HAWAIIAN ELECTRIC CO INC - Quarter Report: 2016 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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 October 28, 2016
Hawaiian Electric Industries, Inc. (Without Par Value)		108,524,493 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 September 30, 2016

TABLE OF CONTENTS



Page No.
ii	Glossary of Terms
iv	Cautionary Note Regarding Forward-Looking Statements

	PART I. FINANCIAL INFORMATION
1	Item 1.	Financial Statements

		Hawaiian Electric Industries, Inc. and Subsidiaries
1		Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2016 and 2015
2		Consolidated Statements of Comprehensive Income (unaudited) - three and nine months ended September 30, 2016 and 2015
3		Consolidated Balance Sheets (unaudited) - September 30, 2016 and December 31, 2015
4		Consolidated Statements of Changes in Shareholders’ Equity (unaudited) - nine months ended September 30, 2016 and 2015
5		Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2016 and 2015
		Hawaiian Electric Company, Inc. and Subsidiaries
6		Consolidated Statements of Income (unaudited) - three and nine months ended September 30, 2016 and 2015
7		Consolidated Statements of Comprehensive Income (unaudited) - three and nine months ended September 30, 2016 and 2015
8		Consolidated Balance Sheets (unaudited) - September 30, 2016 and December 31, 2015
9		Consolidated Statements of Changes in Common Stock Equity (unaudited) - nine months ended September 30, 2016 and 2015
10		Consolidated Statements of Cash Flows (unaudited) - nine months ended September 30, 2016 and 2015
11		Notes to Consolidated Financial Statements (unaudited)
65	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
65		HEI consolidated
70		Electric Utilities
82		Bank
91	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
91	Item 4.	Controls and Procedures

	PART II.	OTHER INFORMATION
92	Item 1.	Legal Proceedings
92	Item 1A.	Risk Factors
93	Item 5.	Other Information
93	Item 6.	Exhibits
94	Signatures

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended September 30, 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

CAUTIONARY NOTE REGARDING 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 “will,” “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following:

•

international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by 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, the effects of the United Kingdom’s referendum to withdraw from the European Union, 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 impacts of the termination of the Merger with NextEra Energy, Inc. (NEE) and the resulting loss of NEE’s resources, expertise and support (e.g., financial and technological), including potentially higher costs and longer lead times to increase levels of renewable energy and to complete projects like Enterprise Resource Planning/Enterprise Asset Management (ERP/ERM) and smart grids, and a higher cost of capital;

•

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 written or oral and 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 September 30						Nine months ended September 30
(in thousands, except per share amounts)	2016			2015			2016			2015
Revenues
Electric utility	$	572,253		$	648,127		$	1,549,700		$	1,779,732
Bank	73,708			69,091			213,297			199,222
Other	94			(42		)	262			(4		)
Total revenues	646,055			717,176			1,763,259			1,978,950
Expenses
Electric utility	482,441			565,470			1,333,876			1,573,278
Bank	50,981			48,289			150,752			138,063
Other	7,191			6,322			18,883			28,278
Total expenses	540,613			620,081			1,503,511			1,739,619
Operating income (loss)
Electric utility	89,812			82,657			215,824			206,454
Bank	22,727			20,802			62,545			61,159
Other	(7,097		)	(6,364		)	(18,621		)	(28,282		)
Total operating income	105,442			97,095			259,748			239,331
Merger termination fee	90,000			—			90,000			—
Interest expense, net—other than on deposit liabilities and other bank borrowings	(19,365		)	(19,229		)	(56,792		)	(57,235		)
Allowance for borrowed funds used during construction	854			737			2,276			1,918
Allowance for equity funds used during construction	2,274			2,057			6,010			5,366
Income before income taxes	179,205			80,660			301,242			189,380
Income taxes	51,592			29,516			96,203			70,406
Net income	127,613			51,144			205,039			118,974
Preferred stock dividends of subsidiaries	471			471			1,417			1,417
Net income for common stock	$	127,142		$	50,673		$	203,622		$	117,557
Basic earnings per common share	$	1.17		$	0.47		$	1.89		$	1.11
Diluted earnings per common share	$	1.17		$	0.47		$	1.88		$	1.11
Dividends per common share	$	0.31		$	0.31		$	0.93		$	0.93
Weighted-average number of common shares outstanding	108,268			107,457			107,951			106,067
Net effect of potentially dilutive shares	204			281			220			280
Adjusted weighted-average shares	108,472			107,738			108,171			106,347

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 September 30						Nine months ended September 30
(in thousands)	2016			2015			2016			2015
Net income for common stock	$	127,142		$	50,673		$	203,622		$	117,557
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on available-for-sale investment securities:
Net unrealized gains (losses) on available-for-sale investment securities arising during the period, net of (taxes) benefits of $1,417, $(2,543), $(5,413) and $(2,382) for the respective periods	(2,147		)	3,851			8,197			3,608
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, nil, $238 and nil for the respective periods	—			—			(360		)	—
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized gains, net of taxes of $205, nil, $368 and nil for the respective periods	321			—			578			—
Less: reclassification adjustment to net income, net of (taxes) benefits of $(110), $37, $(75) and $112 for the respective periods	(173		)	59			(119		)	177
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 $2,324, $3,583, $6,943 and $10,760 for the respective periods	3,641			5,611			10,877			16,850
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,109, $3,243, $6,327 and $9,729 for the respective periods	(3,311		)	(5,091		)	(9,934		)	(15,274		)
Other comprehensive income (loss), net of taxes	(1,669		)	4,430			9,239			5,361
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	125,473		$	55,103		$	212,861		$	122,918

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)	September 30, 2016			December 31, 2015
Assets
Cash and cash equivalents	$	284,355		$	300,478
Accounts receivable and unbilled revenues, net	250,076			242,766
Available-for-sale investment securities, at fair value	996,984			820,648
Stock in Federal Home Loan Bank, at cost	11,218			10,678
Loans receivable held for investment, net	4,675,901			4,565,781
Loans held for sale, at lower of cost or fair value	26,743			4,631
Property, plant and equipment, net of accumulated depreciation of $2,416,937 and $2,339,319 at the respective dates	4,532,556			4,377,658
Regulatory assets	879,775			896,731
Other	459,187			480,457
Goodwill	82,190			82,190
Total assets	$	12,198,985		$	11,782,018
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	134,176		$	138,523
Interest and dividends payable	27,115			26,042
Deposit liabilities	5,380,721			5,025,254
Short-term borrowings—other than bank	—			103,063
Other bank borrowings	265,388			328,582
Long-term debt, net—other than bank	1,579,065			1,578,368
Deferred income taxes	721,470			680,877
Regulatory liabilities	400,479			371,543
Contributions in aid of construction	525,491			506,087
Defined benefit pension and other postretirement benefit plans liability	572,933			589,918
Other	489,466			471,828
Total liabilities	10,096,304			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: 108,503,210 shares and 107,460,406 shares at the respective dates	1,657,421			1,629,136
Retained earnings	427,990			324,766
Accumulated other comprehensive loss, net of tax benefits	(17,023		)	(26,262		)
Total shareholders’ equity	2,068,388			1,927,640
Total liabilities and shareholders’ equity	$	12,198,985		$	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	—	—		203,622			—			203,622
Other comprehensive income, net of taxes	—	—		—			9,239			9,239
Issuance of common stock, net	1,043	28,285		—			—			28,285
Common stock dividends ($0.93 per share)	—	—		(100,398		)	—			(100,398		)
Balance, September 30, 2016	108,503	$	1,657,421	$	427,990		$	(17,023	)	$	2,068,388
Balance, December 31, 2014	102,565	$	1,521,297	$	296,654		$	(27,378	)	$	1,790,573
Net income for common stock	—	—		117,557			—			117,557
Other comprehensive income, net of taxes	—	—		—			5,361			5,361
Issuance of common stock, net	4,894	105,962		—			—			105,962
Common stock dividends ($0.93 per share)	—	—		(98,452		)	—			(98,452		)
Balance, September 30, 2015	107,459	$	1,627,259	$	315,759		$	(22,017	)	$	1,921,001

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

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)



Nine months ended September 30	2016			2015
(in thousands)
Cash flows from operating activities
Net income	$	205,039		$	118,974
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	145,684			137,721
Other amortization	7,368			7,252
Provision for loan losses	15,266			5,436
Loans receivable originated and purchased, held for sale	(172,657		)	(226,081		)
Proceeds from sale of loans receivable, held for sale	168,490			231,509
Deferred income taxes	30,667			2,723
Share-based compensation expense	3,581			4,780
Excess tax benefits from share-based payment arrangements	(398		)	(1,012		)
Allowance for equity funds used during construction	(6,010		)	(5,366		)
Impairment of utility assets	—			4,828
Other	3,234			3,921
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net	(12,104		)	8,248
Decrease in fuel oil stock	6,736			35,942
Increase in regulatory assets	(2,251		)	(23,458		)
Increase (decrease) in accounts, interest and dividends payable	3,399			(34,171		)
Change in prepaid and accrued income taxes and utility revenue taxes	52,558			(8,458		)
Increase in defined benefit pension and other postretirement benefit plans liability	150			418
Change in other assets and liabilities	(39,850		)	(41,954		)
Net cash provided by operating activities	408,902			221,252
Cash flows from investing activities
Available-for-sale investment securities purchased	(354,165		)	(326,965		)
Principal repayments on available-for-sale investment securities	172,829			96,053
Proceeds from sale of available-for-sale investment securities	16,423			—
Purchase of stock from Federal Home Loan Bank	(2,773		)	(1,600		)
Redemption of stock from Federal Home Loan Bank	2,233			60,223
Net increase in loans held for investment	(175,303		)	(101,771		)
Proceeds from sale of commercial loans	37,946			—
Proceeds from sale of real estate acquired in settlement of loans	829			1,258
Proceeds from sale of real estate held-for-sale	1,764			7,280
Capital expenditures	(259,207		)	(276,186		)
Contributions in aid of construction	23,568			34,627
Other	112			4,084
Net cash used in investing activities	(535,744		)	(502,997		)
Cash flows from financing activities
Net increase in deposit liabilities	355,467			202,539
Net increase (decrease) in short-term borrowings with original maturities of three months or less	(103,063		)	53,020
Net increase (decrease) in retail repurchase agreements	(21,121		)	67,934
Proceeds from other bank borrowings	55,835			50,000
Repayments of other bank borrowings	(97,902		)	(40,000		)
Proceeds from issuance of long-term debt	75,000			—
Repayment of long-term debt	(75,000		)	—
Excess tax benefits from share-based payment arrangements	398			1,012
Net proceeds from issuance of common stock	10,901			104,437
Common stock dividends	(83,620		)	(98,452		)
Preferred stock dividends of subsidiaries	(1,417		)	(1,417		)
Other	(4,759		)	(4,453		)
Net cash provided by financing activities	110,719			334,620
Net increase (decrease) in cash and cash equivalents	(16,123		)	52,875
Cash and cash equivalents, beginning of period	300,478			175,542
Cash and cash equivalents, end of period	$	284,355		$	228,417

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 September 30						Nine months ended September 30
(in thousands)	2016			2015			2016			2015
Revenues	$	572,253		$	648,127		$	1,549,700		$	1,779,732
Expenses
Fuel oil	128,624			195,633			334,263			518,670
Purchased power	157,750			160,518			412,667			445,809
Other operation and maintenance	94,789			103,653			298,260			306,519
Depreciation	46,759			44,356			140,300			132,840
Taxes, other than income taxes	54,519			61,310			148,386			169,440
Total expenses	482,441			565,470			1,333,876			1,573,278
Operating income	89,812			82,657			215,824			206,454
Allowance for equity funds used during construction	2,274			2,057			6,010			5,366
Interest expense and other charges, net	(17,323		)	(16,557		)	(49,734		)	(49,170		)
Allowance for borrowed funds used during construction	854			737			2,276			1,918
Income before income taxes	75,617			68,894			174,376			164,568
Income taxes	28,145			25,390			64,682			60,351
Net income	47,472			43,504			109,694			104,217
Preferred stock dividends of subsidiaries	228			228			686			686
Net income attributable to Hawaiian Electric	47,244			43,276			109,008			103,531
Preferred stock dividends of Hawaiian Electric	270			270			810			810
Net income for common stock	$	46,974		$	43,006		$	108,198		$	102,721

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

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.

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)



	Three months ended September 30						Nine months ended September 30
(in thousands)	2016			2015			2016			2015
Net income for common stock	$	46,974		$	43,006		$	108,198		$	102,721
Other comprehensive income (loss), net of taxes:
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized gains, net of taxes of $205, nil, $368 and nil for the respective periods	321			—			578			—
Less: reclassification adjustment to net income, net of taxes of $110, nil, $110 and nil for the respective periods	(173		)	—			(173		)	—
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 $2,110, $3,245, $6,331 and $9,735 for the respective periods	3,314			5,095			9,941			15,285
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,109, $3,243, $6,327 and $9,729 for the respective periods	(3,311		)	(5,091		)	(9,934		)	(15,274		)
Other comprehensive income (loss), net of taxes	151			4			412			11
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	47,125		$	43,010		$	108,610		$	102,732

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)	September 30, 2016			December 31, 2015
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	53,175		$	52,792
Plant and equipment	6,483,562			6,315,698
Less accumulated depreciation	(2,343,601		)	(2,266,004		)
Construction in progress	236,608			175,309
Utility property, plant and equipment, net	4,429,744			4,277,795
Nonutility property, plant and equipment, less accumulated depreciation of $1,231 and $1,229 at respective dates	7,374			7,272
Total property, plant and equipment, net	4,437,118			4,285,067
Current assets
Cash and cash equivalents	22,977			24,449
Customer accounts receivable, net	134,418			132,778
Accrued unbilled revenues, net	95,167			84,509
Other accounts receivable, net	4,629			10,408
Fuel oil stock, at average cost	64,480			71,216
Materials and supplies, at average cost	57,356			54,429
Prepayments and other	35,645			36,640
Regulatory assets	74,681			72,231
Total current assets	489,353			486,660
Other long-term assets
Regulatory assets	805,094			824,500
Unamortized debt expense	267			497
Other	68,994			75,486
Total other long-term assets	874,355			900,483
Total assets	$	5,800,826		$	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	578,921			578,930
Retained earnings	1,081,081			1,043,082
Accumulated other comprehensive income, net of income taxes	1,337			925
Common stock equity	1,766,727			1,728,325
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,279,327			1,278,702
Total capitalization	3,080,347			3,041,320
Commitments and contingencies (Note 4)
Current liabilities
Short-term borrowings from affiliates	21,000			—
Accounts payable	107,497			114,846
Interest and preferred dividends payable	25,934			23,111
Taxes accrued	167,276			191,084
Regulatory liabilities	2,987			2,204
Other	56,753			54,079
Total current liabilities	381,447			385,324
Deferred credits and other liabilities
Deferred income taxes	714,559			654,806
Regulatory liabilities	397,492			369,339
Unamortized tax credits	87,794			84,214
Defined benefit pension and other postretirement benefit plans liability	535,912			552,974
Other	77,784			78,146
Total deferred credits and other liabilities	1,813,541			1,739,479
Contributions in aid of construction	525,491			506,087
Total capitalization and liabilities	$	5,800,826		$	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	—	—		—			108,198			—		108,198
Other comprehensive income, net of taxes	—	—		—			—			412		412
Common stock dividends	—	—		—			(70,199		)	—		(70,199		)
Common stock issuance expenses	—	—		(9		)	—			—		(9		)
Balance, September 30, 2016	15,805	$	105,388	$	578,921		$	1,081,081		$	1,337	$	1,766,727
Balance, December 31, 2014	15,805	$	105,388	$	578,938		$	997,773		$	45	$	1,682,144
Net income for common stock	—	—		—			102,721			—		102,721
Other comprehensive income, net of taxes	—	—		—			—			11		11
Common stock dividends	—	—		—			(67,804		)	—		(67,804		)
Common stock issuance expenses	—	—		(8		)	—			—		(8		)
Balance, September 30, 2015	15,805	$	105,388	$	578,930		$	1,032,690		$	56	$	1,717,064

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)



Nine months ended September 30	2016			2015
(in thousands)
Cash flows from operating activities
Net income	$	109,694		$	104,217
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	140,300			132,840
Other amortization	5,380			4,999
Deferred income taxes	55,648			58,211
Tax credits, net	5,256			4,247
Allowance for equity funds used during construction	(6,010		)	(5,366		)
Impairment of utility assets	—			4,828
Other	(2,022		)	(326		)
Changes in assets and liabilities
Increase in accounts receivable	(655		)	(4,464		)
Decrease (increase) in accrued unbilled revenues	(10,658		)	13,796
Decrease in fuel oil stock	6,736			35,942
Increase in materials and supplies	(2,927		)	(1,723		)
Increase in regulatory assets	(2,251		)	(23,458		)
Decrease in accounts payable	(676		)	(40,375		)
Change in prepaid and accrued income taxes and revenue taxes	(9,595		)	(61,635		)
Increase in defined benefit pension and other postretirement benefit plans liability	360			331
Change in other assets and liabilities	(13,309		)	(20,478		)
Net cash provided by operating activities	275,271			201,586
Cash flows from investing activities
Capital expenditures	(250,704		)	(265,521		)
Contributions in aid of construction	23,568			34,627
Other	1,100			778
Net cash used in investing activities	(226,036		)	(230,116		)
Cash flows from financing activities
Common stock dividends	(70,199		)	(67,804		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,496		)	(1,496		)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	21,000			94,995
Other	(12		)	(223		)
Net cash provided by (used in) financing activities	(50,707		)	25,472
Net decrease in cash and cash equivalents	(1,472		)	(3,058		)
Cash and cash equivalents, beginning of period	24,449			13,762
Cash and cash equivalents, end of period	$	22,977		$	10,704

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 September 30, 2016 and December 31, 2015, the results of their operations for the three and nine months ended September 30, 2016 and 2015 and their cash flows for the nine months ended September 30, 2016 and 2015. All such adjustments are of a normal recurring nature, unless otherwise disclosed below or in other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year.

2 · Termination of proposed merger and other matters

On December 3, 2014, HEI, NextEra Energy, Inc. (NEE) and two subsidiaries of NEE entered into an Agreement and Plan of Merger (the Merger Agreement), under which Hawaiian Electric was to become a subsidiary of NEE. The Merger Agreement contemplated that, prior to the Merger, HEI would distribute to its shareholders all of the common stock of ASB Hawaii, Inc. (ASB Hawaii), the parent company of ASB (such distribution referred to as the Spin-Off).

The closing of the Merger was subject to various conditions, including receipt of regulatory approval from the Hawaii Public Utilities Commission (PUC). In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger. On July 15, 2016, the PUC dismissed the application without prejudice.

On July 16, 2016, NEE terminated the Merger Agreement. Pursuant to the terms of the Merger Agreement, on July 19, 2016, NEE paid HEI a $90 million termination fee and $5 million for the reimbursement of expenses associated with the transaction. In the third quarter of 2016, the Company recognized $64 million of net income, comprised of the termination fee ($55 million), reimbursements of expenses from NEE and insurance ($3 million), and additional tax benefits on the previously non-tax-deductible merger- and spin-off-related expenses incurred through June 30, 2016 ($8 million), less merger- and spin-off-related expenses incurred in the third quarter of 2016 ($2 million) (all net of tax impacts). The Spin-Off of ASB Hawaii was cancelled as it was cross-conditioned on the merger consummation.

In May 2016, the Utilities filed an application for approval of an LNG supply and transport agreement and LNG-related capital equipment and two related applications, which applications were conditioned on the PUC’s approval of the proposed Merger. On July 21, 2016, the Utilities withdrew the three applications.

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 with NEE, several purported class action complaints were filed by alleged stockholders of HEI against HEI, the individual directors of HEI, NEE and others. To date, all of these lawsuits (seven of which were consolidated) have been dismissed, either with or without prejudice.

3 · Segment financial information



(in thousands)	Electric utility		Bank		Other			Total
Three months ended September 30, 2016
Revenues from external customers	$	572,208	$	73,708	$	139		$	646,055
Intersegment revenues (eliminations)	45		—		(45		)	—
Revenues	572,253		73,708		94			646,055
Income (loss) before income taxes	75,617		22,727		80,861			179,205
Income taxes (benefit)	28,145		7,623		15,824			51,592
Net income (loss)	47,472		15,104		65,037			127,613
Preferred stock dividends of subsidiaries	498		—		(27		)	471
Net income (loss) for common stock	46,974		15,104		65,064			127,142
Nine months ended September 30, 2016
Revenues from external customers	$	1,549,602	$	213,297	$	360		$	1,763,259
Intersegment revenues (eliminations)	98		—		(98		)	—
Revenues	1,549,700		213,297		262			1,763,259
Income (loss) before income taxes	174,376		62,545		64,321			301,242
Income taxes (benefit)	64,682		21,483		10,038			96,203
Net income (loss)	109,694		41,062		54,283			205,039
Preferred stock dividends of subsidiaries	1,496		—		(79		)	1,417
Net income (loss) for common stock	108,198		41,062		54,362			203,622
Total assets (at September 30, 2016)	5,800,826		6,336,670		61,489			12,198,985
Three months ended September 30, 2015
Revenues from external customers	$	648,121	$	69,091	$	(36	)	$	717,176
Intersegment revenues (eliminations)	6		—		(6		)	—
Revenues	648,127		69,091		(42		)	717,176
Income (loss) before income taxes	68,894		20,802		(9,036		)	80,660
Income taxes (benefit)	25,390		7,351		(3,225		)	29,516
Net income (loss)	43,504		13,451		(5,811		)	51,144
Preferred stock dividends of subsidiaries	498		—		(27		)	471
Net income (loss) for common stock	43,006		13,451		(5,784		)	50,673
Nine months ended September 30, 2015
Revenues from external customers	$	1,779,708	$	199,222	$	20		$	1,978,950
Intersegment revenues (eliminations)	24		—		(24		)	—
Revenues	1,779,732		199,222		(4		)	1,978,950
Income (loss) before income taxes	164,568		61,159		(36,347		)	189,380
Income taxes (benefit)	60,351		21,382		(11,327		)	70,406
Net income (loss)	104,217		39,777		(25,020		)	118,974
Preferred stock dividends of subsidiaries	1,496		—		(79		)	1,417
Net income (loss) for common stock	102,721		39,777		(24,941		)	117,557
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 third quarters of 2016 and 2015 and nine months ended September 30, 2016 and 2015 approximately $51 million, $58 million, $138 million and $159 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 continues 50% bonus depreciation through 2017 and phases down the percentage to 40% in 2018 and 30% in 2019 and then terminates bonus depreciation thereafter. The extension of bonus depreciation resulted in an increase in 2015 tax depreciation of $123 million. Tax depreciation is expected to increase by approximately $126 million in 2016 and result in increased accumulated deferred tax liabilities.

Additionally, the “Consolidating Appropriations Act, 2016” extended a variety of energy-related credits that were expired or were 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 September 30, 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 nine months ended September 30, 2016 and 2015 each consisted of $2.5 million of interest income received from the 2004 Debentures; $2.4 million of distributions to holders of the Trust Preferred Securities; and $75,000 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 September 30, 2016, the Utilities had five PPAs for firm capacity and other PPAs with IPPs and Schedule Q providers (e.g., customers with cogeneration and/or power production facilities 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 September 30				Nine months ended September 30
(in millions)	2016		2015		2016		2015
AES Hawaii	$	38	$	37	$	112	$	97
Kalaeloa	44		51		109		143
HEP	8		13		23		34
Hpower	19		18		52		50
Puna Geothermal Venture	7		8		19		22
Hawaiian Commercial & Sugar (HC&S)	1		2		1		7
Other IPPs	41		32		97		93
Total IPPs	$	158	$	161	$	413	$	446

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 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 PPA term that ended on May 23, 2016. The PPA automatically extends 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.

On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the PPA prior to October 31, 2017. This agreement complements continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution.

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 September 30, 2016, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $12 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 be at fixed rates not subject to adjustment based on changes in the Gross National Product Implicit Price Deflator. 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 September 30, 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 December 2019. 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 prices are 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. The LSFO Contract will be replaced by a new contract with Chevron for LSFO and diesel fuel to meet MATS requirements for the island of Oahu that begins on January 1, 2017, terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party.

The Utilities are also parties to amended Inter-Island contracts for the supplies of industrial fuel oil and diesel fuels with Chevron and Par Hawaii Refining, LLC (PAR) (formerly known as Hawaii Independent Energy, LLC), respectively, which terminate on December 31, 2016. The Inter-Island contracts will be replaced by a new Inter-Island contract with Chevron for industrial fuel oil, diesel and ultra-low sulfur diesel for the islands of Oahu, Hawaii, Maui and Molokai, which begins on January 1, 2017, terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party.

Hawaii Electric Light and Chevron are also parties to a terminalling agreement for the island of Hawaii, which begins on January 1, 2017, terminates on December 31, 2019 and may automatically renew for annual terms thereafter unless earlier terminated by either party. Currently, terminalling services are provided to Hawaii Electric Light under the Inter-island Fuel Supply Contract with Chevron that expires on December 31, 2016.

The PUC has approved all of the foregoing contracts (LSFO, Inter-Island and Terminalling) and the costs incurred under these contracts are included in the Utilities’ respective ECACs, to the extent such costs are not recovered through the base rates.

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 PAR (formerly known as Hawaii Independent Energy, LLC) for LSFO under a Facility Fuel Supply Contract (fuel contract) between them. The term of the fuel contract between Kalaeloa and PAR ended on May 31, 2016 and is being extended until terminated by one of the parties.

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 18, 2016, Hawaiian Electric and Fortis Hawaii Energy Inc. (Fortis Hawaii), an affiliate of Fortis, Inc. (Fortis), entered into a Fuel Supply Agreement (FSA) whereby Fortis Hawaii intended to sell to Hawaiian Electric liquefied natural gas (LNG) to be produced from the LNG facilities on Tilbury Island in Delta, British Columbia, Canada. Pursuant to the FSA, Fortis Hawaii had arranged, or planned to arrange, for the transportation of gas for delivery to, and liquefaction at, the Tilbury LNG facilities, including with respect to the transport and delivery of LNG across a jetty at such facilities, for the purchase and storage of LNG at such LNG facilities and for the transportation of LNG to delivery points in Hawaii for the benefit of Hawaiian Electric and its subsidiaries. The FSA was subject to approval by the PUC and to the satisfaction of certain conditions precedent, including the consummation of the merger between HEI and NEE. On July 16, 2016, pursuant to the terms of the Merger Agreement, NEE terminated the Merger Agreement. Accordingly, on July 19, 2016, Hawaiian Electric provided notice of termination of the FSA to Fortis Hawaii, effective immediately, and withdrew the application for PUC approval of the FSA, which included a request for approval to commit approximately $341 million to convert existing generating units to use natural gas, and to commit approximately $117 million for containers to support LNG. In addition, on July 19, 2016, Hawaiian Electric withdrew its applications to the PUC for a waiver from the competitive bidding process to allow Hawaiian Electric to construct a modern, efficient, combined cycle generation system at the Kahe power plant that would utilize LNG and to commit $859 million for such project. Hawaiian Electric will continue to evaluate all options to modernize generation using a cleaner fuel to bring price stability and support adding renewable energy for its customers.

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 Hawaii Electric Light 2016 test year 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 Ormat Technologies, Inc. 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.

In February 2016, Huena Power Inc. (Huena) filed with the PUC a Petition for Declaratory Order (which the PUC later dismissed without prejudice) and a Complaint relating to the Geothermal RFP. Hawaii Electric Light filed a motion to dismiss Huena’s Petition which was granted on March 28, 2016. Hawaii Electric Light’s motion to dismiss Huena’s Complaint is still pending.

Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) Implementation Project. The Utilities submitted their 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. In October 2015, the PUC issued a D&O (1) finding that there is a need to replace the Utilities’ 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 two options. As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015. In April 2016, the Utilities filed additional information on the costs and benefits of the project and the Consumer Advocate submitted its reply.

On August 11, 2016, the PUC issued a second D&O approving the Utilities’ request to commence the ERP/EAM implementation project, subject to certain conditions, including a $77.6 million cap on cost recovery as well as a requirement that the Utilities pass onto customers a minimum of $244 million in savings associated with the system over its 12-year service life. Pursuant to the D&O and subsequent orders, the Utilities will be required to file: the proposed methods of passing on to customers the estimated monetary savings attributable to the project by November 7, 2016; a bottom-up, low-level analysis of the project’s benefits; performance metrics and tracking mechanism for passing the project’s benefits on to customers by September 2017; and monthly reports on the status and costs of the project starting February 2017

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. Hawaiian Electric has received all of the major permits for the project, including a 35 year site lease from the U.S. Army. Construction of the facility began in October 2016. The generating station is expected to be placed in service in the first quarter of 2018.

Hamakua Energy Partners, L.P. (HEP) Asset Purchase Agreement. Hawaii Electric Light has been purchasing up to 60 MW (net) of firm capacity from HEP under a power purchase agreement (PPA) that expires on December 30, 2030. The HEP plant currently contributes about 23% of the island of Hawaii’s generating capacity. On December 22, 2015, Hawaii Electric Light entered into an agreement, subject to PUC approval, to acquire the assets of HEP for approximately $84.5 million. If approved by the PUC, the agreement to purchase the existing HEP generating assets will terminate the existing PPA. The elimination of certain required capacity payments under the PPA is expected to result in lower costs to customers. Additionally, by owning the plant, Hawaii Electric Light will be able to manage HEP’s efficient generating units more productively, providing greater flexibility to cycle HEP’s generating units to more effectively manage the Hawaii island grid. This increased operational flexibility will be essential to support and facilitate Hawaii Electric Light’s efforts to integrate more renewable energy onto the grid.

An application to approve the project has been filed with the PUC.

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.

Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, periodically encounter petroleum or other chemical releases into the environment associated with current or previous operations. The Utilities report and take action on

these releases when and as required by applicable law and regulations. The Utilities believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on Hawaiian Electric’s consolidated results of operations, financial condition or liquidity.

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 established 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 are 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 the 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 has proceeded with the implementation of the MATS Compliance Plan and has met all compliance requirements to date including the April 16, 2016 compliance date. Hawaiian Electric submitted a formal compliance demonstration report to the EPA and DOH on September 23, 2016.

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 the 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.

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 September 30, 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. Onshore sampling at the Waiau Power Plant was completed in two phases in December 2015 and June 2016. The extent of the onshore contamination, the appropriate remedial measures to address it and any associated costs have not yet been determined.

As of September 30, 2016, the reserve account balance recorded by Hawaiian Electric to address the PCB contamination was $4.4 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 plans to include the AES facility on Oahu as a partner in the Utilities’ EmRP. Additionally, if the proposed acquisition of the Hamakua Energy Partners (HEP) facility by Hawaii Electric Light is approved by the PUC, the GHG emissions from the HEP facility would need to be addressed in the Utilities’ EmRP. Hawaiian Electric is working with the DOH on the timing of the EmRP modifications to address these changes in the partnership.

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 emissions limits for new and 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, with final limits in effect starting in 2030. The final Clean Power Plan did not set forth guidelines for Alaska, Hawaii, Puerto Rico or Guam, because the EPA did not have enough information to include them at the time the Rule was published. Subsequently, on February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending resolution of several petitions for review in the U.S. Court of Appeals for the D.C. Circuit Court.

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 will continue to pursue the use of cleaner fuels to replace, at least in part, petroleum. 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:



	Nine months ended September 30
(in thousands)	2016			2015
Balance, beginning of period	$	26,848		$	29,419
Accretion expense	10			18
Liabilities incurred	—			—
Liabilities settled	(661		)	(2,349		)
Revisions in estimated cash flows	—			—
Balance, end of period	$	26,197		$	27,088

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. Under the decoupling tariff approved in 2011, the annual RAM is accrued and billed from June 1 of each year through May 31 of the following year.

As part of a January 2013 Settlement Agreement with the Consumer Advocate, which was approved by the PUC, for RAM years 2014 - 2016, Hawaiian Electric was allowed to record RAM revenue beginning on January 1 and to bill such amounts from June 1 of the applicable year through May 31 of the following year (current accrual method). After 2016, the RAM provisions approved in 2011 will again apply to Hawaiian Electric. On November 1, 2016, Hawaiian Electric filed a motion requesting the current accrual method for the RAM that is in place through the end of 2016, be made permanent. If approved, Hawaiian Electric’s ROACE for 2017 would be 75 basis points better than not getting the request approved. Hawaiian Electric’s request is based on a number of factors including changed circumstances since the PUC’s decision on the RAM revenues in 2011, the original intent of decoupling, and consistency with accrual accounting. The filing also requests the implementation of Hawaiian Electric’s current accrual method for RAM revenues for Hawaii Electric Light and Maui Electric beginning in 2017. The Utilities requested a PUC decision by December 31, 2016 but no later than the end of January 2017 and cannot predict the outcome of the request.

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 RAM Cap). 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 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 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. On April 18, 2016, Hawaiian Electric modified its October 26, 2015 application to reduce its request to recover revenue requirements associated with 2015 net plant additions from $40.3 million to $35.7 million for the same reason as Maui Electric regarding the extension of bonus depreciation in 2015. On August 3, 2016, the PUC dismissed Hawaiian Electric’s October 26, 2015 Above the RAM Cap application because the application did not also request approval of the commitment of capital expenditures.

On August 25, 2016, Maui Electric filed an application to recover the revenue requirements associated with 2017 plant additions for substations in the total amount of $27.2 million and other associated costs through the RAM above the 2017 RAM Cap.

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. On May 19, 2016, Hawaii Electric Light amended its annual decoupling filing to update and revise certain cost information. The tariffed rates include: (1) 2016 RAM Revenue Adjustment as determined by the March Order, (2) accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2015 (and associated revenue taxes) to be collected:



($ in millions)	Hawaiian Electric			Hawaii Electric Light			Maui Electric
Annual incremental RAM adjusted revenues	$	11.0		$	2.3		$	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)	$	(13.6	)	$	(2.5	)	$	(4.3	)
Net annual incremental decrease in amount to be collected under the tariffs	$	(2.6	)	$	(0.2	)	$	(1.4	)
Impact on typical residential customer monthly bill (in dollars) *	$	0.01		$	0.13		$	(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 and Hawaii Electric Light have a net annual incremental decrease in amount to be collected under the tariffs, their bills will increase by $0.01 and $0.13, respectively, due to lower anticipated KWH sales.

On May 24, 2016, the PUC approved the annual decoupling filings for Hawaiian Electric and Maui Electric, and as amended on May 19, 2016, for Hawaii Electric Light, to go into effect on June 1, 2016.

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.

Hawaiian Telcom. The Utilities each have separate agreements for the joint ownership and maintenance of utility poles with Hawaiian Telcom, Inc. (Hawaiian Telcom), the respective county or counties in which each utility operates and other third parties, such as the State of Hawaii. The agreements set forth various circumstances requiring pole removal/installation/replacement and the sharing of costs among the joint pole owners. The agreements allow for the cost of work done by one joint pole owner to be shared by the other joint pole owners based on the apportionment of costs in the agreements. The Utilities have maintained, replaced and installed the majority of the jointly-owned poles in each of the respective service territories, and have billed the other joint pole owners for their respective share of the costs. The counties and the State have been fully reimbursing the Utilities for their share of the costs. However, Hawaiian Telcom has been delinquent in reimbursing the Utilities for its share of the costs.

For Hawaiian Electric, a dispute resolution process to collect the unpaid amounts from Hawaiian Telcom is proceeding as specified by the joint pole agreement. For Hawaii Electric Light, the agreement does not specify an alternative dispute resolution process, and thus a complaint for payment was filed with the Circuit Court in June 2016. Maui Electric has not yet commenced any legal action to recover the delinquent amounts. As of September 30, 2016, total receivables under the joint pole agreement, including interest, from Hawaiian Telcom are $20.1 million ($13.7 million at Hawaiian Electric, $5.5 million at Hawaii Electric Light, and $0.9 million at Maui Electric). Management has reserved for the accrued interest on the receivables amounting to $3.9 million. Management expects to prevail on their claims and collect at least $16.2 million.

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 Utilities addressed these orders 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 (DR) 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. In July 2016, the PUC issued an order in the DR Portfolio Tariff proceeding. The PUC granted intervenor and participant status to certain movants, made some preliminary observations on the proposed grid service tariffs and supporting modeling efforts, and instructed the Utilities to move forward with the development of DR programs for all islands. The PUC plans to conduct one or more technical conferences and ordered the Utilities to develop an implementation timeline and procedural schedule to enable an end-of-year implementation.

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. As required by the order, the Utilities submitted a Proposed Revision Plan in November 2015, 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, and submitted updated PSIPs on April 1, 2016. The parties and participants filed comments on the Utilities Proposed Revision Plan in January 2016. The updated PSIPs, filed on April 1, 2016, provide the Utilities’ assumptions, analyses and plans to achieve 100% renewable energy using a diverse mix of energy resources by 2045.

In August 2016, the PUC issued an order establishing a procedural schedule to address the Utilities’ April 1, 2016 PSIP updates, which was further modified in an order issued in October 2016. The utilities are required to file an updated PSIP incorporating input from the Parties, develop alternative scenarios and sensitivity analyses and perform iterations on modeling and simulations by December 23, 2016. The final steps in the procedural schedule are for the parties’ submission of their respective statements of position in February 2017. The Utilities will continue to evaluate all options to achieving the state’s 100% renewable energy goal, to stabilize and reduce customer rates and to maintain safe and reliable service.

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.

On June 15, 2016, the PUC issued an order approving the Utilities’ Advanced Inverter Test Plan with, among other conditions, a requirement to supplement the Test Plan to include testing procedures. In addition, the PUC ordered the Utilities to submit the results of the testing described in the Test Plan by December 15, 2016.

Pursuant to a PUC order, in October 2016, the Utilities submitted tariffs for a Residential Interim Time of Use program, which is limited to 2 years and 5,000 customers. The primary objective is to encourage more efficient use of the electric system and enable more cost-effective integration of renewable energy by shifting customer load from the system’s higher cost, peak demand period to the mid-day period when relatively inexpensive renewable resources are abundant.

On October 3, 2016, the PUC issued an Order, which, in part, granted five additional motions to intervene and establishes a preliminary statement of issues for Phase 2 of this proceeding.

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.



	September 30, 2016				December 31, 2015
(dollars in thousands)	Notional amount		Fair value		Notional amount		Fair value
Window forward contract	$	20,725	$	664	$	—	$	—

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

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

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended September 30, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	404,352		83,105		84,831		—	(35	)	$	572,253
Expenses
Fuel oil	88,676			14,603		25,345		—	—		128,624
Purchased power	118,751			22,728		16,271		—	—		157,750
Other operation and maintenance	64,683			15,017		15,089		—	—		94,789
Depreciation	31,520			9,449		5,790		—	—		46,759
Taxes, other than income taxes	38,666			7,836		8,017		—	—		54,519
Total expenses	342,296			69,633		70,512		—	—		482,441
Operating income	62,056			13,472		14,319		—	(35	)	89,812
Allowance for equity funds used during construction	1,806			238		230		—	—		2,274
Equity in earnings of subsidiaries	14,729			—		—		—	(14,729	)	—
Interest expense and other charges, net	(11,903		)	(2,972	)	(2,483	)	—	35		(17,323		)
Allowance for borrowed funds used during construction	669			91		94		—	—		854
Income before income taxes	67,357			10,829		12,160		—	(14,729	)	75,617
Income taxes	20,113			3,392		4,640		—	—		28,145
Net income	47,244			7,437		7,520		—	(14,729	)	47,472
Preferred stock dividends of subsidiaries	—			133		95		—	—		228
Net income attributable to Hawaiian Electric	47,244			7,304		7,425		—	(14,729	)	47,244
Preferred stock dividends of Hawaiian Electric	270			—		—		—	—		270
Net income for common stock	$	46,974		7,304		7,425		—	(14,729	)	$	46,974

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Three months ended September 30, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	46,974		7,304		7,425		—	(14,729	)	$	46,974
Other comprehensive income (loss), net of taxes:
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized loss, net of tax benefits	321			—		—		—	—		321
Less: reclassification adjustment to net income, net of tax benefits	(173		)	—		—		—	—		(173		)
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	3,314			429		387		—	(816	)	3,314
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(3,311		)	(429	)	(389	)	—	818		(3,311		)
Other comprehensive income (loss), net of taxes	151			—		(2	)	—	2		151
Comprehensive income attributable to common shareholder	$	47,125		7,304		7,423		—	(14,727	)	$	47,125

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended September 30, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	463,394		89,817		94,941		—	(25	)	$	648,127
Expenses
Fuel oil	142,194			17,208		36,231		—	—		195,633
Purchased power	119,302			26,713		14,503		—	—		160,518
Other operation and maintenance	69,621			18,936		15,096		—	—		103,653
Depreciation	29,389			9,313		5,654		—	—		44,356
Taxes, other than income taxes	43,923			8,455		8,932		—	—		61,310
Total expenses	404,429			80,625		80,416		—	—		565,470
Operating income	58,965			9,192		14,525		—	(25	)	82,657
Allowance for equity funds used during construction	1,714			148		195		—	—		2,057
Equity in earnings of subsidiaries	11,858			—		—		—	(11,858	)	—
Interest expense and other charges, net	(11,468		)	(2,674	)	(2,440	)	—	25		(16,557		)
Allowance for borrowed funds used during construction	605			53		79		—	—		737
Income before income taxes	61,674			6,719		12,359		—	(11,858	)	68,894
Income taxes	18,398			2,397		4,595		—	—		25,390
Net income	43,276			4,322		7,764		—	(11,858	)	43,504
Preferred stock dividends of subsidiaries	—			133		95		—	—		228
Net income attributable to Hawaiian Electric	43,276			4,189		7,669		—	(11,858	)	43,276
Preferred stock dividends of Hawaiian Electric	270			—		—		—	—		270
Net income for common stock	$	43,006		4,189		7,669		—	(11,858	)	$	43,006

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Three months ended September 30, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	43,006		4,189		7,669		—	(11,858	)	$	43,006
Other comprehensive income (loss), 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	5,095			682		626		—	(1,308	)	5,095
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(5,091		)	(683	)	(627	)	—	1,310		(5,091		)
Other comprehensive income (loss), net of taxes	4			(1	)	(1	)	—	2		4
Comprehensive income attributable to common shareholder	$	43,010		4,188		7,668		—	(11,856	)	$	43,010

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Nine months ended September 30, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	1,088,537		229,940		231,295		—	(72	)	$	1,549,700
Expenses
Fuel oil	224,995			40,725		68,543		—	—		334,263
Purchased power	313,730			58,885		40,052		—	—		412,667
Other operation and maintenance	202,438			46,574		49,248		—	—		298,260
Depreciation	94,564			28,347		17,389		—	—		140,300
Taxes, other than income taxes	104,764			21,632		21,990		—	—		148,386
Total expenses	940,491			196,163		197,222		—	—		1,333,876
Operating income	148,046			33,777		34,073		—	(72	)	215,824
Allowance for equity funds used during construction	4,771			571		668		—	—		6,010
Equity in earnings of subsidiaries	33,541			—		—		—	(33,541	)	—
Interest expense and other charges, net	(34,113		)	(8,606	)	(7,087	)	—	72		(49,734		)
Allowance for borrowed funds used during construction	1,785			219		272		—	—		2,276
Income before income taxes	154,030			25,961		27,926		—	(33,541	)	174,376
Income taxes	45,022			9,075		10,585		—	—		64,682
Net income	109,008			16,886		17,341		—	(33,541	)	109,694
Preferred stock dividends of subsidiaries	—			400		286		—	—		686
Net income attributable to Hawaiian Electric	109,008			16,486		17,055		—	(33,541	)	109,008
Preferred stock dividends of Hawaiian Electric	810			—		—		—	—		810
Net income for common stock	$	108,198		16,486		17,055		—	(33,541	)	$	108,198

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Nine months ended September 30, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	108,198		16,486		17,055		—	(33,541	)	$	108,198
Other comprehensive income (loss), net of taxes:
Derivatives qualified as cash flow hedges:
Effective portion of foreign currency hedge net unrealized gain, net of taxes	578			—		—		—	—		578
Less: reclassification adjustment to net income, net of tax benefits	(173		)	—		—		—	—		(173		)
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	9,941			1,288		1,162		—	(2,450	)	9,941
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(9,934		)	(1,289	)	(1,166	)	—	2,455		(9,934		)
Other comprehensive income (loss), net of taxes	412			(1	)	(4	)	—	5		412
Comprehensive income attributable to common shareholder	$	108,610		16,485		17,051		—	(33,536	)	$	108,610

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Nine months ended September 30, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Revenues	$	1,254,142		261,604		264,057		—	(71	)	$	1,779,732
Expenses
Fuel oil	364,875			56,834		96,961		—	—		518,670
Purchased power	329,922			73,161		42,726		—	—		445,809
Other operation and maintenance	206,133			51,493		48,893		—	—		306,519
Depreciation	88,167			27,938		16,735		—	—		132,840
Taxes, other than income taxes	119,603			24,783		25,054		—	—		169,440
Total expenses	1,108,700			234,209		230,369		—	—		1,573,278
Operating income	145,442			27,395		33,688		—	(71	)	206,454
Allowance for equity funds used during construction	4,418			458		490		—	—		5,366
Equity in earnings of subsidiaries	29,174			—		—		—	(29,174	)	—
Interest expense and other charges, net	(33,996		)	(7,946	)	(7,299	)	—	71		(49,170		)
Allowance for borrowed funds used during construction	1,557			164		197		—	—		1,918
Income before income taxes	146,595			20,071		27,076		—	(29,174	)	164,568
Income taxes	43,064			7,210		10,077		—	—		60,351
Net income	103,531			12,861		16,999		—	(29,174	)	104,217
Preferred stock dividends of subsidiaries	—			400		286		—	—		686
Net income attributable to Hawaiian Electric	103,531			12,461		16,713		—	(29,174	)	103,531
Preferred stock dividends of Hawaiian Electric	810			—		—		—	—		810
Net income for common stock	$	102,721		12,461		16,713		—	(29,174	)	$	102,721

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (unaudited)

Nine months ended September 30, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Net income for common stock	$	102,721		12,461		16,713		—	(29,174	)	$	102,721
Other comprehensive income (loss), 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	15,285			2,046		1,878		—	(3,924	)	15,285
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(15,274		)	(2,050	)	(1,882	)	—	3,932		(15,274		)
Other comprehensive income (loss), net of taxes	11			(4	)	(4	)	—	8		11
Comprehensive income attributable to common shareholder	$	102,732		12,457		16,709		—	(29,166	)	$	102,732

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

September 30, 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	$	43,945		6,214		3,016		—	—		$	53,175
Plant and equipment	4,148,099			1,234,234		1,101,229		—	—		6,483,562
Less accumulated depreciation	(1,362,474		)	(503,109	)	(478,018	)	—	—		(2,343,601		)
Construction in progress	197,715			18,503		20,390		—	—		236,608
Utility property, plant and equipment, net	3,027,285			755,842		646,617		—	—		4,429,744
Nonutility property, plant and equipment, less accumulated depreciation	5,761			82		1,531		—	—		7,374
Total property, plant and equipment, net	3,033,046			755,924		648,148		—	—		4,437,118
Investment in wholly owned subsidiaries, at equity	570,358			—		—		—	(570,358	)	—
Current assets
Cash and cash equivalents	9,821			7,008		6,047		101	—		22,977
Advances to affiliates	—			18,500		15,500		—	(34,000	)	—
Customer accounts receivable, net	93,253			21,646		19,519		—	—		134,418
Accrued unbilled revenues, net	69,753			12,904		12,510		—	—		95,167
Other accounts receivable, net	11,469			2,852		2,316		—	(12,008	)	4,629
Fuel oil stock, at average cost	45,298			6,885		12,297		—	—		64,480
Materials and supplies, at average cost	32,676			8,424		16,256		—	—		57,356
Prepayments and other	28,073			4,484		3,548		—	(460	)	35,645
Regulatory assets	67,042			4,582		3,057		—	—		74,681
Total current assets	357,385			87,285		91,050		101	(46,468	)	489,353
Other long-term assets
Regulatory assets	594,723			111,715		98,656		—	—		805,094
Unamortized debt expense	193			33		41		—	—		267
Other	42,872			12,786		13,336		—	—		68,994
Total other long-term assets	637,788			124,534		112,033		—	—		874,355
Total assets	$	4,598,577		967,743		851,231		101	(616,826	)	$	5,800,826
Capitalization and liabilities
Capitalization
Common stock equity	$	1,766,727		299,276		270,981		101	(570,358	)	$	1,766,727
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—		34,293
Long-term debt, net	875,573			213,673		190,081		—	—		1,279,327
Total capitalization	2,664,593			519,949		466,062		101	(570,358	)	3,080,347
Current liabilities
Short-term borrowings from affiliate	55,000			—		—		—	(34,000	)	21,000
Accounts payable	79,341			14,844		13,312		—	—		107,497
Interest and preferred dividends payable	17,863			4,034		4,048		—	(11	)	25,934
Taxes accrued	115,245			27,669		24,822		—	(460	)	167,276
Regulatory liabilities	—			1,777		1,210		—	—		2,987
Other	46,326			9,856		12,568		—	(11,997	)	56,753
Total current liabilities	313,775			58,180		55,960		—	(46,468	)	381,447
Deferred credits and other liabilities
Deferred income taxes	510,457			105,574		98,213		—	315		714,559
Regulatory liabilities	274,070			91,897		31,525		—	—		397,492
Unamortized tax credits	57,058			15,774		14,962		—	—		87,794
Defined benefit pension and other postretirement benefit plans liability	396,468			67,415		72,029		—	—		535,912
Other	50,068			13,436		14,595		—	(315	)	77,784
Total deferred credits and other liabilities	1,288,121			294,096		231,324		—	—		1,813,541
Contributions in aid of construction	332,088			95,518		97,885		—	—		525,491
Total capitalization and liabilities	$	4,598,577		967,743		851,231		101	(616,826	)	$	5,800,826

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

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 (unaudited)

Nine months ended September 30, 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	108,198			16,486		17,055		—	(33,541	)	108,198
Other comprehensive income (loss), net of taxes	412			(1	)	(4	)	—	5		412
Common stock dividends	(70,199		)	(9,906	)	(9,795	)	—	19,701		(70,199		)
Common stock issuance expenses	(9		)	(5	)	—		—	5		(9		)
Balance, September 30, 2016	$	1,766,727		299,276		270,981		101	(570,358	)	$	1,766,727

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Nine months ended September 30, 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	102,721			12,461		16,713		—	(29,174	)	102,721
Other comprehensive income (loss), net of taxes	11			(4	)	(4	)	—	8		11
Common stock dividends	(67,804		)	(7,515	)	(11,382	)	—	18,897		(67,804		)
Common stock issuance expenses	(8		)	—		(1	)	—	1		(8		)
Balance, September 30, 2015	$	1,717,064		286,788		262,018		101	(548,907	)	$	1,717,064

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Nine months ended September 30, 2016



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	109,008		16,886		17,341		—	(33,541	)	$	109,694
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries	(33,616		)	—		—		—	33,541		(75		)
Common stock dividends received from subsidiaries	19,776			—		—		—	(19,701	)	75
Depreciation of property, plant and equipment	94,564			28,347		17,389		—	—		140,300
Other amortization	2,462			1,366		1,552		—	—		5,380
Deferred income taxes	41,005			4,529		10,085		—	29		55,648
Tax credits, net	4,314			464		478		—	—		5,256
Allowance for equity funds used during construction	(4,771		)	(571	)	(668	)	—	—		(6,010		)
Other	(1,389		)	(302	)	(331	)	—	—		(2,022		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	328			(2,716	)	(1,313	)	—	3,046		(655		)
Increase in accrued unbilled revenues	(9,673		)	(373	)	(612	)	—	—		(10,658		)
Decrease in fuel oil stock	4,157			1,425		1,154		—	—		6,736
Decrease (increase) in materials and supplies	(1,755		)	(1,559	)	387		—	—		(2,927		)
Decrease (increase) in regulatory assets	(2,474		)	(150	)	373		—	—		(2,251		)
Increase (decrease) in accounts payable	(2,628		)	143		1,809		—	—		(676		)
Change in prepaid and accrued income and utility revenue taxes	(7,324		)	2,230		(4,472	)	—	(29	)	(9,595		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	449			40		(129	)	—	—		360
Change in other assets and liabilities	(10,548		)	2,856		(2,571	)	—	(3,046	)	(13,309		)
Net cash provided by operating activities	201,885			52,615		40,472		—	(19,701	)	275,271
Cash flows from investing activities
Capital expenditures	(188,415		)	(37,835	)	(24,454	)	—	—		(250,704		)
Contributions in aid of construction	18,181			2,691		2,696		—	—		23,568
Other	901			169		30		—	—		1,100
Advances from affiliates	—			(3,000	)	(8,000	)	—	11,000		—
Net cash used in investing activities	(169,333		)	(37,975	)	(29,728	)	—	11,000		(226,036		)
Cash flows from financing activities
Common stock dividends	(70,199		)	(9,906	)	(9,795	)	—	19,701		(70,199		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(810		)	(400	)	(286	)	—	—		(1,496		)
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	32,000			—		—		—	(11,000	)	21,000
Other	(3		)	(8	)	(1	)	—	—		(12		)
Net cash used in financing activities	(39,012		)	(10,314	)	(10,082	)	—	8,701		(50,707		)
Net increase (decrease) in cash and cash equivalents	(6,460		)	4,326		662		—	—		(1,472		)
Cash and cash equivalents, beginning of period	16,281			2,682		5,385		101	—		24,449
Cash and cash equivalents, end of period	$	9,821		7,008		6,047		101	—		$	22,977

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Nine months ended September 30, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments		Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	103,531		12,861		16,999		—	(29,174	)	$	104,217
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries	(29,249		)	—		—		—	29,174		(75		)
Common stock dividends received from subsidiaries	18,972			—		—		—	(18,897	)	75
Depreciation of property, plant and equipment	88,167			27,938		16,735		—	—		132,840
Other amortization	2,029			1,331		1,639		—	—		4,999
Deferred income taxes	46,493			907		10,497		—	314		58,211
Tax credits, net	3,680			372		195		—	—		4,247
Allowance for equity funds used during construction	(4,418		)	(458	)	(490	)	—	—		(5,366		)
Impairment of utility assets	3,380			724		724					4,828
Other	221			(286	)	(261	)				(326		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	(4,226		)	(2,071	)	43		—	1,790		(4,464		)
Decrease in accrued unbilled revenues	6,283			3,696		3,817		—	—		13,796
Decrease in fuel oil stock	25,019			5,358		5,565		—	—		35,942
Decrease (increase) in materials and supplies	(759		)	(1,615	)	651		—	—		(1,723		)
Increase in regulatory assets	(19,138		)	(3,944	)	(376	)	—	—		(23,458		)
Decrease in accounts payable	(34,476		)	(4,070	)	(1,829	)	—	—		(40,375		)
Change in prepaid and accrued income and utility revenue taxes	(52,505		)	(2,276	)	(6,540	)	—	(314	)	(61,635		)
Increase in defined benefit pension and other postretirement benefit plans liability	—			—		331		—	—		331
Change in other assets and liabilities	(16,847		)	722		(2,563	)	—	(1,790	)	(20,478		)
Net cash provided by operating activities	136,157			39,189		45,137		—	(18,897	)	201,586
Cash flows from investing activities
Capital expenditures	(204,406		)	(34,048	)	(27,067	)	—	—		(265,521		)
Contributions in aid of construction	30,153			2,940		1,534		—	—		34,627
Other	583			124		71		—	—		778
Advances from affiliates	4,100			—		(2,500	)	—	(1,600	)	—
Net cash used in investing activities	(169,570		)	(30,984	)	(27,962	)	—	(1,600	)	(230,116		)
Cash flows from financing activities
Common stock dividends	(67,804		)	(7,515	)	(11,382	)	—	18,897		(67,804		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(810		)	(400	)	(286	)	—	—		(1,496		)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	97,495			1,500		(5,600	)	—	1,600		94,995
Other	(219		)	(3	)	(1	)	—	—		(223		)
Net cash provided by (used in) financing activities	28,662			(6,418	)	(17,269	)	—	20,497		25,472
Net increase (decrease) in cash and cash equivalents	(4,751		)	1,787		(94	)	—	—		(3,058		)
Cash and cash equivalents, beginning of period	12,416			612		633		101	—		13,762
Cash and cash equivalents, end of period	$	7,665		2,399		539		101	—		$	10,704

5 · Bank segment

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data



	Three months ended September 30				Nine months ended September 30
(in thousands)	2016		2015		2016		2015
Interest and dividend income
Interest and fees on loans	$	50,444	$	46,413	$	148,571	$	137,646
Interest and dividends on investment securities	4,759		4,213		14,219		10,570
Total interest and dividend income	55,203		50,626		162,790		148,216
Interest expense
Interest on deposit liabilities	1,871		1,355		5,154		3,881
Interest on other borrowings	1,464		1,515		4,416		4,468
Total interest expense	3,335		2,870		9,570		8,349
Net interest income	51,868		47,756		153,220		139,867
Provision for loan losses	5,747		2,997		15,266		5,436
Net interest income after provision for loan losses	46,121		44,759		137,954		134,431
Noninterest income
Fees from other financial services	5,599		5,639		16,799		16,544
Fee income on deposit liabilities	5,627		5,883		16,045		16,622
Fee income on other financial products	2,151		2,096		6,563		6,088
Bank-owned life insurance	1,616		1,021		3,620		3,062
Mortgage banking income	2,347		1,437		5,096		5,327
Gains on sale of investment securities, net	—		—		598		—
Other income, net	1,165		2,389		1,786		3,363
Total noninterest income	18,505		18,465		50,507		51,006
Noninterest expense
Compensation and employee benefits	22,844		22,728		67,197		66,813
Occupancy	3,991		4,128		12,244		12,250
Data processing	3,150		3,032		9,599		9,101
Services	2,427		2,556		8,093		7,730
Equipment	1,759		1,608		5,193		4,999
Office supplies, printing and postage	1,483		1,511		4,431		4,297
Marketing	747		934		2,507		2,619
FDIC insurance	907		809		2,704		2,393
Other expense	4,591		5,116		13,948		14,076
Total noninterest expense	41,899		42,422		125,916		124,278
Income before income taxes	22,727		20,802		62,545		61,159
Income taxes	7,623		7,351		21,483		21,382
Net income	$	15,104	$	13,451	$	41,062	$	39,777

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data



	Three months ended September 30					Nine months ended September 30
(in thousands)	2016			2015		2016			2015
Net income	$	15,104		$	13,451	$	41,062		$	39,777
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on available-for-sale investment securities:
Net unrealized gains (losses) on available-for-sale investment securities arising during the period, net of (taxes) benefits of $1,417, $(2,543), $(5,413) and $(2,382) for the respective periods	(2,147		)	3,851		8,197			3,608
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, nil, $238 and nil for the respective periods	—			—		(360		)	—
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 $144, $249, $421 and $763 for the respective periods	219			376		638			1,155
Other comprehensive income (loss), net of taxes	(1,928		)	4,227		8,475			4,763
Comprehensive income	$	13,176		$	17,678	$	49,537		$	44,540

American Savings Bank, F.S.B.

Balance Sheets Data



(in thousands)	September 30, 2016						December 31, 2015
Assets
Cash and due from banks				$	109,591					$	127,201
Interest-bearing deposits				103,989						93,680
Available-for-sale investment securities, at fair value				996,984						820,648
Stock in Federal Home Loan Bank, at cost				11,218						10,678
Loans receivable held for investment				4,734,638						4,615,819
Allowance for loan losses				(58,737		)				(50,038		)
Net loans				4,675,901						4,565,781
Loans held for sale, at lower of cost or fair value				26,743						4,631
Other				330,054						309,946
Goodwill				82,190						82,190
Total assets				$	6,336,670					$	6,014,755

Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing				$	1,570,613					$	1,520,374
Deposit liabilities—interest-bearing				3,810,108						3,504,880
Other borrowings				265,388						328,582
Other				106,396						101,029
Total liabilities				5,752,505						5,454,865
Commitments and contingencies
Common stock				1						1
Additional paid in capital				342,234						340,496
Retained earnings				250,726						236,664
Accumulated other comprehensive loss, net of tax benefits
Net unrealized gains (losses) on securities	$	5,965					$	(1,872	)
Retirement benefit plans	(14,761		)	(8,796		)	(15,399		)	(17,271		)
Total shareholder’s equity				584,165						559,890
Total liabilities and shareholder’s equity				$	6,336,670					$	6,014,755

Other assets
Bank-owned life insurance				$	141,262					$	138,139
Premises and equipment, net				91,354						88,077
Prepaid expenses				4,072						3,550
Accrued interest receivable				15,489						15,192
Mortgage-servicing rights				9,191						8,884
Low-income housing equity investments				48,474						37,793
Real estate acquired in settlement of loans, net				219						1,030
Other				19,993						17,281
				$	330,054					$	309,946
Other liabilities
Accrued expenses				$	37,671					$	30,705
Federal and state income taxes payable				13,971						13,448
Cashier’s checks				24,923						21,768
Advance payments by borrowers				5,531						10,311
Other				24,300						24,797
				$	106,396					$	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 $165 million and $100 million, respectively, as of September 30, 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
September 30, 2016
Available-for-sale
U.S. Treasury and federal agency obligations	$	186,287	$	3,125	$	(40	)	$	189,372	1	$	9,988	$	(12	)	1	$	3,834	$	(28	)
Mortgage-related securities- FNMA, FHLMC and GNMA	800,794		7,782		(964		)	807,612		18	134,687		(323		)	13	51,458		(641		)
	$	987,081	$	10,907	$	(1,004	)	$	996,984	19	$	144,675	$	(335	)	14	$	55,292	$	(669	)
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 September 30, 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 September 30, 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:



September 30, 2016	Amortized cost		Fair value
(in thousands)
Due in one year or less	$	—	$	—
Due after one year through five years	87,165		88,754
Due after five years through ten years	78,222		79,534
Due after ten years	20,900		21,084
	186,287		189,372
Mortgage-related securities-FNMA,FHLMC and GNMA	800,794		807,612
Total available-for-sale securities	$	987,081	$	996,984

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			Unallo-cated		Total
Three months ended September 30, 2016
Allowance for loan losses:
Beginning balance	$	4,384		$	13,561	$	7,836		$	1,689		$	6,993		$	12		$	17,085		$	3,771		$	—	$	55,331
Charge-offs	(373		)	—		(108		)	—			—			—			(833		)	(1,879		)	—		(3,193		)
Recoveries	92			—		15			187			—			—			347			211			—		852
Provision	154			1,289		(248		)	23			179			(2		)	2,457			1,895			—		5,747
Ending balance	$	4,257		$	14,850	$	7,495		$	1,899		$	7,172		$	10		$	19,056		$	3,998		$	—	$	58,737
Three months ended September 30, 2015
Allowance for loan losses:
Beginning balance	$	4,291		$	10,420	$	6,613		$	2,103		$	2,575		$	18		$	17,469		$	2,876		$	—	$	46,365
Charge-offs	(138		)	—		(185		)	—			—			—			(126		)	(1,271		)	—		(1,720		)
Recoveries	45			—		33			34			—			—			279			241			—		632
Provision	285			987		446			(73		)	944			(5		)	(920		)	1,333			—		2,997
Ending balance	$	4,483		$	11,407	$	6,907		$	2,064		$	3,519		$	13		$	16,702		$	3,179		$	—	$	48,274
Nine months ended September 30, 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	(433		)	—		(108		)	—			—			—			(3,138		)	(4,977		)	—		(8,656		)
Recoveries	144			—		46			306			—			—			907			686			—		2,089
Provision	360			3,508		297			(78		)	2,711			(3		)	4,079			4,392			—		15,266
Ending balance	$	4,257		$	14,850	$	7,495		$	1,899		$	7,172		$	10		$	19,056		$	3,998		$	—	$	58,737
September 30, 2016
Ending balance: individually evaluated for impairment	$	1,625		$	161	$	1,040		$	951		$	—		$	—		$	4,734		$	2				$	8,513
Ending balance: collectively evaluated for impairment	$	2,632		$	14,689	$	6,455		$	948		$	7,172		$	10		$	14,322		$	3,996		$	—	$	50,224
Financing Receivables:
Ending balance	$	2,054,460		$	774,349	$	859,952		$	19,666		$	140,758		$	15,073		$	717,450		$	158,065				$	4,739,773
Ending balance: individually evaluated for impairment	$	21,566		$	3,762	$	5,886		$	4,428		$	—		$	—		$	28,685		$	11				$	64,338
Ending balance: collectively evaluated for impairment	$	2,032,894		$	770,587	$	854,066		$	15,238		$	140,758		$	15,073		$	688,765		$	158,054				$	4,675,435
Nine months ended September 30, 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	(352		)	—		(205		)	—			—			—			(928		)	(3,196		)	—		(4,681		)
Recoveries	112			—		72			219			—			—			726			772			—		1,901
Provision	61			2,453		58			(30		)	(1,952		)	(15		)	2,887			1,974			—		5,436
Ending balance	$	4,483		$	11,407	$	6,907		$	2,064		$	3,519		$	13		$	16,702		$	3,179		$	—	$	48,274
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 probability of default 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:



	September 30, 2016						December 31, 2015
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	681,712	$	114,325	$	643,547	$	642,410	$	86,991	$	703,208
Special mention	58,411		—		17,654		7,710		13,805		7,029
Substandard	34,226		26,433		54,156		40,441		—		47,975
Doubtful	—		—		2,093		—		—		447
Loss	—		—		—		—		—		—
Total	$	774,349	$	140,758	$	717,450	$	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
September 30, 2016
Real estate:
Residential 1-4 family	$	4,293	$	1,626	$	10,576	$	16,495	$	2,037,965	$	2,054,460	$	—
Commercial real estate	—		—		—		—		774,349		774,349		—
Home equity line of credit	827		787		674		2,288		857,664		859,952		—
Residential land	—		—		541		541		19,125		19,666		393
Commercial construction	—		—		—		—		140,758		140,758		—
Residential construction	—		—		—		—		15,073		15,073		—
Commercial	681		997		19		1,697		715,753		717,450		—
Consumer	1,708		636		813		3,157		154,908		158,065		—
Total loans	$	7,509	$	4,046	$	12,623	$	24,178	$	4,715,595	$	4,739,773	$	393
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)	September 30, 2016		December 31, 2015
Real estate:
Residential 1-4 family	$	20,929	$	20,554
Commercial real estate	3,762		1,188
Home equity line of credit	2,404		2,254
Residential land	776		970
Commercial construction	—		—
Residential construction	—		—
Commercial	23,588		20,174
Consumer	1,157		895
Total nonaccrual loans	$	52,616	$	46,035
Real estate:
Residential 1-4 family	$	—	$	—
Commercial real estate	—		—
Home equity line of credit	—		—
Residential land	393		—
Commercial construction	—		—
Residential construction	—		—
Commercial	—		—
Consumer	—		—
Total accruing loans 90 days or more past due	$	393	$	—
Real estate:
Residential 1-4 family	$	13,308	$	13,962
Commercial real estate	—		—
Home equity line of credit	4,501		2,467
Residential land	3,258		4,713
Commercial construction	—		—
Residential construction	—		—
Commercial	4,673		1,104
Consumer	—		—
Total troubled debt restructured loans not included above	$	25,740	$	22,246

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



	September 30, 2016						Three months ended September 30, 2016				Nine months ended September 30, 2016
(in thousands)	Recorded investment		Unpaid principal balance		Related Allowance		Average recorded investment		Interest income recognized*		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate:
Residential 1-4 family	$	10,137	$	11,473	$	—	$	10,069	$	65	$	10,378	$	268
Commercial real estate	1,351		1,645		—		1,206		—		1,177		—
Home equity line of credit	1,300		1,695		—		1,220		6		1,035		15
Residential land	1,608		2,304		—		1,521		16		1,532		47
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial	6,624		7,637		—		14,352		141		9,240		154
Consumer	—		—		—		10		—		3		—
	$	21,020	$	24,754	$	—	$	28,378	$	228	$	23,365	$	484
With an allowance recorded
Real estate:
Residential 1-4 family	$	11,429	$	11,632	$	1,625	$	11,800	$	119	$	11,933	$	356
Commercial real estate	2,411		2,482		161		2,444		—		1,939		—
Home equity line of credit	4,587		4,657		1,040		4,165		36		3,470		91
Residential land	2,819		2,819		951		2,915		44		3,090		165
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial	22,061		22,434		4,734		11,433		65		15,075		275
Consumer	11		11		2		11		—		12		—
	$	43,318	$	44,035	$	8,513	$	32,768	$	264	$	35,519	$	887
Total
Real estate:
Residential 1-4 family	$	21,566	$	23,105	$	1,625	$	21,869	$	184	$	22,311	$	624
Commercial real estate	3,762		4,127		161		3,650		—		3,116		—
Home equity line of credit	5,887		6,352		1,040		5,385		42		4,505		106
Residential land	4,427		5,123		951		4,436		60		4,622		212
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial	28,685		30,071		4,734		25,785		206		24,315		429
Consumer	11		11		2		21		—		15		—
	$	64,338	$	68,789	$	8,513	$	61,146	$	492	$	58,884	$	1,371



	December 31, 2015						Three months ended September 30, 2015				Nine months ended September 30, 2015
(in thousands)	Recorded investment		Unpaid principal balance		Related allowance		Average recorded investment		Interest income recognized*		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate:
Residential 1-4 family	$	10,596	$	11,805	$	—	$	11,159	$	119	$	11,301	$	274
Commercial real estate	1,188		1,436		—		—		74		362		74
Home equity line of credit	707		948		—		498		1		444		3
Residential land	1,644		2,412		—		2,280		29		2,647		125
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial	5,671		6,333		—		4,250		3		5,659		144
Consumer	—		—		—		—		—		—		—
	$	19,806	$	22,934	$	—	$	18,187	$	226	$	20,413	$	620
With an allowance recorded
Real estate:
Residential 1-4 family	$	11,861	$	11,914	$	1,453	$	11,451	$	174	$	11,585	$	430
Commercial real estate	—		—		—		—		—		1,985		—
Home equity line of credit	2,518		2,579		442		2,048		13		1,295		27
Residential land	4,039		4,117		891		3,971		74		4,435		241
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial	15,448		16,073		3,527		18,487		106		10,942		192
Consumer	13		13		7		14		—		15		—
	$	33,879	$	34,696	$	6,320	$	35,971	$	367	$	30,257	$	890
Total
Real estate:
Residential 1-4 family	$	22,457	$	23,719	$	1,453	$	22,610	$	293	$	22,886	$	704
Commercial real estate	1,188		1,436		—		—		74		2,347		74
Home equity line of credit	3,225		3,527		442		2,546		14		1,739		30
Residential land	5,683		6,529		891		6,251		103		7,082		366
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial	21,119		22,406		3,527		22,737		109		16,601		336
Consumer	13		13		7		14		—		15		—
	$	53,685	$	57,630	$	6,320	$	54,158	$	593	$	50,670	$	1,510


*	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 September 30, 2016							Nine months ended September 30, 2016
	Number of contracts	Outstanding recorded investment¹				Net increase in allowance		Number of contracts	Outstanding recorded investment¹				Net increase in allowance
(dollars in thousands)	Number of contracts	Pre-modification		Post-modification		(as of period end)		Number of contracts	Pre-modification		Post-modification		(as of period end)
Troubled debt restructurings
Real estate:
Residential 1-4 family	2	$	251	$	251	$	46	11	$	2,239	$	2,351	$	305
Commercial real estate	—	—		—		—		—	—		—		—
Home equity line of credit	12	1,268		1,268		237		30	2,705		2,705		492
Residential land	—	—		—		—		1	120		121		—
Commercial construction	—	—		—		—		—	—		—		—
Residential construction	—	—		—		—		—	—		—		—
Commercial	6	3,462		3,462		53		14	20,119		20,119		723
Consumer	—	—		—		—		—	—		—		—
	20	$	4,981	$	4,981	$	336	56	$	25,183	$	25,296	$	1,520



	Three months ended September 30, 2015							Nine months ended September 30, 2015
	Number of contracts	Outstanding recorded investment¹				Net increase in allowance		Number of contracts	Outstanding recorded investment¹				Net increase in allowance
(dollars in thousands)	Number of contracts	Pre-modification		Post-modification		(as of period end)		Number of contracts	Pre-modification		Post-modification		(as of period end)
Troubled debt restructurings
Real estate:
Residential 1-4 family	3	$	860	$	866	$	1	10	$	2,055	$	2,079	$	48
Commercial real estate	—	—		—		—		—	—		—		—
Home equity line of credit	10	943		943		140		32	2,062		2,062		300
Residential land	—	—		—		—		—	—		—		—
Commercial construction	—	—		—		—		—	—		—		—
Residential construction	—	—		—		—		—	—		—		—
Commercial	2	1,208		1,208		16		6	1,461		1,461		94
Consumer	—	—		—		—		—	—		—		—
	15	$	3,011	$	3,017	$	157	48	$	5,578	$	5,602	$	442


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 in the indicated periods, and for which the payment of default occurred within one year of the modification, were as follows:



	Three months ended September 30, 2016			Nine months ended September 30, 2016
(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	$	239	1	$	239
Commercial real estate	—	—		—	—
Home equity line of credit	—	—		—	—
Residential land	—	—		—	—
Commercial construction	—	—		—	—
Residential construction	—	—		—	—
Commercial	—	—		1	25
Consumer	—	—		—	—
	1	$	239	2	$	264



	Three months ended September 30, 2015			Nine months ended September 30, 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	—	$	—	—	$	—
Commercial real estate	—	—		—	—
Home equity line of credit	1	7		1	7
Residential land	—	—		—	—
Commercial construction	—	—		—	—
Residential construction	—	—		—	—
Commercial	—	—		—	—
Consumer	—	—		—	—
	1	$	7	1	$	7

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 $2.5 million at September 30, 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 proceeds from the sale of residential mortgages of $70.0 million and $58.2 million for the three months ended September 30, 2016 and 2015 and $168.5 million and $231.5 million for the nine months ended September 30, 2016 and 2015, respectively, and recognized gains on such sales of $2.4 million and $1.4 million for the three months ended September 30, 2016 and 2015 and $5.1 million and $5.3 million for the nine months ended September 30, 2016 and 2015 respectively.

There were no repurchased mortgage loans for the three months ended September 30, 2016 and 2015 and nine months ended September 30, 2016 and 2015. The repurchase reserve was $0.1 million and $0.1 million as of September 30, 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 September 30, 2016 and 2015 and $2.1 million and $2.7 million for the nine months ended September 30, 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
September 30, 2016	$	16,475	$	(7,284	)	$	—	$	9,191
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	1,944			2,636
Amortization	(1,637		)	(2,123		)
Other-than-temporary impairment	—			(4		)
Carrying amount before valuation allowance, September 30	9,191			12,258
Valuation allowance for mortgage servicing rights
Balance, January 1	—			209
Provision (recovery)	—			(205		)
Other-than-temporary impairment	—			(4		)
Balance, September 30	—			—
Net carrying value of mortgage servicing rights	$	9,191		$	12,258

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)	September 30, 2016			December 31, 2015
Unpaid principal balance	$	1,160,266		$	1,097,314
Weighted average note rate	4.00		%	4.05		%
Weighted average discount rate	9.4		%	9.6		%
Weighted average prepayment speed	12.4		%	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)	September 30, 2016			December 31, 2015
Prepayment rate:
25 basis points adverse rate change	$	(533	)	$	(561	)
50 basis points adverse rate change	(952		)	(1,104		)
Discount rate:
25 basis points adverse rate change	(90		)	(111		)
50 basis points adverse rate change	(179		)	(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
September 30, 2016	$165	$—	$165
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
September 30, 2016
Financial institution	$	50	$	53	$	—
Government entities	14		16		—
Commercial account holders	101		135		—
Total	$	165	$	204	$	—
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 risks 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:



	September 30, 2016					December 31, 2015
(in thousands)	Notional amount		Fair value			Notional amount		Fair value
Interest rate lock commitments	$	40,700	$	843		$	22,241	$	384
Forward commitments	43,500		(163		)	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	September 30, 2016				December 31, 2015
(in thousands)	Asset derivatives		Liability derivatives		Asset derivatives		Liability derivatives
Interest rate lock commitments	$	843	$	—	$	384	$	—
Forward commitments	1		164		1		30
	$	844	$	164	$	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 September 30					Nine months ended September 30
(in thousands)		2016		2015			2016			2015
Interest rate lock commitments	Mortgage banking income	$	48	$	139		$	459		$	195
Forward commitments	Mortgage banking income	103		(117		)	(134		)	(18		)
		$	151	$	22		$	325		$	177

Low-Income Housing Tax Credit (LIHTC). ASB’s unfunded commitments to fund its LIHTC investment partnerships were $18.1 million and $10.1 million at September 30, 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 September 30, 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 nine months of 2016, the Company contributed $49 million ($48 million by the Utilities) to its pension and other postretirement benefit plans, compared to $66 million ($65 million by the Utilities) in the first nine 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 $3 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 September 30												Nine months ended September 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2016			2015			2016			2015			2016			2015			2016			2015
HEI consolidated
Service cost	$	15,126		$	16,577		$	831		$	982		$	45,430		$	49,683		$	2,499		$	2,945
Interest cost	20,396			19,229			2,417			2,254			61,154			57,731			7,254			6,757
Expected return on plan assets	(24,640		)	(22,126		)	(3,064		)	(2,912		)	(73,920		)	(66,426		)	(9,207		)	(8,753		)
Amortization of net prior service loss (gain)	(15		)	1			(449		)	(448		)	(43		)	3			(1,345		)	(1,345		)
Amortization of net actuarial loss	6,228			9,191			200			450			18,605			27,608			603			1,346
Net periodic benefit cost	17,095			22,872			(65		)	326			51,226			68,599			(196		)	950
Impact of PUC D&Os	(4,653		)	(10,017		)	336			(60		)	(13,464		)	(29,994		)	1,008			(180		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	12,442		$	12,855		$	271		$	266		$	37,762		$	38,605		$	812		$	770
Hawaiian Electric consolidated
Service cost	$	14,699		$	16,066		$	821		$	967		$	44,097		$	48,197		$	2,463		$	2,902
Interest cost	18,702			17,632			2,334			2,175			56,106			52,897			7,003			6,525
Expected return on plan assets	(22,908		)	(20,635		)	(3,023		)	(2,873		)	(68,725		)	(61,906		)	(9,072		)	(8,621		)
Amortization of net prior service loss (gain)	3			10			(451		)	(450		)	10			30			(1,353		)	(1,352		)
Amortization of net actuarial loss	5,674			8,342			198			438			17,020			25,028			595			1,315
Net periodic benefit cost	16,170			21,415			(121		)	257			48,508			64,246			(364		)	769
Impact of PUC D&Os	(4,653		)	(10,017		)	336			(60		)	(13,464		)	(29,994		)	1,008			(180		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,517		$	11,398		$	215		$	197		$	35,044		$	34,252		$	644		$	589

HEI consolidated recorded retirement benefits expense of $26 million ($23 million by the Utilities) and $27 million ($22 million by the Utilities) in the first nine 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 nine months of 2016 and 2015, the Company’s expenses for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan were $4.1 million and $4.0 million, respectively, and cash contributions were $4.6 million and $4.3 million, respectively. For the first nine months of 2016 and 2015, the Utilities’ expenses for its defined contribution pension plan under the HEIRSP were $1.2 million and $1.1 million, respectively, and cash contributions were $1.2 million and $1.1 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 September 30, 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 September 30, 2016, there were 121,198 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 September 30				Nine months ended September 30
(in millions)	2016		2015		2016		2015
HEI consolidated
Share-based compensation expense ¹	$	1.6	$	1.0	$	3.6	$	4.8
Income tax benefit	0.5		0.3		1.2		1.7
Hawaiian Electric consolidated
Share-based compensation expense ¹	0.5		0.1		1.0		1.3
Income tax benefit	0.2		—		0.4		0.5


¹	For the three and nine months ended September 30, 2016, the Company has not capitalized any share-based compensation. $0.03 million and $0.12 million of this share-based compensation expense was capitalized in the three and nine months ended September 30, 2015.

Stock awards. No nonemployee director stock grants were awarded from January 1 to September 29, 2016. Nonemployee director awards totaling $0.2 million were paid in cash in July 2016. HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:



	Nine months ended September 30
($ in millions)	2016		2015
Shares granted	19,846		28,246
Fair value	$	0.6	$	0.8
Income tax benefit	0.2		0.3

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 September 30, 2016 and December 31, 2015, there were no remaining SARs outstanding.

SARs activity and statistics were as follows:



	Three months ended September 30		Nine months ended September 30
(dollars in thousands, except prices)	2015		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	—		82

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 September 30										Nine months ended September 30
	2016					2015					2016					2015
	Shares			(1)		Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, beginning of period	225,752			$	29.59	252,302			$	28.35	210,634			$	28.82	261,235			$	25.77
Granted	766			30.65		690			30.91		95,048			29.91		85,772			33.69
Vested	(4,419		)	27.26		(19,840		)	25.35		(83,583		)	27.88		(99,891		)	25.69
Forfeited	(2,352		)	29.69		(14,316		)	25.82		(2,352		)	29.69		(28,280		)	26.66
Outstanding, end of period	219,747			$	29.64	218,836			$	28.79	219,747			$	29.64	218,836			$	28.79
Total weighted-average grant-date fair value of shares granted ($ millions)	$	—				$	—				$	2.8				$	2.9


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

As of September 30, 2016, there was $4.4 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.6 years.

For the first nine months of 2016 and 2015, total restricted stock units that vested and related dividends had a fair value of $2.7 million and $3.7 million, respectively, and the related tax benefits were $0.9 million and $1.1 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 September 30							Nine months ended September 30
	2016				2015			2016				2015
	Shares		(1)		Shares	(1)		Shares		(1)		Shares		(1)
Outstanding, beginning of period	83,947		$	22.95	163,423	$	27.63	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	(175	)	22.95		—	—		(175	)	22.95		(18,618	)	26.41
Outstanding, end of period	83,772		$	22.95	163,423	$	27.63	83,772		$	22.95	163,423		$	27.63


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

For the nine months ended September 30, 2016 and 2015, all vested shares in the table above were unissued and cancelled (i.e., lapsed) because the TRS goal was not met.

As of September 30, 2016, there was $0.1 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 0.3 years.

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



	Three months ended September 30								Nine months ended September 30
	2016				2015				2016				2015
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, beginning of period	113,550		$	25.18	220,158		$	26.00	222,647		$	26.02	364,731		$	26.01
Granted (target level)	—		—		—		—		—		—		—		—
Vested (issued)	—		—		—		—		(109,097	)	26.89		(121,249	)	26.05
Cancelled	—		—		(14,050	)	26.89		—		—		(14,050	)	26.89
Forfeited	(699	)	25.19		—		—		(699	)	25.19		(23,324	)	25.85
Outstanding, end of period	112,851		$	25.18	206,108		$	25.94	112,851		$	25.18	206,108		$	25.94


(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 nine months ended September 30, 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 September 30, 2016, there was $0.2 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 0.3 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	7,837			459			943			9,239			405		7		412
Balance, September 30, 2016	$	5,965		$	405		$	(23,393	)	$	(17,023	)	$	405	$	932	$	1,337
Balance, December 31, 2014	$	462		$	(289	)	$	(27,551	)	$	(27,378	)	$	—	$	45	$	45
Current period other comprehensive income	3,608			177			1,576			5,361			—		11		11
Balance, September 30, 2015	$	4,070		$	(112	)	$	(25,975	)	$	(22,017	)	$	—	$	56	$	56

Reclassifications out of AOCI were as follows:



	Amount reclassified from AOCI
	Three months ended September 30						Nine months ended September 30						Affected line item in the
(in thousands)	2016			2015			2016			2015			Statement of Income
HEI consolidated
Net realized gains on securities	$	—		$	—		$	(360	)	$	—		Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Window forward contracts	(173		)	—			(173		)	—			Revenues-electric utility (gains on window forward)
Interest rate contracts (settled in 2011)	—			59			54			177			Interest expense
Retirement benefit plan items
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost	3,641			5,611			10,877			16,850			See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(3,311		)	(5,091		)	(9,934		)	(15,274		)	See Note 6 for additional details
Total reclassifications	$	157		$	579		$	464		$	1,753
Hawaiian Electric consolidated
Derivatives qualified as cash flow hedges
Window forward contracts	$	(173	)	$	—		$	(173	)	$	—		Revenues (gains on window forward)
Retirement benefit plan items
Amortization of prior service credit and net losses recognized during the period in net periodic benefit cost	3,314			5,095			9,941			15,285			See Note 6 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(3,311		)	(5,091		)	(9,934		)	(15,274		)	See Note 6 for additional details
Total reclassifications	$	(170	)	$	4		$	(166	)	$	11

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 and goodwill.

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—other than bank. 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 or notional 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
September 30, 2016
Financial assets
Money market funds	$	45,030	$	—	$	45,030	$	—	$	45,030
Available-for-sale investment securities	996,984		—		996,984		—		996,984
Stock in Federal Home Loan Bank	11,218		—		11,218		—		11,218
Loans receivable, net	4,702,644		—		26,784		4,923,457		4,950,241
Mortgage servicing rights	9,191		—		—		10,971		10,971
Bank-owned life insurance	141,262		—		141,262		—		141,262
Derivative assets	62,581		—		1,508		—		1,508
The Utilities’ derivative assets (included in amount above)	20,725		—		664		—		664
Financial liabilities
Deposit liabilities	5,380,721		—		5,384,924		—		5,384,924
Other bank borrowings	265,388		—		267,892		—		267,892
Long-term debt, net—other than bank	1,579,065		—		1,741,707		—		1,741,707
The Utilities’ long-term debt, net (included in amount above)	1,279,327		—		1,432,766		—		1,432,766
Derivative liabilities	42,344		121		43		—		164
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:



	September 30, 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)	$	—	$	45,030	$	—	$	—	$	10	$	—
Available-for-sale investment securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	807,612	$	—	$	—	$	607,689	$	—
U.S. Treasury and federal agency obligations	—		189,372		—		—		212,959		—
	$	—	$	996,984	$	—	$	—	$	820,648	$	—
Derivative assets
Interest rate lock commitments ¹	$	—	$	843	$	—	$	—	$	384	$	—
Forward commitments ¹	—		1		—		—		1		—
Window forward contract ²	—		664		—		—		—		—
	$	—	$	1,508	$	—	$	—	$	385	$	—
Derivative liabilities ¹
Forward commitments	$	121	$	43	$	—	$	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 September 30, 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
September 30, 2016
Loans	$	1,382	$	—	$	—	$	1,382
Real estate acquired in settlement of loans	219		—		—		219
December 31, 2015
Loans	178		—		—		178
Real estate acquired in settlement of loans	1,030		—		—		1,030

At September 30, 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

September 30, 2016

Residential loans

1,370

Fair value of property or collateral

Appraised value less 7% selling costs

42-91%

64%

Home equity lines of credit

Fair value of property or collateral

Appraised value less 7% selling costs

N/A (2)

Total loans

1,382

Real estate acquired in settlement of loans

219

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



Nine months ended September 30	2016			2015
(in millions)
Supplemental disclosures of cash flow information
HEI consolidated
Interest paid to non-affiliates	$	61		$	61
Income taxes paid	19			62
Income taxes refunded	45			55
Hawaiian Electric consolidated
Interest paid to non-affiliates	43			43
Income taxes paid	—			13
Income taxes refunded	20			12
Supplemental disclosures of noncash activities
HEI consolidated
Common stock dividends reinvested in HEI common stock (financing) ¹	17			—
Loans transferred from held for investment to held for sale (investing)	14			—
Real estate transferred from property, plant and equipment to other assets held-for-sale (investing)	1			5
Obligations to fund low income housing investments (operating)	14			1
HEI consolidated and Hawaiian Electric consolidated
Additions to electric utility property, plant and equipment - unpaid invoices and accruals (investing)	(7		)	1

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 subsequently issued revenue-related ASUs, as applicable) 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.

Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which is intended to improve financial reporting by requiring timelier recording of credit losses on loans and other financial instruments held by financial institutions and other organizations. ASU No. 2016-13 requires the measurement of all expected credit losses for financial assets held at the reporting date (based on historical experience, current conditions and reasonable and supportable forecasts) and enhanced disclosures to help financial statement users better understand significant estimates and judgments used in estimating credit losses, as well as the credit quality and underwriting standards of an organization’s portfolio. In addition, ASU No. 2016-13 amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The other-than-temporary impairment model of accounting for credit losses on AFS debt securities will be replaced with an estimate of expected credit losses only when the fair value is below the amortized cost of the asset. The length of time the fair value of an AFS debt security has been below the amortized cost will no longer impact the determination of whether a credit loss exists. The AFS debt security model will also require the use of an allowance to record the estimated losses (and subsequent recoveries). The accounting for the initial recognition of the estimated expected credit losses for purchased financial assets with credit deterioration would be recognized through an allowance for loan losses with an offset to the cost basis of the related financial asset at acquisition (i.e., there is no impact to net income at initial recognition).

The Company plans to adopt ASU 2016-13 in the first quarter of 2020 and has not yet determined the impact of adoption.

Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides guidance on eight specific cash flow issues - debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies (including bank-owned life insurance policies), distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle.

The Company plans to adopt ASU 2016-15 in the first quarter of 2018 using a retrospective transition method and has not yet determined the impact of adoption.

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 13% as of September 30, 2016, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. The HEI Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI).

The facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.

Hawaiian Electric. On April 2, 2014, Hawaiian Electric and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (Hawaiian Electric Facility). The Hawaiian Electric Facility increased Hawaiian Electric’s line of credit to $200 million from $175 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. The Hawaiian Electric Facility provided improved pricing compared to its prior facility. Under the Hawaiian Electric Facility, draws would generally bear interest, based on Hawaiian Electric’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points, as of August 3, 2016. The Hawaiian Electric Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the Hawaiian Electric Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. The Hawaiian Electric Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, Hawaiian Electric, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 41% for Hawaii Electric Light and 41% for Maui Electric as of September 30, 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 September 30, 2016, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI.

The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay 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 with subsequent resetting interest rates averaging 1.23% through September 30, 2016). 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 third quarters of 2016 and 2015 and nine months ended September 30, 2016 and 2015, HEI charged the Utilities $0.7 million, $1.7 million, $5.2 million and $4.9 million, respectively, and HEI charged ASB $0.3 million, $0.5 million, $1.8 million and $1.7 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. As of September 30, 2016, Hawaiian Electric’s short-term borrowings from HEI were $21 million.

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 September 30				Nine months ended September 30
(in millions)	2016		2015		2016		2015
HEI consolidated
HMSA costs	$	7	$	8	$	21	$	22
HMSA expense*	5		6		15		16
HDS costs	1		1		2		2
HDS expense*	1		1		2		2
Hawaiian Electric consolidated
HMSA costs	5		6		17		17
HMSA expense*	3		4		10		11
HDS costs	1		1		2		2
HDS expense*	—		—		1		1

* 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 and nine months ended September 30, 2016) financial statements and notes thereto included in this Form 10-Q.

HEI consolidated

RESULTS OF OPERATIONS



(in thousands, except per	Three months ended September 30				%
share amounts)	2016		2015		change		Primary reason(s)*
Revenues	$	646,055	$	717,176	(10	)	Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income	105,442		97,095		9		Increases for the electric utility and bank segments, partly offset by higher loss for the “other” segment
Merger termination fee	90,000		—		NM		See Note 2 of the Consolidated Financial Statements.
Net income for common stock	127,142		50,673		151		Merger termination fee at corporate (in the “other” segment) and higher net income for the electric utility and bank segments
Basic earnings per common share	$	1.17	$	0.47	149		Higher net income, partly offset by the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding	108,268		107,457		1		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans



(in thousands, except per	Nine months ended September 30				%
share amounts)	2016		2015		change		Primary reason(s)*
Revenues	$	1,763,259	$	1,978,950	(11	)	Decrease for the electric utility segment, partly offset by increase for the bank segment
Operating income	259,748		239,331		9		Increases at all segments
Merger termination fee	90,000		—		NM		See Note 2 of the Consolidated Financial Statements.
Net income for common stock	203,622		117,557		73		Merger termination fee at corporate (in the “other” segment) and higher net income for the electric utility and bank segments
Basic earnings per common share	$	1.89	$	1.11	70		Higher net income, partly offset by the impact of higher weighted average shares outstanding
Weighted-average number of common shares outstanding	107,951		106,067		2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans


*	Also, see segment discussions which follow.

NM Not meaningful

Notes: The Company’s effective tax rates (combined federal and state income tax rates) for the third quarters of 2016 and 2015 were 29% and 37%, respectively, and for the first nine months of 2016 and 2015 were 32% and 37%, respectively. The effective tax rate was lower for the quarter and nine months ended September 30, 2016 compared to the same periods in 2015 due primarily to tax benefits recognized on previously nondeductible merger- and spin-off-related expenses and other tax benefits recognized as a result of moving out of a federal net operating loss position.

HEI’s consolidated ROACE was 12.3% for the twelve months ended September 30, 2016 and 8.1% for the twelve months ended September 30, 2015.

Dividends. The payout ratios for the first nine months of 2016 and full year 2015 were 49% 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.

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 nine months of 2016 with higher visitor expenditures and arrivals as compared to the same period a year ago. Visitor arrivals increased 2.6% and expenditures increased 3.7% in the first nine months compared to the same time period of 2015. The Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the fourth quarter of 2016 to slightly increase by 0.3% over the fourth quarter of 2015. The modest change is a result of stable U.S. West markets and growth in seats from U.S. East and Asian countries, other than Japan, being offset by declines for all other regions (Japan, Canada, Oceania and other).

Hawaii’s preliminary unemployment rate remained relatively stable at 3.3% in September 2016, lower than the state’s 3.4% rate in September 2015 and the September 2016 national unemployment rate of 5.0%.

Hawaii real estate activity, as indicated by the home sale market, experienced growth in median sales prices and closed sales for the first nine months of 2016 relative to the same time period in 2015. Median sales prices for single family residential homes and condominiums on Oahu increased 5.2% and 8.7%, respectively, over the first nine months of 2015. Closed sales for single family residential homes and condominiums increased by 4.8% and 9.0%, respectively, over the first nine months of 2015.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. In the third quarter of 2016, prices for crude remained stable, with only a slight average price increase relative to the prior quarter.

Information received since the July 2016 Federal Open Market Committee (FOMC) meeting indicates that the labor market remains strong and household spending has been growing. However, fixed business investment has continued to be weak and inflation has continued to remain below the FOMC target of 2%. In the September 21, 2016 meeting, the FOMC reaffirmed its federal funds rate target of 0.25% to 0.5%.

Overall, Hawaii is expected to see a continuation of the moderate expansion experienced in the first nine months of 2016. Tourism gains are forecasted to be marginally higher than in 2015. Construction remains high, as activity is expected to continue in 2016 as planned and permitted building continues and as new recently approved projects begin.

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 nine months of 2016, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a return, net of investment management fees, of 9.9%. Included in this return is the return on ASB’s plan assets, which are managed with a liability driven investment strategy. For the first nine months of 2016, ASB’s defined benefit pension plan assets generated a return, net of investment management fees, of 15.1%, due primarily to the lower interest rate environment since the investments were purchased. The market value of the Company’s defined benefit pension and other postretirement benefit plans’ assets as of September 30, 2016 and December 31, 2015 was $1.6 billion (including $1.4 billion for the Utilities) and $1.4 billion (including $1.3 billion for the Utilities), respectively.

The net periodic pension cost is 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.

The following table reflects the sensitivity of the qualified defined benefit pension projected benefit obligation (PBO) as of December 31, 2016 associated with a change in the pension benefits discount rate actuarial assumption by the indicated basis points and constitutes “forward-looking statements.”



	Change in 4.60%	Impact on HEI	Impact on the
Actuarial Assumption	assumption in basis points	consolidated PBO	Utilities PBO
Pension benefits discount rate	- 100/+100	$320 million/$(250) million	$300 million/$(234) million

In October 2016, the Society of Actuaries (SOA) released MP-2016 (mortality improvement scale), an update from MP-2014, to reflect three additional years of U.S. population mortality experience data. Application of MP-2016, as published,

will result in lower future pension and OPEB plan obligations, costs and required contribution amounts. The Company is currently evaluating whether to adopt the use of MP-2016 in its measurement of its pension and OPEB plan obligations at December 31, 2016. The Company used the SOA published tables and improvement scales for December 31, 2014 and December 31, 2015 measurements. The Internal Revenue Service is evaluating mortality assumptions for purposes of developing prescribed tables for ERISA minimum funding purposes. The earliest the Company anticipates a change in IRS methodology is January 1, 2018. Since December 31, 2014, the Company is using different mortality assumptions for ERISA funding versus financial reporting and accounting.

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 September 30						Nine months ended September 30
(in thousands)	2016			2015			2016			2015			Primary reason(s)
Revenues	$	94		$	(42	)	$	262		$	(4	)
Operating income (loss)	(7,097		)	(6,364		)	(18,621		)	(28,282		)	Lower merger and spin-off-related expenses (including expense reimbursements from NEE and insurers) in the first nine months of 2016 (see below)
Merger termination fee	90,000			—			90,000			—			See Note 2 of the Consolidated Financial Statements.
Net income (loss)	65,064			(5,784		)	54,362			(24,941		)	Merger termination fee and $8 million of tax benefits on previously non-deductible expenses related to the previously proposed merger with NEE and spin-off of ASBH

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. For the third quarter and first nine months of 2016, merger and spin-off related expenses (net of $6 million of reimbursements from NEE and insurers) recorded at HEI contributed $2 million and $5 million to operating losses, respectively. Expenses recorded at HEI related to the previously proposed merger with NEE and spin-off of ASBH amounted to $2 million and $15 million for the third quarter and first nine months of 2015, respectively. See Note 2, “Termination of proposed merger and other matters,”

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)	September 30, 2016				December 31, 2015
Short-term borrowings—other than bank	$	—	—	%	$	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	2,068		56		1,928		53
	$	3,681	100	%	$	3,643	100	%

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



	Average balance		Balance
(in millions)	Nine months ended September 30, 2016		September 30, 2016		December 31, 2015
Short-term borrowings ¹
Commercial paper	$	58	$	—	$	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 nine months of 2016 was $103 million. As of October 28, 2016, HEI had no 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 September 30, 2016, HEI satisfied its share purchase requirements for the plans through new issuances, except that from June 2 through August 9, 2016, HEI satisfied the share purchase requirements of the HEIRSP and ASB 401(k) Plan through open market purchases of its common stock. For the first nine months of 2016, the Company raised $28 million through the new issuances of approximately 0.9 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.

As of October 28, 2016, the Fitch Ratings, Inc. (Fitch), Moody's Investors Service’s (Moody's) and Standard & Poor’s (S&P) ratings of HEI were as follows:



	Fitch	Moody’s	S&P
Long-term issuer default and senior unsecured debt; senior unsecured debt; and corporate credit; respectively	BBB	*	BBB-
Commercial paper	F3	P-3	A-3
Outlook	Stable	Stable	Stable

* Not rated.

The above ratings reflect only the view, at the time the ratings are issued or affirmed, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

On July 19, 2016, S&P affirmed HEI’s ‘BBB-’ long-term issuer credit and other ratings, and removed the ratings from CreditWatch with positive implications. HEI’s outlook is stable. S&P stated that “the rating actions reflect the termination of the company’s [HEI’s] planned merger with NextEra, which would have led to higher ratings for HEI.”

On July 20, 2016, Fitch affirmed HEI’s long-term issuer default rating at ‘BBB’ following the termination of the merger agreement with NextEra Energy, Inc. and removed the ratings from Rating Watch Positive. HEI’s outlook is stable. Fitch stated that “the rating affirmation reflects Fitch’s view that the political and regulatory framework in Hawaii, while adverse to the proposed merger with NextEra, will remain ultimately supportive of HECO’s [Hawaiian Electric’s] credit profile as the utility

faces rising penetration of distributed generation and a capital intensive fleet modernization plan….HEI’s ratings are supported, in turn, by the credit profile of its subsidiaries: HECO [Hawaiian Electric] and American Savings Bank FSB (ASB).”

On August 3, 2016, Moody’s downgraded HEI’s short-term rating for commercial paper from P-2 to P-3. HEI’s outlook is stable. Moody’s noted, “[t]he downgrade of HEI’s commercial paper rating to P-3 reflects HEI’s heavy dependence on HECO [Hawaiian Electric]. Although HEI also owns American Savings Bank, we view HECO [Hawaiian Electric] as the primary credit and ratings driver of the parent company.” A Moody’s VP-Senior Credit Officer stated, “[t]he ratings downgrade is prompted by our concern that HECO [Hawaiian Electric] will continue to face significant challenges in transforming its generation base to 100% renewable sources in an unpredictable and highly political regulatory environment. We believe that the regulatory environment could become contentious as this transformation is executed despite recently falling customer bills, driven by lower fuel oil prices, and the company’s decision to moderate its still significant capital expenditure program.”

For the first nine months of 2016, net cash provided by operating activities of HEI consolidated was $409 million (including a $90 million termination fee paid by NEE). Net cash used by investing activities for the same period was $536 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, partly offset by ASB’s repayments and calls of investment securities, proceeds from the sale of commercial loans and Hawaiian Electric’s contributions in aid of construction. Net cash provided by financing activities during this period was $111 million as a result of several factors, including net increases in ASB’s deposit liabilities 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, other bank borrowings and retail repurchase agreements. 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 nine months of 2016, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $47 million and $18 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 “Cautionary Note Regarding 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 September 30				Increase
2016		2015		(decrease)						(dollars in millions, except per barrel amounts)
$	572	$	648	$	(76	)				Revenues. Net decrease largely due to:
							$	(59	)	lower fuel prices
							(17		)	lower KWH generated
							(4		)	lower purchased power expense
							4			higher RAM
129		196		(67		)				Fuel oil expense. Decrease due to lower fuel cost and lower KWH generated
158		161		(3		)				Purchased power expense. Decrease due to lower purchased power energy prices
95		104		(9		)				Operation and maintenance expenses. Decrease due to:
							(5		)	write off of ERP software costs in 2015
							(3		)	lower overhaul costs due to fewer overhauls performed
							(1		)	lower LNG consultant costs
101		106		(5		)				Other expenses. Decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
90		83		7						Operating income. Increase due to an overall decrease in expenses
47		43		4						Net income for common stock. Increase due to higher operating income

2,372		2,468		(96		)				Kilowatthour sales (millions)
72.3		74.9		(2.6		)				Wet-bulb temperature (Oahu average; degrees Fahrenheit)
1,496		1,711		(215		)				Cooling degree days (Oahu)
$	57.72	$	81.35	$	(23.63	)				Average fuel oil cost per barrel



Nine months ended September 30				Increase
2016		2015		(decrease)						(dollars in millions, except per barrel amounts)
$	1,550	$	1,780	$	(230	)				Revenues. Net decrease largely due to:
							$	(191	)	lower fuel prices
							(37		)	lower purchased power expense
							(13		)	lower KWH generated
							12			higher RAM
334		519		(185		)				Fuel oil expense. Decrease largely due to lower fuel prices and lower KWH generated
413		446		(33		)				Purchased power expense. Decrease due to lower purchased power energy prices
298		307		(8		)				Operation and maintenance expenses. Net decrease due to:
							(6		)	lower transmission, distribution and generation costs due to: -lower vegetation management costs, -less boiler and steam maintenance work, -storm repair costs incurred in 2015 and -less MATS compliance costs
							(5		)	write off of ERP software costs in 2015
							(1		)	2015 Smart Grid costs
							(1		)	lower bad debt reserve for one customer account
							4			higher PSIP consultant costs
							2			higher LNG consultant costs
289		302		(13		)				Other expenses. Net decrease in revenue taxes due to lower revenue, partly offset by higher depreciation expense for plant investments
216		206		10						Operating income. Increase due to an overall decrease in expenses
108		103		5						Net income for common stock. Increase due to higher operating income

6,613		6,656		(43		)				Kilowatthour sales (millions)
69.8		70.2		(0.4		)				Wet-bulb temperature (Oahu average; degrees Fahrenheit)
3,637		3,687		(50		)				Cooling degree days (Oahu)
$	52.06	$	79.13	$	(27.07	)				Average fuel oil cost per barrel
459,590		457,051		2,539						Customer accounts (end of period)

Notes: The Utilities effective tax rates (combined federal and state income tax rates) for the third quarters of 2016 and 2015 and for the first nine months of 2016 and 2015 were 37%.

Hawaiian Electric’s consolidated ROACE was 8.1% for the twelve months ended September 30, 2016 and 7.9% for the twelve months ended September 30, 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 2% lower than 2015 as a result of continued cost containment efforts and because 2015 included expenses that are not expected to be incurred in 2016.

The net book value (cost less accumulated depreciation) of utility property, plant and equipment (PPE) as of September 30, 2016 amounted to $4 billion, of which approximately 25% related to production PPE, 66% related to transmission and distribution PPE, and 9% related to other PPE. Approximately 2% 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 the 2015 RPS goal. The Utilities' RPS for 2015 was 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 providing plans to achieve 100% renewable energy using a diverse mix of energy resources by 2045. 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). The PUC issued an order in August 2016 establishing a procedural schedule requiring a further update of the PSIPs by December 1, 2016. The order was further modified in an order issued in October 2016. The utilities are required to file an updated PSIP incorporating input from the Parties, develop alternative scenarios and sensitivity analyses, and perform iterations on modeling and simulations by December 23, 2016. The Utilities will continue to evaluate all options to achieving the state’s 100% renewable energy goal, to stabilize and reduce customer rates, and to maintain safe and reliable service.

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, if approved by the PUC, would 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. In June 2016, the PUC proposed a draft program, and the Utilities and other participating parties filed comments on the draft program. As part of the investigatory docket, on September 28, 2016, the PUC held an informal technical conference with the parties to establish and facilitate a constructive dialogue toward the development of a comprehensive community-based renewable energy program and tariff.

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.

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). The Utilities are awaiting a PUC procedural order for the proceeding.

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 September 30, 2016) returns were as follows:



%	Return on rate base (RORB)*						ROACE**						Rate-making ROACE***
Twelve months ended September 30, 2016	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric
Utility returns	7.31		7.61		7.28		7.94		8.46		8.45		8.91		8.82		8.74
PUC-allowed returns	8.11		8.31		7.34		10.00		10.00		9.00		10.00		10.00		9.00
Difference	(0.80	)	(0.70	)	(0.06	)	(2.06	)	(1.54	)	(0.55	)	(1.09	)	(1.18	)	(0.26	)

* 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 for financial reporting purposes 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 (see “Decoupling” in Note 4 of the Consolidated Financial Statements),

•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 credited $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
2017 (3)
Hawaii Electric Light
2010 (4)
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 (5)
Request	8/16/12	$	19.8	4.2	10.25	8.30	$	455	57.05
Closed	3/27/13
2016 (6)
Request	9/19/16	$	19.3	6.5	10.60	8.44	$	479	57.12
Maui Electric
2012 (7)
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 (8)	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) See “Hawaiian Electric 2017 test year rate case” below.

(4)

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.

(5) 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.


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

(7) 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.


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

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, and further explained its view 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.

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 whether the PUC will accept this abbreviated filing to satisfy Maui Electric’s obligation to file a rate case in 2015, whether additional material will be required or whether Maui Electric will be required to proceed with a traditional rate proceeding.

Hawaii Electric Light 2016 test year rate case. On September 19, 2016, Hawaii Electric Light filed an application with the PUC for a general rate increase of $19.3 million over revenues at current effective rates (for a 6.5% increase in revenues), based on an 8.44% rate of return (which incorporates a return on equity of 10.60%). The last rate increase in base rates was in January 2011. The $19.3 million requested is to cover higher operating costs (including expanded vegetation management focusing on albizia tree removal and increased pension costs) and system upgrades to increase reliability, improve customer service and integrate more renewable energy. As part of this case, Hawaii Electric Light is also taking steps towards innovative ratemaking by proposing implementation of performance based regulation (PBR) mechanisms to measure and link certain revenues to its performance in areas of customer service, reliability and communication relating to the rooftop solar interconnection process. Hawaii Electric Light pointed out that it has increased its use of renewables from 34.6% Renewable Portfolio Standards (RPS) in 2010 to 48.7% RPS in 2015, using wind, hydroelectricity, solar and geothermal resources to generate electricity. Hawaii Electric Light also proposed revenue adjustments to recover costs associated with the acquisition and operation of the power plant currently owned by Hamakua Energy Partners, L.P. Hawaii Electric Light requested approval of the acquisition of this power plant in a separate application.

Hawaiian Electric 2017 test year rate case. On September 16, 2016, Hawaiian Electric filed with the PUC a Notice of Intent to file an application for a general rate case on or before December 30, 2016, utilizing a 2017 calendar test year.

Hawaiian Electric’s filing is required to satisfy the obligation to file a general rate case under the triennial rate case cycle established by the PUC in the decoupling final D&O.

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. An application for PUC approval of an amendment to the PPA was filed in April 2014 and the PUC approved the amendment in June 2016.

•

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 and the PUC concurred with that recommendation in their D&O issued in September 2016.

•

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. On September 15, 2016, Hawaiian Electric filed the Amended and Restated PPA, dated August 12, 2016, which reflects the completion of the interconnection requirements study, including, among other things, amendments related to the final design of the facility, scope of work, cost, schedule and reporting milestones.


•	In July 2015, the PUC approved the 27.6 MW Waianae Solar project that is being developed by Eurus Energy America. It is expected to be in service at the end of 2016, at which time it will be the largest solar project in Hawaii.


•	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 set to expire November 2016. The

contract has been extended from November 2016 to November 2017 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. In June 2016, the PUC proposed a draft program, and the Utilities and other participating parties filed comments on the draft program. As part of the investigatory docket, on September 28, 2016, the PUC held an informal technical conference with the parties to establish and facilitate a constructive dialogue toward the development of a comprehensive community-based renewable energy program and tariff.

•

On May 5, 2016, Maui Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Maui Electric Dispatchable Firm Generation Request for Proposals. The solicitation intends to seek approximately 20 MW of new renewable generation capacity and approximately 20 MW of fuel flexible firm generation resources on the island of Maui by 2022, as proposed in the PSIP Update Report.


•	On June 6, 2016, Hawaiian Electric filed a request for the PUC to open a docket and assign an Independent Observer to oversee the Hawaiian Electric Renewable Energy Request for Proposals. The solicitation intends to seek new renewable energy generation on the island of Oahu to be placed into service by the end of 2020, consistent with the Five-Year Action Plan proposed in the PSIP Update Report.

•

In July 2016, Hawaiian Electric announced plans to build, own and operate a 20-MW solar facility in conjunction with the Department of the Navy at a Navy/Air Force joint base, subject to PUC approval. On October 3, 2016, Hawaiian Electric filed with the PUC a request to waive the $67 million project from the Competitive Bidding Framework and to approve expenditures for the project. The renewable energy generated by the solar facility will feed into Oahu’s electrical grid at a cost of 9.54 cents per kilowatt-hour.


•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of September 30, 2016, there were 23 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 September 30, 2016, there were approximately 293 MW, 69 MW and 77 MW of installed distributed renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively, for tariff-based customer generation programs, namely NEM, Customer Grid Supply (CGS) and Customer Self Supply (CSS).

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

PUC Commissioner. On June 29, 2016, the Governor appointed Thomas Gorak on an interim basis to replace PUC Commissioner Michael Champley, whose term expired on June 30, 2016. Mr. Gorak served as the PUC’s Chief Counsel from September 2013 to June 2016. His term as a PUC Commissioner began on July 1, 2016 and is subject to Senate confirmation in the 2017 legislative session.

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. On August 1, 2016, Hawaiian Electric and Kalaeloa entered into an agreement that neither party will give written notice of termination of the PPA prior to October 31, 2017. This agreement complements continued negotiations between the parties and accounts for time needed for PUC approval of a negotiated resolution. The PPA with AES Hawaii, Inc. is scheduled to expire in 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 11.4 MW-net, 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. Due to the recent frequency of reactivations of Kahului Units 1 and 2 to meet system requirements, these units were removed from deactivated status and designated as reactivated in September 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. In May 2016, Maui Electric requested that the PUC open a new docket for Maui Electric’s competitive bidding process for additional firm capacity resources. In September 2016, Maui Electric submitted an application to purchase and install three temporary mobile distributed generation diesel engines to address increasing reserve capacity shortfalls on the island of Maui.

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)	September 30, 2016				December 31, 2015
Short-term borrowings	$	21	1	%	$	—	—	%
Long-term debt, net	1,279		41		1,279		42
Preferred stock	34		1		34		1
Common stock equity	1,767		57		1,728		57
	$	3,101	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)	Nine months ended September 30, 2016		September 30, 2016		December 31, 2015
Short-term borrowings ¹
Commercial paper	$	18	$	—	$	—
Line of credit draws	—		—		—
Borrowings from HEI	3		21		—
Undrawn capacity under line of credit facility			200		200

¹ The maximum amount of Hawaiian Electric’s external short-term borrowings during the first nine months of 2016 was $61 million. As of September 30, 2016, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $18.5 million and $15.5 million, respectively. As of October 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 October 28, 2016, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $18.5 million and $15.5 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 HEI 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 June 2016, the PUC issued a D&O approving the issue and sale of each utility’s common stock in 2016 up to the amounts requested in the application.

Hawaiian Electric and Maui Electric have PUC 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.

In August 2016, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed an application with the PUC for approval to issue, on or before December 31, 2017, unsecured obligations bearing taxable interest (Hawaiian Electric up to $100 million, Hawaii Electric Light up to $10 million and Maui Electric up to $30 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.

On November 2, 2016, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed an application with the PUC for approval to issue unsecured obligations bearing taxable interest and/or refunding SPRBs prior to December 31, 2020 to refinance three series of outstanding revenue bonds up to $252 million, $88 million and $75 million, respectively.

As of October 28, 2016, the Fitch, Moody’s and S&P ratings of Hawaiian Electric were as follows:



	Fitch	Moody’s	S&P
Long-term issuer default, issuer and corporate credit, respectively	BBB+	Baa2	BBB-
Commercial paper	F2	P-2	A-3
Senior unsecured debt/special purpose revenue bonds	A-	Baa2	BBB-
Hawaiian Electric-obligated preferred securities of trust subsidiary	*	Baa3	BB
Cumulative preferred stock (selected series)	*	Ba1	*
Subordinated debt	BBB	*	*
Outlook	Stable	Stable	Stable

* Not rated.

On July 19, 2016, S&P affirmed Hawaiian Electric’s ‘BBB-’ long-term issuer credit and other ratings, and removed the ratings from CreditWatch with positive implications. The outlook is stable. S&P stated that “the rating actions reflect the termination of the company’s [HEI’s] planned merger with NextEra, which would have led to higher ratings for HEI.”

On July 20, 2016, Fitch affirmed Hawaiian Electric’s long-term issuer default rating at ‘BBB+’ with a stable outlook. Fitch stated that “the rating affirmation reflects Fitch’s view that the political and regulatory framework in Hawaii, while adverse to the proposed merger with NextEra, will remain ultimately supportive of HECO’s [Hawaiian Electric’s] credit profile as the utility faces rising penetration of distributed generation and a capital intensive fleet modernization plan.”

On August 3, 2016, Moody’s downgraded Hawaiian Electric’s senior unsecured debt rating from Baa1 to Baa2 and downgraded other ratings. Hawaiian Electric’s outlook is stable. A Moody’s VP-Senior Credit Officer stated, “[t]he ratings downgrade is prompted by our concern that HECO [Hawaiian Electric] will continue to face significant challenges in transforming its generation base to 100% renewable sources in an unpredictable and highly political regulatory environment. We believe that the regulatory environment could become contentious as this transformation is executed despite recently falling customer bills, driven by lower fuel oil prices, and the company’s decision to moderate its still significant capital expenditure program.”

Cash flows. Nine months ended September 30, 2016 compared to nine months ended September 30, 2015. The following table reflects the changes in cash flows for the comparative periods:



	Nine months ended September 30
(in thousands)	2016			2015			Change
Net cash provided by operating activities	$	275,271		$	201,586		$	73,685
Net cash used in investing activities	(226,036		)	(230,116		)	4,080
Net cash provided by (used in) financing activities	(50,707		)	25,472			(76,179		)

Net cash provided by operating activities. 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.

The increase in net cash provided by operating activities was impacted by the following:


•	Higher cash from a refund of federal income taxes in 2016 due to the extension of bonus depreciation enacted in the fourth quarter of 2015 and lower revenue taxes paid resulting from lower revenues due largely to lower fuel prices.


•	Lower payments for fuel oil and the timing of various payments (see change in “Decrease in accounts payable” on the Hawaiian Electric Consolidated Statements of Cash Flows)

Net cash used in investing activities. The decrease in net cash used in investing activities was driven primarily by decreased capital expenditures, offset by lower proceeds from contributions in aid of construction.

Net cash provided by (used in) financing activities. Financing activities provided supplemental cash for both day-to-day operations and capital requirements for the first nine months of 2015, but used cash in the same period of 2016. The changes in net cash provided by (used in) financing activities primarily is a reflection of the the lower proceeds from short-term borrowings.

The Utilities’ net capital expenditures estimate for 2016 is currently $340 million, which excludes the HEP acquisition in 2016, based on the PUC extension of the procedural schedule for the approval into January 2017. The actual net capital expenditures could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the timing of PUC decisions. Proceeds from the issuance of equity and long-term debt, cash flows from operating activities, temporary increases in short-term borrowings and borrowings from affiliates and existing cash and cash equivalents are expected to provide the forecasted $340 million needed for the net capital expenditures in 2016 as well as to pay down commercial paper or other short term borrowings, fund any unanticipated expenditures not included in the 2016 forecast such as increases in the costs or acceleration of the construction of capital projects, unanticipated capital expenditures that may be required by new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements.

Bank



	Three months ended September 30				Increase
(in millions)	2016		2015		(decrease)		Primary reason(s)
Interest income	$	55	$	51	$	4	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 September 30, 2016 increased by $253 million compared to the same period in 2015 as average commercial real estate, consumer, home equity lines of credit and residential balances increased by $225 million, $42 million, $36 million and $12 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased by $63 million primarily due to a decrease in the syndicated national credit loan portfolio. The yield on earning assets increased by 6 basis points as the adjustable rate loans repriced upward with the increase in the prime rate at end of 2015 and there was a shift in mix of the loan portfolio with the growth of the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 12 basis points. The average investment securities portfolio balance increased by $166 million due to the use of excess liquidity to purchase investments.
Noninterest income	19		18		1		Noninterest income increased slightly for the three months ended September 30, 2016 compared to noninterest income for the same period in 2015 as higher mortgage banking income and bank-owned life insurance income was largely offset by a lower gain on sale of real estate.
Revenues	74		69		5
Interest expense	3		3		—		Interest expense was 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 September 30, 2016 increased by $477 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $333 million and $144 million, respectively. Other borrowings decreased by $79 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate increased by 3 basis points.
Provision for loan losses	6		3		3		The provision for loan losses increased by $2.8 million primarily due to increased reserves for growth in the loan portfolio, additional loan loss reserves for commercial loans due to downgrades of specific commercial credits and additional reserves for the consumer loan portfolio. Delinquency rates have decreased from 0.58% at September 30, 2015 to 0.51% at September 30, 2016. The net charge-off ratio for the three months ended September 30, 2016 was 0.20% compared to a net charge-off ratio of 0.10% for the same period in 2015. The increase in net charge-offs were primarily 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 loan charge-offs related to specific commercial borrowers.
Noninterest expense	42		42		—		Noninterest expense for the three months ended September 30, 2016 was flat compared to the same period in 2015.
Expenses	51		48		3
Operating income	23		21		2		Higher net interest income and noninterest income was partly offset by higher provision loan losses.
Net income	15		13		2



	Nine months ended September 30				Increase
(in millions)	2016		2015		(decrease)			Primary reason(s)
Interest income	$	163	$	148	$	15		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 nine months ended September 30, 2016 increased by $232 million compared to the same period in 2015 as average commercial real estate, home equity lines of credit, consumer and residential balances increased by $208 million, $33 million, $25 million and $16 million, respectively. The growth in these loan portfolios was reflective of ASB’s portfolio mix target and loan growth strategy. The average commercial loan balance decreased $52 million primarily due to a decrease in syndicated national credit loan portfolio. The yield on earning assets increased by 8 basis points as adjustable rate loans repriced upward with the increase in the prime rate at end of 2015 and there was a shift in the mix of the loan portfolio with the growth in the commercial real estate and consumer loan portfolios, which resulted in an increase in loan portfolio yields of 11 basis points. The average investment securities portfolio balance increased by $242 million due to the use of excess liquidity to purchase investments. The average FHLB stock balance decreased by $28 million as FHLB stock in excess of the required holdings was repurchased by the FHLB.
Noninterest income	50		51		(1		)	Noninterest income decreased slightly for the nine months ended September 30, 2016 compared to noninterest income for the nine months ended September 30, 2015 as higher gain on sale of securities and higher fee income on other financial products were more than offset by lower gain on sale of real estate and lower deposit fee income.
Revenues	213		199		14
Interest expense	10		9		1			The increase in interest expense for the nine months ended September 30, 2016 compared to the same period in 2015 was primarily due to the increase in term certificates. Average deposit balances for the nine months ended September 30, 2016 increased by $418 million compared to the same period in 2015 due to an increase in core deposits and term certificates of $321 million and $97 million, respectively. Other borrowings decreased by $33 million primarily due to a decrease in repurchase agreements. The interest-bearing liability rate increased by 2 basis points.
Provision for loan losses	15		5		10			The provision for loan losses increased by $9.8 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 commercial loans due to downgrades of specific commercial credits. The provision for loan losses for the nine months ended September 30, 2015 included the reversal of the Pahoa lava reserves. Delinquency rates have decreased from 0.58% at September 30, 2015 to 0.51% at September 30, 2016. The net charge-off ratio for the nine months ended September 30, 2016 was 0.19% compared to a net charge-off ratio of 0.08% 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 loan charge-offs related to specific commercial borrowers.
Noninterest expense	126		124		2			The increase in noninterest expense for the nine months ended September 30, 2016 was primarily due to the costs related to the replacement and upgrade of the electronic banking platform.
Expenses	151		138		13
Operating income	62		61		1			Higher net interest income was largely offset by higher provision loan losses, lower noninterest income and higher noninterest expense.
Net income	41		40		1

See Note 5 of the Consolidated Financial Statements and “Economic conditions” in the “HEI Consolidated” section above.

ASB continues to maintain its low-risk profile, strong balance sheet and straightforward community banking business model.

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



	Three months ended September 30		Nine months ended September 30
(percent)	2016	2015	2016	2015
Return on average assets	0.97	0.92	0.89	0.92
Return on average equity	10.36	9.73	9.50	9.69
Net interest margin	3.57	3.53	3.59	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 September 30	2016						2015
(dollars in thousands)	Average balance			Interest income/ expense		Yield/ rate (%)	Average balance			Interestincome/ expense		Yield/ rate (%)
Assets:
Interest-earning deposits	$	97,885		$	124	0.50	$	111,574		$	72	0.25
FHLB Stock	11,218			54		1.89	10,748			14		0.51
Available-for-sale investment securities	928,698			4,581		1.97	762,572			4,127		2.17
Loans
Residential 1-4 family	2,077,135			22,044		4.24	2,065,421			22,493		4.36
Commercial real estate	888,886			9,113		4.08	663,805			6,690		4.00
Home equity line of credit	864,589			7,204		3.31	828,096			6,684		3.20
Residential land	18,764			282		6.00	17,876			268		5.97
Commercial	750,366			7,327		3.87	813,475			7,376		3.58
Consumer	159,226			4,474		11.18	117,699			2,902		9.79
Total loans ^1,2	4,758,966			50,444		4.22	4,506,372			46,413		4.10
Total interest-earning assets ¹	5,796,767			55,203		3.80	5,391,266			50,626		3.74
Allowance for loan losses	(55,480		)				(46,726		)
Non-interest-earning assets	514,120						486,995
Total assets	$	6,255,407					$	5,831,535
Liabilities and shareholder’s equity:
Savings	$	2,139,863		$	358	0.07	$	1,990,016		$	319	0.06
Interest-bearing checking	837,480			43		0.02	784,265			35		0.02
Money market	161,149			52		0.13	164,200			52		0.13
Time certificates	597,537			1,418		0.94	453,460			949		0.83
Total interest-bearing deposits	3,736,029			1,871		0.20	3,391,941			1,355		0.16
Advances from Federal Home Loan Bank	100,000			792		3.10	101,739			794		3.05
Securities sold under agreements to repurchase	161,652			672		1.63	238,822			721		1.18
Total interest-bearing liabilities	3,997,681			3,335		0.33	3,732,502			2,870		0.30
Non-interest bearing liabilities:
Deposits	1,572,821						1,440,136
Other	101,759						105,804
Shareholder’s equity	583,146						553,093
Total liabilities and shareholder’s equity	$	6,255,407					$	5,831,535
Net interest income				$	51,868					$	47,756
Net interest margin (%) ³						3.57						3.53



Nine months ended September 30	2016						2015
(dollars in thousands)	Average balance			Interest income/ expense		Yield/ rate (%)	Average balance			Interestincome/ expense		Yield/ rate (%)
Assets:
Interest-earning deposits	$	80,738		$	304	0.50	$	133,343		$	253	0.25
FHLB Stock	11,094			142		1.71	39,372			59		0.20
Available-for-sale investment securities	892,726			13,773		2.06	650,645			10,258		2.10
Loans
Residential 1-4 family	2,076,308			66,565		4.27	2,059,921			67,714		4.38
Commercial real estate	854,977			25,993		4.04	646,769			19,251		3.97
Home equity line of credit	857,652			21,058		3.28	824,510			19,683		3.19
Residential land	18,577			843		6.05	17,347			830		6.38
Commercial	753,783			22,294		3.93	805,333			21,847		3.61
Consumer	143,514			11,818		11.00	118,974			8,321		9.35
Total loans ^1,2	4,704,811			148,571		4.21	4,472,854			137,646		4.10
Total interest-earning assets ¹	5,689,369			162,790		3.81	5,296,214			148,216		3.73
Allowance for loan losses	(52,902		)				(46,295		)
Non-interest-earning assets	505,014						488,103
Total assets	$	6,141,481					$	5,738,022
Liabilities and shareholder’s equity:
Savings	$	2,095,975		$	1,034	0.07	$	1,967,446		$	928	0.06
Interest-bearing checking	831,412			127		0.02	776,100			102		0.02
Money market	164,596			157		0.13	163,659			152		0.12
Time certificates	539,314			3,836		0.95	442,224			2,699		0.82
Total interest-bearing deposits	3,631,297			5,154		0.19	3,349,429			3,881		0.15
Advances from Federal Home Loan Bank	101,232			2,363		3.07	100,586			2,353		3.09
Securities sold under agreements to repurchase	182,671			2,053		1.48	216,066			2,115		1.29
Total interest-bearing liabilities	3,915,200			9,570		0.32	3,666,081			8,349		0.30
Non-interest bearing liabilities:
Deposits	1,549,467						1,413,351
Other	100,210						111,175
Shareholder’s equity	576,604						547,415
Total liabilities and shareholder’s equity	$	6,141,481					$	5,738,022
Net interest income				$	153,220					$	139,867
Net interest margin (%) ³						3.59						3.52


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


²	Includes recognition of deferred loan fees of $0.6 million and $0.6 million for the three months ended September 30, 2016 and 2015, respectively, and $2.1 million and $1.9 million for the nine months ended September 30, 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 2016 year-to-date net interest margin has increased compared to the same period in the prior year.

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:



	September 30, 2016				December 31, 2015
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate:
Residential 1-4 family	$	2,054,460		43.4	$	2,069,665		44.8
Commercial real estate	774,349			16.3	690,561			14.9
Home equity line of credit	859,952			18.1	846,294			18.3
Residential land	19,666			0.4	18,229			0.4
Commercial construction	140,758			3.0	100,796			2.2
Residential construction	15,073			0.3	14,089			0.3
Total real estate, net	3,864,258			81.5	3,739,634			80.9
Commercial	717,450			15.2	758,659			16.4
Consumer	158,065			3.3	123,775			2.7
	4,739,773			100.0	4,622,068			100.0
Less: Deferred fees and discounts	(5,135		)		(6,249		)
Allowance for loan losses	(58,737		)		(50,038		)
Total loans, net	$	4,675,901			$	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 4% of the portfolio and are included in the amortizing balances identified in the table above.



	September 30, 2016			December 31, 2015
Outstanding balance (in thousands)	$	859,952		$	846,294
Percent of portfolio in first lien position	44.1		%	42.9		%
Net charge-off ratio	0.01		%	0.02		%
Delinquency ratio	0.27		%	0.25		%



							End of draw period – interest only									Current
September 30, 2016	Total			Interest only			2016-2017			2018-2020			Thereafter			amortizing
Outstanding balance (in thousands)	$	859,952		$	657,203		$	9,543		$	134,302		$	513,358		$	202,749
% of total	100		%	76		%	1		%	15		%	60		%	24		%

As of September 30, 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 96% 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 September 30, 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:



	September 30, 2016				December 31, 2015
(dollars in thousands)	Balance		% of total		Balance		% of total
U.S. Treasury and federal agency obligations	$	189,372	19	%	$	212,959	26	%
Mortgage-related securities — FNMA, FHLMC and GNMA	807,612		81		607,689		74
Total available-for-sale investment securities	$	996,984	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 September 30, 2016, ASB’s funding sources consisted of 95% deposits and 5% other borrowings compared to 94% deposits and 6% other borrowings as of December 31, 2015. The weighted average cost of deposits for the first nine 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 September 30, 2016, ASB had an unrealized gain, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $6.0 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 nine months of 2016, ASB recorded a provision for loan losses of $15.3 million primarily due to increased loss reserves for growth in the loan portfolio, additional loan loss reserves for the consumer loan portfolio and loan loss reserves for commercial loans due to downgrades of specific commercial credits. During the first nine months of 2015, ASB recorded a provision for loan losses of $5.4 million primarily due to loan loss reserves for the commercial real estate and commercial loan portfolios due to downgrades of specific credits, partly offset by the reversal of the Pahoa lava reserves and commercial loan payoffs. Financial stress on ASB’s customers may result in higher levels of delinquencies and losses.



	Nine months ended September 30						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	15,266			5,436			6,275
Less: net charge-offs	6,567			2,780			1,855
Allowance for loan losses, end of period	$	58,737		$	48,274		$	50,038
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.19		%	0.08		%	0.04		%

We maintain a reserve for credit losses that consists of two components, the allowance for loan losses and a reserve for unfunded loan commitments (unfunded reserve). The level of the unfunded reserve is adjusted by recording an expense or recovery in other noninterest expense. As of September 30, 2016 and December 31, 2015, the reserve for unfunded loan commitments was $1.8 million and $1.7 million, respectively.

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. 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 September 30, 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 13.3% and a Tier-1 leverage ratio of 8.6%.

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 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.

Military Lending Act. The Department of Defense (DOD) amended its regulation that implements the Military Lending Act (MLA), which became effective on October 3, 2016. The DOD amended its regulation primarily for the purpose of extending the protections of the MLA to a broader range of closed-end and open-end credit products. It initially applied to three narrowly-defined “consumer credit” products: closed-end payday loans; closed-end auto title loans; and closed-end tax refund anticipation loans. The DOD revised the scope of the definition of ‘‘consumer credit’’ to be generally consistent with the credit products that have been subject to the requirements of the Regulation Z, namely: credit offered or extended to a covered borrower primarily for personal, family, or household purposes and that is (i) subject to a finance charge or (ii) payable by a written agreement in more than four installments.

Additionally, the DOD elected to exercise its discretion by generally requiring any fees for credit insurance products or for credit-related ancillary products to be included in the Military Annual Percentage Rate. The DOD also modified the disclosures that a creditor must provide to a covered borrower and implemented the enforcement provisions of the MLA. ASB has modified certain products, practices and associated training to conform to these changes.

Overtime Rules. The Secretary of Labor updated the overtime regulations of the Fair Labor Standards Act to simplify and modernize them. The Department of Labor issued final rules that will raise the salary threshold indicating eligibility from $455/week to $913/week ($47,476 per year), and update automatically the salary threshold every three years, based on wage growth over time, increasing predictability. The final rule will become effective on December 1, 2016. ASB is reviewing its pay schedules currently to determine necessary actions for compliance.

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)	September 30, 2016		December 31, 2015		% change
Total assets	$	6,337	$	6,015	5
Available-for-sale investment securities	997		821		21
Loans receivable held for investment, net	4,676		4,566		2
Deposit liabilities	5,381		5,025		7
Other bank borrowings	265		329		(19	)

As of September 30, 2016, ASB was one of Hawaii’s largest financial institutions based on assets of $6.3 billion and deposits of $5.4 billion.

As of September 30, 2016, ASB’s unused FHLB borrowing capacity was approximately $1.8 billion. As of September 30, 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 $2.5 million at September 30, 2016. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the nine months ended September 30, 2016, net cash provided by ASB’s operating activities was $42 million. Net cash used during the same period by ASB’s investing activities was $310 million, primarily due to purchases of investment securities of $354 million, a net increase in loans receivable of $175 million and additions to premises and equipment of $8 million, partly offset by repayments and calls of investment securities of $173 million, proceeds from the sale of investments securities of $16 million and proceeds from the sale of loans of commercial loans of $38 million. Net cash provided by financing activities during this period was $260 million, primarily due to increases in deposit liabilities of $355 million, partly offset by a net decrease in retail repurchase agreements of $21 million, maturities of securities sold under agreements to repurchase of $42 million, a net decrease in escrow deposits of $5 million and $27 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 September 30, 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 13.3% (10.0%) and a Tier-1 leverage ratio of 8.6% (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 September 30, 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)	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
+300	2.0	%	1.6	%	(1.5	)%	(9.3	)%
+200	0.8		0.6		0.9		(5.3	)
+100	—		(0.1	)	1.9		(1.9	)
-100	(0.2	)	(0.5	)	(6.7	)	(1.2	)

Management believes that ASB’s interest rate risk position as of September 30, 2016 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was more asset sensitive for all rate increases as of September 30, 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 $1.0 billion as of September 30, 2016 compared to $974 million as of December 31, 2015 due to the growth and mix of the balance sheet. Assets increased by $322 million with market valuation exceeding the growth and valuation of funding liabilities.

The change in EVE to rising rates became less sensitive as of September 30, 2016 compared to December 31, 2015 as the duration of assets shortened while the duration of liabilities lengthened. The downward shift in the yield curve led to faster prepayment expectations and shortened the durations of the fixed rate mortgage and investment portfolios. On the liability side of the balance sheet, core deposits grew by $190 million with the mix shifting to longer duration products. Additionally, the behavior (decay and repricing) assumptions of certain core deposits were 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 September 30, 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 September 30, 2016, at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes in internal control over financial reporting during the third 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 September 30, 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 September 30, 2016, at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes in internal control over financial reporting during the third 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 “Cautionary Note Regarding Forward-Looking Statements” on pages iv and v herein. After the termination of the Merger Agreement, certain of the “Risk Factors Relating to the Merger” described on pages 25 and 26 of the Form 10-K may no longer be relevant. Also, there are risks that the termination of the Merger with NEE and the associated loss of NEE’s resources, expertise and support (e.g., financial and technological), could have negative impacts, including potentially higher costs and longer lead times to increase levels of renewable energy and to complete projects like ERP/ERM and smart grids, and a higher cost of capital.

Item 5. Other Information

A. Ratio of earnings to fixed charges.



	Nine months ended September 30		Years ended December 31
	2016	2015	2015	2014	2013	2012	2011
HEI and Subsidiaries
Excluding interest on ASB deposits	5.34	3.68	3.68	3.80	3.55	3.30	3.24
Including interest on ASB deposits	5.04	3.54	3.54	3.65	3.42	3.15	3.04
Hawaiian Electric and Subsidiaries	4.18	4.03	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, nine months ended September 30, 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		Letter agreement dated July 28, 2016 and executed August 1, 2016 extending the term of the Power Purchase Agreement (PPA) between Hawaiian Electric Company and Kalaeloa Partners, L.P. dated as of October 14, 1988 (as amended)

Hawaiian Electric Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, nine months ended September 30, 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: November 4, 2016		Date: November 4, 2016