Edgar Filing: HAWAIIAN ELECTRIC INDUSTRIES INC

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, 2016

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 28, 2016
Hawaiian Electric Industries, Inc. (Without Par Value)		107,890,279 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, 2016

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, 2016 and 2015
2		Consolidated Statements of Comprehensive Income - three months ended March 31, 2016 and 2015
3		Consolidated Balance Sheets - March 31, 2016 and December 31, 2015
4		Consolidated Statements of Changes in Shareholders’ Equity - three months ended March 31, 2016 and 2015
5		Consolidated Statements of Cash Flows - three months ended March 31, 2016 and 2015
		Hawaiian Electric Company, Inc. and Subsidiaries
6		Consolidated Statements of Income - three months ended March 31, 2016 and 2015
6		Consolidated Statements of Comprehensive Income - three months ended March 31, 2016 and 2015
7		Consolidated Balance Sheets - March 31, 2016 and December 31, 2015
8		Consolidated Statements of Changes in Common Stock Equity - three months ended March 31, 2016 and 2015
9		Consolidated Statements of Cash Flows - three months ended March 31, 2016 and 2015
10		Notes to Consolidated Financial Statements
61	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
61		HEI consolidated
64		Electric Utilities
74		Bank
80	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
81	Item 4.	Controls and Procedures

	PART II.	OTHER INFORMATION
83	Item 1.	Legal Proceedings
83	Item 1A.	Risk Factors
83	Item 5.	Other Information
84	Item 6.	Exhibits
85	Signatures

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2016

GLOSSARY OF TERMS



Terms		Definitions
AES Hawaii		AES Hawaii, Inc.
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. (dissolved in 2015); 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
DER		Distributed Energy Resources
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
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
FERC		Federal Energy Regulatory Commission
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
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.
HIE		Hawaii Independent Energy, LLC
HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., ASB Hawaii, Inc., HEI Properties, Inc. (dissolved in 2015) 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
Kalaeloa		Kalaeloa Partners, L.P.
KWH		Kilowatthour/s (as applicable)
LNG		Liquefied natural gas
LTIP		Long-term incentive plan
MATS		Mercury and Air Toxics Standards
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
MW		Megawatt/s (as applicable)
NEE		NextEra Energy, Inc.
NEM		Net energy metering
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
PSIPs		Power Supply Improvement Plans
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, obtaining (and the timing and terms and conditions of) required governmental and regulatory approvals, and the ability to maintain relationships with employees, customers or suppliers and to integrate the businesses;


•	the ability of ASB Hawaii, Inc. (ASB Hawaii) and its subsidiary, American Savings Bank, F.S.B. (ASB), to operate successfully after the Spin-Off;

•

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 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, the conflict in Syria, terrorist acts by ISIS or others, potential conflict or crisis with North Korea 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 potential delay by the Public Utilities Commission of the State of Hawaii (PUC) in considering (and potential disapproval of actual or proposed) renewable energy proposals and related costs; reliance by the Utilities on outside parties such as the state, independent power producers (IPPs) and developers; and uncertainties surrounding technologies, solar power, wind power, proposed undersea cables, biofuels, environmental assessments required to meet renewable portfolio standards (RPS) goals and the impacts of implementation of the renewable energy proposals 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 proposed and being developed in response to the four orders that the 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 or modifications 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 the Utilities 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 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)	2016			2015
Revenues
Electric utility	$	482,052		$	573,442
Bank	68,840			64,348
Other	68			72
Total revenues	550,960			637,862
Expenses
Electric utility	426,726			515,806
Bank	49,246			43,717
Other	6,137			8,833
Total expenses	482,109			568,356
Operating income (loss)
Electric utility	55,326			57,636
Bank	19,594			20,631
Other	(6,069		)	(8,761		)
Total operating income	68,851			69,506
Interest expense, net—other than on deposit liabilities and other bank borrowings	(20,126		)	(19,100		)
Allowance for borrowed funds used during construction	662			499
Allowance for equity funds used during construction	1,739			1,413
Income before income taxes	51,126			52,318
Income taxes	18,301			19,979
Net income	32,825			32,339
Preferred stock dividends of subsidiaries	473			473
Net income for common stock	$	32,352		$	31,866
Basic earnings per common share	$	0.30		$	0.31
Diluted earnings per common share	$	0.30		$	0.31
Dividends per common share	$	0.31		$	0.31
Weighted-average number of common shares outstanding	107,620			103,281
Net effect of potentially dilutive shares	161			286
Adjusted weighted-average shares	107,781			103,567

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)	2016			2015
Net income for common stock	$	32,352		$	31,866
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 $4,905 and 2,278 for the respective periods	7,428			3,451
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized gain, net of taxes of $638 and nil for the respective periods	1,002			—
Less: reclassification adjustment to net income, net of tax benefits of $35 and $37 for the respective periods	54			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 $2,257 and $3,486 for the respective periods	3,538			5,459
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,052 and $3,127 for the respective periods	(3,222		)	(4,911		)
Other comprehensive income, net of taxes	8,800			4,058
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	41,152		$	35,924

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, 2016			December 31, 2015
Assets
Cash and cash equivalents	$	334,743		$	300,478
Accounts receivable and unbilled revenues, net	210,280			242,766
Available-for-sale investment securities, at fair value	906,295			820,648
Stock in Federal Home Loan Bank, at cost	11,218			10,678
Loans receivable held for investment, net	4,589,950			4,565,781
Loans held for sale, at lower of cost or fair value	7,900			4,631
Property, plant and equipment, net of accumulated depreciation of $2,355,984 and $2,339,319 at the respective dates	4,423,567			4,377,658
Regulatory assets	888,408			896,731
Other	415,955			480,457
Goodwill	82,190			82,190
Total assets	$	11,870,506		$	11,782,018
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	119,288		$	138,523
Interest and dividends payable	27,890			26,042
Deposit liabilities	5,139,932			5,025,254
Short-term borrowings—other than bank	95,485			103,063
Other bank borrowings	329,081			328,582
Long-term debt, net—other than bank	1,578,618			1,578,368
Deferred income taxes	700,782			680,877
Regulatory liabilities	383,793			371,543
Contributions in aid of construction	513,520			506,087
Defined benefit pension and other postretirement benefit plans liability	584,490			589,918
Other	421,155			471,828
Total liabilities	9,894,034			9,820,085
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: 107,875,779 shares and 107,460,406 shares at the respective dates	1,635,890			1,629,136
Retained earnings	323,751			324,766
Accumulated other comprehensive loss, net of tax benefits	(17,462		)	(26,262		)
Total shareholders’ equity	1,942,179			1,927,640
Total liabilities and shareholders’ equity	$	11,870,506		$	11,782,018

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, 2015	107,460	$	1,629,136	$	324,766		$	(26,262	)	$	1,927,640
Net income for common stock	—	—		32,352			—			32,352
Other comprehensive income, net of taxes	—	—		—			8,800			8,800
Issuance of common stock, net	416	6,754		—			—			6,754
Common stock dividends ($0.31 per share)	—	—		(33,367		)	—			(33,367		)
Balance, March 31, 2016	107,876	$	1,635,890	$	323,751		$	(17,462	)	$	1,942,179
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

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	2016			2015
(in thousands)
Cash flows from operating activities
Net income	$	32,825		$	32,339
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	48,594			45,865
Other amortization	1,928			2,371
Provision for loan losses	4,766			614
Loans receivable originated and purchased, held for sale	(42,719		)	(79,070		)
Proceeds from sale of loans receivable, held for sale	40,363			78,332
Increase in deferred income taxes	13,008			3,828
Share-based compensation expense	1,013			1,754
Excess tax benefits from share-based payment arrangements	(380		)	(968		)
Allowance for equity funds used during construction	(1,739		)	(1,413		)
Changes in assets and liabilities
Decrease in accounts receivable and unbilled revenues, net	28,108			58,331
Decrease in fuel oil stock	22,812			20,731
Decrease (increase) in regulatory assets	1,585			(10,827		)
Increase in accounts, interest and dividends payable	30,135			22,053
Change in prepaid and accrued income taxes and utility revenue taxes	(14,343		)	(9,461		)
Increase in defined benefit pension and other postretirement benefit plans liability	137			123
Change in other assets and liabilities	4,499			(25,992		)
Net cash provided by operating activities	170,592			138,610
Cash flows from investing activities
Available-for-sale investment securities purchased	(122,387		)	(63,370		)
Principal repayments on available-for-sale investment securities	48,819			28,486
Purchase of stock from Federal Home Loan Bank	(1,373		)	—
Redemption of stock from Federal Home Loan Bank	833			5,590
Net increase in loans held for investment	(28,137		)	(12,524		)
Proceeds from sale of real estate acquired in settlement of loans	232			606
Capital expenditures	(127,818		)	(123,527		)
Contributions in aid of construction	13,761			9,145
Other	819			3,549
Net cash used in investing activities	(215,251		)	(152,045		)
Cash flows from financing activities
Net increase in deposit liabilities	114,678			127,913
Net decrease in short-term borrowings with original maturities of three months or less	(7,578		)	(88,472		)
Net increase in retail repurchase agreements	19,041			21,451
Proceeds from other bank borrowings	20,835			—
Repayments of other bank borrowings	(39,369		)	—
Proceeds from issuance of long-term debt	75,000			—
Repayment of long-term debt	(75,000		)	—
Excess tax benefits from share-based payment arrangements	380			968
Net proceeds from issuance of common stock	3,022			104,468
Common stock dividends	(27,716		)	(31,829		)
Preferred stock dividends of subsidiaries	(473		)	(473		)
Other	(3,896		)	(3,965		)
Net cash provided by financing activities	78,924			130,061
Net increase in cash and cash equivalents	34,265			116,626
Cash and cash equivalents, beginning of period	300,478			175,542
Cash and cash equivalents, end of period	$	334,743		$	292,168

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)	2016			2015
Revenues	$	482,052		$	573,442
Expenses
Fuel oil	113,740			176,806
Purchased power	115,859			136,007
Other operation and maintenance	103,908			104,002
Depreciation	46,781			44,243
Taxes, other than income taxes	46,438			54,748
Total expenses	426,726			515,806
Operating income	55,326			57,636
Allowance for equity funds used during construction	1,739			1,413
Interest expense and other charges, net	(17,308		)	(16,325		)
Allowance for borrowed funds used during construction	662			499
Income before income taxes	40,419			43,223
Income taxes	14,553			15,850
Net income	25,866			27,373
Preferred stock dividends of subsidiaries	229			229
Net income attributable to Hawaiian Electric	25,637			27,144
Preferred stock dividends of Hawaiian Electric	270			270
Net income for common stock	$	25,367		$	26,874

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)	2016			2015
Net income for common stock	$	25,367		$	26,874
Other comprehensive income, net of taxes:
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized gain, net of taxes of $638 and nil for the respective periods	1,002			—
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 $2,061 and $3,141 for the respective periods	3,236			4,933
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,052 and $3,127 for the respective periods	(3,222		)	(4,911		)
Other comprehensive income, net of taxes	1,016			22
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	26,383		$	26,896

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, 2016			December 31, 2015
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	53,207		$	52,792
Plant and equipment	6,356,006			6,315,698
Less accumulated depreciation	(2,284,928		)	(2,266,004		)
Construction in progress	198,004			175,309
Utility property, plant and equipment, net	4,322,289			4,277,795
Nonutility property, plant and equipment, less accumulated depreciation of $1,230 and $1,229 at respective dates	7,375			7,272
Total property, plant and equipment, net	4,329,664			4,285,067
Current assets
Cash and cash equivalents	49,042			24,449
Customer accounts receivable, net	103,739			132,778
Accrued unbilled revenues, net	85,367			84,509
Other accounts receivable, net	6,773			10,408
Fuel oil stock, at average cost	48,404			71,216
Materials and supplies, at average cost	54,256			54,429
Prepayments and other	21,803			36,640
Regulatory assets	89,192			72,231
Total current assets	458,576			486,660
Other long-term assets
Regulatory assets	799,216			824,500
Unamortized debt expense	420			497
Other	74,495			75,486
Total other long-term assets	874,131			900,483
Total assets	$	5,662,371		$	5,672,210
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	578,926			578,930
Retained earnings	1,045,049			1,043,082
Accumulated other comprehensive income, net of income taxes	1,941			925
Common stock equity	1,731,304			1,728,325
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,278,916			1,278,702
Total capitalization	3,044,513			3,041,320
Commitments and contingencies (Note 4)
Current liabilities
Short-term borrowings from non-affiliates	12,998			—
Accounts payable	95,090			114,846
Interest and preferred dividends payable	27,015			23,111
Taxes accrued	129,239			191,084
Regulatory liabilities	5,416			2,204
Other	75,006			54,079
Total current liabilities	344,764			385,324
Deferred credits and other liabilities
Deferred income taxes	670,126			654,806
Regulatory liabilities	378,377			369,339
Unamortized tax credits	85,902			84,214
Defined benefit pension and other postretirement benefit plans liability	547,517			552,974
Other	77,652			78,146
Total deferred credits and other liabilities	1,759,574			1,739,479
Contributions in aid of construction	513,520			506,087
Total capitalization and liabilities	$	5,662,371		$	5,672,210

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, 2015	15,805	$	105,388	$	578,930		$	1,043,082		$	925	$	1,728,325
Net income for common stock	—	—		—			25,367			—		25,367
Other comprehensive income, net of taxes	—	—		—			—			1,016		1,016
Common stock dividends	—	—		—			(23,400		)	—		(23,400		)
Common stock issuance expenses	—	—		(4		)	—			—		(4		)
Balance, March 31, 2016	15,805	$	105,388	$	578,926		$	1,045,049		$	1,941	$	1,731,304
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

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	2016			2015
(in thousands)
Cash flows from operating activities
Net income	$	25,866		$	27,373
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	46,781			44,243
Other amortization	1,774			1,698
Increase in deferred income taxes	13,558			15,132
Change in tax credits, net	1,702			2,576
Allowance for equity funds used during construction	(1,739		)	(1,413		)
Changes in assets and liabilities
Decrease in accounts receivable	28,297			29,104
Decrease (increase) in accrued unbilled revenues	(858		)	27,880
Decrease in fuel oil stock	22,812			20,731
Decrease (increase) in materials and supplies	173			(1,357		)
Decrease (increase) in regulatory assets	1,585			(10,827		)
Increase in accounts payable	27,766			15,380
Change in prepaid and accrued income taxes and revenue taxes	(42,018		)	(63,696		)
Increase in defined benefit pension and other postretirement benefit plans liability	205			110
Change in other assets and liabilities	20,967			(9,774		)
Net cash provided by operating activities	146,871			97,160
Cash flows from investing activities
Capital expenditures	(125,183		)	(118,874		)
Contributions in aid of construction	13,761			9,145
Other	45			243
Net cash used in investing activities	(111,377		)	(109,486		)
Cash flows from financing activities
Common stock dividends	(23,400		)	(22,601		)
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	12,998			30,000
Other	—			(216		)
Net cash provided by (used in) financing activities	(10,901		)	6,684
Net increase (decrease) in cash and cash equivalents	24,593			(5,642		)
Cash and cash equivalents, beginning of period	24,449			13,762
Cash and cash equivalents, end of period	$	49,042		$	8,120

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, 2015.

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 consolidated HEI’s and Hawaiian Electric’s financial positions as of March 31, 2016 and December 31, 2015, the results of their operations and their cash flows for the three months ended March 31, 2016 and 2015. All such adjustments are of a normal recurring nature, unless otherwise disclosed below or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year.

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 to 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 price 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, Inc. (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). Some, but not all, of these conditions have been satisfied and certain of these conditions will only be satisfied shortly before closing.

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

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 June 3, 2016, and further provides that upon termination of the Merger Agreement under specified circumstances NEE would be required to pay HEI a termination fee of $90 million and reimburse HEI for up to $5 million of its documented out-of-pocket expenses incurred in connection with the Merger Agreement.

On January 29, 2015, HEI submitted its application to the FERC requesting all necessary authorizations 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 the FRB advising the FRB of its intent to seek deregistration as a Savings & Loan Holding Company (SLHC) to be effective upon the contemplated Spin-off of ASB Hawaii.

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.

On March 30, 2015, ASB Hawaii filed its Form 10 and, on April 1, 2016, filed Amendment No. 1 thereto. This is the registration statement for the ASB Hawaii shares expected to be distributed in the Spin-Off.

HEI Shareholders approved the proposed merger agreement with NEE on June 10, 2015.

On August 7, 2015, each of HEI and NEE filed their respective notifications pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act), with the U.S. Department of Justice and Federal Trade Commission. On September 8, 2015, the mandatory, pre-merger waiting period under the HSR Act expired.

PUC application. In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger (under which Hawaiian Electric would become a wholly-owned indirect subsidiary of NEE). 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 reduce the RAM, which amounts to approximately $60 million in cumulative savings for customers, over the four-year base rate moratorium, subject to certain exceptions and conditions, including that the following remain in effect: the revenue balancing account (RBA) and RAM tariff provisions, the Renewable Energy Infrastructure Program, and Renewable Energy Infrastructure Surcharge, the integrated resource planning/DSM Recovery tariff provisions, the ECAC tariff provisions, the PPAC tariff provision and the Pension and OPEB tracker mechanism. Various governmental, environmental and commercial interests groups have been allowed to intervene in the proceeding.

Twenty-eight interveners filed direct testimonies in the docket in July 2015. Eleven interveners recommended the merger not be approved, eleven recommended approval only with conditions, and six did not specifically make a recommendation either way. The Consumer Advocate filed its direct testimonies on August 10, 2015, stating that the Applicants have not justified that the proposed transaction is in the public interest but that if the Consumer Advocate’s recommended conditions were adopted, the results would reflect substantial net benefits that would support a finding that the proposed transaction is in the public interest. Among its recommended conditions was a rate plan to permanently reduce the Utilities’ rates by approximately $62 million annually. On August 31, 2015, the Applicants filed their responsive testimonies, offering a number of additional commitments, including:


•	subject to PUC approval, completing full smart meter deployment to all customers by December 31, 2019


•	reflecting 100% of all net non-fuel O&M savings achieved by the Utilities and limiting non-fuel O&M expenses to levels no higher than the non-fuel O&M expenses in 2014, adjusted for inflation, in the revenue requirements in the first rate case following the four-year rate case moratorium


•	establishing a funding mechanism of $2.5 million per year during the four-year rate case moratorium to be used for purposes in the public interest at the PUC’s discretion and direction


•	committing to corporate giving of at least $2.2 million for a minimum of 10 years post-closing


•	committing to not selling the Utilities or their holding company for at least 10 years post-closing

On October 7, 2015, the other parties filed rebuttal testimonies, and on October 16, 2015, the Applicants filed their surrebuttal testimonies. Discovery was conducted over a six month period and concluded on October 14, 2015 with the filing of final information request (IR) responses.

On November 27, 2015, pursuant to entering into an agreement with the Department of the Navy on behalf of the Department of Defense (DOD), the Applicants filed a motion to admit revised stipulated commitments into evidence, which revised Applicants’ commitments to include the following 3 main changes:


•	committing to undertake good faith efforts to achieve a consolidated renewable portfolio standard of thirty-five percent of net electricity sales by December 31, 2020, and fifty percent of net electricity sales by December 31, 2030;


•	committing to and specifying in detail how $60 million in total rate credits will be provided over the four-year base rate moratorium period; and


•	committing to (i) establish a new intermediate holding company, Hawaiian Electric Utility Holdings, which will have a voting board of directors and a majority of the members of the board of directors who will be residents of Hawaii, (ii) implement a suite of additional ring fencing commitments, and (iii) develop employees from within the Companies to fill executive vacancies.

In connection with the agreement, on November 27, 2015, the DOD filed a motion to withdraw from the proceeding. Prior to this date, three other parties had withdrawn from the proceeding. On January 4, 2016, the PUC issued an order granting the Applicants’ motion to admit revised stipulated commitments into evidence and permitting additional discovery and testimony by the other parties regarding the revised stipulated commitments, and denying the DOD’s motion to withdraw.

Evidentiary hearings were held over 22 days in November 2015 through March 2016. Post-evidentiary hearing opening briefs were filed in March 2016 and reply briefs were filed in May 2016. A PUC decision is pending.

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. On January 23, 2015, the Cohn State Action was voluntarily dismissed. On January 27, 2015, Cohn filed a purported class action captioned Cohn v. Hawaiian Electric Industries, Inc., et al., Civil No. 15-00029-JMS-RLP 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 Cohn Federal Action). On February 13, 2015, the state court orally granted the plaintiffs’ motions to consolidate the seven state court actions and appoint co-lead counsel and entered a written order granting the motions on March 6, 2015. On March 10, 2015, plaintiffs filed a first consolidated complaint in state court that added as a defendant J.P. Morgan Securities, LLC (JP Morgan), the financial advisor to HEI for the Merger, and deleted Hawaiian Electric Company, Inc. as a defendant and concurrently served a first request for production of documents on HEI and the individual directors. On March 17, 2015, plaintiffs filed a motion for limited expedited discovery in the consolidated state action and thereafter on March 25, 2015 withdrew their request for limited discovery and first request for production of documents as a result of the parties’ agreement to conduct certain specified limited discovery which included a stipulated confidentiality agreement and protective order protecting the confidentiality of certain information exchanged between the parties in connection with discovery in the consolidated action that was filed on April 6, 2015. On April 15 and 17, 2015, a deposition of a representative of HEI and a representative of JP Morgan were taken, respectively. On April 21, 2015, plaintiffs confirmed the cancellation of the preliminary injunction hearing that had been scheduled for May 5, 2015 in the consolidated

action and on April 23, 2015, the state court entered a stipulation and order to extend indefinitely the time to answer or otherwise respond to the first amended consolidated complaint. On April 30, 2015, the state court entered a consolidated case management order confirming the consolidated treatment of the state actions for purposes of case management, pretrial discovery, procedural and other matters. On May 27, 2015, the federal court entered a stipulation and order approving the stipulation of the parties to stay the Cohn Federal Action pending the resolution of the state court consolidated action and administratively closing the Cohn Federal Action without prejudice to any party. On May 29, 2015, the state court entered a stipulated order amending the consolidated caption to read IN RE Consolidated HEI Shareholder Cases, Master File No. Civil No. 1CC15-1-HEI, to add JP Morgan as a named defendant in each individual action, add the caption for the Grieco Action, and remove Hawaiian Electric Company, Inc. from the caption in the Brown Action. In October 2015, several depositions of HEI representatives were taken in the state consolidated action. On February 9, 2016, plaintiffs filed an ex parte motion for second extension of time to file the pretrial statement in the state consolidated action from February 15, 2016 to August 15, 2016.

The actions allege, among other things, that members of HEI's Board of Directors (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 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 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 in the complaints are without merit and intend to defend these lawsuits vigorously.

3 · Segment financial information



(in thousands)	Electric utility		Bank		Other			Total
Three months ended March 31, 2016
Revenues from external customers	$	482,045	$	68,840	$	75		$	550,960
Intersegment revenues (eliminations)	7		—		(7		)	—
Revenues	482,052		68,840		68			550,960
Income (loss) before income taxes	40,419		19,594		(8,887		)	51,126
Income taxes (benefit)	14,553		6,921		(3,173		)	18,301
Net income (loss)	25,866		12,673		(5,714		)	32,825
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	25,367		12,673		(5,688		)	32,352
Total assets (at March 31, 2016)	5,662,371		6,140,514		67,621			11,870,506
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
Total assets (at December 31, 2015)*	5,672,210		6,014,755		95,053			11,782,018

* See Note 11 for the impact to prior period financial information of the adoption of Accounting Standards Update (ASU) No. 2015-03.

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 and the profit on such sales is nominal.

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 and the profit on such fees is nominal.

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, 2016 and 2015 approximately $43 million and $51 million, respectively, of revenue taxes in “revenues” and in “taxes, other than income taxes” expense.

Recent tax developments. On December 18, 2015, Congress passed, and President Obama signed into law, the “Protecting Americans from Tax Hikes (PATH) Act of 2015” and the “Consolidating Appropriations Act, 2016,” providing government funding and a number of significant tax changes.

The provision with the greatest impact on the Company is the extension of bonus depreciation. The PATH Act retroactively extended 50% bonus depreciation for qualified property acquired and placed in service in 2015 and continues 50% bonus depreciation through 2017. The bonus depreciation percentage decreases to 40% in 2018 and 30% in 2019 and terminates thereafter. The extension of bonus depreciation is expected to result in an increase in 2015 tax depreciation of approximately $117 million, primarily attributable to the Utilities. The PATH Act also made the research credit permanent, providing a 20% credit on the amount that the cost of qualified research expenditures for the tax year exceeds an amount based on prior expenditures.

Additionally, the “Consolidating Appropriations Act, 2016” extended a variety of energy-related credits that were expired or soon to expire. These credits include the production credit for wind facilities and the 30% investment credit for qualified solar energy property, with various phase-out dates through 2021.

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, 2016 and December 31, 2015 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, 2016 and 2015 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, 2016, the Utilities had five 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 or less who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs. Purchases from all IPPs were as follows:



	Three months ended March 31
(in millions)	2016		2015
AES Hawaii	$	38	$	34
Kalaeloa	29		44
HEP	11		11
Hpower	16		16
Puna Geothermal Venture	7		7
Hawaiian Commercial & Sugar (HC&S)	—		2
Other IPPs	15		22
Total IPPs	$	116	$	136

In October 2015 the amended PPA between Maui Electric and HC&S became effective following PUC approval in September 2015. The amended PPA amends the pricing structure and rates for energy sold to Maui Electric, eliminates the capacity payment to HC&S, eliminates Maui Electric’s minimum purchase obligation, provides that Maui Electric may request up to 4 MW of scheduled energy during certain months, and be provided up to 16 MW of emergency power, and extends the term of the PPA from 2014 to 2017. In 2016 HC&S requested to terminate the PPA in January of 2017, approximately 1 year early due to HC&S ceasing sugar operations.

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 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 2015, 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.

Hawaiian Electric and Kalaeloa are in negotiations to address the upcoming end of the PPA term ending on May 23, 2016. The PPA will automatically extend on a month-to-month basis as long as the parties are still negotiating in good faith. The month-to-month term extensions shall end 60 days after either party notifies the other in writing that negotiations have terminated.

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. The energy payments paid by Hawaiian Electric will fluctuate as fuel prices change, however, 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, 2016, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $8 million.

AES Hawaii, Inc. In March 1988, Hawaiian Electric entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc.), which, as amended (through Amendment No. 2) and approved by the PUC, provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 30 years beginning in September 1992. In November 2015, Hawaiian Electric entered into an Amendment No. 3, for which PUC approval has been requested. If approved by the PUC, Amendment No. 3 would increase the firm capacity from 180 MW to a maximum of 189 MW. The payments that Hawaiian Electric makes to AES Hawaii for energy associated with the first 180 MW of firm capacity include a fuel component, a variable O&M component and a fixed O&M component, all of which are subject to adjustment based on changes in the Gross National Product Implicit Price Deflator. If Amendment No. 3 is approved by the PUC, payments for energy associated with firm capacity in excess of 180 MW will not include any O&M component or be subject to adjustment based on changes in the Gross National Product Implicit Price Delflator. The capacity payments that Hawaiian Electric makes to AES Hawaii are fixed in accordance with the PPA and, if approved by the PUC, Amendment No. 3.

Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in AES Hawaii by reason of the provisions of Hawaiian Electric’s PPA with AES Hawaii. However, management has concluded that Hawaiian Electric is not the primary beneficiary of AES Hawaii because Hawaiian Electric does not have the power to control the most significant activities of AES Hawaii that impact AES Hawaii’s economic performance, including operations and maintenance of AES Hawaii’s facility. Thus, Hawaiian Electric has not consolidated AES Hawaii in its consolidated financial statements. As of March 31, 2016, Hawaiian Electric’s accounts payable to AES Hawaii 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.

Hawaiian Electric and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to the Low Sulfur Fuel Oil Supply Contract (LSFO Contract) for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on December 31, 2016 and may automatically renew for annual terms thereafter unless earlier terminated by either party. The PUC approved the recovery of costs incurred under this contract on April 30, 2013.

On August 27, 2014, Chevron and Hawaiian Electric entered into a first amendment of the LSFO Contract. 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 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. In March 2015, the amendment was approved by the PUC.

The Utilities are also 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, but have been extended through December 31, 2016. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.

In August 2014, Chevron and the Utilities entered into a third amendment to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract (Inter-island 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.

In June 2015, the Utilities issued Requests for Proposals (RFP) for most of their fuel needs with supplies beginning in 2017 after the expiration of Chevron LSFO and Chevron/HIE Interisland contracts on December 31, 2016. Proposals were received in July 2015.

On February 18, 2016, Hawaiian Electric and Chevron entered into a fuel supply contract for LSFO, diesel and fuel to meet MATS requirements (2016 LSFO Contract) for the island of Oahu which terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Also on February 18, 2016, the Utilities and Chevron entered into a supply contract for industrial fuel oil, diesel and ultra-low sulfur diesel (Petroleum Fuels Contract) for the islands of Oahu, Maui, Molokai and the island of Hawaii , which terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Finally, on February 18, 2016, Hawaii Electric Light and Chevron entered into a fuels terminalling agreement which terminates on December 31, 2019 for the island of Hawaii and may automatically renew for annual terms thereafter unless earlier terminated by either party. Currently, terminalling services are provided for under the Inter-island Fuel Supply Contract with Chevron that expires on December 31, 2016. Each of these contracts are for a term of three years and become effective upon PUC approval, which approval has been requested by an application filed in February 2016, and each contract can be terminated if PUC approval is not received by October 1, 2016. Additionally, Chevron is required to comply with the agreed upon fuel specifications as set forth in the 2016 LSFO Contract and the Petroleum Fuels Contract.

The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under Hawaiian Electric’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays HIE for LSFO under a Facility Fuel Supply Contract (fuel contract) between them (assigned to HIE upon its purchase of the assets of Tesoro Hawaii Corp. as described above). The term of the fuel contract between Kalaeloa and HIE ends May 31, 2016 and may be extended for terms thereafter unless terminated by one of the parties.

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

AES Hawaii, Inc. Under a PPA entered into in March 1988, as amended, for a period of 30 years beginning September 1992, Hawaiian Electric agreed to purchase 180 MW of firm capacity from AES Hawaii. In August 2012, Hawaiian Electric filed an application with the PUC seeking an exemption from the PUC’s Competitive Bidding Framework to negotiate an amendment to the PPA to purchase 186 MW of firm capacity, and amend the energy pricing formula in the PPA. The PUC approved the exemption in April 2013, but Hawaiian Electric and AES Hawaii were not able to reach agreement on an amendment. In June 2015, AES Hawaii filed an arbitration demand regarding a dispute about whether Hawaiian Electric was obligated to buy up to 9 MW of additional capacity based on a 1992 letter. Hawaiian Electric responded to the arbitration demand and, in October 2015, AES Hawaii and Hawaiian Electric entered into a Settlement Agreement to stay the arbitration proceeding. The Settlement Agreement includes certain conditions precedent which, if satisfied, will release the parties from the claims under the arbitration proceeding. Among the conditions precedent is the successful negotiation of an amendment to the existing purchase power agreement and PUC approval of such amendment.

On November 13, 2015, Hawaiian Electric entered into Amendment No. 3 to the AES Hawaii PPA, subject to PUC approval. Amendment No. 3 provides more favorable pricing for the additional 9 MW than the existing pricing, the benefit of which will be passed on to customers, and among other things, provides (1) for an increase in firm capacity of up to 9 MW (the Additional Capacity) above the 180 MW capacity of the AES Hawaii facility, subject to a demonstration of such increased available capacity, (2) for the payment for the Additional Capacity to include a Priority Peak Capacity Charge, a Non-Peak Capacity Charge, a Priority Peak Energy Charge and a Non-Peak Energy Charge and (3) that AES will make certain operational commitments to improve reliability, and Hawaiian Electric will pay a reliability bonus according to a schedule for reduced Full Plant Trips. On January 22, 2016, Amendment No. 3 was filed with the PUC for approval. If such approval is obtained, the final condition to the Settlement Agreement’s release of the parties from the arbitration claims will be satisfied. The arbitration proceeding has been stayed to allow the PUC approval proceeding to proceed.

Liquefied natural gas. On May 31, 2015, the previous August 2014 agreement with FortisBC Energy Inc. (Fortis) for liquefaction capacity for liquefied natural gas (LNG) was superseded with a liquefaction Heads of Agreement by and between FortisBC Holdings Inc. and Hawaiian Electric. The agreement, which is subject to PUC approval, other regulatory approvals and permits and other conditions precedent before it becomes effective, provides for LNG liquefaction capacity purchases of 700,000 tonnes per year for the first five years, 600,000 tonnes per year for the next five years and 500,000 tonnes per year for the last ten 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’ 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.

Utility projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.

Renewable energy project matters. In February 2012, the PUC granted Hawaiian Electric’s request for deferred accounting treatment for the inter-island project support costs. The amount of the deferred costs was limited to $5.89 million. Through December 31, 2013, Hawaiian Electric deferred $3.1 million related to outside contractor service costs incurred with the Oahu 200 MW RFP, and began amortizing such costs over 3 years beginning in July 2014.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, Hawaii Electric Light filed an application to defer 2012 costs related to the Geothermal RFP. In November 2015, the PUC approved the deferral of $2.1 million of costs related to the Geothermal RFP, and will review the prudency and reasonableness of the deferred costs in the next Hawaii Electric Light rate case. In February 2013, Hawaii Electric Light issued the Final Geothermal RFP. Six bids were received, but Hawaii Electric Light notified bidders that none of the submitted bids sufficiently met both the low-cost and technical requirements of the Geothermal RFP. In October 2014, Hawaii Electric Light issued Addendum No. 1 (Best and Final Offer) and Attachment A (Best and Final Offer Bidder's Response Package) directly to five eligible bidders. The submittals received in January 2015 were considered for final selection of one project to proceed with PPA negotiations. In February 2015, Ormat Technologies, Inc. was selected for an award and began PPA negotiations with Hawaii Electric Light. In February 2016, Hawaii Electric Light provided the PUC with a status update notifying the PUC that the selected bidder had determined the proposed project not to be economically and financially viable, resulting in conclusion of PPA negotiations. On March 8, 2016, the Independent Observer issued a report on the results of the negotiation phase of the Geothermal RFP.

Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) Implementation Project. The Utilities submitted its Enterprise Information System Roadmap to the PUC in June 2014 and refiled an application for an ERP/EAM implementation project in July 2014 with an estimated cost of $82.4 million. The refiled application addressed the concerns raised by the PUC, about the initial application, regarding the benefits to customers of completing this project. The estimated cost of the project included the cost of ERP software that had been purchased and recorded as a deferred cost.

To address the Consumer Advocate’s position that the proceeding should be stayed to determine if the project as proposed in the application is reasonable and necessary for future operations as an indirect NEE subsidiary, in May 2015, the Utilities filed a report describing the impact the pending merger with NEE would have on the scope, costs and benefits of the ERP/EAM project. The report indicated that the two viable courses of action for replacing its current system are Option A (to proceed with the project as initially scoped in the Application), and Option B (to move the Utilities to NEE’s existing ERP/EAM solutions). Option B is estimated to cost approximately $20.8 million less than Option A, but can only be pursued if the merger is approved. The Utilities requested the PUC to approve the commencement of work on Option B if the merger is approved; and in the alternative, Option A if the merger is not approved.

In October 2015, the PUC issued a D&O (1) finding that there is a need to replace the existing ERP/EAM system, (2) denying the Utilities request to defer the costs for the ERP software purchased in 2012 and (3) deferring any ruling on whether it is reasonable and in the public interest for the Utilities to commence with the project under Options B or A. As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015, and pursuant to the remaining procedural schedule in the docket, in April 2015: (1) the Utilities filed additional information on the cost and benefits of the project, (2) the Consumer Advocate filed comments on that additional information and (3) the Utilities filed a reply to the Consumer Advocate’s comments. There are no steps remaining in the procedural schedule, and the Utilities are awaiting the issuance of a final D&O.

Schofield Generating Station Project. 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 the construction of a 50 MW utility owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks. In September 2015, the PUC approved Hawaiian Electric’s application to expend $167 million for the project. In approving the project, the PUC placed a cost cap of $167 million for the project, stated 90% of the cap is allowed for cost recovery through cost recovery mechanisms other than base rates, and stated the $167 million cap will be adjusted downward due to any reduction in the cost of the engine contract due to a reduction in the foreign exchange rate. Hawaiian Electric was required to take all necessary steps to lock in the lowest possible exchange rate. On January 5, 2016, Hawaiian Electric executed a window forward agreement which lowered the cost of the engine contract by $9.7 million, resulting in a revised project cost cap of $157.3 million. The generating station is now expected to be placed in service in the first quarter of 2018.

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.

Clean Water Act Section 316(b). On August 14, 2014, the 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 each 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 State of Hawaii Department of Health (DOH) can determine what entrainment or impingement controls, if any, might be necessary at the affected facilities to comply with the new 316(b) rule.

Mercury Air Toxics Standards. On February 16, 2012, EPA published the final rule establishing the National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs) in the Federal Register. 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. Hawaiian Electric received a one-year extension to comply by April 16, 2016. Hawaiian Electric initially selected a MATS compliance strategy based on switching to lower emission fuels, but has since continued developing and refining its emission control strategy. Hawaiian Electric’s liquid oil-fired steam generating units that are subject to the MATS limits may be able to comply with the new standards without a significant fuel switch in combination with a suite of operational changes.

On April 16, 2012, Hawaiian Electric submitted to the EPA a Petition for Reconsideration and Stay (Petition) that asked the EPA to revise an emissions standard for non-continental oil-fired EGUs on the grounds that the promulgated standard was incorrectly derived. On April 21, 2015, the EPA denied Hawaiian Electric's Petition and Hawaiian Electric subsequently filed a lawsuit on June 29, 2015 appealing EPA’s denial. On April 4, 2016, the D.C. Circuit Court of Appeals granted Hawaiian Electric’s uncontested motion to dismiss the case. Hawaiian Electric believes it can comply with the MATS standards due to the operational changes it has made to reduce emissions.

1-Hour Sulfur Dioxide National Ambient Air Quality Standard. On August 1, 2015, the EPA published the Data Requirements Rule for the 2010 1-Hour Sulfur Dioxide (SO₂₎ Primary National Ambient Air Quality Standard (NAAQS). Hawaiian Electric is working with the DOH to gather data EPA requires through the installation and operation of two new 1-hour SO₂ air quality monitoring stations on the island of Oahu. This data will be integrated into the DOH’s statewide monitoring network and will assist the State’s development of its strategy to maintain the NAAQS and comply with the new 1-Hour SO₂ Rule in its State Implementation Plan.

Recent Settlements. Hawaiian Electric resolved outstanding claims raised by the U.S. Fish and Wildlife Service (USFWS) and the Hawaii Department of Land and Natural Resources, Division of Forestry and Wildlife (DOFAW) in March 2016. The USFWS and DOFAW had alleged that Hawaiian Electric violated the Endangered Species Act of 1973 in April of 2011, by clearing vegetation and impacting the habitat for Achatinella mustelina, an endangered Hawaiian tree snail, while servicing its facilities on Mt. Kaala on Oahu. In the respective final settlements resolving the governments’ claims, Hawaiian Electric did not admit any liability, but paid a penalty of $250 to the U.S. Fish and Wildlife Service, and provided $200,000 to the Division of Forestry and Wildlife to rebuild an aging predator-proof snail enclosure in the Pahole Natural Area Reserve.

Potential Clean Air Act Enforcement. On July 1, 2013, Hawaii Electric Light and Maui Electric (the Utilities) received a letter from the U.S. Department of Justice (DOJ) alleging potential violations of the Prevention of Significant Deterioration and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. In correspondence dated November 4, 2014, the DOJ also identified potential violations by Hawaiian Electric at its Kahe facility and proposed resolving the identified, potential violations by entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities continue to negotiate with the DOJ to resolve these issues, 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 identified environmental impacts in the subsurface soil at the Site. Although Maui Electric never operated at the Site or owned the Site property, after 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 environmental contamination. 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. Maui Electric has a reserve balance of $3.6 million as of March 31, 2016 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.

Pearl Harbor sediment study. In July 2014, the U.S. Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is a Potentially Responsible Party responsible for cleanup of PCB contamination in sediment in the area offshore of the Waiau Power Plant as part of the Pearl Harbor Superfund Site. The Navy has also requested that Hawaiian Electric reimburse the costs incurred by the Navy to date to investigate the area. The Navy has completed a remedial investigation and a feasibility study (FS) for the remediation of contaminated sediment at several locations in Pearl Harbor and issued its Final FS Report on June 29, 2015. On February 2, 2016, the Navy released the Proposed Plan for Pearl Harbor Sediment Remediation and Hawaiian Electric submitted comments. The extent of the contamination, the appropriate remedial measures to address it and Hawaiian Electric’s potential responsibility for any associated costs have not been determined.

On March 23, 2015, Hawaiian Electric received a letter from the EPA requesting that Hawaiian Electric submit a work plan to assess potential sources and extent of PCB contamination onshore at the Waiau Power Plant. Hawaiian Electric submitted a sampling and analysis (SAP) work plan to the EPA and the DOH. Sampling of outfall sediments at the Waiau Power Plant was completed in accordance with the SAP in December 2015. The extent of the onshore contamination, the appropriate remedial measures to address it and any associated costs have not yet been determined.

As of March 31, 2016, the reserve account recorded by Hawaiian Electric to address the PCB contamination stands at $4.3 million. The reserve represents the probable and reasonably estimable cost to complete the onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment. The final remediation costs will depend on the results of the onshore investigation and assessment of potential source control requirements, as well as the further investigation of contaminated sediment offshore from the Waiau Power Plant.

Global climate change and greenhouse gas emissions reduction. National and international concerns 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 federal legislative and regulatory proposals and action by the State of Hawaii to reduce GHG emissions.

In July 2007, the State Legislature passed 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. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 (i.e., the final GHG rule), which went into effect on June 30, 2014. In general, Act 234 and the corresponding GHG rule require affected sources (that have the potential to emit GHGs in excess of established thresholds) to reduce their GHG emissions by 16% below 2010 emission levels by 2020. In accordance with the GHG rule, the Utilities submitted their Emissions Reduction Plan (EmRP) to the DOH on June 30, 2015, demonstrating how they will comply. The Utilities have committed to a 16% reduction in GHG emissions company-wide. Pursuant to the State’s GHG rule, the DOH will incorporate the proposed facility-specific GHG emission limits into each facility’s covered source permit based on the 2020 levels specified in Hawaiian Electric’s approved EmRP.

The GHG rule also requires affected sources to pay an annual fee that is based on tons per year of GHG emissions starting on the effective date of the regulations. The fee for the Utilities is estimated to be approximately $0.5 million annually. The latest assessment of the proposed federal and final state GHG rules is that the continued growth in renewable power generation will significantly reduce the compliance costs and risk for the Utilities.

As part of a negotiated amendment to the Power Purchase Agreement between Hawaiian Electric and AES Hawaii (AES), Hawaiian Electric will include the AES facility on Oahu as a partner in the Utilities’ EmRP. Similarly, with the proposed acquisition of the Hamakua Energy Partners (HEP) facility by Hawaii Electric Light, the GHG emissions from the HEP facility will be addressed in the Utilities’ EmRP. Both the AES PPA amendment and the HEP acquisition are subject to PUC approval so the inclusion of these facilities in the Utilities’ EmRP is also subject to PUC approval.

On September 22, 2009, the EPA issued its “Final Mandatory Reporting of Greenhouse Gases Rule,” which requires certain sources that emit GHGs to report their GHG emissions. Following these requirements, the Utilities have submitted the required reports for 2010 through 2015 to the EPA.

The EPA issued the final federal rule for GHG emission reductions from existing EGUs, also known as the Clean Power Plan, on August 3, 2015. The Clean Power Plan set interim state-wide emissions limits for EGUs operating in the 48 contiguous states that must be met on average from 2022 through 2029; final limits will apply from 2030. The final Clean

Power Plan did not set forth guidelines for Alaska, Hawaii, Puerto Rico or Guam, therefore Hawaiian Electric is not currently subject to this Rule.

The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including 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 LNG 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 more comprehensive GHG regulations that might be promulgated; however, the various initiatives that the Utilities are pursuing are likely to provide a sound basis for appropriately managing the Utilities’ carbon footprint and thereby meet both state and federal GHG reduction goals.

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. This effect could potentially result in impacts to coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and result in increased flooding and storm damage due to heavy rainfall, increased rates of beach erosion, saltwater intrusion into freshwater aquifers and terrestrial ecosystems, and higher water tables in low-lying areas. The effects of climate change on the weather (for example, more intense or more frequent rain events, flooding, or hurricanes), sea levels, and freshwater 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 activity and expenditures occurring in partial settlement of these liabilities. Both removal projects are expected to continue through 2016.

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)	2016			2015
Balance, beginning of period	$	26,848		$	29,419
Accretion expense	3			6
Liabilities incurred	—			—
Liabilities settled	(138		)	(1,614		)
Revisions in estimated cash flows	—			—
Balance, end of period	$	26,713		$	27,811

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.

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. The Utilities are updating the performance metrics on a quarterly basis.

On March 31, 2015, the PUC issued an Order (the March 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 March Order modified 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 RAM was 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. The modifications do 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, was retained by the PUC in its March Order, and the PUC made no change in the authorized return on common equity. The PUC stated that performance-based ratemaking is not adopted at this time.

As required by the March Order, the Parties filed initial and reply briefs related to 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 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.

In accordance with the March Order, the Utilities and the Consumer Advocate filed on June 15, 2015, their Joint Proposed Modified REIP Framework/Standards and Guidelines regarding the eligibility of projects for cost recovery above the RAM Cap through the REIP surcharge. On the same date, the Utilities filed their proposed standards and guidelines on the eligibility of projects for cost recovery through the RAM above the RAM Cap. On June 30, 2015, the Consumer Advocate filed comments on this proposal, and the County of Hawaii filed comments on both the REIP and the RAM above the RAM Cap proposals. On October 26, 2015, Hawaiian Electric filed an application to recover the revenue requirements associated with 2015 net plant additions in the amount of $40.3 million (later reduced to $35.7 million) and other associated costs for its Underground Cable Program and the 138kV Transmission and 46kV Sub-Transmission Structures Major Baseline Projects through the RAM above the 2015 RAM Cap. On October 30, 2015, Maui Electric filed an application to recover the revenue requirements associated with 2015 net plant additions in the amount of $4.3 million and other associated costs for its transmission and distribution and generation plant reliability Major Baseline Project through the RAM above the 2015 RAM

Cap. In November 2015, the Consumer Advocate filed preliminary statements of position (PSOPs) on these two applications, recommending that the PUC reject the applications. In December 2015, the Utilities filed responses to the Consumer Advocate’s PSOPs, pointing out that the PUC had already authorized the filing of such applications for recovery of capital costs above the RAM Cap and requesting that the PUC proceed with review of the applications. In March 2016, Maui Electric withdrew its October 30, 2015 application. Maui Electric determined that the application is unnecessary because it could recover the revenue requirements associated with its 2015 net plant additions under the RAM Cap due to: (1) the extension of bonus depreciation in 2015 which resulted in an increased level of accumulated deferred income taxes as an offset to 2015 net plant additions; and (2) the recorded amount of net plant additions in 2015 was less than the estimate of net plant additions in the application. In April 2016, Hawaiian Electric reduced its 2015 net plant additions in its October 26, 2015 application for the same reason as Maui Electric regarding the extension of bonus depreciation in 2015.

Annual decoupling filings. On March 31, 2016, the Utilities submitted to the PUC their annual decoupling filings for tariffed rates that will be effective from June 1, 2016 through May 31, 2017. The net annual incremental amounts to be collected (refunded) were comprised as follows:



($ in millions)	Hawaiian Electric			Hawaii Electric Light			Maui Electric
2016 Annual incremental RAM adjusted revenues	$	11.0		$	2.9		$	2.4
Annual change in accrued earnings sharing credits	$	—		$	—		$	0.5
Annual change in accrued RBA balance as of December 31, 2015 (and associated revenue taxes) (refunded)	$	(13.6	)	$	(2.5	)	$	(4.3	)
Net annual incremental amount to be collected (refunded) under the tariffs	$	(2.6	)	$	0.4		$	(1.4	)
Impact on typical residential customer monthly bill (in dollars) *	$	0.01		$	0.41		$	(0.95	)

* Based on a 500 kilowatthour (KWH) bill for Hawaiian Electric, Maui Electric and Hawaii Electric Light. The bill impact for Lanai and Molokai customers is a decrease of $0.76, based on a 400 KWH bill. Although Hawaiian Electric’s net annual incremental amount is a refund, the typical residential customer monthly bill will increase $0.01 due to lower anticipated KWH sales.

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 to monitor, prepare for, respond to, and take other actions necessary in connection with the June 2014 Kilauea lava flow such that Hawaii Electric Light can request PUC approval to recover those costs in a future rate case. The Consumer Advocate objected to the request. A PUC decision is pending.

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 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) 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 - 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 - the Utilities’ Plan was filed in June 2014.


•	Action Plan for improving efficiencies in the interconnection requirements studies - the Utilities’ Plan was filed in May 2014.


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


•	Integrated interconnection queue for each distribution circuit for each island grid - 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 (see “Distributed Energy Resources (DER) Investigative Proceeding” below) 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 an integrated Demand Response Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. Subsequently, the Utilities submitted status updates and an update and supplemental report to the Plan. On July 28, 2015, the PUC issued an order appointing a special advisor to guide, monitor and review the Utility’s Plan design and implementation. On December 30, 2015, the Utilities filed applications with the PUC (1) for approval of their proposed DR Portfolio Tariff Structure, Reporting Schedule and Cost Recovery of Program Costs through the Demand-Side Management (DSM) Surcharge, and (2) for approval to defer and recover certain computer software and software development costs for a Demand Response Management System (DRMS) through the Renewable Energy Infrastructure Program (REIP) Surcharge.

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 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 is currently being reviewed by the PUC in a new docket along with the Hawaiian Electric and Hawaii Electric Light PSIPs. Maui Electric filed its second annual SICRP status update in September 2015.

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 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.

In November 2015, the PUC issued an order in the proceeding to review the PSIPs filed. The order provided observations and concerns on the PSIPs submitted. In November 2015, as required by the order, the Utilities submitted a Proposed Revision Plan, which included a schedule and a work plan to supplement, amend and update the PSIPs in order to address the PUC’s observations and concerns, including an Interim PSIP Update filing in February 2016 and updated PSIPs by April 1, 2016. The parties and participants filed comments on the Utilities Proposed Revision Plan in January 2016. The PUC is expected to provide further guidance regarding the substance and course of the proceeding.

In February 2016, the Utilities filed their PSIP Update Interim Status Report with the PUC, which discusses the status of the Utilities’ ongoing planning and analysis for a diverse mix of energy resources to meet the state’s 100% RPS goal by 2045. The updated PSIPs were filed on April 1, 2016.

Distributed Energy Resources (DER) Investigative Proceeding. In March 2015, the PUC issued an order to address DER issues.

On June 29, 2015, the Utilities submitted their final Statement of Position in the DER proceeding, which included:


(1)	new pricing provisions for future rooftop photovoltaic (PV) systems,


(2)	technical standards for advanced inverters,


(3)	new options for customers including battery-equipped rooftop PV systems,


(4)	a pilot time-of-use rate,


(5)	an improved method of calculating the amount of rooftop PV that can be safely installed, and


(6)	a streamlined and standardized PV application process.

On October 12, 2015, the PUC issued a D&O establishing DER reforms that: (1) promote rapid adoption of the next generation of solar PV and other distributed energy technologies; (2) encourage more competitive pricing of distributed energy resource systems; (3) lower overall energy supply costs for all customers; and (4) help to manage DER in terms of each island’s limited grid capacity.

The D&O approved a customer self-supply tariff and a customer grid supply tariff to govern customer generators connected to the Utilities’ systems. These tariffs replace the Net Energy Metering (NEM) program.

The D&O ordered the Utilities, among other things, (a) to collaborate with inverter manufacturers to develop a test plan by December 15, 2015 for the highest priority advanced inverter functions that are not UL certified and (b) to complete the circuit-level hosting capacity analysis for all islands in the Utilities’ service territories by December 10, 2015. The DER Phase 2 of this docket began in November 2015 and focused on further developing competitive markets for distributed energy resources, including storage.

On October 21, 2015, The Alliance for Solar Choice, LLC (TASC) filed a complaint in Hawaii state court seeking an order enjoining the PUC from implementing the D&O and declaring that the D&O be reversed, modified and/or remanded to the PUC for further proceedings. On January 19, 2016, the Circuit Court entered a final judgment against TASC on all of its claims. TASC has filed a notice of appeal from the final judgment. TASC also filed a second appeal of the D&O directly with the Intermediate Court of Appeals. On April 20, 2016, the Intermediate Court of Appeals approved stipulations to dismiss both appeals with prejudice.

Derivative financial instrument. On January 5, 2016, Hawaiian Electric executed a window forward agreement to hedge the foreign currency risk associated with the anticipated purchase of engines from a European manufacturer to be included as part of the Schofield generating station. This window forward agreement has been designated as a cash flow hedge under which a single guaranteed exchange rate agreed upon on a certain date for future currency transactions scheduled to occur on specific dates with a “window” or range of plus/minus 30 days. Unrealized gains are recorded at fair value as assets in “other current assets,” and unrealized losses are recorded at fair value as liabilities in “other current liabilities,” both for the period they are outstanding. For this window forward agreement, the effective portion is reported as a component of accumulated other comprehensive income until reclassified into net income consistent with any gains or losses recognized on the engines. The generating station is expected to be placed in service in the first quarter of 2018.



	March 31, 2016				December 31, 2015
(dollars in thousands)	Notional amount		Fair value		Notional amount		Fair value
Window forward contract	$	31,335	$	1,640	$	—	$	—

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

Three months ended March 31, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	337,175		73,183		71,706		—	(12	)	$	482,052
Expenses
Fuel oil	74,085			14,374		25,281		—	—		113,740
Purchased power	91,917			16,797		7,145		—	—		115,859
Other operation and maintenance	69,558			16,441		17,909		—	—		103,908
Depreciation	31,522			9,449		5,810		—	—		46,781
Taxes, other than income taxes	32,684			6,891		6,863		—	—		46,438
Total expenses	299,766			63,952		63,008		—	—		426,726
Operating income	37,409			9,231		8,698		—	(12	)	55,326
Allowance for equity funds used during construction	1,406			127		206		—	—		1,739
Equity in earnings of subsidiaries	7,929			—		—		—	(7,929	)	—
Interest expense and other charges, net	(11,865		)	(2,965	)	(2,490	)	—	12		(17,308		)
Allowance for borrowed funds used during construction	529			49		84		—	—		662
Income before income taxes	35,408			6,442		6,498		—	(7,929	)	40,419
Income taxes	9,771			2,346		2,436		—	—		14,553
Net income	25,637			4,096		4,062		—	(7,929	)	25,866
Preferred stock dividends of subsidiaries	—			134		95		—	—		229
Net income attributable to Hawaiian Electric	25,637			3,962		3,967		—	(7,929	)	25,637
Preferred stock dividends of Hawaiian Electric	270			—		—		—	—		270
Net income for common stock	$	25,367		3,962		3,967		—	(7,929	)	$	25,367

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income

Three months ended March 31, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	25,367		3,962		3,967		—	(7,929	)	$	25,367
Other comprehensive income, net of taxes:
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized gain, net of taxes	1,002			—		—		—	—		1,002
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	3,236			458		418		—	(876	)	3,236
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(3,222		)	(458	)	(418	)	—	876		(3,222		)
Other comprehensive income, net of taxes	1,016			—		—		—	—		1,016
Comprehensive income attributable to common shareholder	$	26,383		3,962		3,967		—	(7,929	)	$	26,383

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income

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

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 Balance Sheet

March 31, 2016



(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	$	43,972		6,219		3,016		—	—		$	53,207
Plant and equipment	4,059,986			1,213,924		1,082,096		—	—		6,356,006
Less accumulated depreciation	(1,325,559		)	(490,883	)	(468,486	)	—	—		(2,284,928		)
Construction in progress	163,196			16,648		18,160		—	—		198,004
Utility property, plant and equipment, net	2,941,595			745,908		634,786		—	—		4,322,289
Nonutility property, plant and equipment, less accumulated depreciation	5,762			82		1,531		—	—		7,375
Total property, plant and equipment, net	2,947,357			745,990		636,317		—	—		4,329,664
Investment in wholly owned subsidiaries, at equity	557,885			—		—		—	(557,885	)	—
Current assets
Cash and cash equivalents	29,307			12,070		7,564		101	—		49,042
Advances to affiliates	—			12,500		7,000		—	(19,500	)	—
Customer accounts receivable, net	69,744			18,399		15,596		—	—		103,739
Accrued unbilled revenues, net	60,022			12,857		12,488		—	—		85,367
Other accounts receivable, net	13,180			1,271		1,269		—	(8,947	)	6,773
Fuel oil stock, at average cost	34,553			5,688		8,163		—	—		48,404
Materials and supplies, at average cost	30,543			6,892		16,821		—	—		54,256
Prepayments and other	18,430			2,223		2,436		—	(1,286	)	21,803
Regulatory assets	80,918			5,563		2,711		—	—		89,192
Total current assets	336,697			77,463		74,048		101	(29,733	)	458,576
Other long-term assets
Regulatory assets	586,873			112,052		100,291		—	—		799,216
Unamortized debt expense	304			60		56		—	—		420
Other	47,516			14,129		12,850		—	—		74,495
Total other long-term assets	634,693			126,241		113,197		—	—		874,131
Total assets	$	4,476,632		949,694		823,562		101	(587,618	)	$	5,662,371
Capitalization and liabilities
Capitalization
Common stock equity	$	1,731,304		293,358		264,426		101	(557,885	)	$	1,731,304
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	875,308			213,608		190,000		—	—		1,278,916
Total capitalization	2,628,905			513,966		459,426		101	(557,885	)	3,044,513
Current liabilities
Short-term borrowings from non-affiliates	12,998			—		—		—	—		12,998
Short-term borrowings from affiliate	19,500			—		—		—	(19,500	)	—
Accounts payable	73,021			12,391		9,678		—	—		95,090
Interest and preferred dividends payable	18,543			4,173		4,301		—	(2	)	27,015
Taxes accrued	87,303			22,787		20,435		—	(1,286	)	129,239
Regulatory liabilities	—			4,063		1,353		—	—		5,416
Other	62,307			9,019		12,625		—	(8,945	)	75,006
Total current liabilities	273,672			52,433		48,392		—	(29,733	)	344,764
Deferred credits and other liabilities
Deferred income taxes	477,446			102,039		90,353		—	288		670,126
Regulatory liabilities	259,907			87,514		30,956		—	—		378,377
Unamortized tax credits	55,446			15,555		14,901		—	—		85,902
Defined benefit pension and other postretirement benefit plans liability	405,024			69,103		73,390		—	—		547,517
Other	49,944			13,625		14,371		—	(288	)	77,652
Total deferred credits and other liabilities	1,247,767			287,836		223,971		—	—		1,759,574
Contributions in aid of construction	326,288			95,459		91,773		—	—		513,520
Total capitalization and liabilities	$	4,476,632		949,694		823,562		101	(587,618	)	$	5,662,371

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet

December 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	$	43,557		6,219		3,016		—	—		$	52,792
Plant and equipment	4,026,079			1,212,195		1,077,424		—	—		6,315,698
Less accumulated depreciation	(1,316,467		)	(486,028	)	(463,509	)	—	—		(2,266,004		)
Construction in progress	147,979			11,455		15,875		—	—		175,309
Utility property, plant and equipment, net	2,901,148			743,841		632,806		—	—		4,277,795
Nonutility property, plant and equipment, less accumulated depreciation	5,659			82		1,531		—	—		7,272
Total property, plant and equipment, net	2,906,807			743,923		634,337		—	—		4,285,067
Investment in wholly owned subsidiaries, at equity	556,528			—		—		—	(556,528	)	—
Current assets
Cash and cash equivalents	16,281			2,682		5,385		101	—		24,449
Advances to affiliates	—			15,500		7,500		—	(23,000	)	—
Customer accounts receivable, net	93,515			20,508		18,755		—	—		132,778
Accrued unbilled revenues, net	60,080			12,531		11,898		—	—		84,509
Other accounts receivable, net	16,421			1,275		1,674		—	(8,962	)	10,408
Fuel oil stock, at average cost	49,455			8,310		13,451		—	—		71,216
Materials and supplies, at average cost	30,921			6,865		16,643		—	—		54,429
Prepayments and other	25,505			9,091		2,295		—	(251	)	36,640
Regulatory assets	63,615			4,501		4,115		—	—		72,231
Total current assets	355,793			81,263		81,716		101	(32,213	)	486,660
Other long-term assets
Regulatory assets	608,957			114,562		100,981		—	—		824,500
Unamortized debt expense	359			74		64		—	—		497
Other	47,731			14,693		13,062		—	—		75,486
Total other long-term assets	657,047			129,329		114,107		—	—		900,483
Total assets	$	4,476,175		954,515		830,160		101	(588,741	)	$	5,672,210
Capitalization and liabilities
Capitalization
Common stock equity	$	1,728,325		292,702		263,725		101	(556,528	)	$	1,728,325
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	875,163			213,580		189,959		—	—		1,278,702
Total capitalization	2,625,781			513,282		458,684		101	(556,528	)	3,041,320
Current liabilities
Short-term borrowings from affiliate	23,000			—		—		—	(23,000	)	—
Accounts payable	84,631			17,702		12,513		—	—		114,846
Interest and preferred dividends payable	15,747			4,255		3,113		—	(4	)	23,111
Taxes accrued	131,668			30,342		29,325		—	(251	)	191,084
Regulatory liabilities	—			1,030		1,174		—	—		2,204
Other	41,083			8,760		13,194		—	(8,958	)	54,079
Total current liabilities	296,129			62,089		59,319		—	(32,213	)	385,324
Deferred credits and other liabilities
Deferred income taxes	466,133			100,681		87,706		—	286		654,806
Regulatory liabilities	254,033			84,623		30,683		—	—		369,339
Unamortized tax credits	54,078			15,406		14,730		—	—		84,214
Defined benefit pension and other postretirement benefit plans liability	409,021			69,893		74,060		—	—		552,974
Other	51,273			13,243		13,916		—	(286	)	78,146
Total deferred credits and other liabilities	1,234,538			283,846		221,095		—	—		1,739,479
Contributions in aid of construction	319,727			95,298		91,062		—	—		506,087
Total capitalization and liabilities	$	4,476,175		954,515		830,160		101	(588,741	)	$	5,672,210

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity

Three months ended March 31, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Balance, December 31, 2015	$	1,728,325		292,702		263,725		101	(556,528	)	$	1,728,325
Net income for common stock	25,367			3,962		3,967		—	(7,929	)	25,367
Other comprehensive income, net of taxes	1,016			—		—		—	—		1,016
Common stock dividends	(23,400		)	(3,302	)	(3,265	)	—	6,567		(23,400		)
Common stock issuance expenses	(4		)	(4	)	(1	)	—	5		(4		)
Balance, March 31, 2016	$	1,731,304		293,358		264,426		101	(557,885	)	$	1,731,304

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity

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 Cash Flows

Three months ended March 31, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	25,637		4,096		4,062		—	(7,929	)	$	25,866
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries	(7,954		)	—		—		—	7,929		(25		)
Common stock dividends received from subsidiaries	6,592			—		—		—	(6,567	)	25
Depreciation of property, plant and equipment	31,522			9,449		5,810		—	—		46,781
Other amortization	1,045			268		461		—	—		1,774
Increase in deferred income taxes	9,764			1,277		2,517		—	—		13,558
Change in tax credits, net	1,386			154		162		—	—		1,702
Allowance for equity funds used during construction	(1,406		)	(127	)	(206	)	—	—		(1,739		)
Changes in assets and liabilities:
Decrease in accounts receivable	22,606			2,113		3,563		—	15		28,297
Decrease (increase) in accrued unbilled revenues	58			(326	)	(590	)	—	—		(858		)
Decrease in fuel oil stock	14,902			2,622		5,288		—	—		22,812
Decrease (increase) in materials and supplies	378			(27	)	(178	)	—	—		173
Decrease in regulatory assets	79			397		1,109		—	—		1,585
Increase in accounts payable	24,827			1,652		1,287		—	—		27,766
Change in prepaid and accrued income and utility revenue taxes	(31,916		)	(1,634	)	(8,466	)	—	(2	)	(42,018		)
Increase in defined benefit pension and other postretirement benefit plans liability	177			13		15		—	—		205
Change in other assets and liabilities	15,249			5,562		169		—	(13	)	20,967
Net cash provided by operating activities	112,946			25,489		15,003		—	(6,567	)	146,871
Cash flows from investing activities
Capital expenditures	(97,363		)	(16,649	)	(11,171	)	—	—		(125,183		)
Contributions in aid of construction	11,585			969		1,207		—	—		13,761
Other	22			23		—		—	—		45
Advances from affiliates	—			3,000		500		—	(3,500	)	—
Net cash used in investing activities	(85,756		)	(12,657	)	(9,464	)	—	(3,500	)	(111,377		)
Cash flows from financing activities
Common stock dividends	(23,400		)	(3,302	)	(3,265	)	—	6,567		(23,400		)
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	9,498			—		—		—	3,500		12,998
Other	8			(8	)	—		—	—		—
Net cash used in financing activities	(14,164		)	(3,444	)	(3,360	)	—	10,067		(10,901		)
Net increase in cash and cash equivalents	13,026			9,388		2,179		—	—		24,593
Cash and cash equivalents, beginning of period	16,281			2,682		5,385		101	—		24,449
Cash and cash equivalents, end of period	$	29,307		12,070		7,564		101	—		$	49,042

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows

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		608		—	—		1,698
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		)
Changes in assets and liabilities:
Decrease 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		)
Increase (decrease) in accounts payable	16,520			(2,548	)	1,408		—	—		15,380
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	(8,614		)	203		(517	)	—	(846	)	(9,774		)
Net cash provided by operating activities	66,599			18,300		18,560		—	(6,299	)	97,160
Cash flows from investing activities
Capital expenditures	(92,242		)	(14,902	)	(11,730	)	—	—		(118,874		)
Contributions in aid of construction	8,121			758		266		—	—		9,145
Other	175			26		42		—	—		243
Advances from (to) affiliates	3,500			—		—		—	(3,500	)	—
Net cash used in investing activities	(80,446		)	(14,118	)	(11,422	)	—	(3,500	)	(109,486		)
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

5 · Bank segment

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data



	Three months ended March 31
(in thousands)	2016		2015
Interest and dividend income
Interest and fees on loans	$	48,437	$	45,198
Interest and dividends on investment securities	5,017		3,051
Total interest and dividend income	53,454		48,249
Interest expense
Interest on deposit liabilities	1,592		1,260
Interest on other borrowings	1,485		1,466
Total interest expense	3,077		2,726
Net interest income	50,377		45,523
Provision for loan losses	4,766		614
Net interest income after provision for loan losses	45,611		44,909
Noninterest income
Fees from other financial services	5,499		5,355
Fee income on deposit liabilities	5,156		5,315
Fee income on other financial products	2,205		1,889
Bank-owned life insurance	998		983
Mortgage banking income	1,195		1,822
Other income, net	333		735
Total noninterest income	15,386		16,099
Noninterest expense
Compensation and employee benefits	22,434		21,766
Occupancy	4,138		4,113
Data processing	3,172		3,116
Services	2,911		2,341
Equipment	1,663		1,701
Office supplies, printing and postage	1,365		1,483
Marketing	861		841
FDIC insurance	884		811
Other expense	3,975		4,205
Total noninterest expense	41,403		40,377
Income before income taxes	19,594		20,631
Income taxes	6,921		7,156
Net income	$	12,673	$	13,475

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data



	Three months ended March 31
(in thousands)	2016		2015
Net income	$	12,673	$	13,475
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 $4,905 and $2,278 for the respective periods	7,429		3,451
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 $137 and $259 for the respective periods	208		392
Other comprehensive income, net of taxes	7,637		3,843
Comprehensive income	$	20,310	$	17,318

American Savings Bank, F.S.B.

Balance Sheets Data



(in thousands)	March 31, 2016						December 31, 2015
Assets
Cash and due from banks				$	110,200					$	127,201
Interest-bearing deposits				120,428						93,680
Available-for-sale investment securities, at fair value				906,295						820,648
Stock in Federal Home Loan Bank, at cost				11,218						10,678
Loans receivable held for investment				4,642,276						4,615,819
Allowance for loan losses				(52,326		)				(50,038		)
Net loans				4,589,950						4,565,781
Loans held for sale, at lower of cost or fair value				7,900						4,631
Other				312,333						309,946
Goodwill				82,190						82,190
Total assets				$	6,140,514					$	6,014,755

Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing				$	1,541,402					$	1,520,374
Deposit liabilities—interest-bearing				3,598,530						3,504,880
Other borrowings				329,081						328,582
Other				99,605						101,029
Total liabilities				5,568,618						5,454,865
Commitments and contingencies
Common stock				1						1
Additional paid in capital				341,192						340,496
Retained earnings				240,337						236,664
Accumulated other comprehensive loss, net of tax benefits
Net unrealized gains (losses) on securities	$	5,556					$	(1,872	)
Retirement benefit plans	(15,190		)	(9,634		)	(15,399		)	(17,271		)
Total shareholder’s equity				571,896						559,890
Total liabilities and shareholder’s equity				$	6,140,514					$	6,014,755

Other assets
Bank-owned life insurance				$	138,732					$	138,139
Premises and equipment, net				89,525						88,077
Prepaid expenses				5,329						3,550
Accrued interest receivable				15,723						15,192
Mortgage-servicing rights				8,857						8,884
Low-income housing equity investments				36,450						37,793
Real estate acquired in settlement of loans, net				797						1,030
Other				16,920						17,281
				$	312,333					$	309,946
Other liabilities
Accrued expenses				$	26,055					$	30,705
Federal and state income taxes payable				22,324						13,448
Cashier’s checks				21,542						21,768
Advance payments by borrowers				6,403						10,311
Other				23,281						24,797
				$	99,605					$	101,029

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 $229 million and $100 million, respectively, as of March 31, 2016 and $229 million and $100 million, respectively, as of December 31, 2015.

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
(dollars in thousands)										Number of issues	Fair value		Amount			Number of issues	Fair value		Amount
March 31, 2016
Available-for-sale
U.S. Treasury and federal agency obligations	$	215,716	$	3,078	$	(97	)	$	218,697	—	$	—	$	—		2	$	9,511	$	(97	)
Mortgage-related securities- FNMA, FHLMC and GNMA	681,354		7,852		(1,608		)	687,598		9	67,217		(256		)	21	100,991		(1,352		)
	$	897,070	$	10,930	$	(1,705	)	$	906,295	9	$	67,217	$	(256	)	23	$	110,502	$	(1,449	)
December 31, 2015
Available-for-sale
U.S. Treasury and federal agency obligations	$	213,234	$	1,025	$	(1,300	)	$	212,959	13	$	83,053	$	(866	)	3	$	17,378	$	(434	)
Mortgage-related securities- FNMA, FHLMC and GNMA	610,522		3,564		(6,397		)	607,689		38	305,785		(2,866		)	25	125,817		(3,531		)
	$	823,756	$	4,589	$	(7,697	)	$	820,648	51	$	388,838	$	(3,732	)	28	$	143,195	$	(3,965	)

ASB does not believe that the investment securities that were in an unrealized loss position at March 31, 2016, represent an other-than-temporary impairment. Total gross unrealized losses were primarily attributable to rising interest rates relative to when the investment securities were purchased and not due to the credit quality of the investment securities. The contractual cash flows of the investment securities are backed by the full faith and credit guaranty of the United States government or an agency of the government. ASB does not intend to sell the securities before the recovery of its amortized cost basis and there have been no adverse changes in the timing of the contractual cash flows for the securities. ASB did not recognize OTTI for the quarters ended March 31, 2016 and 2015.

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, 2016	Amortized cost		Fair value
(in thousands)
Due in one year or less	$	—	$	—
Due after one year through five years	111,299		112,991
Due after five years through ten years	66,398		67,413
Due after ten years	38,019		38,293
	215,716		218,697
Mortgage-related securities-FNMA,FHLMC and GNMA	681,354		687,598
Total available-for-sale securities	$	897,070	$	906,295

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, 2016
Allowance for loan losses:
Beginning balance	$	4,186		$	11,342	$	7,260		$	1,671		$	4,461		$	13		$	17,208		$	3,897		$	—	$	50,038
Charge-offs	(45		)	—		—			—			—			—			(1,343		)	(1,570		)	—		(2,958		)
Recoveries	17			—		15			103			—			—			135			210			—		480
Provision	435			464		(103		)	(34		)	1,703			(1		)	991			1,311			—		4,766
Ending balance	$	4,593		$	11,806	$	7,172		$	1,740		$	6,164		$	12		$	16,991		$	3,848		$	—	$	52,326
March 31, 2016
Ending balance: individually evaluated for impairment	$	1,653		$	50	$	629		$	841		$	—		$	—		$	3,643		$	7				$	6,823
Ending balance: collectively evaluated for impairment	$	2,940		$	11,756	$	6,543		$	899		$	6,164		$	12		$	13,348		$	3,841		$	—	$	45,503
Financing Receivables:
Ending balance	$	2,055,020		$	703,661	$	846,467		$	18,940		$	130,487		$	16,241		$	740,596		$	136,244				$	4,647,656
Ending balance: individually evaluated for impairment	$	22,585		$	3,727	$	3,820		$	4,477		$	—		$	—		$	26,099		$	13				$	60,721
Ending balance: collectively evaluated for impairment	$	2,032,435		$	699,934	$	842,647		$	14,463		$	130,487		$	16,241		$	714,497		$	136,231				$	4,586,935
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
December 31, 2015
Ending balance: individually evaluated for impairment	$	1,453		$	—	$	442		$	891		$	—		$	—		$	3,527		$	7				$	6,320
Ending balance: collectively evaluated for impairment	$	2,733		$	11,342	$	6,818		$	780		$	4,461		$	13		$	13,681		$	3,890		$	—	$	43,718
Financing Receivables:
Ending balance	$	2,069,665		$	690,561	$	846,294		$	18,229		$	100,796		$	14,089		$	758,659		$	123,775				$	4,622,068
Ending balance: individually evaluated for impairment	$	22,457		$	1,188	$	3,225		$	5,683		$	—		$	—		$	21,119		$	13				$	53,685
Ending balance: collectively evaluated for impairment	$	2,047,208		$	689,373	$	843,069		$	12,546		$	100,796		$	14,089		$	737,540		$	123,762				$	4,568,383

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 loss given default 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, 2016						December 31, 2015
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	655,307	$	110,744	$	679,370	$	642,410	$	86,991	$	703,208
Special mention	16,096		—		12,662		7,710		13,805		7,029
Substandard	32,258		19,743		48,302		40,441		—		47,975
Doubtful	—		—		262		—		—		447
Loss	—		—		—		—		—		—
Total	$	703,661	$	130,487	$	740,596	$	690,561	$	100,796	$	758,659

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, 2016
Real estate:
Residential 1-4 family	$	5,537	$	2,215	$	10,626	$	18,378	$	2,036,642	$	2,055,020	$	—
Commercial real estate	—		—		—		—		703,661		703,661		—
Home equity line of credit	1,218		508		340		2,066		844,401		846,467		—
Residential land	—		—		148		148		18,792		18,940		—
Commercial construction	—		—		—		—		130,487		130,487		—
Residential construction	—		—		—		—		16,241		16,241		—
Commercial	391		984		308		1,683		738,913		740,596		—
Consumer	1,249		579		446		2,274		133,970		136,244		—
Total loans	$	8,395	$	4,286	$	11,868	$	24,549	$	4,623,107	$	4,647,656	$	—
December 31, 2015
Real estate:
Residential 1-4 family	$	4,967	$	3,289	$	11,503	$	19,759	$	2,049,906	$	2,069,665	$	—
Commercial real estate	—		—		—		—		690,561		690,561		—
Home equity line of credit	896		706		477		2,079		844,215		846,294		—
Residential land	—		—		415		415		17,814		18,229		—
Commercial construction	—		—		—		—		100,796		100,796		—
Residential construction	—		—		—		—		14,089		14,089		—
Commercial	125		223		878		1,226		757,433		758,659		—
Consumer	1,383		593		644		2,620		121,155		123,775		—
Total loans	$	7,371	$	4,811	$	13,917	$	26,099	$	4,595,969	$	4,622,068	$	—

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, 2016		December 31, 2015
Real estate:
Residential 1-4 family	$	21,028	$	20,554
Commercial real estate	3,727		1,188
Home equity line of credit	2,801		2,254
Residential land	698		970
Commercial construction	—		—
Residential construction	—		—
Commercial	17,862		20,174
Consumer	797		895
Total nonaccrual loans	$	46,913	$	46,035
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	$	13,803	$	13,962
Commercial real estate	—		—
Home equity line of credit	2,643		2,467
Residential land	3,779		4,713
Commercial construction	—		—
Residential construction	—		—
Commercial	8,400		1,104
Consumer	—		—
Total troubled debt restructured loans not included above	$	28,625	$	22,246

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



	March 31, 2016						Three months ended March 31, 2016
(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	$	10,502	$	11,606	$	—	$	10,392	$	51
Commercial real estate	1,166		1,429		—		1,173		—
Home equity line of credit	913		1,159		—		849		—
Residential land	1,489		2,185		—		1,590		16
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	5,079		5,831		—		4,999		6
Consumer	—		—		—		—		—
	$	19,149	$	22,210	$	—	$	19,003	$	73
With an allowance recorded
Real estate:
Residential 1-4 family	$	12,083	$	12,286	$	1,653	$	12,018	$	122
Commercial real estate	2,561		2,570		50		854		—
Home equity line of credit	2,907		2,977		629		2,944		27
Residential land	2,988		2,988		841		3,378		67
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	21,020		21,714		3,643		16,970		30
Consumer	13		13		7		13		—
	$	41,572	$	42,548	$	6,823	$	36,177	$	246
Total
Real estate:
Residential 1-4 family	$	22,585	$	23,892	$	1,653	$	22,410	$	173
Commercial real estate	3,727		3,999		50		2,027		—
Home equity line of credit	3,820		4,136		629		3,793		27
Residential land	4,477		5,173		841		4,968		83
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	26,099		27,545		3,643		21,969		36
Consumer	13		13		7		13		—
	$	60,721	$	64,758	$	6,823	$	55,180	$	319



	December 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	$	10,596	$	11,805	$	—	$	11,552	$	89
Commercial real estate	1,188		1,436		—		555		—
Home equity line of credit	707		948		—		400		1
Residential land	1,644		2,412		—		2,637		52
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	5,671		6,333		—		7,295		2
Consumer	—		—		—		—		—
	$	19,806	$	22,934	$	—	$	22,439	$	144
With an allowance recorded
Real estate:
Residential 1-4 family	$	11,861	$	11,914	$	1,453	$	11,510	$	126
Commercial real estate	—		—		—		4,482		—
Home equity line of credit	2,518		2,579		442		626		6
Residential land	4,039		4,117		891		5,189		83
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	15,448		16,073		3,527		4,982		50
Consumer	13		13		7		15		—
	$	33,879	$	34,696	$	6,320	$	26,804	$	265
Total
Real estate:
Residential 1-4 family	$	22,457	$	23,719	$	1,453	$	23,062	$	215
Commercial real estate	1,188		1,436		—		5,037		—
Home equity line of credit	3,225		3,527		442		1,026		7
Residential land	5,683		6,529		891		7,826		135
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial	21,119		22,406		3,527		12,277		52
Consumer	13		13		7		15		—
	$	53,685	$	57,630	$	6,320	$	49,243	$	409


*	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 or

reduction 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 and the impact on the allowance for loan losses were as follows:



	Three months ended March 31, 2016
	Number of contracts	Outstanding recorded investment¹				Net increase in allowance
(dollars in thousands)	Number of contracts	Pre-modification		Post-modification		(as of period end)
Troubled debt restructurings
Real estate:
Residential 1-4 family	4	$	1,097	$	1,215	$	161
Commercial real estate	—	—		—		—
Home equity line of credit	10	669		669		74
Residential land	—	—		—		—
Commercial construction	—	—		—		—
Residential construction	—	—		—		—
Commercial	3	16,200		16,200		525
Consumer	—	—		—		—
	17	$	17,966	$	18,084	$	760



	Three months ended March 31, 2015
	Number of contracts	Outstanding recorded investment¹				Net increase in allowance
(dollars in thousands)	Number of 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


¹	The reported balances include loans that became TDR during the period, and were fully paid-off, charged-off, or sold prior to period end.

Loans modified in TDRs that experienced a payment default of 90 days or more during the three months ended March 31, 2016 and 2015, and for which the payment of default occurred within one year of the modification, were as follows:



Three months ended March 31	2016			2015
(dollars in thousands)	Number of contracts	Recorded investment		Number of contracts	Recorded investment
Troubled debt restructurings that subsequently defaulted
Real estate:
Residential 1-4 family	1	$	488	—	$	—
Commercial real estate	—	—		—	—
Home equity line of credit	—	—		—	—
Residential land	—	—		—	—
Commercial construction	—	—		—	—
Residential construction	—	—		—	—
Commercial	—	—		—	—
Consumer	—	—		—	—
	1	$	488	—	$	—

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. Commitments to lend additional funds to borrowers whose loan terms have been modified in a TDR totaled $2.3 million at March 31, 2016.

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 loans other than the servicing rights of certain loans sold.

ASB received $40.4 million and $78.3 million of proceeds from the sale of residential mortgages for the quarters ended March 31, 2016 and 2015, respectively, and recognized gains on such sales of $1.2 million and $1.8 million for the quarters ended March 31, 2016 and 2015, respectively. Repurchased mortgage loans for the quarters ended March 31, 2016 and 2015 were nil and nil, respectively. The repurchase reserve was $0.1 million and nil for the quarters ended March 31, 2016 and 2015, respectively.

Mortgage servicing fees, a component of other income, net, were $0.7 million and $0.9 million for the three months ended March 31, 2016 and 2015, respectively.

Changes in the carrying value of mortgage servicing rights were as follows:



(in thousands)	Gross carrying amount¹		Accumulated amortization¹			Valuation allowance		Net carrying amount
March 31, 2016	$	14,986	$	(6,129	)	$	—	$	8,857
December 31, 2015	14,531		(5,647		)	—		8,884

¹ Reflects the impact of loans paid in full.

Changes related to mortgage servicing rights were as follows:



(in thousands)	2016			2015
Mortgage servicing rights
Balance, January 1	$	8,884		$	11,749
Amount capitalized	455			906
Amortization	(482		)	(647		)
Other-than-temporary impairment	—			(2		)
Carrying amount before valuation allowance, March 31	8,857			12,006
Valuation allowance for mortgage servicing rights
Balance, January 1	—			209
Provision (recovery)	—			(166		)
Other-than-temporary impairment	—			(2		)
Balance, March 31	—			41
Net carrying value of mortgage servicing rights	$	8,857		$	11,965

ASB capitalizes mortgage servicing rights acquired through either the purchase or origination of mortgage loans for sale with servicing rights retained. On a monthly basis, ASB compares the net carrying value of the mortgage servicing rights to its fair value to determine if there are any changes to the valuation allowance and/or other-than-temporary impairment for the mortgage servicing rights. ASB’s MSRs are stratified based on predominant risk characteristics of the underlying loans including loan type such as fixed-rate 15 and 30 year mortgages and note rate in bands of 50 to 100 basis points. For each stratum, fair value is calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. 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. 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.

ASB uses a present value cash flow model using techniques described above to estimate the fair value of MSRs. 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.

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



(dollars in thousands)	March 31, 2016			December 31, 2015
Unpaid principal balance	$	1,114,800		$	1,097,314
Weighted average note rate	4.04		%	4.05		%
Weighted average discount rate	9.6		%	9.6		%
Weighted average prepayment speed	10.8		%	9.3		%

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



(dollars in thousands)	March 31, 2016			December 31, 2015
Prepayment rate:
25 basis points adverse rate change	$	(537	)	$	(561	)
50 basis points adverse rate change	(1,008		)	(1,104		)
Discount rate:
25 basis points adverse rate change	(99		)	(111		)
50 basis points adverse rate change	(196		)	(220		)

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. ASB pledges investment securities as collateral for securities sold under agreements to repurchase. 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, 2016	$229	$—	$229
December 31, 2015	229	—	229



	Gross amount not offset in the Balance Sheet
(in millions)	Liabilities presented in the Balance Sheet		Financial instruments		Cash collateral pledged
March 31, 2016
Financial institution	$	50	$	57	$	—
Government entities	37		44		—
Commercial account holders	142		161		—
Total	$	229	$	262	$	—
December 31, 2015
Financial institution	$	50	$	56	$	—
Government entities	56		61		—
Commercial account holders	123		144		—
Total	$	229	$	261	$	—

The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts or into segregated tri-party custodial accounts at the FHLB. 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 consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.

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, 2016					December 31, 2015
(in thousands)	Notional amount		Fair value			Notional amount		Fair value
Interest rate lock commitments	$	32,135	$	655		$	22,241	$	384
Forward commitments	30,516		(192		)	23,644		(29		)

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, 2016				December 31, 2015
(in thousands)	Asset derivatives		Liability derivatives		Asset derivatives		Liability derivatives
Interest rate lock commitments	$	655	$	—	$	384	$	—
Forward commitments	—		192		1		30
	$	655	$	192	$	385	$	30

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)		2016			2015
Interest rate lock commitments	Mortgage banking income	$	271		$	445
Forward commitments	Mortgage banking income	(163		)	(159		)
		$	108		$	286

Low-Income Housing Tax Credit (LIHTC). ASB’s unfunded commitments to fund its LIHTC investment partnerships were $7.6 million and $10.1 million at March 31, 2016 and December 31, 2015, respectively. These unfunded commitments were unconditional and legally binding and are recorded in other liabilities with a corresponding increase in other assets. Cash contributions and payments made on commitments to LIHTC investment partnerships are classified as operating activities in the Company’s consolidated statements of cash flows. As of March 31, 2016, 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. ASB is subject in the normal course of business to pending and threatened legal proceedings. Management does not anticipate that the aggregate ultimate liability arising out of these pending or threatened legal proceedings will be material to its financial position. However, ASB cannot rule out the possibility that such outcomes could have a material adverse effect on the results of operations or liquidity for a particular reporting period in the future.

6 · Retirement benefits

Defined benefit pension and other postretirement benefit plans information. For the first three months of 2016, the Company contributed $16 million ($16 million by the Utilities) to its pension and other postretirement benefit plans, compared to $21 million ($21 million by the Utilities) in the first three months of 2015. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2016 is $65 million ($64 million by the Utilities, $1 million by HEI and nil by ASB), compared to $88 million ($86 million by the Utilities, $2 million by HEI and nil by ASB) in 2015. In addition, the Company expects to pay directly $2 million ($1 million by the Utilities) of benefits in 2016, compared to $1 million ($0.4 million by the Utilities) paid in 2015.

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)	2016			2015			2016			2015
HEI consolidated
Service cost	$	15,391		$	16,466		$	836		$	869
Interest cost	20,277			19,139			2,474			2,235
Expected return on plan assets	(24,664		)	(22,151		)	(3,052		)	(2,907		)
Amortization of net prior service loss (gain)	(14		)	1			(448		)	(448		)
Amortization of net actuarial loss	5,969			8,962			287			430
Net periodic benefit cost	16,959			22,417			97			179
Impact of PUC D&Os	(4,046		)	(9,513		)	189			98
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	12,913		$	12,904		$	286		$	277
Hawaiian Electric consolidated
Service cost	$	14,933		$	15,983		$	822		$	855
Interest cost	18,603			17,516			2,389			2,159
Expected return on plan assets	(22,932		)	(20,632		)	(3,003		)	(2,859		)
Amortization of net prior service loss (gain)	4			10			(451		)	(451		)
Amortization of net actuarial loss	5,461			8,094			284			422
Net periodic benefit cost	16,069			20,971			41			126
Impact of PUC D&Os	(4,046		)	(9,513		)	189			98
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	12,023		$	11,458		$	230		$	224

HEI consolidated recorded retirement benefits expense of $9 million ($8 million by the Utilities) and $9 million ($8 million by the Utilities) in the first three months of 2016 and 2015, 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 2016 and 2015, 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 $1.4 million, respectively, and cash contributions were $2.7 million and $2.5 million, respectively. For the first three months of 2016 and 2015, the Utilities’ expense for its defined contribution pension plan under the HEIRSP was $0.4 million and $0.4 million, respectively, and cash contributions were $0.4 million and $0.4 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, 2016, approximately 3.4 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 0.4 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, 2016, there were 141,044 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)	2016		2015
HEI consolidated
Share-based compensation expense ¹	$	1.0	$	1.8
Income tax benefit	0.3		0.6
Hawaiian Electric consolidated
Share-based compensation expense ¹	0.3		0.5
Income tax benefit	0.1		0.2


¹	For the three months ended March 31, 2016, the Company has not capitalized any share-based compensation. $0.04 million of this share-based compensation expense was capitalized in the three months ended March 31, 2015.

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 March 31, 2016 and December 31, 2015, there were no remaining SARs outstanding.

SARs activity and statistics were as follows:



	Three months ended
(dollars in thousands, except prices)	March 31, 2015
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
	2016					2015
	Shares			(1)		Shares			(1)
Outstanding, beginning of period	210,634			$	28.82	261,235			$	25.77
Granted	94,282			29.90		84,294			33.74
Vested	(78,379		)	27.92		(79,219		)	25.77
Forfeited	—			—		(4,619		)	25.83
Outstanding, end of period	226,537			$	29.59	261,691			$	28.33
Total weighted-average grant-date fair value of shares granted ($ millions)	$	2.8				$	2.8


(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, 2016, there was $6.1 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 3.0 years.

For the first three months of 2016 and 2015, total restricted stock units that vested and related dividends had a fair value of $2.5 million and $3.0 million, respectively, and the related tax benefits were $0.9 million and $1.0 million, respectively.

Long-term incentive plan payable in stock. The 2014-2016 long-term incentive plan (LTIP) provides 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 period includes 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 three-year period. In addition, the 2014-2016 LTIP has performance goals related to levels of

HEI consolidated return on average common equity (ROACE), Hawaiian Electric consolidated ROACE and ASB net income — all based on the three-year averages, and ASB return on assets relative to performance peers. The 2015-2017 and the 2016-2018 LTIP provide for performance awards payable in cash, and thus, are 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
	2016				2015
	Shares		(1)		Shares		(1)
Outstanding, beginning of period	162,500		$	27.66	257,956		$	28.45
Granted (target level)	—		—		—		—
Vested (issued or unissued and cancelled)	(78,553	)	32.69		(75,915	)	30.71
Forfeited	—		—		(13,264	)	26.00
Outstanding, end of period	83,947		$	22.95	168,777		$	27.63


(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.

For the three months ended March 31, 2016 and 2015, there were no vested LTIP awards linked to TRS. For the three months ended March 31, 2016, all of the shares vested (which were granted at target level based on the satisfaction of TRS performance) for the 2013-2015 LTIP lapsed.

As of March 31, 2016, there was $0.4 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 0.8 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
	2016				2015
	Shares		(1)		Shares		(1)
Outstanding, beginning of period	222,647		$	26.02	364,731		$	26.01
Granted (target level)	—		—		—		—
Vested (issued)	(109,097	)	26.89		(121,249	)	26.05
Forfeited	—		—		(13,263	)	25.72
Outstanding, end of period	113,550		$	25.18	230,219		$	26.00


(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, 2016 and 2015, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $3.6 million and $4.7 million and the related tax benefits were $1.4 million and $1.8 million, respectively.

As of March 31, 2016, there was $0.7 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 0.8 years.

8 · 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 used 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 gains (losses) on derivatives			Retirement benefit plans			AOCI			Unrealized gains on derivatives		Retirement benefit plans		AOCI
Balance, December 31, 2015	$	(1,872	)	$	(54	)	$	(24,336	)	$	(26,262	)	$	—	$	925	$	925
Current period other comprehensive income	7,428			1,056			316			8,800			1,002		14		1,016
Balance, March 31, 2016	$	5,556		$	1,002		$	(24,020	)	$	(17,462	)	$	1,002	$	939	$	1,941
Balance, December 31, 2014	$	462		$	(289	)	$	(27,551	)	$	(27,378	)	$	—	$	45	$	45
Current period other comprehensive income	3,451			59			548			4,058			—		22		22
Balance, March 31, 2015	$	3,913		$	(230	)	$	(27,003	)	$	(23,320	)	$	—	$	67	$	67

Reclassifications out of AOCI were as follows:



	Amount reclassified from AOCI
	Three months ended March 31						Affected line item in the
(in thousands)	2016			2015			Statement of Income
HEI consolidated
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	$	54		$	59		Interest expense
Retirement benefit plan items
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost	3,537			5,459			See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(3,222		)	(4,911		)	See Note 6 for additional details
Total reclassifications	$	369		$	607
Hawaiian Electric consolidated
Retirement benefit plan items
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost	$	3,236		$	4,933		See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(3,222		)	(4,911		)	See Note 6 for additional details
Total reclassifications	$	14		$	22

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. 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 fixed-rate 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, including broker market transactions and third party pricing services.

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.

Window forward contract. The estimated fair value was obtained from a third-party financial services provider based on the effective exchange rate offered for the foreign currency denominated transaction. Window forward contracts 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, the carrying amount is a reasonable estimate of fair value because it can only be redeemed at par. For bank-owned life insurance, the carrying amount is the cash surrender value of the insurance policies, which 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 or notional amount		Quoted prices in active markets for identical assets		Significant other observable inputs		Significant unobservable inputs
(in thousands)	Carrying or notional amount		(Level 1)		(Level 2)		(Level 3)		Total
March 31, 2016
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	906,295		—		906,295		—		906,295
Stock in Federal Home Loan Bank	11,218		—		11,218		—		11,218
Loans receivable, net	4,597,850		—		7,938		4,837,177		4,845,115
Mortgage servicing rights	8,857		—		—		11,231		11,231
Bank-owned life insurance	138,732		—		138,732		—		138,732
Derivative assets	63,470		—		2,295		—		2,295
The Utilities’ derivative assets (included in amount above)	31,335		—		1,640		—		1,640
Financial liabilities
Deposit liabilities	5,139,932		—		5,144,128		—		5,144,128
Short-term borrowings—other than bank	95,485		—		95,485		—		95,485
The Utilities’ short-term borrowings (included in amount above)	12,998		—		12,998		—		12,998
Other bank borrowings	329,081		—		333,743		—		333,743
Long-term debt, net—other than bank	1,578,618		—		1,704,567		—		1,704,567
The Utilities’ long-term debt, net (included in amount above)	1,278,916		—		1,397,598		—		1,397,598
Derivative liabilities	30,516		139		53		—		192
December 31, 2015
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	820,648		—		820,648		—		820,648
Stock in Federal Home Loan Bank	10,678		—		10,678		—		10,678
Loans receivable, net	4,570,412		—		4,639		4,744,886		4,749,525
Mortgage servicing rights	8,884		—		—		11,790		11,790
Bank-owned life insurance	138,139		—		138,139		—		138,139
Derivative assets	22,616		—		385		—		385
Financial liabilities
Deposit liabilities	5,025,254		—		5,024,500		—		5,024,500
Short-term borrowings—other than bank	103,063		—		103,063		—		103,063
Other bank borrowings	328,582		—		333,392		—		333,392
Long-term debt, net—other than bank*	1,578,368		—		1,669,087		—		1,669,087
The Utilities’ long-term debt, net (included in amount above)*	1,278,702		—		1,363,766		—		1,363,766
Derivative liabilities	23,269		15		15		—		30

* See Note 11 for the impact to prior period financial information of the adoption of ASU No. 2015-03.

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



	March 31, 2016						December 31, 2015
	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	$	—	$	687,598	$	—	$	—	$	607,689	$	—
U.S. Treasury and federal agency obligations	—		218,697		—		—		212,959		—
	$	—	$	906,295	$	—	$	—	$	820,648	$	—
Derivative assets
Interest rate lock commitments ¹	$	—	$	655	$	—	$	—	$	384	$	—
Forward commitments ¹	—		—		—		—		1		—
Window forward contract ²	—		1,640		—		—		—		—
	$	—	$	2,295	$	—	$	—	$	385	$	—
Derivative liabilities ¹
Interest rate lock commitments	$	—	$	—	$	—	$	—	$	—	$	—
Forward commitments	139		53		—		15		15		—
	$	139	$	53	$	—	$	15	$	15	$	—

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.

² Asset derivatives are included in other current assets in the balance sheets.

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, 2016.

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. The carrying value of 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, 2016
Loans	$	82	$	—	$	—	$	82
Real estate acquired in settlement of loans	797		—		—		797
December 31, 2015
Loans	178		—		—		178
Real estate acquired in settlement of loans	1,030		—		—		1,030

At March 31, 2016 and 2015, there were no adjustments to fair value for ASB’s loans held for sale which were carried at the lower of cost or fair value.

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, 2016

Residential loans

Fair value of property or collateral

Appraised value less 7% selling costs

42-66%

54%

Real estate acquired in settlement of loans

797

Fair value of property or collateral

Appraised value less 7% selling costs

100%

December 31, 2015

Residential loans

Fair value of property or collateral

Appraised value less 7% selling costs

N/A (2)

Home equity lines of credit

128

Fair value of property or collateral

Appraised value less 7% selling costs

N/A (2)

Total loans

178

Real estate acquired in settlement of loans

1,030

Fair value of property or collateral

Appraised value less 7% selling cost

100%

(1) Represent percent of outstanding principal balance.


(2)	N/A - Not applicable. There is one loan in each fair value measurement type.

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	2016			2015
(in millions)
Supplemental disclosures of cash flow information
HEI consolidated
Interest paid to non-affiliates	$	20		$	21
Income taxes paid	1			1
Income taxes refunded	45			47
Hawaiian Electric consolidated
Interest paid to non-affiliates	12			13
Income taxes refunded	20			6
Supplemental disclosures of noncash activities
HEI consolidated
Common stock dividends reinvested in HEI common stock ¹	6			—
Real estate transferred from property, plant and equipment to other assets held-for-sale (investing)	—			5
HEI consolidated and Hawaiian Electric consolidated
Additions to electric utility property, plant and equipment - unpaid invoices and accruals (investing)	(48		)	(41		)

¹ The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions. From January 6, 2016, HEI satisfied the share purchase requirements of the DRIP through new issuances of its common stock. In 2015, HEI satisfied such requirements with cash through open market purchases of its common stock.

11 · Recent accounting pronouncements

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 (and the clarifying guidance in ASU No. 2016-10, “Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing”) in the first quarter of 2018, 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.

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 retrospectively adopted ASU No. 2015-03 in the first quarter 2016 and the adoption did not have a material impact on the Company’s financial condition and had no impact on the Company’s results of operations or liquidity.

The table below summarizes the impact to the prior period financial statements of the adoption of ASU No. 2015-03:



(in thousands)	As previously filed		Adjustment from adoption of ASU No. 2015-03			As currently reported

December 31, 2015
HEI Consolidated Balance Sheet and Note 3 - Segment financial information (Total assets)
Other assets	$	488,635	$	(8,178	)	$	480,457
Total assets and Total liabilities and shareholders’ equity	11,790,196		(8,178		)	11,782,018
Long-term debt, net-other than bank	1,586,546		(8,178		)	1,578,368
Total liabilities	9,828,263		(8,178		)	9,820,085
Hawaiian Electric Consolidated Balance Sheet and Note 3 - Segment financial information (Total assets)
Unamortized debt expense	8,341		(7,844		)	497
Total other long-term assets	908,327		(7,844		)	900,483
Total assets and Total capitalization and liabilities	5,680,054		(7,844		)	5,672,210
Long-term debt, net	1,286,546		(7,844		)	1,278,702
Total capitalization	3,049,164		(7,844		)	3,041,320
Note 4 - Hawaiian Electric Consolidating Balance Sheet
Hawaiian Electric (parent only)
Unamortized debt expense	5,742		(5,383		)	359
Total other long-term assets	662,430		(5,383		)	657,047
Total assets and Total capitalization and liabilities	4,481,558		(5,383		)	4,476,175
Long-term debt, net	880,546		(5,383		)	875,163
Total capitalization	2,631,164		(5,383		)	2,625,781
Hawaii Electric Light
Unamortized debt expense	1,494		(1,420		)	74
Total other long-term assets	130,749		(1,420		)	129,329
Total assets and Total capitalization and liabilities	955,935		(1,420		)	954,515
Long-term debt, net	215,000		(1,420		)	213,580
Total capitalization	514,702		(1,420		)	513,282
Maui Electric
Unamortized debt expense	1,105		(1,041		)	64
Total other long-term assets	115,148		(1,041		)	114,107
Total assets and Total capitalization and liabilities	831,201		(1,041		)	830,160
Long-term debt, net	191,000		(1,041		)	189,959
Total capitalization	459,725		(1,041		)	458,684

Investments in certain entities that calculate net asset value per share. In May 2015, the FASB issued ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent),” which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and limits certain disclosures to those investments.

The Company retrospectively adopted ASU No. 2015-07 in the first quarter 2016; thus, the fair value disclosures for retirement benefit plan assets will be revised in the SEC Form 10-K for the year ended December 31, 2016.

Financial instruments. In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities,” which, among other things:


•	Requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income.


•	Requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes.


•	Requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset (i.e., securities or loans and receivables).


•	Eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost.

The Company plans to adopt ASU No. 2016-01 in the first quarter of 2018 and has not yet determined the impact of adoption.

Leases. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which requires that lessees recognize a liability to make lease payments (the lease liability) and a right-of-use asset, representing its right to use the underlying asset for the lease term, for all leases (except short-term leases) at the commencement date.

The Company plans to adopt ASU 2016-02 in the first quarter of 2019 (using a modified retrospective transition approach for leases existing at, or entered into after, January 1, 2017) and has not yet determined the impact of adoption.

Stock compensation. In March 2016, the FASB issued ASU No. 2016-09, “Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies several aspects of the accounting for share-based payment transactions. For example, all excess tax benefits and tax deficiencies should be recognized as income tax expense or benefit in the income statement; excess tax benefits should be classified along with other income tax cash flows as an operating activity on the statement of cash flows; an entity can make an accounting policy election to account for forfeitures when they occur; the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and the cash payments made to taxing authorities on the employees’ behalf for withheld shares should be classified as financing activities on the statement of cash flows.

The Company plans to adopt ASU 2016-09 in the first quarter of 2017 and has not yet determined the impact of adoption. Provisions requiring recognition of excess tax benefits and tax deficiencies in the income statement will be applied prospectively. Provisions related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements and forfeitures will be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of January 1, 2017. Provisions related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement will be applied retrospectively. Provisions related to the presentation of excess tax benefits on the statement of cash flows will be applied either using a prospective transition method or a retrospective transition method.

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 17% as of March 31, 2016, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. HEI currently intends to terminate the HEI Facility if, and when, the proposed Merger closes. 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 42% for Hawaii Electric Light and 41% for Maui Electric as of March 31, 2016, 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, 2016, 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 NEE. 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 NEE.

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.

HEI. On March 21, 2016, HEI entered into a $75 million term loan agreement with Bank of America, N.A., which matures on March 23, 2018 and includes substantially the same financial covenant and customary conditions as the HEI credit agreement described above. On March 23, 2016, HEI drew an initial $75 million Eurodollar term loan at an initial interest rate of 1.18% for an initial one month interest period (and a subsequent interest rate of 1.19% for a one month interest period). The proceeds from the term loan were used to pay-off HEI’s $75 million 4.41% senior note at maturity on March 24, 2016.

13 · Related party transactions

For general management and administrative services in the first quarters of 2016 and 2015, HEI charged the Utilities $2.1 million and $1.7 million, respectively, and HEI charged ASB $0.8 million and $0.3 million, respectively. The amounts charged by HEI to its subsidiaries for services provided by HEI employees are allocated primarily on the basis of time expended in providing such services.

Mr. Timothy Johns, a member of the Hawaiian Electric Board of Directors, is an executive officer of Hawaii Medical Service Association (HMSA). Ms. Susan Li, an executive of Hawaiian Electric, is the Vice Chairperson of the Hawaii Dental Service (HDS) Board of Directors. The Company’s HMSA costs and expense (for health insurance premiums, claims plus administration expense and stop-loss insurance coverages) and HDS costs and expense (for dental insurance premiums) and the Utilities’ HMSA costs and expense (for health insurance premiums) and HDS costs and expense (for dental insurance premiums) were as follows:



	Three months ended March 31
(in millions)	2016		2015
HEI consolidated
HMSA costs	$	7	$	7
HMSA expense*	5		5
HDS costs	1		1
HDS expense*	1		1
Hawaiian Electric consolidated
HMSA costs	6		6
HMSA expense*	3		4
HDS costs	1		1
HDS expense*	—		—

* Charged the remaining costs primarily to electric utility plant.

The costs and expense in the table above are gross amounts (i.e., not net of employee contributions to employee benefits).

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 2015 Form 10-K and should be read in conjunction with such discussion and the 2015 annual consolidated financial statements of HEI and Hawaiian Electric and notes thereto included in HEI’s and Hawaiian Electric’s 2015 Form 10-K, as well as the quarterly (as of and for the three months ended March 31, 2016) 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)	2016		2015		change		Primary reason(s)*
Revenues	$	550,960	$	637,862	(14	)	Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income	68,851		69,506		(1	)	Decreases for the electric utility and bank segments, partly offset by lower loss for the “other” segment
Net income for common stock	32,352		31,866		2		Lower net loss for the “other” segment, partly offset by lower net income for the electric utility and bank segments
Basic earnings per common share	$	0.30	$	0.31	(3	)	Higher net income, more than offset by the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding	107,620		103,281		4		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans


*	Also, see segment discussions which follow.

Notes: The Company’s effective tax rates (combined federal and state income tax rates) for the first three months of 2016 and 2015 were 36% and 38%, respectively. The effective tax rate was lower for the quarter ended March 31, 2016 compared to the same periods in 2015 due primarily to a decrease in the amount of nondeductible merger- and spin-off-related expenses.

HEI’s consolidated ROACE was 8.4% for the twelve months ended March 31, 2016 and 8.5% for the twelve months ended March 31, 2015.

Dividends. The payout ratios for the first three months of 2016 and full year 2015 were 103% and 82%, respectively. HEI currently expects to maintain its 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 HEI 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 three months of 2016 with continued strength in arrivals and visitor expenditures as compared to the same period a year ago. Visitor expenditures increased 2.6% and arrivals increased 3.6% compared to the first three months of 2015. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the second quarter of 2016 to decrease by 0.2% over the second quarter of 2015 driven by an expected decrease in domestic seats from the East Coast (-7.2%) and international seats from Japan (-5.3%) and Canada (-4.3%).

Hawaii’s unemployment rate continued to decline to 3.1% in March 2016, lower than the state’s 3.9% rate in March 2015 and the March 2016 national unemployment rate of 5.0%.

Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices in the first quarter of 2016. Median sales prices for single family residential homes and condominiums on Oahu increased 7.2% and 4.5%, respectively, over the first quarter of 2015. The number of closed sales was also up slightly above 17% for both housing types in the first quarter of 2016.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. In 2016, prices of all petroleum fuels have continued to fall to historic lows. The price of oil remains volatile with significant market price sensitivity towards increasing global oil stocks and economic uncertainty in China and India.

At its April 2016 meeting, the Federal Open Market Committee (FOMC) maintained the federal funds rate target of 0.25% to 0.5%, given inflation remains to be below the long-term target of 2%. FOMC anticipates the target range to remain stable until further signs of meeting the inflationary and labor market targets.

Overall, Hawaii is expected to see a continuation of 2016’s moderate expansion. Tourism gains will be marginal, with domestic gains being offset by economic weakening in Canada and Japan. Construction remains high, as activity is expected to continue in 2016 as planned and permitted building continues and as new recently approved projects begin. The biggest risk to local economic growth aligns with the risk and uncertainty of the global economy and its potential impact on the U.S. economy as a whole.

Recent tax developments. See “Recent tax developments” in Note 4 and income taxes paid and refunded in Note 10 of the Consolidated Financial Statements.

Retirement benefits. For the first three months of 2016, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a gain, including investment management fees, of 2.1%. The market value of these assets as of March 31, 2016 and December 31, 2015 was $1.5 billion (including $1.3 billion for the Utilities) and $1.4 billion (including $1.3 billion for the Utilities), respectively.

The net periodic pension cost is expected to be higher than the ERISA minimum required contribution for 2016 as it was for 2015. Therefore, to satisfy the requirements of the Utilities’ pension tracking mechanism, net periodic pension cost will be the basis of the cash funding for 2016 as it was for 2015. The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2016 will be $65 million ($64 million by the Utilities, $1 million by HEI and nil by ASB), compared to $88 million in 2015. The 2016 contribution is expected to fully satisfy the minimum contribution requirements, including requirements of the Utilities’ pension and OPEB tracking mechanisms and the plans’ funding policies. The decline in the 2016 contribution from 2015 is largely due to the increase in the discount rate and a downward revision to the Mortality Improvement Scale, which resulted in a decline in net periodic pension cost.

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)	2016			2015			Primary reason(s)
Revenues	$	68		$	72
Operating loss	(6,069		)	(8,761		)	Lower administrative and general expenses due to lower merger- and spin-off-related expenses
Net loss	(5,688		)	(8,483		)	Lower operating loss and higher tax benefits relative to the losses in first quarter 2016 (due to non-deductibility of certain merger- and spin-off-related expenses)

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 which held passive, venture capital investments (all of which have been sold or abandoned prior to its dissolution in December 2015); and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions. Expenses related to the pending merger with NEE and spin-off of ASBH of $1.5 million and $4.4 million were included in the results of the stand-alone corporate operations of HEI during the first quarters of 2016 and 2015, respectively.

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, 2016				December 31, 2015
Short-term borrowings—other than bank	$	95	3	%	$	103	3	%
Long-term debt, net—other than bank	1,579		43		1,578		43
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,942		53		1,928		53
	$	3,650	100	%	$	3,643	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, 2016		March 31, 2016		December 31, 2015
Short-term borrowings ¹
Commercial paper	$	88	$	83	$	103
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 2016 was $103 million. As of April 28, 2016, HEI had $83 million of outstanding commercial paper, 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.

From March 6, 2014 through January 5, 2016, HEI satisfied the share purchase requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than through new issuances. From January 6 through March 31, 2016, the Company raised $8.7 million through the issuance of approximately 0.3 million shares of common stock under the DRIP, HEIRSP and ASB 401(k) Plan.

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 the 4.7 million shares remaining under the equity forward transactions for proceeds of $104.5 million.

In October 2015, HEI amended and extended a two-year $125 million term loan agreement that it entered into on May 2, 2014, which extended term loan now matures on October 6, 2017. In March 2016, HEI entered into a $75 million term loan agreement with Bank of America, N.A., which matures on March 23, 2018. See Note 12 of the Consolidated Financial Statements.

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 2016, net cash provided by operating activities of HEI consolidated was $171 million. Net cash used by investing activities for the same period was $215 million, primarily due to Hawaiian Electric’s consolidated capital expenditures, purchases of ASB’s investment securities, and net increases in ASB’s loans held for investment and stock in FHLB, partly offset by ASB’s repayments and calls of investment securities and Hawaiian Electric’s contributions in aid of construction. Net cash provided by financing activities during this period was $79 million as a result of several factors, including net increases in ASB’s deposit liabilities and retail repurchase agreements and proceeds from the issuance of HEI common stock, partly offset by the payment of common stock dividends and net decreases in short-term borrowings and other bank borrowings. 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 2016, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $23 million and $9 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 2015 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 2015 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

Results.



Three months ended March 31				Increase
2016		2015		(decrease)						(dollars in millions, except per barrel amounts)
$	482	$	573	$	(91	)				Revenues. Net decrease largely due to:
							$	(81	)	lower fuel prices
							(18		)	lower purchased power energy costs
							(6		)	lower KWH purchased
							13			higher KWH generated
114		177		(63		)				Fuel oil expense. Decrease largely due to lower fuel prices, partly offset by higher KWH generated
116		136		(20		)				Purchased power expense. Decrease due to lower purchased power energy prices and lower KWH purchased
104		104		—						Operation and maintenance expenses. Net decrease due to:
							(1		)	2015 costs for damage to combined heat and power generating unit
							(1		)	storm repair costs incurred in 2015
							(1		)	bad debt reserve for one customer account in 2015
							3			higher PSIP costs incurred in 2016
							1			higher LNG consulting costs incurred in 2016
93		99		(6		)				Other expenses. Decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
55		58		(3		)				Operating income. Decrease due to higher depreciation
25		27		(2		)				Net income for common stock. Decrease due to lower operating income

2,085		2,044		41						Kilowatthour sales (millions)
67.3		66.5		0.8						Wet-bulb temperature (Oahu average; degrees Fahrenheit)
884		795		89						Cooling degree days (Oahu)
$	53.99	$	86.60	$	(32.61	)				Average fuel oil cost per barrel
458,464		456,171		2,293						Customer accounts (end of period)

Note: The electric utilities had effective tax rates for the first three months of 2016 and 2015 of 36% and 37%.

Hawaiian Electric’s consolidated ROACE was 7.9% for the twelve months ended March 31, 2016 and 7.8% for the twelve months ended March 31, 2015.

The Utilities’ consolidated KWH sales have declined each year since 2007. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the Utilities’ full year 2016 KWH sales are expected to be below the 2015 level.

Other operation and maintenance expenses (excluding expense covered by surcharges or by third parties) for 2016 are expected to be 4% lower than 2015 as 2015 included significant write-offs and reserves that are not expected to recur in 2016. The Utilities are managing expenses to offset higher than planned PSIP and LNG consultant costs incurred during the first quarter of 2016.

The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of March 31, 2016 amounted to $4 billion, of which approximately 26% related to production PPE, 65% 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.

Transition to renewable energy. 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 Utilities are committed to assisting the State of Hawaii in achieving its Renewable Portfolio Standard goal of 100% renewable energy by 2045. Hawaii’s RPS law was revised in the 2015 Legislature and requires electric utilities to meet an RPS of 15%, 30%, 40%, 70% and 100% by December 31, 2015, 2020, 2030, 2040 and 2045, respectively. Energy savings resulting from DSM energy efficiency programs and solar water heating do not count toward these RPS. The Utilities have been successful in adding significant amounts of renewable energy resources to their electric systems and exceeded their 2015 RPS goal. The Utilities' RPS for 2015 is 23%, exceeding the 2015 RPS goal, and the Utilities led the nation in 2015 in the percentage of its customers who have installed PV systems. (See "Developments in renewable energy efforts” below).

In 2014, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed proposed Power Supply Improvement Plans (PSIPs) with the PUC, as required by PUC orders issued in April 2014 (see “April 2014 regulatory orders” in Note 4 of the Consolidated Financial Statements). Updated PSIPs were filed in April 2016. Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, and offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), and the Utilities proposed a switch from high-priced oil to lower cost liquefied natural gas.

On October 1, 2015, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed a proposed community-based renewable energy program and tariff with the PUC that will allow customers who cannot, or chose not to, take advantage of rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. The program, upon approval by the PUC, will allow customers to buy an interest in electricity generated by community renewable projects on their island without installing systems on their own roofs or property. In November 2015, the PUC suspended the tariff submittal and opened an investigatory docket.

The Utilities are pursuing the transition to renewable energy in a manner that will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel, ensure reliable service as more intermittent renewables are integrated to the grid and enable more options for customers as distributed technologies advance. To achieve 100% renewables by 2045, the Utilities seek to achieve a diversified mix of renewable resources, including utility scale and distributed resources. 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. As more generating resources 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. 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. As part of its transition, 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.

The Utilities continue to pursue liquefied natural gas (LNG) as a cleaner and lower cost transition fuel to meet the State’s goal to move from oil to renewable energy. Since 2014 the Utilities have been evaluating delivering LNG in specialized shipping containers to their generating stations on a transitional basis, an approach that requires minimal on-island infrastructure. In March 2014, Hawaiian Electric issued a RFP for the supply of containerized LNG and is currently in negotiations to resolve key contractual provisions with the preferred bidder. In August 2015, Hawaii State Governor Ige voiced his opposition to LNG as a replacement fuel for power generation citing (a) the high infrastructure costs, (b) permitting requirements as primary obstacles and (c) the potential to distract Hawaii from achieving the State's renewable energy goals. The Utilities have subsequently filed their updated Power Supply Improvement Plans outlining strategies that integrate LNG with the State’s renewable goals. The Utilities still anticipate finalizing an LNG Fuel Supply Agreement in 2016. The Utilities would seek approval from the PUC for the fuel agreement and for the commitment of funds related to capital improvements at various power plants concurrently.

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 was completed in 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. In March 2016, the Utilities sought PUC approval to commit funds for an expansion of the smart grid project. The smart grid project is expected to cost $340 million and be implemented over 5 years (beginning in 2017 for Oahu and 2018 for the Hawaii Island and Maui County).

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 of 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

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

Actual and PUC-allowed (as of March 31, 2016) returns were as follows:



%	Return on rate base (RORB)*						ROACE**						Rate-making ROACE***
Twelve months ended March 31, 2016	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric
Utility returns	7.28		6.80		7.32		7.85		7.26		8.53		9.00		7.66		8.88
PUC-allowed returns	8.11		8.31		7.34		10.00		10.00		9.00		10.00		10.00		9.00
Difference	(0.83	)	(1.51	)	(0.02	)	(2.15	)	(2.74	)	(0.47	)	(1.00	)	(2.34	)	(0.12	)

* 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 when compared to the period prior to the implementation of decoupling. This 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 modification to the 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 2016 is expected to be 90 to 110 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 through the RAM, 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. The earnings share mechanism was not triggered for any of the utilities in 2015. For 2014, the earnings sharing mechanism was triggered for Maui Electric, and Maui Electric has been crediting $0.5 million to its customers for their portion of the earnings sharing during the period June 2015 to May 2016. 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 2016 annual decoupling filings.

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 PUC issued several important regulatory decisions during the last few years, including a number of interim and final rate case decisions. 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 (filed/ 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
2016 (5)	6/17/15
Maui Electric
2012 (6)
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 (7)	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 (described below), approved by the PUC in March 2013, the rate case was withdrawn and the docket has been closed.


(5)	See “Hawaii Electric Light 2016 test year rate case” below.

(6) 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.


(7)	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. For the three months ended March 31, 2016 and 2015, Hawaiian Electric had additional net RAM revenues of $2 million and $5 million, respectively.

Hawaiian Electric 2014 test year rate case. On June 27, 2014, Hawaiian Electric submitted an abbreviated rate case filing (abbreviated filing), stating that it intends to forgo 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 stated that it 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 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.

Hawaii Electric Light 2016 test year rate case. On June 17, 2015, Hawaii Electric Light filed its notice of intent to file a general rate case application by December 30, 2016, and simultaneously filed a motion which requested an extension to file its 2016 rate case to no later than December 30, 2016. On November 19, 2015, the PUC issued an order granting Hawaii Electric Light’s motion, extending the deadline to file its 2016 rate case to December 30, 2016 and imposing a number of conditions, including the removal of all HEI non-incentive executive compensation from the Company’s base rates, a demonstration that it substantially reduced its cost structure, a proposal of a set of economic incentive and cost recovery mechanisms to further encourage reductions in rates and an acceleration of its clean energy transformation, and a proposal to modify the ECAC to provide incentives to reduce fuel and purchased power expenses.

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

Developments in renewable energy efforts. Developments in the Utilities’ efforts to further 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, ordering 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.

•

In May 2012, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua Bioenergy, LLC (Hu Honua) for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii. Per the terms of the PPA, the Hu Honua plant was scheduled to be in service in 2016. However, Hu Honua encountered construction delays, failed to meet its current obligations under the PPA and failed to provide adequate assurances that it could perform or had the financial means to perform. Hawaii Electric Light terminated the PPA on March 1, 2016. Hawaii Electric Light and Hu Honua are currently in discussions regarding the possibility of reinstating the PPA under revised terms and conditions.

•

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. In September 2015, the PUC approved Hawaiian Electric's application with conditions and limitations. See "Schofield Generating Station Project" in Note 4 of the Consolidated Financial Statements.

•

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. In September 2015, Anaergia Services, Maui Energy park and Maui Resource Recovery Facility filed a Petition for Declaratory Order, asking the PUC to find that Hawaiian Electric and Maui Electric have violated Hawaii state law and clear legislative policy by wrongfully refusing and failing to forward several bona fide requests for preferential rates for the purchase

of firm renewable energy produced in conjunction with agricultural activities to the PUC for approval. The PUC held a hearing in March 2016. In April 2016, the PUC’s Hearing Officer issued a recommended D&O that confirms Maui Electric abided by state law.

•

In December 2013, Hawaiian Electric requested PUC approval for a waiver of the Na Pua Makani Power Partners, LLC’s (NPM) proposed 24-MW wind farm located in the Kahuku area on Oahu from the competitive bidding process and the PPA for Renewable As-Available Energy dated October 3, 2013 between Hawaiian Electric and NPM for the proposed 24-MW wind farm. In December 2014, the PUC approved both the waiver request and the PPA. Hawaiian Electric and NPM are currently working on an amendment to the PPA to incorporate the results of the interconnection requirements study.

•

In July 2015, the PUC issued orders approving (with conditions) four PPAs for a combined 137 MW of solar projects. In January 2016, two of the four approved projects (which are SunEdison projects) received notices of default from Hawaiian Electric for failure to meet guaranteed project milestones, and in February 2016 a third project (also a SunEdison project) received a notice of failure to meet a substantial commitment milestone. In January 2016, the PUC reopened proceedings for the three SunEdison projects. In February 2016, Hawaiian Electric filed project status reports with the PUC and terminated the three SunEdison PPAs totaling 109.6 MW. SunEdison maintains that the terminations were improper. SunEdison and the Consumer Advocate filed responses with the PUC regarding Hawaiian Electric’s status reports, and a technical conference was held on March 18, 2016. On April 12, 2016, the PUC issued a staff report concerning the termination of the PPAs. The staff report stated that Hawaiian Electric acted too hastily and without an in-depth analysis, however, the staff report acknowledged that it is within Hawaiian Electric’s management discretion to determine whether or not to terminate the PPAs. The PUC has not yet closed the dockets for these projects. On April 21, 2016, SunEdison filed for Chapter 11 bankruptcy protection.


•	In July 2015, Maui Electric signed two PPAs, with Kuia Solar and South Maui Renewable Resources (which subsequently assigned its PPA to SSA Solar of HI 3, LLC), each for a 2.87-MW solar facility. In February 2016, the PUC approved both PPAs, subject to certain conditions and modifications.

•

In September 2015, the PUC approved Hawaiian Electric’s 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. Renewable Energy Group has supplied 3 million to 7 million gallons per year to CIP CT-1 under its contract with Hawaiian Electric originally set to expire November 2015. The contract has been extended from November 2015 to November 2016 as a contingency supply contract with no volume purchase requirements.

•

In October 2015, the Utilities filed with the PUC a proposal for a Community-Based Renewable Energy program and tariff that would allow customers who cannot, or chose not to, take advantage of rooftop solar to receive the benefits of renewable energy to help offset their monthly electric bills and support clean energy for Hawaii. In November 2015, the PUC suspended the filing and opened a docket to investigate the matter.


•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of March 31, 2016, there were 14 MW, 3 MW and 4 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, 2016, there were approximately 269 MW, 63 MW and 70 MW of installed NEM capacity from renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.


•	The Utilities began accepting applications for Customer Grid Supply (CGS) and Customer Self Supply (CSS) in October 2015. As of March 31, 2016 there were 0 kW, 36 kW and 0 kW of installed CGS and CSS capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.

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 2016, Hawaiian Electric filed its 2016 Adequacy of Supply (AOS) letter, which indicated that based on its May 2015 sales and peak forecast for the 2016 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 2017.

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 2022 timeframe. Hawaiian Electric is proceeding with future firm capacity additions in coordination with the State of Hawaii Department of Transportation in 2016, 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 is expected to be in service in the first quarter of 2018. 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 2016, Hawaii Electric Light filed its 2016 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2018 is sufficient to meet reasonably expected demands for service and provide for reasonable reserves for emergencies. The 2016 AOS letter also indicated that the Company's Shipman plant in Hilo was retired in 2015.

Additional generation from other renewable resources could be added in the 2020-2025 timeframe.

Maui Electric. In January 2016, Maui Electric filed its 2016 AOS letter, which indicated that Maui Electric’s generation capacity for the islands of Lanai and Molokai for the next three years is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. The 2016 AOS letter also indicated that without the peak reduction benefits of demand response but with the equivalent firm capacity value of wind generation, Maui Electric expects to have a small reserve capacity shortfall from 2017 to 2022 on the island of Maui. Maui Electric is evaluating several measures to mitigate the anticipated reserve capacity shortfall. Maui Electric anticipates needing a significant amount of additional firm capacity on Maui in the 2022 timeframe after the planned retirement of Kahului Power Plant. In February 2014, Maui Electric deactivated two fossil fuel generating units, with a combined rating of 9.5 MW, at its Kahului Power Plant. Due to various system conditions including lack of wind generation, approaching storms, and scheduled and unscheduled outages of generating units, transmission lines, and independent power producers, the two deactivated units at Kahului Power Plant were reactivated for several days in 2015 and 2016. In consideration of the time needed to acquire replacement firm generating capacity, Maui Electric now anticipates the retirement of all generating units at the Kahului Power Plant, which have a combined rating of 32.3 MW, in the 2022 timeframe. A capacity planning analysis is in progress to better define needs and timing. 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.

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, 2016				December 31, 2015
Short-term borrowings	$	13	—	%	$	—	—	%
Long-term debt, net	1,279		42		1,279		42
Preferred stock	34		1		34		1
Common stock equity	1,731		57		1,728		57
	$	3,057	100	%	$	3,041	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, 2016		March 31, 2016		December 31, 2015
Short-term borrowings ¹
Commercial paper	$	26	$	13	$	—
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 2016 was $61 million. As of March 31, 2016, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $12.5 million and $7 million, respectively. As of April 28, 2016, Hawaiian Electric had no outstanding commercial paper, no draws under its line of credit facility and no borrowings from HEI. Also, as of April 28, 2016, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $12.5 million and $7 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 the Series 2007A and Refunding Series 2007B SPRBs 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.

In May 2015, up to $80 million of Special Purpose Revenue Bonds (SPRBs) ($70 million for Hawaiian Electric, $2.5 million for Hawaii Electric Light and $7.5 million for Maui Electric) were authorized by the Hawaii legislature for issuance, with PUC approval, prior to June 30, 2020 to finance the utilities’ capital improvement programs.

In June 2015, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed an application with the PUC for approval to issue and sell each utility’s common stock in one or more sales in 2016 (Hawaiian Electric’s sale to the owner at the time of each such sale of up to $330 million and Hawaii Electric Light’s and Maui Electric’s sales to Hawaiian Electric of up to $15 million and $45 million, respectively), and the purchase of the Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric in 2016.

In February 2016, Hawaiian Electric and Maui Electric filed an application with the PUC for approval to issue in 2016 unsecured obligations bearing taxable interest (Hawaiian Electric up to $70 million and Maui Electric up to $20 million), with the proceeds 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.

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. In 2016, net cash provided by operating activities increased by $50 million. In 2016, noncash depreciation and amortization amounted to $49 million due to an increase in plant and equipment and deferred income taxes increased $14 million. Further, net cash provided by operating activities included a net decrease of $27 million in accounts receivable and accrued unbilled revenues due largely to the decrease in customer bills as a result of lower fuel oil prices included in rates, a $23 million decrease in fuel oil stock, and a $28 million increase in accounts payable due to the decrease in the fuel oil prices and timing of vendor payments.

For the first three months in 2016, net cash used in investing activities increased by $2 million compared to the prior year. Further in 2016, capital expenditures amounted to $125 million, offset by contributions in aid of construction of $14 million.

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. For the first three months in 2016, cash flows used in financing activities changed by a negative $18 million compared to the prior year.

Further in 2016, cash used in financing activities consisted of $24 million common and preferred stock dividend payments offset by the proceeds received from short-term borrowings of $13 million.

Bank



	Three months ended March 31				Increase
(in millions)	2016		2015		(decrease)			Primary reason(s)
Interest income	$	53	$	48	$	5		The increase in interest income was the result of higher average earning asset balances and an increase in yields on earning assets. ASB’s average loan portfolio balance for the three months ended March 31, 2016 increased by $188 million compared to the same period in 2015 as average commercial real estate, home equity lines of credit and residential balances increased by $174 million, $29 million, and $16 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The yield on earning assets increased by 11 basis points as the adjustable rate loans repriced upward with the increase in the prime rate at end of 2015, which resulted in an increase in loan portfolio yields of 10 basis points. The average investment securities portfolio balance increased by $305 million due to the purchase of investments with excess liquidity. The average FHLB stock balance decreased by $58 million as FHLB stock in excess of the required holdings was repurchased by the FHLB.
Noninterest income	16		16		—			Noninterest income was relatively flat for the three months ended March 31, 2016 compared to noninterest income for the three months ended March 31, 2015. Mortgage banking income decreased $0.6 million as result of a decrease in residential mortgage loan sales volume in first quarter of 2016 compared to the same period in 2015.
Revenues	69		64		5
Interest expense	3		3		—			Interest expense was relatively flat as growth in the deposit liabilities was primarily in low rate core deposits, which had a minimal impact to interest expense. Average deposit balances for the three months ended March 31, 2016 increased by $363 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $297 million and $66 million, respectively. Other borrowings increased by $10 million primarily due to an increase in repurchase agreements. The interest-bearing liability rate increased by 2 basis points.
Provision for loan losses	5		1		4			The provision for loan losses increased by $4.2 million primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for two commercial loans. Credit quality and trends continued to be stable and good, reflecting prudent credit risk management and a strong Hawaii economy. Delinquency rates have decreased from 0.60% at March 31, 2015 to 0.53% at March 31, 2016. The net charge-off ratio for the three months ended March 31, 2016 was 0.21% compared to a net charge-off ratio of 0.04% for the same period in 2015. The increase in net charge-offs were due to an increase in consumer loan portfolio charge-offs as a result of ASB’s strategic expansion of its unsecured consumer loan product offering with risk-based pricing and a loan charge-off related to one commercial borrower.
Noninterest expense	41		40		1			Noninterest expense for the three months ended March 31, 2016 was $1.0 million higher than the noninterest expense for the same period in 2015 primarily due to higher compensation and benefit expenses and higher services expenses for ASB’s electronic banking platform project to enhance online and mobile services for both consumer and business customers.
Expenses	49		44		5
Operating income	20		21		(1		)	Higher net interest income was more than offset by higher provision loan losses, lower noninterest income and higher noninterest expense.
Net income	13		13		—

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)	2016	2015
Return on average assets	0.84	0.96
Return on average equity	8.89	9.96
Net interest margin	3.62	3.52

Average balance sheet and net interest margin. The following tables provides a summary of average balances including major categories of interest, earning assets and interest-bearing liabilities:



Three months ended March 31	2016						2015
(dollars in thousands)	Average balance			Interest income/ expense		Yield/ rate (%)	Average balance			Interestincome/ expense		Yield/ rate (%)
Assets:
Interest-earning deposits	$	79,320		$	99	0.49	$	130,294		$	81	0.25
FHLB Stock	10,779			44		1.64	68,626			18		0.11
Available-for-sale investment securities	854,401			4,874		2.28	549,125			2,952		2.15
Loans
Residential 1-4 family	2,076,525			22,320		4.30	2,060,485			22,661		4.40
Commercial real estate	808,407			8,164		4.03	634,251			6,062		3.84
Home equity line of credit	851,329			6,865		3.24	822,510			6,476		3.19
Residential land	18,206			276		6.06	16,381			274		6.69
Commercial	748,774			7,372		3.94	789,329			7,068		3.62
Consumer	128,189			3,440		10.79	120,602			2,657		8.93
Total loans ^1,2	4,631,430			48,437		4.19	4,443,558			45,198		4.09
Total interest-earning assets ¹	5,575,930			53,454		3.84	5,191,603			48,249		3.73
Allowance for loan losses	(50,449		)				(45,929		)
Non-interest-earning assets	497,204						487,233
Total assets	$	6,022,685					$	5,632,907
Liabilities and shareholder’s equity:
Savings	$	2,048,157		$	333	0.07	$	1,943,466		$	300	0.06
Interest-bearing checking	821,868			42		0.02	765,172			33		0.02
Money market	167,244			53		0.13	163,737			50		0.12
Time certificates	499,617			1,164		0.93	433,747			877		0.82
Total interest-bearing deposits	3,536,886			1,592		0.18	3,306,122			1,260		0.15
Advances from Federal Home Loan Bank	102,061			786		3.05	100,000			775		3.10
Securities sold under agreements to repurchase	207,033			699		1.34	198,939			691		1.39
Total interest-bearing liabilities	3,845,980			3,077		0.32	3,605,061			2,726		0.30
Non-interest bearing liabilities:
Deposits	1,506,595						1,374,311
Other	100,175						112,344
Shareholder’s equity	569,935						541,191
Total liabilities and shareholder’s equity	$	6,022,685					$	5,632,907
Net interest income				$	50,377					$	45,523
Net interest margin (%) ³						3.62						3.52


¹	Includes loans held for sale, at lower of cost or fair value.


²	Includes loan fees of $0.8 million and $0.5 million for the three months ended March 31, 2016 and 2015, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.


³	Defined as net interest income as a percentage of average total interest-earning assets.

Earning assets, interest-bearing 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 interest-bearing liabilities. The interest rate

environment has been impacted by disruptions in the financial markets over a period of several years and these conditions had a negative impact on ASB’s net interest margin during that period. With the recent interest increase by the Feds, ASB’s net interest margin has increased.

The loan portfolio 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, 2016				December 31, 2015
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate:
Residential 1-4 family	$	2,055,020		44.2	$	2,069,665		44.8
Commercial real estate	703,661			15.1	690,561			14.9
Home equity line of credit	846,467			18.2	846,294			18.3
Residential land	18,940			0.4	18,229			0.4
Commercial construction	130,487			2.8	100,796			2.2
Residential construction	16,241			0.4	14,089			0.3
Total real estate, net	3,770,816			81.1	3,739,634			80.9
Commercial	740,596			16.0	758,659			16.4
Consumer	136,244			2.9	123,775			2.7
	4,647,656			100.0	4,622,068			100.0
Less: Deferred fees and discounts	(5,380		)		(6,249		)
Allowance for loan losses	(52,326		)		(50,038		)
Total loans, net	$	4,589,950			$	4,565,781

Home equity — key credit statistics

Attention has been given by regulators and rating agencies to the potential for increased exposure to credit losses associated with home equity lines of credit (HELOC) that were originated during the period of rapid home price appreciation between 2003 and 2007 as they have reached, or are starting to reach, the end of their 10-year, interest only payment periods. Once the interest only payment period has ended, payments are reset to include principal repayments along with interest. ASB does not have a large exposure to HELOCs originated between 2003 and 2007. Nearly all of the HELOC originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older equity lines represent 3% of the portfolio and are included in the amortizing balances identified in the table above.



	March 31, 2016			December 31, 2015
Outstanding balance (in thousands)	$	846,467		$	846,294
Percent of portfolio in first lien position	43.2		%	42.9		%
Net charge-off (recovery) ratio	(0.01		)%	0.02		%
Delinquency ratio	0.24		%	0.25		%



							End of draw period – interest only									Current
March 31, 2016	Total			Interest only			2016-2017			2018-2020			Thereafter			amortizing
Outstanding balance (in thousands)	$	846,467		$	649,102		$	10,254		$	145,561		$	493,287		$	197,365
% of total	100		%	77		%	1		%	17		%	59		%	23		%

As of March 31, 2016, the HELOC portfolio comprised 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 97% 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, 2016, approximately 20% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option.

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, 2016				December 31, 2015
(dollars in thousands)	Balance		% of total		Balance		% of total
U.S. Treasury and federal agency obligations	$	218,697	24	%	$	212,959	26	%
Mortgage-related securities — FNMA, FHLMC and GNMA	687,598		76		607,689		74
Total available-for-sale investment securities	$	906,295	100	%	$	820,648	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 Des Moines and securities sold under agreements to repurchase continue to be additional sources of funds. As of March 31, 2016 and December 31, 2015, ASB’s interest-bearing liabilities consisted of 94% deposits and 6% other borrowings. The weighted average cost of deposits for the first three months of 2016 and 2015 was 0.13% and 0.11%, respectively.

Federal Home Loan Bank Merger. In the second quarter of 2015, the FHLB of Des Moines and the FHLB of Seattle successfully completed the merger of the two banks and operated as one under the name FHLB of Des Moines as of June 1, 2015. The FHLB of Des Moines will continue to be a source of liquidity for ASB.

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 the investment securities, respectively. In addition, changes in credit spreads also impact the fair values of the investment securities.

As of March 31, 2016, ASB had an unrealized gain, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $5.6 million compared to an unrealized loss, net of taxes, of $1.9 million at December 31, 2015. See “Item 3. Quantitative and qualitative disclosures about market risk” for a discussion of ASB’s interest rate risk sensitivity.

During the first three months of 2016, ASB recorded a provision for loan losses of $4.8 million primarily due to increased loss reserves for growth in the commercial real estate loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for two commercial loans. During the first three months of 2015, ASB recorded a provision for loan losses of $0.6 million primarily due to increased loss reserves for growth in the loan portfolio and additional loss reserves for the consumer 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)	2016			2015			2015
Allowance for loan losses, January 1	$	50,038		$	45,618		$	45,618
Provision for loan losses	4,766			614			6,275
Less: net charge-offs	2,478			437			1,855
Allowance for loan losses, end of period	$	52,326		$	45,795		$	50,038
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.21		%	0.04		%	0.04		%

Legislation and regulation. ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC) and the 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 transferred to the OCC, the FDIC, the 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 was effective October 3, 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. The debit card interchange fees received by ASB 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, or 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 tier 1 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, 2016, ASB met the new capital requirements with a Common equity Tier-1 ratio of 12.0%, a Tier-1 capital ratio of 12.0%, a Total capital ratio of 13.2% and a Tier-1 leverage ratio of 8.7%.

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 had 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 had receded, the lava flow remained active upslope and the reserves for the commercial real estate loan remained in place at March 31, 2015. In May 2015, the flow front near Pahoa remained cold and hard, no longer threatening any homes or businesses. All major tenants of the commercial center had returned by the end of March, and property occupancy stabilized soon thereafter. As a result, at the end of May 2015 the commercial real estate loan was restored to performing status and the reserves for lava risk were reversed.

FINANCIAL CONDITION

Liquidity and capital resources.



(dollars in millions)	March 31, 2016		December 31, 2015		% change
Total assets	$	6,141	$	6,015	2
Available-for-sale investment securities	906		821		10
Loans receivable held for investment, net	4,590		4,566		1
Deposit liabilities	5,140		5,025		2
Other bank borrowings	329		329		—

As of March 31, 2016, ASB was one of Hawaii’s largest financial institutions based on assets of $6.1 billion and deposits of $5.1 billion.

As of March 31, 2016, ASB’s unused FHLB borrowing capacity was approximately $1.7 billion. As of March 31, 2016, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.9 billion. Commitments to lend to borrowers whose loan terms have been modified in troubled debt restructurings totaled $2.3 million at March 31, 2016. 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, 2016, net cash provided by ASB’s operating activities was $11 million. Net cash used during the same period by ASB’s investing activities was $104 million, primarily due to purchases of investment securities of $122 million, a net increase in loans receivable of $28 million and additions to premises and equipment of $3 million, partly offset by repayments and calls of investment securities of $49 million. Net cash provided by financing activities during this period was $102 million, primarily due to increases in deposit liabilities of $115 million and a net increase in retail repurchase agreements of $19 million, partly offset by maturities of securities sold under agreements to repurchase of $19 million, a net decrease in mortgage escrow deposits of $4 million and $9 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, 2016, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a Common equity Tier-1 ratio of 12.0% (6.5%), a Tier-1 capital ratio of 12.0% (8.0%), a Total capital ratio of 13.2% (10.0%) and a Tier-1 leverage ratio of 8.7% (5.0%). As of December 31, 2015, ASB was well-capitalized with a Common equity Tier-1 ratio of 12.1%, Tier-1 capital ratio of 12.1%, a Total capital ratio of 13.3% and a Tier-1 leverage ratio of 8.8%. 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 HEI’s and Hawaiian Electric’s Quantitative and Qualitative Disclosures About Market Risk in Part II, Item 7A of HEI’s 2015 Form 10-K (pages 80 to 82).

ASB’s interest-rate risk sensitivity measures as of March 31, 2016 and December 31, 2015 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, 2016		December 31, 2015		March 31, 2016		December 31, 2015
+300	2.0	%	1.6	%	(9.6	)%	(9.3	)%
+200	0.8		0.6		(5.2	)	(5.3	)
+100	—		(0.1	)	(1.5	)	(1.9	)
-100	(0.3	)	(0.5	)	(3.3	)	(1.2	)

Management believes that ASB’s interest rate risk position as of March 31, 2016 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was slightly more asset sensitive for all rate increases as of March 31, 2016 compared to December 31, 2015. The repricing assumption of certain core deposits was updated and resulted in slower repricing of those deposit balances in the twelve-month simulation period. This shift to less rate sensitive deposits increased ASB’s asset sensitivity.

ASB’s base EVE increased to $987 million as of March 31, 2016 compared to $974 million as of December 31, 2015 due to growth in capital and flattening of the yield curve.

The change in EVE to rising rates became less sensitive for 100 and 200 basis point increases and slightly more sensitive for a 300 basis point increase as of March 31, 2016 compared to December 31, 2015. In the first quarter of 2016, the residential fixed rate mortgage portfolio repayment history was analyzed and prepayment assumptions were updated to reflect the current interest rate environment and ASB’s residential mortgage repayment behavior. In rising rate scenarios, the price sensitivity for the residential portfolio increased as the portfolio extended in average life due to the slower prepayment expectations. The liability side of the balance sheet offsets this increase in sensitivity as core deposit balances grew $74 million, primarily in longer duration products. Additionally, the repricing assumption of certain core deposits was updated, resulting in longer duration deposit liabilities.

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:

Disclosure Controls and Procedures

The Company maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

As of March 31, 2016, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Management, including the Company’s Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective, as of March 31, 2016, at the reasonable assurance level.

Material Weakness Previously Identified

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. As discussed in the Company’s 2015 Annual Report on Form 10-K, the Company did not maintain effective controls over the preparation and review of its Consolidated Statement of Cash Flows. Specifically, controls were not designed to ensure that non-cash transactions were properly identified, evaluated and presented in the Statement of Cash Flows, and management’s review process was not effective. The control deficiency resulted in the restatement of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2013 and for the three months ended March 31, 2015 and 2014, and the six months ended June 30, 2015 and 2014. The control deficiency also resulted in the revision of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2014 and for the nine months ended September 30, 2014.

Remediation of Previously Identified Material Weakness

The Company’s management, with oversight from its Audit Committee of the Board of Directors of HEI, has completed the remediation of the material weakness related to the preparation and review of its Consolidated Statement of Cash Flows. In order to address this material weakness, effective for the year ended December 31, 2015, management enhanced existing controls and implemented new controls relating to the preparation and review of the Statement of Cash Flows. The enhanced controls included improved spreadsheet templates that facilitated the identification and classification of the non-cash items for the Statement of Cash Flows, and an expanded roll forward reconciliation and review of cash capital expenditures. Management also implemented new review controls, specifically an additional review of non-cash items and significant transactions to ensure that they are properly evaluated and presented in the Statement of Cash Flows and an additional review of the Statement of Cash Flows for overall reasonableness. Management has assessed that these new controls have operated effectively for two quarters and therefore concluded that the material weakness related to the preparation and review of its Consolidated Statement of Cash Flows is remediated.

Changes in Internal Control Over Financial Reporting

There have been no changes in internal control over financial reporting during the first quarter of 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Hawaiian Electric:

Disclosure Controls and Procedures

Hawaiian Electric maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by Hawaiian Electric in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to Hawaiian Electric’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

As of March 31, 2016, an evaluation was performed under the supervision and with the participation of Hawaiian Electric’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Hawaiian Electric’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Management, including Hawaiian Electric’s Chief Executive Officer and Chief Financial Officer, concluded that Hawaiian Electric’s disclosure controls and procedures were effective, as of March 31, 2016, at the reasonable assurance level.

Material Weakness Previously Identified

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. As discussed in Hawaiian Electric’s 2015 Annual Report on Form 10-K, Hawaiian Electric did not maintain effective controls over the preparation and review of its Consolidated Statement of Cash Flows. Specifically, controls were not designed to ensure that non-cash transactions were properly identified, evaluated and presented in the Statement of Cash Flows, and management’s review process was not effective. The control deficiency resulted in the restatement of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2013 and for the three months ended March 31, 2015 and 2014, and the six months ended June 30, 2015 and 2014. The control deficiency also resulted in the revision of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2014 and for the nine months ended September 30, 2014.

Remediation of Previously Identified Material Weakness

Hawaiian Electric’s management, with oversight from its Audit Committee of the Board of Directors of Hawaiian Electric, has completed the remediation of the material weakness related to the preparation and review of its Consolidated Statement of Cash Flows. In order to address this material weakness, effective for the year ended December 31, 2015, management enhanced existing controls and implemented new controls relating to the preparation and review of the Statement of Cash Flows. The enhanced controls included improved spreadsheet templates that facilitated the identification and classification of the non-cash items for the Statement of Cash Flows, and an expanded roll forward reconciliation and review of cash capital expenditures. Management also implemented new review controls, specifically an additional review of non-cash items and significant transactions to ensure that they are properly evaluated and presented in the Statement of Cash Flows and an additional review of the Statement of Cash Flows for overall reasonableness. Management has assessed that these new controls have operated effectively for two quarters and therefore concluded that the material weakness related to the preparation and review of its Consolidated Statement of Cash Flows is remediated.

Changes in Internal Control Over Financial Reporting

There have been no changes in internal control over financial reporting during the first quarter of 2016 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.

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 2015 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 25 to 35 of HEI’s and Hawaiian Electric’s 2015 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 5. Other Information

A. Ratio of earnings to fixed charges.



	Three months ended March 31		Years ended December 31
	2016	2015	2015	2014	2013	2012	2011
HEI and Subsidiaries
Excluding interest on ASB deposits	3.07	3.21	3.68	3.80	3.55	3.30	3.24
Including interest on ASB deposits	2.94	3.10	3.54	3.65	3.42	3.15	3.04
Hawaiian Electric and Subsidiaries	3.12	3.39	3.97	4.04	3.72	3.37	3.52

See HEI Exhibit 12.1 and Hawaiian Electric Exhibit 12.2.

Item 6. Exhibits



HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2016 and 2015 and years ended December 31, 2015, 2014, 2013, 2012 and 2011

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 10.1		Inter-island Supply Contract for Petroleum Fuels by and between Chevron U.S.A. Inc. and Hawaiian Electric, Hawaii Electric Light and Maui Electric dated February 18, 2016 (confidential treatment has been requested for portions of this exhibit)

Hawaiian Electric Exhibit 10.2		Supply Contract for LSFO, Diesel and MATS Fuel by and between Hawaiian Electric and Chevron U.S.A. Inc. dated February 18, 2016 (confidential treatment has been requested for portions of this exhibit)

Hawaiian Electric Exhibit 10.3		Fuels Terminalling Agreement by and between Chevron U.S.A. Inc. and Hawaii Electric Light dated February 18, 2016 (confidential treatment has been requested for portions of this exhibit)

Hawaiian Electric Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2016 and 2015 and years ended December 31, 2015, 2014, 2013, 2012 and 2011

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 4, 2016		Date: May 4, 2016