by the Utilities) of benefits in 2015, compared to $2 million ($1 million by the Utilities) paid in 2014.

On August 8, 2014 and July 6, 2012, President Obama signed the Highway and Transportation Funding Act of 2014 (HATFA) and the Moving Ahead for Progress in the 21st Century Act (MAP-21), respectively, which included provisions related to the funding and administration of pension plans with no impact to the Company’s or the Utilities' accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to apply HATFA for 2014, which improved the plans’ Adjusted Funding Target Attainment Percentage for funding and benefit distribution purposes and thereby reduced the 2014 minimum funding requirement. HATFA caused the minimum required funding under the Employee Retirement Income Security Act of 1974, as amended (ERISA) to be less than the net periodic cost for 2014; therefore, to satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities contributed the net periodic cost in 2014 and expect to contribute the net periodic cost in 2015.

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 met the threshold

requirements in each of 2013 and 2014 so that the more conservative assumptions did not apply for either the 2014 or 2015 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 HEI consolidated and Hawaiian Electric consolidated were as follows:



	Three months ended March 31
	Pension benefits						Other benefits
(in thousands)	2015			2014			2015			2014
HEI consolidated
Service cost	$	16,466		$	12,127		$	869		$	883
Interest cost	19,139			18,001			2,235			2,160
Expected return on plan assets	(22,151		)	(20,347		)	(2,907		)	(2,708		)
Amortization of net prior service loss (gain)	1			22			(448		)	(448		)
Amortization of net actuarial loss (gain)	8,962			5,038			430			(3		)
Net periodic benefit cost (credit)	22,417			14,841			179			(116		)
Impact of PUC D&Os	(9,513		)	(3,011		)	98			445
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	12,904		$	11,830		$	277		$	329
Hawaiian Electric consolidated
Service cost	$	15,983		$	11,697		$	855		$	856
Interest cost	17,516			16,436			2,159			2,079
Expected return on plan assets	(20,632		)	(18,171		)	(2,859		)	(2,663		)
Amortization of net prior service loss (gain)	10			15			(451		)	(451		)
Amortization of net actuarial loss	8,094			4,560			422			—
Net periodic benefit cost (credit)	20,971			14,537			126			(179		)
Impact of PUC D&Os	(9,513		)	(3,011		)	98			445
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,458		$	11,526		$	224		$	266

HEI consolidated recorded retirement benefits expense of $9 million ($8 million by the Utilities) and $8 million ($8 million by the Utilities) in the first three months of 2015 and 2014, respectively, and charged the remaining net periodic benefit cost 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 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 issuance of the PUC’s D&O in the respective utility’s next rate case.

Defined contribution plans information. For the first three months of 2015 and 2014, 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 $1.4 million and $1.1 million, respectively, and cash contributions were $2.5 million and $2.8 million, respectively. For the first three months of 2015 and 2014, the Utilities’ expense for its defined contribution pension plan under the HEIRSP was $0.4 million and $0.2 million, respectively, and cash contributions were $0.4 million and $0.2 million, respectively.

7 · Share-based compensation

Under the 2010 Equity and Incentive Plan, as amended, HEI can issue shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights (SARs), restricted shares, restricted stock units, performance shares and other share-based and cash-based awards. The 2010 Equity and Incentive Plan (original EIP) was amended and restated effective March 1, 2014 (EIP) and an additional 1.5 million shares was added to the shares available for issuance under these programs.

As of March 31, 2015, approximately 3.5 million shares remained available for future issuance under the terms of the EIP, (assuming recycling of shares withheld to satisfy minimum statutory tax liabilities relating to EIP awards), including an estimated 0.8 million shares that could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals for awards outstanding under long-term incentive plans (assuming that such performance goals are achieved at maximum levels).

Under the 2011 Nonemployee Director Stock Plan (2011 Director Plan), HEI can issue shares of common stock as compensation to nonemployee directors of HEI, Hawaiian Electric and ASB. As of March 31, 2015, there were 169,290 shares remaining available for future issuance under the 2011 Director Plan.

Share-based compensation expense and the related income tax benefit were as follows:



	Three months ended March 31
(in millions)	2015		2014
HEI consolidated
Share-based compensation expense ¹	$	1.8	$	2.4
Income tax benefit	0.6		0.8
Hawaiian Electric consolidated
Share-based compensation expense ¹	0.5		0.7
Income tax benefit	0.2		0.3


¹	$0.04 million and $0.04 million of this share-based compensation expense was capitalized in the three months ended March 31, 2015 and 2014, respectively.

Stock awards. In the second quarter of each year, HEI grants shares to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan. The number of shares issued to each nonemployee director of HEI, Hawaiian Electric and ASB is determined based on the closing price of HEI Common Stock on the grant date.

Stock appreciation rights. As of December 31, 2014, the shares underlying SARs outstanding totaled 80,000, with a weighted-average exercise price of $26.18. As of March 31, 2015, there were no remaining SARs outstanding.

SARs activity and statistics were as follows:



	Three months ended March 31
(dollars in thousands, except prices)	2015		2014
Shares underlying SARS exercised	80,000		-
Weighted-average price of shares exercised	$	26.18	-
Intrinsic value of shares exercised ¹	502		-
Tax benefit realized for the deduction of exercises	162		-

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



	Three months ended March 31
	2015					2014
	Shares			(1)		Shares			(1)
Outstanding, beginning of period	261,235			$	25.77	288,151			$	25.17
Granted	84,294			33.74		115,036			25.19
Vested	(79,219		)	25.77		(71,029		)	25.79
Forfeited	(4,619		)	25.83		—			—
Outstanding, end of period	261,691			$	28.33	332,158			$	25.04
Total weighted-average grant-date fair value of shares granted ($ millions)	$	2.8				$	2.9


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

As of March 31, 2015, there was $6.5 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 2.9 years.

For the first three months of 2015 and 2014, total restricted stock units that vested and related dividends had a fair value of $3.0 million and $2.0 million, respectively, and the related tax benefits were $1.0 million and $0.7 million, respectively.

Long-term incentive plan payable in stock. The 2013-2015 long-term incentive plan (LTIP) and 2014-2016 LTIP provide for performance awards under the original EIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition 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 2013-2015 LTIP and 2014-2016 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on average common equity (ROACE), Hawaiian Electric consolidated net income, Hawaiian Electric consolidated ROACE and ASB net income — all based on the applicable three-year averages, and ASB return on assets relative to performance peers. The 2015-2017 LTIP provides for performance awards payable in cash, and thus, is not included in the tables below.

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



	Three months ended March 31
	2015					2014
	Shares			(1)		Shares			(1)
Outstanding, beginning of period	257,956			$	28.45	232,127			$	32.88
Granted (target level)	—			—		96,793			22.95
Vested (issued or unissued and cancelled)	(75,915		)	30.71		(70,189		)	35.46
Forfeited	(13,264		)	26.00		(488		)	32.13
Outstanding, end of period	168,777			$	27.63	258,243			$	28.46
Total weighted-average grant-date fair value of shares granted ($ millions)	$	—				$	2.2


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

The grant date fair values of the shares were determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period.

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:



	2014
Risk-free interest rate	0.66		%
Expected life in years	3
Expected volatility	17.8		%
Range of expected volatility for Peer Group	12.4% to 23.3%
Grant date fair value (per share)	$	22.95

For the three months ended March 31, 2015 and 2014, there were no vested LTIP awards linked to TRS. For the three months ended March 31, 2015, all of the shares vested (which were granted at target level based on the satisfaction of TRS performance) for the 2012-2014 LTIP lapsed.

As of March 31, 2015, there was $1.6 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 1.3 years.

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 March 31
	2015					2014
	Shares			(1)		Shares			(1)
Outstanding, beginning of period	364,731			$	26.01	296,843			$	26.14
Granted (target level)	—			—		128,873			25.19
Vested (issued)	(121,249		)	26.05		(65,089		)	24.95
Forfeited	(13,263		)	25.72		(557		)	26.55
Outstanding, end of period	230,219			$	26.00	360,070			$	26.01
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)	$	—				$	3.2


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

For the three months ended March 31, 2015 and 2014, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $4.7 million and $1.9 million and the related tax benefits were $1.8 million and $0.8 million, respectively.

As of March 31, 2015, there was $2.4 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 1.3 years.

8 · 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 (i.e., restricted shares that became fully vested in the fourth quarter of 2014) and unrestricted common stock:



Three months ended March 31, 2014	Basic and diluted
Distributed earnings	$	0.31
Undistributed earnings	0.14
	$	0.45

As of March 31, 2015, there were no remaining share awards that could have been potentially antidilutive. As of March 31, 2014, the antidilutive effect of SARs on 102,000 shares of HEI common stock (for which the exercise prices were greater than the closing market prices of HEI’s common stock on such dates), was not included in the computation of diluted EPS.

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 the equity forward transactions, HEI was 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 was subject to certain adjustments in accordance with the terms of the equity forward transactions.

The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in Accounting Standards Codification (ASC) Topic 480, “Distinguishing Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging,” and that they qualified for an exception from derivative accounting under ASC Topic 815 because the forward sale transactions were indexed to its own stock. On December 19, 2013 and July 14, 2014, HEI settled 1.3 million and 1.0 million shares under the equity forward for proceeds of $32.1 million (net of the underwriting discount of $1.3 million) and $23.9 million (net of underwriting discount of $1.0 million), respectively, which funds were ultimately used to purchase Hawaiian Electric shares. On March 20, 2015, HEI settled the remaining 4.7 million shares under the equity forward for proceeds of $104.5 million (net of the underwriting discount of $4.7 million), which funds were were used to purchase Hawaiian Electric shares, for the reduction of debt and for general corporate purposes. The proceeds were recorded in equity at the time of settlement. Prior to their settlement, the shares remaining under the equity forward transactions were reflected in HEI’s diluted EPS calculations using the treasury stock method.

Accumulated other comprehensive income. Changes in the balances of each component of accumulated other comprehensive income/(loss) (AOCI) were as follows:



	HEI Consolidated												Hawaiian Electric Consolidated
(in thousands)	Net unrealized gains (losses) on securities			Unrealized losses on derivatives			Retirement benefit plans			AOCI			AOCI -retirement benefit plans
Balance, December 31, 2014	$	462		$	(289	)	$	(27,551	)	$	(27,378	)	$	45
Current period other comprehensive income	3,451			59			548			4,058			22
Balance, March 31, 2015	$	3,913		$	(230	)	$	(27,003	)	$	(23,320	)	$	67

Balance, December 31, 2013	$	(3,663	)	$	(525	)	$	(12,562	)	$	(16,750	)	$	608
Current period other comprehensive income	805			59			303			1,167			9
Balance, March 31, 2014	$	(2,858	)	$	(466	)	$	(12,259	)	$	(15,583	)	$	617

Reclassifications out of AOCI were as follows:



	Amount reclassified from AOCI
	Three months ended March 31
(in thousands)	2015			2014			Affected line item in the Statement of Income
HEI consolidated
Net realized gains on securities	$	3,451		$	(1,715	)	Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	59			59			Interest expense
Retirement benefit plan items
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost	5,459			2,813			See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(4,911		)	(2,510		)	See Note 6 for additional details
Total reclassifications	$	4,058		$	(1,353	)
Hawaiian Electric consolidated
Retirement benefit plan items
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost	$	4,933		$	2,519		See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(4,911		)	(2,510		)	See Note 6 for additional details
Total reclassifications	$	22		$	9

9 · Fair value measurements

Fair value estimates are estimates of 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 and the Utilities use their 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 or the Utilities 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 and the Utilities’ 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 and the Utilities group their 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.

Classification in the hierarchy is based upon the lowest level input that is significant to the fair value measurement of the asset or liability. For instruments classified in Level 1 and 2 where inputs are primarily based upon observable market data, there is less judgment applied in arriving at the fair value. For instruments classified in Level 3, management judgment is more significant due to the lack of observable market data.

Fair value is also used on a nonrecurring basis to evaluate certain assets for impairment or for disclosure purposes. Examples of nonrecurring uses of fair value include mortgage servicing rights accounted for by the amortization method, loan impairments for certain loans, goodwill and AROs. The fair value of Hawaiian Electric’s ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by Hawaiian Electric’s credit spread (also see Note 4).

Fair value measurement and disclosure valuation methodology. Following are descriptions of the valuation methodologies used for assets and liabilities recorded at fair value and for estimating fair value for financial instruments not carried at fair value:

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

Investment securities. The fair value of ASB’s investment securities is determined quarterly through pricing obtained from independent third-party pricing services or from brokers not affiliated with the trade. Non-binding broker quotes are infrequent and generally occur for new securities that are settled close to the month-end pricing date. The third-party pricing vendors the Company uses for pricing its securities are reputable firms that provide pricing services on a global basis and have processes in place to ensure quality and control. The third-party pricing services use a variety of methods to determine the fair value of securities that fall under Level 2 of the Company’s fair value measurement hierarchy. Among the considerations are quoted prices for similar securities in an active market, yield spreads for similar trades, adjustments for liquidity, size, collateral characteristics, historic and generic prepayment speeds, and other observable market factors.

To enhance the robustness of the pricing process, ASB will on a quarterly basis compare its standard third-party vendor’s price with that of another third-party vendor. If the prices are within an acceptable tolerance range, the price of the standard vendor will be accepted. If the variance is beyond the tolerance range, an evaluation will be conducted by ASB and a challenge to the price may be made. Fair value in such cases will be based on the value that best reflects the data and observable characteristics of the security. In all cases, the fair value used will have been independently determined by a third-party pricing vendor or non-affiliated broker and not by ASB.

Loans held for sale. Residential mortgage loans carried at the lower of cost or market are valued using market observable pricing inputs, which are derived from third party loan sales and securitizations and, therefore, are classified within Level 2 of the valuation hierarchy.

Loans held for investment. Fair value of loans held for investment is derived using a discounted cash flow approach which includes an evaluation of the underlying loan characteristics. The valuation model uses loan characteristics which includes product type, maturity dates, and the underlying interest rate of the portfolio. This information is input into the valuation models along with various forecast valuation assumptions including prepayment forecasts, to determine the discount rate. These assumptions are derived from internal and third party sources. Noting the valuation is derived from model-based techniques, ASB includes loans held for investment within Level 3 of the valuation hierarchy.

Impaired loans. At the time a loan is considered impaired, it is valued at the lower of cost or fair value. Fair value is determined primarily by using an income, cost, or market approach and is normally provided through appraisals. Impaired loans carried at fair value generally receive specific allocations within the allowance for loan losses. For collateral-dependent loans, fair value is commonly based on recent real estate appraisals. These appraisals may utilize a single valuation approach or a combination of approaches including comparable sales and the income approach. Adjustments are routinely made in the appraisal process by the independent appraisers to adjust for differences between the comparable sales and income data available. Such adjustments typically result in a Level 3 classification of the inputs for determining fair value. Non-real estate collateral may be valued using an appraisal, net book value per the borrower’s financial statements, or aging reports, adjusted or discounted based on management’s historical knowledge, changes in market conditions from the time of the valuation, and management’s expertise and knowledge of the client and client’s business, resulting in a Level 3 fair value classification. Generally, impaired loans are evaluated quarterly for additional impairment and adjusted accordingly.

Other real estate owned. Foreclosed assets are carried at fair value (less estimated costs to sell) and is generally based upon appraisals or independent market prices that are periodically updated subsequent to classification as real estate owned. Such adjustments typically result in a Level 3 classification of the inputs for determining fair value. ASB estimates the fair value of collateral-dependent loans and real estate owned using the sales comparison approach.

Mortgage servicing rights. Mortgage servicing rights (MSR) are capitalized at fair value based on market data at the time of sale and accounted for in subsequent periods at the lower of amortized cost or fair value. Mortgage servicing rights are evaluated for impairment at each reporting date. ASB's MSR is stratified based on predominant risk characteristics of the underlying loans including loan type and note rate. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment expectations and income and expenses associated with servicing residential mortgage loans for others. Impairment is recognized through a valuation allowance for each stratum when the carrying amount exceeds fair value, with any associated provision recorded as a component of loan servicing fees included in "Other income, net" in the consolidated statements of income. A direct write-down is recorded when the recoverability of the valuation allowance is deemed to be unrecoverable. ASB compares the fair value of MSR to an estimated value calculated by an independent third-party. The third-party relies on both published and unpublished sources of market related assumptions and their own experience and expertise to arrive at a value. ASB uses the third-party value only to assess the reasonableness of its own estimate.

Time deposits. 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 borrowings. For advances and repurchase agreements, fair value is estimated using quantitative discounted cash flow models that require the use of interest rate inputs that are currently offered for advances and repurchase agreements of similar remaining maturities. The majority of market inputs are actively quoted and can be validated through external sources.

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.

Interest rate lock commitments (IRLCs). 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.

Forward sales commitments. To be announced (TBA) mortgage-backed securities 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 using quoted prices in the market place that are observable and are classified as Level 2 measurements.

The following table presents the carrying amount, fair value, and placement in the fair value hierarchy of the Company’s financial instruments. For stock in Federal Home Loan Bank of Seattle, the carrying amount is a reasonable estimate of fair value. For financial liabilities such as noninterest-bearing demand, interest-bearing demand, and savings and money market deposits, the carrying amount is a reasonable estimate of fair value as these liabilities have no stated maturity.



			Estimated fair value
	Carrying amount		Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobservable inputs
(in thousands)	Carrying amount		(Level 1)		(Level 2)		(Level 3)		Total
March 31, 2015
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	590,648		—		590,648		—		590,648
Stock in Federal Home Loan Bank of Seattle	63,711		—		63,711		—		63,711
Loans receivable, net	4,411,410		—		—		4,616,814		4,616,814
Derivative assets	851		—		851		—		851
Financial liabilities
Deposit liabilities	4,751,328		—		4,752,331		—		4,752,331
Short-term borrowings—other than bank	30,500		—		30,500		—		30,500
The Utilities’ short-term borrowings (included in amount above)	30,000		—		30,000		—		30,000
Other bank borrowings	312,094		—		320,329		—		320,329
Long-term debt, net—other than bank	1,506,546		—		1,645,545		—		1,645,545
The Utilities’ long-term debt, net (included in amount above)	1,206,546		—		1,336,267		—		1,336,267
Derivative liabilities	281		249		32		—		281
December 31, 2014
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	550,394		—		550,394		—		550,394
Stock in Federal Home Loan Bank of Seattle	69,302		—		69,302		—		69,302
Loans receivable, net	4,397,457		—		—		4,578,822		4,578,822
Derivative assets	398		—		398		—		398
Financial liabilities
Deposit liabilities	4,623,415		—		4,623,773		—		4,623,773
Short-term borrowings—other than bank	118,972		—		118,972		—		118,972
Other bank borrowings	290,656		—		298,837		—		298,837
Long-term debt, net—other than bank	1,506,546		—		1,622,736		—		1,622,736
The Utilities’ long-term debt, net (included in amount above)	1,206,546		—		1,313,893		—		1,313,893
Derivative liabilities	114		71		43		—		114

As of March 31, 2015 and December 31, 2014, loans serviced by ASB for others had notional amounts of $1.5 billion and $1.4 billion, and the estimated fair value of the mortgage servicing rights for such loans was $14.6 million and $14.5 million, respectively.

Fair value measurements on a recurring basis. Assets and liabilities measured at fair value on a recurring basis were as follows:



	March 31, 2015						December 31, 2014
	Fair value measurements using						Fair value measurements using
(in thousands)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Money market funds (“other” segment)	$	—	$	10	$	—	$	—	$	10	$	—
Available-for-sale investment securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	450,421	$	—	$	—	$	430,834	$	—
U.S. Treasury and federal agency obligations	—		140,227		—		—		119,560		—
	$	—	$	590,648	$	—	$	—	$	550,394	$	—
Derivative assets ¹
Interest rate lock commitments	$	—	$	836	$	—	$	—	$	393	$	—
Forward commitments	—		15		—		—		5		—
	$	—	$	851	$	—	$	—	$	398	$	—
Derivative liabilities ¹
Interest rate lock commitments	$	—	$	1	$	—	$	—	$	3	$	—
Forward commitments	249		31		—		71		40		—
	$	249	$	32	$	—	$	71	$	43	$	—

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.

There were no transfers of financial assets and liabilities between Level 1 and Level 2 of the fair value hierarchy during the quarter ended March 31, 2015.

Fair value measurements on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis and therefore are not included in the tables above. These measurements primarily result from assets carried at the lower of cost or fair value or from impairment of individual assets. Assets measured at fair value on a nonrecurring basis were as follows:



			Fair value measurements
(in thousands)	Balance		Level 1		Level 2		Level 3
March 31, 2015
Loans	$	2,494	$	—	$	—	$	2,494
Real estate acquired in settlement of loans	665		—		—		665
December 31, 2014
Loans	2,445		—		—		2,445
Real estate acquired in settlement of loans	288		—		—		288

At March 31, 2015 and 2014, there were no adjustments to fair value for ASB’s loans held for sale.

The following table presents quantitative information about Level 3 fair value measurements for financial instruments measured at fair value on a nonrecurring basis:



					Significant unobservable input value ¹
($ in thousands)	Fair value		Valuation technique	Significant unobservable input	Range	Weighted Average
March 31, 2015
Residential loans	$	2,377	Fair value of property or collateral	Appraised value less 7% selling costs	39-99%	78%
Home equity lines of credit	3		Fair value of property or collateral	Appraised value less 7% selling costs		7%
Commercial loans	114		Fair value of property or collateral	Fair value of business assets		88%
Total loans	$	2,494
Real estate acquired in settlement of loans	$	665	Fair value of property or collateral	Appraised value less 7% selling costs	100%	100%
December 31, 2014
Residential loans	$	2,297	Fair value of property or collateral	Appraised value less 7% selling costs	39-99%	83%
Home equity lines of credit	3		Fair value of property or collateral	Appraised value less 7% selling costs		7%
Commercial loans	145		Fair value of property or collateral	Fair value of business assets		91%
Total loans	$	2,445
Real estate acquired in settlement of loans	$	288	Fair value of property or collateral	Appraised value less 7% selling cost	100%	100%

¹ Represent percent of outstanding principal balance.

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

10 · Cash flows



Three months ended March 31	2015		2014
(in millions)
Supplemental disclosures of cash flow information
HEI consolidated
Interest paid to non-affiliates	$	21	$	20
Income taxes paid	1		1
Income taxes refunded	47		19
Hawaiian Electric consolidated
Interest paid to non-affiliates	13		13
Income taxes refunded	6		8
Supplemental disclosures of noncash activities
HEI consolidated
Increases in common stock related to director and officer compensatory plans	2		1
Real estate acquired in settlement of loans	—		1
Real estate transferred from property, plant and equipment to other assets held-for-sale	5		—
Obligations to fund low income housing investments	—		10
HEI consolidated and Hawaiian Electric consolidated
Additions to electric utility property, plant and equipment - unpaid invoices and other	24		9

11 · Recent accounting pronouncements

Investments in Qualified Affordable Housing Projects. In January 2014, the FASB issued ASU No. 2014-01, “Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which permits entities to make an accounting policy election to account for their investments in qualified affordable housing projects using the proportional amortization method if certain conditions are met and investment amortization, net of tax credits, may be recognized in the income statement as a component of income taxes attributable to continuing operations. The amendments also require additional disclosures.

The Company retrospectively adopted ASU No. 2014-01 in the first quarter of 2015. For prior periods, pursuant to ASU No. 2014-01, (a) amortization expense related to ASB’s qualifying investments in low income housing tax credits was reclassified from noninterest expense to income taxes; and (b) additional amortization, net of associated tax benefits was recognized in income taxes as a result of the adoption. The cumulative effect to retained earnings as of January 1, 2014 of adopting this guidance was a reduction of $0.7 million. Amounts in the financial statements as of December 31, 2014 and 2013 and for the three months ended March 31, 2014, have been updated to reflect the retrospective application.

For the quarter ended March 31, 2015, ASB recognized $1.3 million of amortization, $1.4 million of tax credits and $0.5 million of other tax benefits associated with the low income housing tax credits within income taxes.

The table below summarizes the impact to prior period financial statements of the adoption of ASU No. 2014-01:



	HEI Consolidated							ASB
(in thousands)	As previously filed		Adjustment from adoption of ASU No. 2014-01			As currently reported		As previously filed		Adjustment from adoption of ASU No. 2014-01			As currently reported
(in thousands)	As previously filed		Adjustment from adoption of ASU No. 2014-01			As currently reported		As previously filed		Adjustment from adoption of ASU No. 2014-01			As currently reported
HEI Consolidated Income Statement/ASB Statement of Income Data
Three months ended March 31, 2014
Bank expenses/Noninterest expense	$	41,996	$	(908	)	$	41,088	$	38,370	$	(908	)	$	37,462
Bank operating income/Income before income taxes	$	21,623	$	908		$	22,531	$	21,624	$	908		$	22,532
Income taxes	$	24,673	$	1,048		$	25,721	$	7,085	$	1,048		$	8,133
Net income for common stock/Net income	$	45,927	$	(140	)	$	45,787	$	14,539	$	(140	)	$	14,399
HEI Consolidated Balance Sheet/ASB Balance Sheet Data
December 31, 2014
Other assets	$	541,542	$	981		$	542,523	$	304,435	$	981		$	305,416
Total assets and Total liabilities and shareholders’ equity	$	11,184,161	$	981		$	11,185,142	$	5,565,241	$	981		$	5,566,222
Deferred income taxes/Other liabilities	$	631,734	$	1,836		$	633,570	$	116,527	$	1,836		$	118,363
Total liabilities	$	9,358,440	$	1,836		$	9,360,276	$	5,030,598	$	1,836		$	5,032,434
Retained earnings	$	297,509	$	(855	)	$	296,654	$	212,789	$	(855	)	$	211,934
Total shareholders’ equity	$	1,791,428	$	(855	)	$	1,790,573	$	534,643	$	(855	)	$	533,788
HEI Consolidated Statement of Changes in Stockholders’ Equity
December 31, 2013
Retained earnings	$	255,694	$	(664	)	$	255,030
Total shareholders’ equity	$	1,727,070	$	(664	)	$	1,726,406

Reclassification of loans upon foreclosure. In January 2014, the FASB issued ASU No. 2014-04, “Receivables-Troubled Debt Restructurings by Creditors (Subtopic 310-40): Reclassification of Residential Real Estate Collateralized Consumer Mortgage Loans upon Foreclosure,” which clarifies when an in substance repossession or foreclosure occurs, and a creditor is considered to have received physical possession of residential real estate property collateralizing a consumer loan. A creditor is considered to have received physical possession of residential real estate property collateralizing a consumer loan upon either: (1) the creditor obtaining legal title to the residential real estate property upon completion of a foreclosure; or (2) the borrower

conveying all interest in the residential real estate property to the creditor to satisfy that loan through a deed in lieu of foreclosure or through a similar legal agreement. The amendment also requires additional disclosures.

The Company adopted ASU No. 2014-04 in the first quarter of 2015 and the adoption did not have a material impact on the Company’s results of operations, financial condition or liquidity.

Revenues from contracts. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers: (Topic 606).” The core principle of the guidance in ASU No. 2014-09 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve that core principle, an entity should apply the following steps: (1) identify the contract/s with a customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when, or as, the entity satisfies a performance obligation.

The Company plans to adopt ASU No. 2014-09 in the first quarter of 2017, but has not determined the method of adoption (full or modified retrospective application) nor the impact of adoption on its results of operations, financial condition or liquidity.

Repurchase agreements. In June 2014, the FASB issued ASU No. 2014-11, “Transfers and Servicing (Topic 860): Repurchase-to-Maturity Transactions, Repurchase Financings, and Disclosure,” which changes the accounting for repurchase-to-maturity transactions and repurchase financing arrangements. It also requires additional disclosures about repurchase agreements and other similar transactions. The ASU requires a new disclosure for transactions economically similar to repurchase agreements in which the transferor retains substantially all of the exposure to the economic return on the transferred financial assets throughout the term of the transaction. The ASU also requires expanded disclosures about the nature of collateral pledged in repurchase agreements and similar transactions accounted for as secured borrowings.

The Company adopted ASU No. 2014-11 in the first quarter of 2015 and the adoption did not have a material impact on the Company’s results of operations, financial condition or liquidity.

Debt issuance costs. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.

The Company plans to retrospectively adopt ASU No. 2015-03 in the first quarter 2016 and does not expect the adoption to have a material impact on the Company’s results of operations, financial condition or liquidity.

12 · Credit agreements and long-term debt

Credit agreements.

HEI. On April 2, 2014, HEI and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (HEI Facility). The HEI Facility increased HEI’s line of credit to $150 million from $125 million, extended the term of the facility to April 2, 2019, and provided improved pricing compared to HEI’s prior facility. Under the HEI Facility, draws would generally bear interest, based on HEI’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points. The HEI Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the HEI Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. In addition, the HEI Consolidated Net Worth covenant, as defined in the original facility, was removed from the HEI Facility, leaving only one financial covenant (relating to HEI’s ratio of funded debt to total capitalization, each on a non-consolidated basis). Under the credit 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 14% as of March 31, 2015, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. The HEI Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with 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).

The 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.

Hawaiian Electric. On April 2, 2014, Hawaiian Electric and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (Hawaiian Electric Facility). The Hawaiian Electric Facility increased Hawaiian Electric’s line of credit to $200 million from $175 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. The Hawaiian Electric Facility provided improved pricing compared to its prior facility. Under the Hawaiian Electric Facility, draws would generally bear interest, based on Hawaiian Electric’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 125 basis points and annual fees on undrawn commitments of 17.5 basis points. The Hawaiian Electric Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the Hawaiian Electric Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. The Hawaiian Electric Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which 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, Hawaiian Electric, 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 41% for Hawaii Electric Light and 42% for Maui Electric as of March 31, 2015, as calculated under the agreement)). In addition to customary defaults, Hawaiian Electric’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 Hawaiian Electric fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 57% as of March 31, 2015, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI. Under the proposed Merger Agreement, Hawaiian Electric will become a wholly-owned subsidiary of NextEra. The terms of the Hawaiian Electric Facility are such that the proposed Merger would constitute a “Change in Control.” Hawaiian Electric has requested, and the financial institutions providing the Hawaiian Electric Facility have consented and agreed, that the proposed Merger shall not constitute a “Change in Control,” as defined in the credit agreement, provided that (i) the Merger is consummated and (ii) Hawaiian Electric becomes and remains a wholly-owned subsidiary of NextEra.

The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay Hawaiian Electric’s short-term indebtedness, to make loans to subsidiaries and for Hawaiian Electric’s capital expenditures, working capital and general corporate purposes.

Changes in long-term debt.

May 2014 loan. On May 2, 2014, HEI entered into a loan agreement with The Bank of Tokyo-Mitsubishi UFJ, Ltd., Royal Bank of Canada and U.S. Bank, National Association, which agreement includes substantially the same financial covenant and customary conditions as the HEI credit agreement described above. On May 2, 2014, HEI drew a $125 million Eurodollar term loan for a term of two years and at a resetting interest rate ranging from 1.12% to 1.15% through March 31, 2015. The proceeds from the term loan were used to pay off $100 million of 6.51% medium term notes at maturity on May 5, 2014, pay down maturing commercial paper and for general corporate purposes.

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 Hawaiian Electric’s 2014 Form 10-K and should be read in conjunction with such discussion and the 2014 annual consolidated financial statements of HEI and Hawaiian Electric and notes thereto included in HEI’s and Hawaiian Electric’s 2014 Form 10-K, as well as the quarterly (as of and for the three months ended March 31, 2015) financial statements and notes thereto included in this Form 10-Q.

HEI consolidated

RESULTS OF OPERATIONS



(in thousands, except per	Three months ended March 31				%
share amounts)	2015		2014		change		Primary reason(s)*
Revenues	$	637,862	$	783,749	(19	)	Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income	69,506		89,214		(22	)	Decrease for the electric utility and the bank segments and higher losses for the “other” segment
Net income for common stock	31,866		45,787		(30	)	Lower net income for the electric utility and the bank segments and higher net loss for the “other” segment
Basic earnings per common share	$	0.31	$	0.45	(31	)	Lower net income and the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding	103,281		101,382		2		Issuances of shares under the equity forward transaction, 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 income tax rates) for the first three months of 2015 and 2014 were 38% and 36%, respectively. The effective tax rate was higher for the three months ended March 31, 2015 compared to the same period in 2014 due primarily to nondeductible merger-related expenses and the adoption of ASU No. 2014-01, which changed the presentation of the benefits of low income housing credits.

HEI’s consolidated ROACE was 8.5% for the twelve months ended March 31, 2015 and 10.4% for the twelve months ended March 31, 2014.

Dividends. The payout ratios for the first three months of 2015 and full year 2014 were 100% and 75%, 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. See Note 2 of the Consolidated Financial Statements for a discussion of a special dividend of $0.50 per share contemplated in the Merger Agreement.

Economic conditions.

Note: The statistical data in this section is from public third-party sources that management believes to be reliable (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization; U.S. Bureau of Labor Statistics; Department of Labor and Industrial Relations (DLIR); Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS® and national and local newspapers).

Hawaii’s tourism industry, a significant driver of Hawaii’s economy, ended the first two months of 2015 with lower visitor expenditures and relatively flat arrivals as compared to the same period a year ago. Visitor expenditures decreased 3.3% and arrivals increased 0.8% compared to the first two months of 2014. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the second quarter of 2015 to increase by 9.0% over the second quarter of 2014 driven by an expected 13.3% increase in domestic seats.

Hawaii’s unemployment rate was relatively stable at 4.1% in March 2015, lower than the state’s 4.6% rate in March 2014 and the March 2015 national unemployment rate of 5.5%.

Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices in the first quarter of 2015. Median sales prices for single family residential homes and condominiums on Oahu increased 3.2% and 5.4%, respectively, over the first quarter of 2014. However, the number of closed sales was down slightly in the first quarter of 2015.

Closed sales for single family residential homes were down 4.0% and condominiums were down 1.4% compared to the first quarter of 2014.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. In 2014, prices of all petroleum fuels plateaued during the first three quarters of the year before falling strongly over the course of 2014’s final quarter and continued to trend downward through the first quarter of 2015.

At its April 2015 meeting, the Federal Open Market Committee (FOMC) held the federal funds rate target at 0% to 0.25% and does not anticipate raising the target range until it has seen further improvement in the labor market and is reasonably confident that inflation will move back to 2% over the medium term.

Overall, Hawaii is expected to see a continuation of 2014’s moderate expansion. Tourism gains will be marginal, with most of the growth coming from the neighbor islands. Construction remains mixed, but activity is expected to ramp up in 2015 as planned and permitted Kakaako condominium building intensifies. The biggest risk to local economic growth continues to be the possibility of a substantial cut in active duty military in Hawaii.

Recent tax developments. The Tax Increase Prevention Act of 2014 provided an extension of 50% bonus depreciation through December 31, 2014, increasing the Company's 2014 federal tax depreciation by an estimated $162 million, primarily attributable to the Utilities. Previously, the American Taxpayer Relief Act of 2012 provided 50% bonus depreciation through December 31, 2013, resulting in an increase in 2013 federal tax depreciation of $160 million, primarily attributable to the Utilities. Under current tax law, there is no provision for bonus depreciation in 2015 and future years.

Also, see “Recent tax developments” in Note 4 and Hawaiian Electric’s consolidated income taxes refunded in Note 10 of the Consolidated Financial Statements.

Retirement benefits. For the first three months of 2015, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a return, net of investment management fees, of 2.5%. The market value of these assets as of March 31, 2015 and December 31, 2014 was $1.5 billion (including $1.3 billion for the Utilities) and $1.4 billion (including $1.3 billion for the Utilities), respectively.

The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2015 will be $86 million ($84 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 OPEB tracking mechanisms and the plans’ funding policies.

Commitments and contingencies. See Note 4, “Electric utility segment” and Note 5, “Bank segment,” of the Consolidated Financial Statements.

Recent accounting pronouncements. See Note 11, “Recent accounting pronouncements,” of the Consolidated Financial Statements.

“Other” segment.



	Three months ended March 31
(in thousands)	2015			2014			Primary reason(s)
Revenues	$	72		$	68
Operating loss	(8,761		)	(3,983		)	Higher administrative and general expenses, primarily due to higher merger-related expenses ($4.4 milllion), and charitable foundation contribution
Net loss	(8,483		)	(4,032		)	Higher operating loss and lower tax benefits (partly due to non-deductibility of certain merger-related expenses), partly offset by lower interest expense

The “other” business segment includes results of the stand-alone corporate operations of HEI and ASB Hawaii, Inc. (ASBH), 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.

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)	March 31, 2015				December 31, 2014
Short-term borrowings—other than bank	$	30	1	%	$	119	3	%
Long-term debt, net—other than bank	1,507		43		1,507		44
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,898		55		1,791		52
	$	3,469	100	%	$	3,451	100	%

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



	Average balance		Balance
(in millions)	Three months ended March 31, 2015		March 31, 2015		December 31, 2014
Short-term borrowings ¹
Commercial paper	$	102	$	1	$	119
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility			150		150

¹ This table does not include Hawaiian Electric’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 three months of 2015 was $134 million. At April 30, 2015, HEI had no commercial paper outstanding and its line of credit facility was undrawn.

HEI has a line of credit facility, as amended and restated on April 2, 2014, of $150 million. See Note 12 of the Consolidated Financial Statements.

The Company raised $3 million through the issuance of approximately 0.1 million shares of common stock under the DRIP, the HEIRSP and ASB 401(k) Plan from January 1 through March 5, 2014. As of March 6, 2014, HEI began satisfying the share purchase requirements of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances.

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. See Note 8 of the Consolidated Financial Statements. In March 2015, HEI issued 4.7 million shares under the equity forward for proceeds of $104.5 million.

On May 2, 2014, HEI closed a two-year term loan from three banks for $125 million. See Note 12 of the Consolidated Financial Statements for a brief description of the loan agreement and the application of the proceeds of the loan.

In December 2014, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities.

For the first three months of 2015, net cash provided by operating activities of HEI consolidated was $77 million. Net cash used by investing activities for the same period was $88 million, due to Hawaiian Electric’s consolidated capital expenditures, purchases of ASB’s investment securities, a net increase in ASB’s loans held for investment, partly offset by ASB’s repayments of investment securities and redemption of stock from the FHLB of Seattle, and Hawaiian Electric’s contributions in aid of construction. Net cash provided by financing activities during this period was $128 million as a result of several factors, including proceeds from the issuance of shares under the equity forward, net increases in ASB’s deposit liabilities and retail repurchase agreements, partly offset by net decreases in short-term borrowings and the payment of common stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), Hawaiian Electric’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 three months of 2015, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $23 million and $8 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 47 to 48, 62 to 64, and 74 to 76 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2014 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 48 to 49, 64 to 65, and 76 to 79 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2014 Form 10-K.

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. The Utilities continue 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 last few years, including a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below).

On August 26, 2014, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed proposed plans for Hawaii’s energy future with the PUC, as required by PUC orders issued in April 2014. The plans filed were the Hawaiian Electric Power Supply Improvement Plan, Maui Electric Power Supply Improvement Plan, Hawaii Electric Light Power Supply Improvement Plan, Hawaiian Electric Companies Distributed Generation Interconnection Plan, and Hawaiian Electric Companies Integrated Interconnection Queue Plan. Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), and switch from high-priced oil to lower cost liquefied natural gas.

Transition to renewable energy. The Utilities are committed to assisting the State of Hawaii in achieving or exceeding its 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 (LNG) 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. In December 2013, the Utilities executed a non-binding memorandum of understanding with The Gas Company, LLC d/b/a HawaiiGAS, documenting the parties’ desire to work together to (a) develop and/or secure infrastructure for large scale importation of LNG into Hawaii and (b) establish a consortium to competitively procure the LNG and provide storage and regasification of it at an LNG terminal site. In March 2014, Hawaiian Electric issued a RFP for the supply of containerized LNG. Hawaiian Electric received 3 final bid submissions in May 2014 and is in the final stage of selecting an LNG supplier. Also, see "Liquefied natural gas" in Note 4 of the Consolidated Financial Statements for a description of Hawaiian Electric's agreement with Fortis BC Energy Inc.

After launching a smart grid customer engagement plan during the second quarter of 2014. Hawaiian Electric replaced approximately 5,200 residential and commercial meters with smart meters, 160 direct load control switches, fault circuit indicators and remote controlled switches in selected areas across Oahu as part of the Smart Grid Initial Phase implementation. Also under the Initial Phase a grid efficiency measure called Volt/Var Optimization (or Conservation Voltage

Reduction) was turned on, customer energy portals were launched and are available for customer use and a PrePay Application was launched. The Initial Phase implementation will be completed by the end of 2015. The smart grid provides benefits such as customer tools to manage their electric bills, potentially shortening outages and enabling the Utilities to integrate more low-cost renewable energy, like wind and solar, which will reduce Hawaii’s dependence on imported oil. The Utilities are planning to seek approval from the PUC in 2015 to commit funds for an expansion of the smart grid project, including at Hawaii Electric Light and Maui Electric.

Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by the Utilities in 2011 and 2012. The decoupling model implemented delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes. On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. On March 31, 2015, the PUC issued an Order to make certain modifications to the decoupling mechanism. See "Decoupling" in Note 4 of the Consolidated Financial Statements for a discussion on changes to the RAM mechanism. Under decoupling, as modified by the PUC, the most significant drivers for improving earnings are:

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

•managing O&M expense and capital additions relative to authorized RAM adjustments; and

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

Actual and PUC-allowed (as of March 31, 2015) returns were as follows:



%	Return on rate base (RORB)*					ROACE**						Rate-making ROACE***
Twelve months ended March 31, 2015	Hawaiian Electric		Hawaii Electric Light		Maui Electric	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric
Utility returns	7.23		6.00		7.52	8.03		6.18		8.87		8.94		6.28		9.48
PUC-allowed returns	8.11		8.31		7.34	10.00		10.00		9.00		10.00		10.00		9.00
Difference	(0.88	)	(2.31	)	0.18	(1.97	)	(3.82	)	(0.13	)	(1.06	)	(3.72	)	0.48

* 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 incentive compensation and certain 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 actually achieved due to the following:

•the timing of general rate case decisions,


•	the effective date of June 1 (rather than January 1) for the RAMs for Hawaii Electric Light and Maui Electric currently, and for Hawaiian Electric beginning in 2017,

•plant additions not recoverable through the RAM or other mechanism outside of the RAM cap,

the modifications to the rate base RAM and RBA interest rate per the PUC's February 2014 decision on decoupling (as discussed in Note 4 of the Consolidated Financial Statements), and

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

The structural gap in 2015 to 2017 is expected to be 100 to 120 basis points. Factors which impact the range of the structural gap include the actual sales impacting the size of the RBA regulatory asset, the actual level of plant additions in any given year relative to the amount recoverable under the RAM cap, and the timing, nature, and size of any general rate case. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the Utilities. Items not likely to be covered by the annual RAMs include the changes in rate base for the regulatory asset for pension contributions in excess of the pension amount in rates, investments in software projects, changes in fuel inventory and O&M and capital additions in excess of indexed escalations. The specific magnitude of the impact will depend on various factors, including changes in the required annual pension contribution, the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.

As part of decoupling, the Utilities also track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. At year-end, each utility's rate-making ROACE is compared against its ROACE allowed by the PUC to determine whether earnings sharing has been triggered. Annual earnings of a utility over and above the ROACE allowed by the PUC are shared between the utility and its ratepayers on a tiered basis. For 2014, the earnings sharing mechanism was triggered for Maui Electric, and Maui Electric will credit $0.5 million to its

customers for their portion of the earnings sharing. Earnings sharing credits are included in the annual decoupling filing for the following year.

Annual decoupling filings. See “Decoupling” in Note 4 of the Consolidated Financial Statements for a discussion of the 2015 annual decoupling filings.

Results.



Three months ended March 31				Increase
2015		2014		(decrease)						(dollars in millions, except per barrel amounts)
$	573	$	720	$	(147	)				Revenues. Decrease largely due to:
							$	(95	)	lower fuel prices
							(35		)	lower purchased power costs
							(28		)	lower KWH generated
177		286		(109		)				Fuel oil expense. Decrease largely due to lower fuel cost and lower KWH generated
136		165		(29		)				Purchased power expense. Decrease due to lower purchased power energy prices partially offset by higher KWH purchased
104		89		15						Operation and maintenance expenses. Increase due to:
							5			higher transmission, distribution and generation maintenance costs
							2			higher overhaul costs in the first quarter of 2015 compared to the prior year quarter that included no major overhauls
							2			higher bad debt reserves for one customer account
							1			higher consulting costs for our energy transformation plans
							1			accrued costs for damage to combined heat and power generating unit
							1			higher employee benefit costs
99		110		(11		)				Other expenses. Decrease in revenue taxes due to lower revenues offset by higher depreciation expense for plant investments
58		71		(13		)				Operating income. Decrease due to an increase in operation and maintenance expenses
27		35		(8		)				Net income for common stock. Decrease due to lower operating income

2,044		2,126		(82		)				Kilowatthour sales (millions)
66.5		67.1		(0.6		)				Wet-bulb temperature (Oahu average; degrees Fahrenheit)
795		828		(33		)				Cooling degree days (Oahu)
$	86.60	$	131.15	$	(44.55	)				Average fuel oil cost per barrel
456,171		452,626		3,545						Customer accounts (end of period)

Note: The electric utilities had effective tax rates for the first three months of 2015 and 2014 of 37% and 37%, respectively.

Hawaiian Electric’s consolidated ROACE was 7.8% for the twelve months ended March 31, 2015 and 8.7% for the twelve months ended March 31, 2014.

The Utilities’ consolidated kilowatthour (KWH) sales have declined each year since 2007. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the Utilities’ 2015 KWH sales are expected to further decline below 2014 levels.

Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2015 are projected to increase 2% as compared to 2014 as the Utilities execute on strategies which are not currently recovered in rates such as the costs associated with the clean energy transformation.

The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of March 31, 2015 amounted to $3.9 billion, of which approximately 27% related to production PPE, 64% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 3% of the total net book value relates to generation PPE that has been deactivated or that the Utilities plan to deactivate or decommission. See “Adequacy of supply” below.

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

Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility is currently required by PUC order to initiate a rate proceeding every third year (on a staggered basis) to allow the PUC and the Consumer Advocate to regularly evaluate decoupling and to allow 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.

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, and the details of any granted interim and final PUC D&O increases.



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
Hawaiian Electric
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
2014 (2)	6/27/14
Hawaii Electric Light
2010 (3)
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 (4)
Request	8/16/12	$	19.8	4.2	10.25	8.30	$	455	57.05
Closed	3/27/13
Maui Electric
2012 (5)
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
2015 (6)	12/30/14

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) Hawaiian Electric filed a request with the PUC for a general rate increase of $113.5 million, based on depreciation rates and methodology as proposed by Hawaiian Electric in a separate depreciation proceeding. Hawaiian Electric’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) See “Hawaiian Electric 2014 test year rate case” below.

(3)

Hawaii Electric Light’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, Hawaii Electric Light 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. Hawaii Electric Light implemented

the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. Hawaii Electric Light 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.

(4) Hawaii Electric Light’s request was 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 Order (described below), the rate case was withdrawn and the docket has been closed.

(5) Maui Electric’s request was 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 4 of the Consolidated Financial Statements.


(6)	See “Maui Electric 2015 test year rate case” below.

Hawaiian Electric 2011 test year rate case. In the Hawaiian Electric 2011 test year rate case, the PUC had granted Hawaiian Electric’s request to defer Customer Information System (CIS) project 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 Hawaiian Electric to accrue AFUDC on these deferred costs until the completion of the regulatory audit.

On January 28, 2013, the Utilities 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 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 Hawaii Electric Light 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 Hawaiian Electric 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, Hawaiian Electric will be allowed to record RAM revenues starting on January 1 (instead of the prior start date of June 1) for the years 2014, 2015 and 2016. This resulted in additional revenues of $5 million and $7 million for the first quarters of 2015 and 2014, respectively.

Hawaiian Electric 2014 test year rate case. On October 30, 2013 Hawaiian Electric filed with the PUC a Notice of Intent to file an application for a general rate case (on or after January 2, 2014, but before June 30, 2014, using a 2014 test year) and a motion, which was subsequently recommended by the Consumer Advocate, for approval of test period waiver. Hawaiian Electric’s filing of a 2014 rate case would be in accordance with a PUC order which calls for a mandatory triennial rate case cycle. On March 7, 2014, the PUC issued an order granting Hawaiian Electric’s motion to waive the requirement to utilize a split test year, and authorized a 2014 test year.

On June 27, 2014, Hawaiian Electric submitted an abbreviated rate case filing (abbreviated filing), stating that it intends to forego the opportunity to seek a general rate increase in base rates, and if approved, this filing would result in no change in base rates. Hawaiian Electric stated that it is foregoing a rate increase request in recognition that its customers are already in a challenging high electricity bill environment. The abbreviated filing explained that Hawaiian Electric is aggressively attacking the root causes of high rates, by, among other things, vigorously pursuing the opportunity to switch from oil to liquefied natural gas, acquiring lower-cost renewable energy resources, pursuing opportunities to achieve operational efficiencies, and deactivating older, high-cost generation. Instead of seeking a rate increase, Hawaiian Electric is focused on developing and executing the new business model, plans and strategies required by the PUC’s April 2014 regulatory orders discussed in Note 4 of the Consolidated Financial Statements, as well as other actions that will reduce rates.

Hawaiian Electric further explained that the abbreviated filing satisfies the obligation to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O. If the PUC determines that additional materials are required, Hawaiian Electric stated it will work with the Consumer Advocate on a schedule to submit additional information as needed. Hawaiian Electric asked for an expedited decision on this filing and stated that if the PUC decides that such a ruling is not in order, Hawaiian Electric reserves the right to supplement the abbreviated filing with additional material to support the increase in revenue requirements forgone by this filing—calculated to be $56 million over revenues at current effective rates. Hawaiian Electric’s revenue at current effective rates includes: (1) the revenue from Hawaiian Electric’s base rates, including the revenue from the energy cost adjustment clause and the purchased power adjustment clause, (2) the revenue that would be included in the decoupling RBA in 2014 based on 2014 test year forecasted sales, and (3) the revenue from the 2014 RAM implemented in connection with the decoupling mechanism.

Under Hawaiian Electric’s proposal, the decoupling RBA and RAM would continue, subject to any change to these mechanisms ordered by the PUC in Schedule B of the decoupling proceedings, the DSM surcharge would continue since demand response (DR) program costs would not be rolled into base rates (as required in the April 28, 2014 DR Order) until the next rate case, and the pension and OPEB tracking mechanisms would continue. Hawaiian Electric plans to file its next rate case according to the normal rate case cycle using a 2017 test year. If circumstances change, Hawaiian Electric may file its

next rate case earlier.

Management cannot predict whether the PUC will accept this abbreviated filing to satisfy Hawaiian Electric’s obligation to file a rate case in 2014, whether additional material will be required or whether Hawaiian Electric will be required to proceed with a traditional rate proceeding.

Maui Electric 2015 test year rate case. On October 17, 2014, Maui Electric filed its notice of intent to file a general rate case application by the end of 2014, utilizing a 2015 calendar test year. The rate case filing is required to satisfy the obligation to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O. On December 30, 2014, Maui Electric filed its abbreviated 2015 test year rate case filing. In recognition that its customers have been enduring a high bill environment, Maui Electric proposed no change to its base rates, thereby foregoing the opportunity to seek a general rate increase. If Maui Electric were to seek an increase in base rates, its requested increase in revenue, based on its revenue requirement for a normalized 2015 test year, would have been $11.6 million, or 2.8%, over revenues at current effective rates with estimated 2015 RAM revenues. The normalized 2015 test year revenue requirement is based on an estimated cost of common equity of 10.75%. Management cannot predict any actions by the PUC as a result of this filing.

Integrated resource planning and April 2014 regulatory orders. See “April 2014 regulatory orders” in Note 4 to the Consolidated Financial Statements.

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. The Utilities 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 2014, the Utilities achieved an RPS without DSM energy savings of an estimated 21%, primarily through a comprehensive portfolio of renewable energy PPAs, net energy metering programs and biofuels. The Utilities have been successful in adding significant amounts of renewable energy resources to their electric systems. The Utilities are on track to exceed their 2015 RPS goal, and lead the nation in terms of the amount of photovoltaic (PV) systems installed by its customers.

As more generating resources, whether utility scale or distributed generation, are added to the Utilities’ electric systems and as customers reduce their energy usage, the ability to accommodate additional generating resources and to accept energy from existing resources is becoming more challenging. As a result, there is a growing risk that energy production from generating resources may need to be curtailed and the interconnection of additional resources will need to be closely evaluated. Also, under the state’s renewable energy strategy, there has been exponential growth in recent years in variable generation (e.g. solar and wind) on Hawaii’s island grids. Much of this variable generation is in the form of distributed generators interconnected at distribution circuits that cannot be directly controlled by system operators. As a consequence, grid resiliency in response to events that cause significant frequency and/or voltage excursions has weakened, and the prospects for larger and more frequent service outages have increased. The Utilities have been progressively making changes in their operating practices, are making investments in grid modernization technologies, and are working with the solar industry to mitigate these risks and continue the integration of more renewable energy.

Developments in the Utilities’ efforts to implement their renewable energy strategy include the following:

•

In July 2011, the PUC directed Hawaiian Electric 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, Hawaiian Electric filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200-MW RFP. First, it issued an order that Hawaiian Electric 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 project developer retained an equivalent ability to develop the project as when it submitted its bid in 2008 and its term sheet in 2011. Third, the PUC 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 approved Hawaiian Electric’s 3-year biodiesel supply contract with Renewable Energy Group for continued biodiesel supply to CIP CT-1 of 3 million to 7 million gallons per year.


•	In May 2012, Maui Electric 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, Hawaiian Electric 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, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, 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. Bids were received in January 2015, and in February 2015, Ormat Technologies, Inc. was selected to provide 25 MW of additional geothermal energy, subject to successful contract negotiations and PUC approval of the final agreement.

•

In August 2012, the battery facility at a 30-MW Kahuku wind farm experienced a fire. After the interconnection infrastructure was rebuilt and voltage regulation equipment was installed, the facility came up to full output in January 2014 to perform control system acceptance testing, and energy is being purchased at a base rate until PUC approval of an amendment to the PPA. An application for PUC approval of an amendment to the PPA was filed in April 2014.

•

In August 2012, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric 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. In May 2014, Hawaiian Electric filed an application with the PUC to allow expenditures of $170 million for execution of the project, which is expected to be placed in service by the end of 2017.


•	In September 2012, Hawaiian Electric 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 beginning in 2013.


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


•	In December 2012, the 5-MW Kalaeloa Solar Two, LLC PV facility was placed into commercial operation, selling power to Hawaiian Electric under a 20-year contract.

•

In February 2013, Hawaiian Electric issued an “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding,” which 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 Hawaiian Electric obtained waivers from the PUC Competitive Bidding Framework for certain projects, subject to certain conditions. In the fourth quarter of 2014, Hawaiian Electric filed applications requesting PUC approval of power purchase agreements for renewable as-available energy for seven projects that were granted waivers from the Competitive Bidding Framework.

•

In May 2013, Maui Electric requested a waiver from the PUC Competitive Bidding Framework to conduct negotiations for a PPA for approximately 4.5 to 6.0 MW of firm power from a proposed Mahinahina Energy Park, LLC project, fueled with biofuel. The PUC approved the waiver request, provided that an executed PPA must be filed for PUC approval by February 2015. The parties did not execute a PPA by the PUC deadline, but continue to negotiate.


•	In October 2013, Hawaiian Electric requested approval from the PUC for a waiver from the competitive bidding process and to commit $42.4 million for the purchase and installation of a 15-MW utility-scale PV generation system at its Kahe Power generation station property. In November 2014, the PUC denied the request for a waiver from the competitive bidding process.


•	In October 2013, the PUC approved Hawaiian Electric’s 20-year contract with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant to begin within five years of November 25, 2013.


•	In November 2013, the 5-MW Kalaeloa Renewable Energy Park, LLC PV facility was placed into commercial operation selling power to Hawaiian Electric under a 20-year contract.

•

In December 2013, Hawaiian Electric requested PUC approval for a waiver of the Na Pua Makani Power Partners, LLC’s proposed 24-MW wind farm located in the Kahuku area on Oahu from the competitive bidding process and of the PPA for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and Na Pua Makani Power Partners, LLC for the proposed 24-MW wind farm. In December 2014, the PUC approved both the waiver request and the PPA.


•	In April 2014, Hawaiian Electric requested PUC approval of a PPA for Renewable As-Available Energy with Lanikuhana Solar, LLC for a proposed 20-MW PV facility on Oahu.


•	In June 2014, the PUC approved the Utilities 3-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC to spot purchase up to 200,000 gallons per month of as available biodiesel at cost parity to petroleum diesel.


•	In March 2015, Hawaiian Electric requested PUC approval of a 2-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC to supply 2 million to 3 million gallons of biodiesel at CIP CT-1 and the Honolulu International Airport Emergency Power Facility beginning in November 2015 when existing contracts are set to expire.


•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of March 31, 2015, there were 12 MW, 1 MW and 3 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.

•

As of March 31, 2015, there were approximately 222 MW, 49 MW and 52 MW of installed net energy metering capacity from renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively. The amount of net energy metering capacity installed in the first three months of 2015 was about 32% lower than the amount installed in the first three months of 2014, principally due to higher circuit saturations (resulting in the need for further technical reviews and potential equipment modification and/or upgrades).

Other regulatory matters. In addition to the items below, also see Note 4 of the Consolidated Financial Statements.

Adequacy of supply.

Hawaiian Electric. In January 2015, Hawaiian Electric filed its 2015 Adequacy of Supply (AOS) letter, which indicated that based on its February 2014 sales and peak forecast for the 2015 to 2017 time period, Hawaiian Electric’s generation capacity will be sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2016, notwithstanding a generation shortfall event in January 2015, due to unexpected concurrent outages of a utility generating unit and several IPPs.

In accordance to its planning criteria, Hawaiian Electric deactivated two fossil fuel generating units from active service at its Honolulu Power Plant in January 2014 and anticipates deactivating two additional fossil fuel units at its Waiau Power Plant in the 2016 timeframe. Hawaiian Electric is proceeding with future firm capacity additions in coordination with the State of Hawaii Department of Transportation in 2015, and with the U.S. Department of the Army for a utility owned and operated renewable, dispatchable, including black start capabilities, generation security project on federal lands, which may be in service in the 2018 timeframe. Hawaiian Electric is continuing negotiations with two firm capacity IPPs on Oahu under PPAs scheduled to expire in 2016 and 2022.

Hawaii Electric Light. In January 2015, Hawaii Electric Light filed its 2015 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2017 is sufficient to meet reasonably expected demands for service and provide for reasonable reserves for emergencies.

Hawaii Electric Light is anticipating the addition of the Hu Honua Bioenergy, LLC plant in 2016, and potentially additional generation in the 2020-2025 timeframe. The addition of the Hu Honua Bioenergy plant will provide Hawaii Electric Light with the opportunity to deactivate existing fossil fueled generating capacity.

Maui Electric. In January 2015, Maui Electric filed its 2015 AOS letter, which indicated that Maui Electric’s generation capacity through 2018 is sufficient to meet the forecasted demands on the islands of Maui, Lanai, and Molokai. Maui Electric anticipates needing additional firm capacity on Maui in the 2019 timeframe. In February 2014, Maui Electric deactivated two fossil fuel generating units at its Kahului Power Plant. The two deactivated units at Kahului Power Plant were reactivated in the first quarter of 2015 on 4 days due to shortfalls of generation. Maui Electric anticipates the retirement of all generating units at the Kahului Power Plant in the 2019 timeframe. Maui Electric plans to issue one or more RFPs for energy storage, demand response and firm generating capacity, and to make system improvements needed to ensure reliability and voltage support in this timeframe.

The PSIPs, Distributed Generation Interconnection Plan, Integrated Interconnection Queue Plan and Demand Response Portfolio Plan filed in response to the April 2014 regulatory orders may affect the resource plans.

April 2014 regulatory orders. In April 2014, the PUC issued four orders that collectively provide certain key policy, resource planning, and operational directives to the Utilities. See “April 2014 regulatory orders” in Note 4 of the Consolidated Financial Statements.

Commitments and contingencies. See Note 4 of the Consolidated Financial Statements.

Recent accounting pronouncements. See Note 11, “Recent accounting pronouncements,” of the Consolidated Financial Statements.

FINANCIAL CONDITION

Liquidity and capital resources. Management believes that Hawaiian Electric’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities and commercial paper and draws on 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.

Hawaiian Electric’s consolidated capital structure was as follows:



(dollars in millions)	March 31, 2015				December 31, 2014
Short-term borrowings	$	30	1	%	$	—	—	%
Long-term debt, net	1,207		41		1,207		41
Preferred stock	34		1		34		1
Common stock equity	1,686		57		1,682		58
	$	2,957	100	%	$	2,923	100	%

Information about Hawaiian Electric’s short-term borrowings (other than from Hawaii Electric Light and Maui Electric) and Hawaiian Electric’s line of credit facility were as follows:



	Average balance		Balance
(in millions)	Three months ended March 31, 2015		March 31, 2015		December 31, 2014
Short-term borrowings ¹
Commercial paper	$	24	$	30	$	—
Line of credit draws	—		—		—
Borrowings from HEI	—		—		—
Undrawn capacity under line of credit facility	—		200		200

¹ The maximum amount of Hawaiian Electric’s external short-term borrowings during the first three months of 2015 was $62 million. At March 31, 2015, Hawaii Electric Light and Maui Electric had short-term borrowings from Hawaiian Electric of $10 million and $3 million respectively. At April 30, 2015, Hawaiian Electric had $45 million of outstanding commercial paper, no draws under its line of credit facility and no borrowings from HEI. Also, at April 30, 2015, Hawaii Electric Light and Maui Electric had short-term borrowings from Hawaiian Electric of $7 million and $6 million, respectively. Intercompany borrowings are eliminated in consolidation.

Hawaiian Electric has a line of credit facility, as amended and restated on April 2, 2014, of $200 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. See Note 12 of the Consolidated Financial Statements.

Special purpose revenue bonds (SPRBs) have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) capital improvement projects of Hawaiian Electric and its subsidiaries, but the sources of their repayment are the non-collateralized obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the DBF, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on SPRBs currently outstanding and issued prior to 2009 are insured by Financial Guaranty Insurance Company (FGIC), which was placed in a rehabilitation proceeding in the State of New York in June 2012. On August 19, 2013 FGIC’s plan of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings of FGIC, which at the time the insured obligations were issued were higher than the ratings of the Utilities, have been withdrawn. Management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future.

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 the Utilities, up to specified amounts, during the period 2013 through 2015, subject to certain conditions. On October 3, 2013, after obtaining such expedited approvals, the Utilities issued through a private placement taxable non-collateralized senior notes with an aggregate principal amount of $236 million. In September 2014, the Utilities filed a request with the PUC under the expedited approval procedure for approval to issue unsecured obligations bearing taxable interest through December 31, 2015 of up to $80 million (Hawaiian Electric $50 million, Hawaii Electric Light $25 million and Maui Electric $5 million), which represents the remaining unused amount subject to the expedited approval procedure for long-term debt financings. The proceeds are expected to be used, as applicable, to finance capital expenditures, repay long-term and/or short term debt used to finance or refinance capital expenditures and/or to reimburse funds used for payment of the capital expenditures. In April 2015, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed with the PUC a letter request for the expedited authorization to issue up to an additional $47 million of unsecured obligations bearing taxable interest in the event the Utilities decide to refinance outstanding revenue bonds (Hawaiian Electric $40 million, Hawaii Electric Light $5 million and Maui Electric $2 million) in 2015.

Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from) net income. For the first three months in 2015 and 2014, net cash provided by operating activities increased by $32 million and

decreased by $53 million, respectively, compared to the prior year. In 2015, noncash depreciation and amortization amounted to $45 million due to an increase in plant and equipment. Further, the changes in assets and liabilities included a decrease of $57 million in accounts receivable and accrued unbilled revenues due to the timing of customer payments, a $21 million decrease in fuel oil stock, a $49 million decrease in accounts payable due to timing of vendor payments, and an $11 million increase in regulatory assets. In 2014, noncash depreciation and amortization amounted to $43 million due to an increase in plant and equipment. Further, the change in assets and liabilities included increases of $34 million of fuel oil stock and $9 million in regulatory assets offset by a decrease of $9 million in accounts payable.

In 2015 and 2014, net cash used in investing activities decreased by $12 million and increased by $1 million, respectively, compared to the prior year. In 2015 and 2014, capital expenditures amounted to $54 million and $64 million, respectively, offset by contributions in aid of construction of $9 million and $7 million, respectively.

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. In 2015 and 2014, cash flows from financing activities decreased by $5 million and $11 million, respectively, compared to the prior year. In 2015 and 2014, cash provided by financing activities consisted primarily of net proceeds received from short-term borrowings of $30 million and $35 million, respectively. This was offset by payments of $23 million of common and preferred stock dividends during the first three months of 2015 and 2014.

The Utilities have re-evaluated the timing of 2015 - 2017 net capital expenditures, revising their prior 3-year forecast from a range of $1.1 billion to $2.0 billion downward to a range of $0.8 billion to $1.7 billion. 2015 is the transitional year under the revised RAM and Hawaiian Electric will propose a new approval process for projects exceeding the new GDPPI cap under the revised mechanism. Given the change to the RAM, the number of other high priority issues before the PUC and the continuing refinement of transformation plans, the forecast for 2015 net capital expenditures was reduced from $420 million to $250 million. As a result, Hawaiian Electric will not need an equity infusion from HEI in 2015 and is re-evaluating the amount of long-term debt needed in 2015. The 2015 rate base growth is now expected to be between 1.5% to 3.0%. This forecast could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and approvals, and the outcome of competitive bidding for new generation. Hawaiian Electric’s consolidated cash flows from operating activities (net income for common stock, adjusted for non-cash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and preferred stock dividends, are currently not expected to provide sufficient cash to cover the forecasted net capital expenditures over the 3-year forecast period. Debt and equity financing are expected to be required to fund this estimated shortfall and to fund any unanticipated expenditures not included in the 2015 - 2017 forecast, such as increases in the costs or acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements.

Bank



	Three months ended March 31				Increase
(in millions)	2015		2014		(decrease)			Primary reason(s)
Interest income	$	48	$	47	$	1		The impact of higher average earning asset balances was partly offset by lower yields on earning assets. ASB’s average loan portfolio balance for the first quarter of 2015 increased by $265 million compared to the same period in 2014 as average commercial real estate, home equity lines of credit and residential balances increased by $129 million, $66 million, and $57 million, respectively. The growth in these loan portfolios was reflective of 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 generally lower than the average loan portfolio yields. The average investment and mortgage-related securities portfolio balance increased by $24 million due to the purchase of investments with excess liquidity.
Noninterest income	16		17		(1		)	Lower noninterest income primarily due to $3 million lower gain on sale of securities in 2015 compared to 2014 as a result of the gain from the sale of ASB’s municipal bond portfolio in 2014, partly offset by $1 million higher deposit fee income and $1 million higher gain on sale of loans as a result of higher refinancing activity which increased loan production volumes in 2015 compared to 2014 and ASB’s decision to sell most of the low-rate loan production.
Revenues	64		64		—
Interest expense	3		3		—			Average deposit balances for the first quarter of 2015 increased by $273 million compared to the same period in 2014 due to an increase in core deposits. Average term certificate balances remained flat. Other borrowings increased by $51 million primarily due to an increase in repurchase agreements.
Provision for loan losses	1		1		—			The provision for loan losses decreased by $0.4 million as credit quality and trends continue to be stable and good, reflecting prudent credit risk management and a strong Hawaii economy. The net charge-off ratio for the first quarter of 2015 and 2014 was 0.04% and 0.02%, respectively.
Noninterest expense	40		37		3			Noninterest expense for the first quarter of 2015 was $2.9 million higher than the noninterest expense for the same period in 2014 primarily due to $1.0 million higher pension costs and $0.7 million reversal of debit card expenses in first quarter of 2014 with no similar reversal in 2015.
Expenses	44		41		3
Operating income	20		23		(3		)	Higher noninterest expenses and lower noninterest income, partly offset by higher net interest income and lower provision for loan losses.
Net income	13		14		(1		)

See Note 5 of the 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, return on average equity and net interest margin were as follows:



	Three months ended March 31
(percent)	2015	2014
Return on average assets	0.96	1.09
Return on average equity	9.96	10.94
Net interest margin	3.52	3.64

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:



Three months ended March 31	2015						2014
(dollars in thousands)	Average balance			Interest¹ income/ expense		Yield/ rate (%)	Average balance			Interest¹income/ expense		Yield/ rate (%)
Assets:
Other investments ²	$	198,920		$	99	0.20	$	176,766		$	76	0.17
Securities purchased under resale agreements	—			—		—	8,000			8		0.38
Available-for-sale investment securities	549,125			2,952		2.15	525,582			3,101		2.36
Loans
Residential 1-4 family	2,060,485			22,661		4.40	2,003,541			22,669		4.53
Commercial real estate	634,251			6,062		3.84	505,205			5,373		4.28
Home equity line of credit	822,510			6,476		3.19	756,428			6,098		3.27
Residential land	16,381			274		6.69	15,873			243		6.12
Commercial	789,329			7,068		3.62	786,290			7,233		3.72
Consumer	120,602			2,657		8.93	111,666			2,066		7.48
Total loans ^3,4	4,443,558			45,198		4.09	4,179,003			43,682		4.20
Total interest-earning assets ³	5,191,603			48,249		3.73	4,889,351			46,867		3.85
Allowance for loan losses	(45,929		)				(40,514		)
Non-interest-earning assets	487,233						445,249
Total assets	$	5,632,907					$	5,294,086
Liabilities and shareholder’s equity:
Savings	$	1,943,466		$	300	0.06	$	1,840,042		$	268	0.06
Interest-bearing checking	765,172			33		0.02	717,759			29		0.02
Money market	163,737			50		0.12	180,990			57		0.13
Time certificates	433,747			877		0.82	433,756			871		0.81
Total interest-bearing deposits	3,306,122			1,260		0.15	3,172,547			1,225		0.16
Advances from Federal Home Loan Bank	100,000			775		3.10	100,000			775		3.10
Securities sold under agreements to repurchase	198,939			691		1.39	148,408			630		1.70
Total interest-bearing liabilities	3,605,061			2,726		0.30	3,420,955			2,630		0.31
Non-interest bearing liabilities:
Deposits	1,374,311						1,234,566
Other	112,344						111,955
Shareholder’s equity	541,191						526,610
Total liabilities and shareholder’s equity	$	5,632,907					$	5,294,086
Net interest income				$	45,523					$	44,237
Net interest margin (%) ⁵						3.52						3.64

¹ Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of nil and $0.2 million for the three months ended March 31, 2015 and 2014, respectively.


²	Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank of Seattle.


³	Includes loans held for sale, at lower of cost or fair value.


⁴	Includes loan fees of $0.5 million and $1.1 million for the three months ended March 31, 2015 and 2014, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.


⁵	Defined as net interest income, on a fully taxable equivalent basis, as a percentage of average total interest-earning assets.

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 over a period of several years 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 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 loans receivable was as follows:



	March 31, 2015				December 31, 2014
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate:
Residential 1-4 family	$	2,039,099		45.8	$	2,044,205		46.0
Commercial real estate	561,189			12.6	531,917			12.0
Home equity line of credit	814,265			18.3	818,815			18.4
Residential land	18,155			0.4	16,240			0.4
Commercial construction	77,164			1.7	96,438			2.2
Residential construction	20,804			0.5	18,961			0.4
Total real estate, net	3,530,676			79.3	3,526,576			79.4
Commercial	803,545			18.0	791,757			17.8
Consumer	119,310			2.7	122,656			2.8
	4,453,531			100.0	4,440,989			100.0
Less: Deferred fees and discounts	(6,232		)		(6,338		)
Allowance for loan losses	(45,795		)		(45,618		)
Total loans, net	$	4,401,504			$	4,389,033

Home equity — key credit statistics.



	March 31, 2015			December 31, 2014
Outstanding balance (in thousands)	$	814,265		$	818,815
Percent of portfolio in first lien position	41.4		%	40.9		%
Net charge-off (recovery) ratio	(0.01		)%	(0.07		)%
Delinquency ratio	0.30		%	0.25		%



							End of draw period – interest only									Current
March 31, 2015	Total			Interest only			2015-2016			2017-2019			Thereafter			amortizing
Outstanding balance (in thousands)	$	814,265		$	608,948		$	983		$	138,588		$	469,377		$	205,317
% of total	100		%	75		%	—		%	17		%	58		%	25		%

The HELOC portfolio makes up 18% 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 95% 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 principal and interest payments. As of March 31, 2015, approximately 20% of the portfolio balances were 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 5% of the portfolio and are included in the amortizing balances identified in the table above.

Loan portfolio risk elements. See Note 5 of the Consolidated Financial Statements.

Available-for-sale investment securities. ASB’s investment portfolio was comprised as follows:



	March 31, 2015				December 31, 2014
(dollars in thousands)	Balance		% of total		Balance		% of total
U.S. Treasury and federal agency obligations	$	140,227	24	%	$	119,560	22	%
Mortgage-related securities — FNMA, FHLMC and GNMA	450,421		76		430,834		78
Total available-for-sale investment securities	$	590,648	100	%	$	550,394	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. government.

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. As of March 31, 2015 and December 31, 2014, ASB’s costing liabilities consisted of 94% deposits and 6% other borrowings. The weighted average cost of deposits for the first three months of 2015 and 2014 was 0.11% and 0.12%, respectively.

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 March 31, 2015 and December 31, 2014, ASB had an unrealized gain, net of taxes, on available-for-sale investments securities (including securities pledged for repurchase agreements) in AOCI of $4.0 million and $0.5 million, respectively. See “Item 3. Quantitative and qualitative disclosures about market risk.”

During the first three months of 2015, ASB recorded a provision for loan losses of $0.6 million primarily due to growth in the loan portfolio and net charge-offs during the year for consumer loans. During the first three months of 2014, ASB recorded a provision for loan losses of $1.0 million primarily due to net charge-offs during the year for consumer loans and growth in the loan portfolio. Financial stress on ASB’s customers may result in higher levels of delinquencies and losses.



	Three months ended March 31						Year ended December 31
(in thousands)	2015			2014			2014
Allowance for loan losses, January 1	$	45,618		$	40,116		$	40,116
Provision for loan losses	614			995			6,126
Less: net charge-offs	437			188			624
Allowance for loan losses, end of period	$	45,795		$	40,923		$	45,618
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.04		%	0.02		%	0.01		%

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, ASB Hawaii 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, ASB Hawaii and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision (OTS) transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASB Hawaii, 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. If the Spin-Off of ASB Hawaii occurs as contemplated by the Merger Agreement, HEI (or its successor) will no longer be required to serve as a source of strength to ASB. 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.

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.

Also, the Dodd-Frank Act directs the Bureau to publish rules and forms that combine certain disclosures that consumers receive in connection with applying for and closing on a mortgage loan under the Truth in Lending Act and the Real Estate Settlement Procedures Act. Consistent with this requirement, the Bureau amended Regulation X (Real Estate Settlement Procedures Act) and Regulation Z (Truth in Lending) to establish new disclosure requirements and forms in Regulation Z for most closed-end consumer credit transactions secured by real property. In addition to combining the existing disclosure requirements and implementing new requirements, the final rule provides extensive guidance regarding compliance with those requirements. This rule is effective August 1, 2015.

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, on July 1, 2013, ASB became non-exempt as the consolidated assets of HEI exceeded $10 billion. ASB’s debit card interchange fees have been lower as a result of the application of this Amendment.

Final Capital Rules. 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 (such as ASB Hawaii). The FRB indicated that it would release a proposal on intermediate holding companies 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. The FRB has not yet issued such a proposal, nor a proposal on how to apply the Basel III capital rules to SLHCs that are substantially engaged in commercial or insurance underwriting activities, such as grandfathered unitary SLHCs like HEI.

Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would initially 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%, and these requirements would increase in subsequent years. 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 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 capital requirements identified by the agencies. The phased-in effective dates of the capital requirements under the final rule are:

Minimum Capital Requirements



Effective dates	1/1/2015		1/1/2016		1/1/2017		1/1/2018		1/1/2019
Capital conservation buffer			0.625	%	1.25	%	1.875	%	2.50	%
Common equity Tier-1 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 was effective January 1, 2015 for ASB. As of March 31, 2015, ASB met the new capital requirements with a Tier-1 leverage ratio of 8.9%, a Common equity Tier-1 ratio of 12.1%, a Tier-1 capital ratio of 12.1% and a Total capital ratio of 13.2%.

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 eventually be effective for HEI or ASB Hawaii as well. If the Spin-Off of ASB Hawaii occurs as contemplated by the Merger Agreement, HEI (or its successor) will no longer be subject to the final capital rules as applied to SLHCs. If the fully phased-in capital requirements were currently applicable to HEI, management believes HEI would satisfy the capital requirements, including the fully phased-in capital conservation buffer. Management cannot predict what final rule the FRB may adopt concerning intermediate holding companies or their impact on ASB Hawaii, if any.

Commitments and contingencies. See Note 5 of the Consolidated Financial Statements.

Potential impact of lava flows. In June 2014, lava from the Kilauea Volcano on the island of Hawaii began flowing toward the town of Pahoa. ASB has been monitoring its loan exposure on properties most likely to be impacted by the projected path of the lava flow. At March 31, 2015, the outstanding amount of the residential, commercial real estate and home equity lines of credit loans collateralized by property in areas most likely affected by the lava flow totaled $13 million. For residential 1-4 mortgages in the area, ASB required lava insurance to cover the dwelling replacement cost as a condition of making the loan. As of December 31, 2014, ASB provided $1.8 million reserves for a commercial real estate loan impacted by the lava flows. Although the lava threat was downgraded from a warning to a watch in March 2015 and the immediate threat to homes and businesses in Pahoa has receded, the lava flow remains active upslope and the reserves for the commercial real estate loan remained in place. Other than the reserves for the commercial real estate loan, the impact to property values and borrowers’ ability to repay their loans as a result of the lava flow cannot be determined at this time, but ASB does not expect the impact on ASB's financial condition or results of operations to be material.

FINANCIAL CONDITION

Liquidity and capital resources.



(dollars in millions)	March 31, 2015		December 31, 2014		% change
Total assets	$	5,725	$	5,566	3
Available-for-sale investment securities	591		550		7
Loans receivable held for investment, net	4,402		4,389		—
Deposit liabilities	4,751		4,623		3
Other bank borrowings	312		291		7

As of March 31, 2015, ASB was one of Hawaii’s largest financial institutions based on assets of $5.7 billion and deposits of $4.8 billion.

As of March 31, 2015, ASB’s unused FHLB borrowing capacity was approximately $1.3 billion. As of March 31, 2015, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.8 billion. There were no commitments to lend to borrowers whose loan terms have been impaired or modified in troubled debt restructurings as of March 31, 2015. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the three months ended March 31, 2015, net cash provided by ASB’s operating activities was $16 million. Net cash used during the same period by ASB’s investing activities was $43 million, primarily due to purchases of investment securities of $63 million, a net increase in loans receivable of $13 million and additions to premises and equipment of $5 million, partly offset by repayments of investment securities of $28 million, redemption of stock from the FHLB of Seattle of $6 million and proceeds

from the sale of premises and equipment of $4 million. Net cash provided by financing activities during this period was $136 million, primarily due to increases in deposit liabilities of $128 million and a net increase in retail repurchase agreements of $21 million, partly offset by a net decrease in mortgage escrow deposits of $4 million, payments on low income housing investment commitments of $2 million, respectively, and the payment of $8 million in common stock dividends to HEI (through ASB Hawaii).

ASB believes that maintaining a satisfactory regulatory capital position provides a basis for public confidence, affords protection to depositors, helps to ensure continued access to capital markets on favorable terms and provides a foundation for growth. 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 March 31, 2015, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a Tier-1 leverage ratio of 8.9% (5.0%), a Common equity tier-1 ratio of 12.1% (6.5%), a Tier-1 capital ratio of 12.1% (8.0%) and a Total capital ratio of 13.2% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASB Hawaii).

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 79 to 81, HEI’s and Hawaiian Electric’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2014 Form 10-K.

ASB’s interest-rate risk sensitivity measures as of March 31, 2015 and December 31, 2014 constitute “forward-looking statements” and were as follows:



Change in interest rates	Change in NII (gradual change in interest rates)				Change in EVE (instantaneous change in interest rates)
(basis points)	March 31, 2015		December 31, 2014		March 31, 2015		December 31, 2014
+300	2.3	%	1.9	%	(4.8	)%	(6.1	)%
+200	1.0		0.7		(1.9	)	(2.9	)
+100	0.3		0.1		(0.2	)	(0.7	)
-100	(0.5	)	(0.5	)	(3.1	)	(2.5	)

Management believes that ASB’s interest rate risk position as of March 31, 2015 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was more asset sensitive for all rate increases as of March 31, 2015 compared to December 31, 2014. The $118 million growth in interest bearing deposits, which has a short-term repricing horizon, made ASB more asset sensitive.

ASB’s base EVE increased to $957 million as of March 31, 2015 compared to $947 million as of December 31, 2014 due to growth in capital and flattening of the yield curve.

The change in EVE to rising rates became less sensitive as of March 31, 2015 compared to December 31, 2014. The flattening of the yield curve, with long term rates falling, caused mortgage rates to decrease and led to faster prepayment expectations and shortened the duration of the fixed rate mortgage portfolio. Additionally, the liability mix changed as the longer duration core deposit balances grew by $125 million, and thereby reduced overall EVE sensitivity.

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, pretax 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.

Item 4. Controls and Procedures

HEI:

Changes in Internal Control over Financial Reporting

During the first quarter of 2015, 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 March 31, 2015 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 March 31, 2015. Based on their evaluations, as of March 31, 2015, 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.

Hawaiian Electric:

Changes in Internal Control over Financial Reporting

During the first quarter of 2015, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of Hawaiian Electric and its subsidiaries’ internal control over financial reporting as of March 31, 2015 that has materially affected, or is reasonably likely to materially affect, Hawaiian Electric and its subsidiaries’ internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Alan M. Oshima, Hawaiian Electric Chief Executive Officer, and Tayne S. Y. Sekimura, Hawaiian Electric Chief Financial Officer, have evaluated the disclosure controls and procedures of Hawaiian Electric as of March 31, 2015. Based on their evaluations, as of March 31, 2015, 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 Hawaiian Electric in reports Hawaiian Electric 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 Hawaiian Electric management, including Hawaiian Electric’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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 and Hawaiian Electric’s 2014 Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this Form 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2, 4 and 5 of the 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 Hawaiian Electric 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 26 to 35 of HEI’s and Hawaiian Electric’s 2014 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” and the Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on pages iv and v herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(c) Purchases of HEI common shares were made in the open market during the first quarter to satisfy the requirements of certain plans as follows:

ISSUER PURCHASES OF EQUITY SECURITIES



Period*	(a) Total Number of Shares Purchased **	(b) Average Price Paid per Share **	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 to 31, 2015	19,693	$34.39	—	NA
February 1 to 28, 2015	8,251	$33.44	—	NA
March 1 to 31, 2015	233,899	$32.28	—	NA

NA Not applicable.

* Trades (total number of shares purchased) are reflected in the month in which the order is placed.

** The purchases were made to satisfy the requirements of the DRIP, the HEIRSP and the ASB 401(k) Plan for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP, the HEIRSP and the ASB 401(k) Plan. Of the shares listed in column (a), 18,943 of the 19,693 shares, 5,321 of the 8,251 shares and 210,399 of the 233,899 shares were purchased for the DRIP, none of the 19,693 shares, none of the 8,251 shares and 19,400 of the 233,899 shares were purchased for the HEIRSP and the remainder was purchased for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.

Item 5. Other Information

A. Ratio of earnings to fixed charges.



	Three months ended March 31		Years ended December 31
	2015	2014	2014	2013	2012	2011	2010
HEI and Subsidiaries
Excluding interest on ASB deposits	3.21	3.88	3.80	3.55	3.30	3.24	2.90
Including interest on ASB deposits	3.10	3.74	3.65	3.42	3.15	3.04	2.65
Hawaiian Electric and Subsidiaries	3.39	4.07	4.04	3.72	3.37	3.52	2.88

Prior period ratios reflect the retrospective application of ASU No. 2014-01, “Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which was adopted as of January 1, 2015 and did not have a material impact on the Company’s financial condition or results of operations. See “Investments in qualified affordable housing projects” in Note 11 of the Consolidated Financial Statements.

See HEI Exhibit 12.1 and Hawaiian Electric Exhibit 12.2.

Item 6. Exhibits



HEI Exhibit 4		First Amendment to Master Trust Agreement (dated as of September 4, 2012) effective March 1, 2015 between HEI and ASB and Fidelity Management Trust Company

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2015 and 2014 and years ended December 31, 2014, 2013, 2012, 2011 and 2010

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

Hawaiian Electric Exhibit 10		Third Amendment, dated February 11, 2015, to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Hawaii Independent Energy (formerly known as Tesoro, which was formerly known as BHP Petroleum Americas Refining Inc.), LLC and Hawaiian Electric, Maui Electric and Hawaii Electric Light, dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly)

Hawaiian Electric Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2015 and 2014 and years ended December 31, 2014, 2013, 2012, 2011 and 2010

Hawaiian Electric Exhibit 31.3		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Alan M. Oshima (Hawaiian Electric Chief Executive Officer)

Hawaiian Electric Exhibit 31.4		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (Hawaiian Electric Chief Financial Officer)

Hawaiian Electric Exhibit 32.2		Hawaiian Electric Certification Pursuant to 18 U.S.C. Section 1350

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/ Alan M. Oshima
	Constance H. Lau		Alan M. Oshima
	President and Chief Executive Officer		President and Chief Executive Officer
	(Principal Executive Officer of HEI)		(Principal Executive Officer of Hawaiian Electric)


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 Hawaiian Electric)
	Officer of HEI)


Date: May 6, 2015		Date: May 6, 2015