HAWAIIAN ELECTRIC INDUSTRIES INC - Annual Report: 2015 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934



Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-8503	HAWAIIAN ELECTRIC INDUSTRIES, INC., a Hawaii corporation 1001 Bishop Street, Suite 2900, Honolulu, Hawaii 96813 Telephone (808) 543-5662	99-0208097
1-4955	HAWAIIAN ELECTRIC COMPANY, INC., a Hawaii corporation 900 Richards Street, Honolulu, Hawaii 96813 Telephone (808) 543-7771	99-0040500

Securities registered pursuant to Section 12(b) of the Act:



Registrant	Title of each class	Name of each exchange on which registered
Hawaiian Electric Industries, Inc.	Common Stock, Without Par Value	New York Stock Exchange
Hawaiian Electric Company, Inc.	Guarantee with respect to 6.50% Cumulative Quarterly Income Preferred Securities Series 2004 (QUIPSSM) of HECO Capital Trust III	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:



Registrant		Title of each class
Hawaiian Electric Industries, Inc.		None
Hawaiian Electric Company, Inc.		Cumulative Preferred Stock

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.



Hawaiian Electric Industries Inc. Yes X No	Hawaiian Electric Company, Inc. Yes No X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



Hawaiian Electric Industries Inc. Yes No X	Hawaiian Electric Company, Inc. Yes No X

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	Hawaiian Electric Company, Inc. Yes X No

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	Hawaiian Electric Company, Inc. Yes X No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

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

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 No X	Hawaiian Electric Company, Inc. Yes No X



	Aggregate market value of the voting and non- voting common equity held by non-affiliates of the registrants as of	Number of shares of common stock outstanding of the registrants as of
	June 30, 2015	June 30, 2015	February 12, 2016
Hawaiian Electric Industries, Inc. (HEI)	$3,194,385,337	107,446,530 (Without par value)	107,624,726 (Without par value)
Hawaiian Electric Company, Inc. (Hawaiian Electric)	None	15,805,327 ($6 2/3 par value)	15,805,327 ($6 2/3 par value)

DOCUMENTS INCORPORATED BY REFERENCE

Hawaiian Electric’s Exhibit 99.1, consisting of:

Hawaiian Electric’s Directors, Executive Officers and Corporate Governance—Part III

Hawaiian Electric’s Executive Compensation—Part III

Hawaiian Electric’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—

Part III

Hawaiian Electric’s Certain Relationships and Related Transactions, and Director Independence—Part III

Hawaiian Electric’s Principal Accounting Fees and Services—Part III

Selected sections of Proxy Statement of HEI for the 2016 Annual Meeting of Shareholders to be filed-Part III

This combined Form 10-K represents separate filings by Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc. Information contained herein relating to any individual registrant is filed by each registrant on its own behalf. Hawaiian Electric makes no representations as to any information not relating to it or its subsidiaries.

TABLE OF CONTENTS



		Page

Glossary of Terms		ii
Forward-Looking Statements		vi

	PART I

Item 1.	Business	1
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	80
Item 8.	Financial Statements and Supplementary Data	83
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	183
Item 9A.	Controls and Procedures	183
Item 9B.	Other Information	185

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	185
Item 11.	Executive Compensation	187
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	188
Item 13.	Certain Relationships and Related Transactions, and Director Independence	189
Item 14.	Principal Accounting Fees and Services	189

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	189
Signatures		194

GLOSSARY OF TERMS

Defined below are certain terms used in this report:



Terms		Definitions

ABO		Accumulated benefit obligation
AES Hawaii		AES Hawaii, Inc.
AFUDC		Allowance for funds used during construction
AOCI		Accumulated other comprehensive income (loss)
AOS		Adequacy of supply
APBO		Accumulated postretirement benefit obligation
ARO		Asset retirement obligations
ASB		American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, 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
Btu		British thermal unit
CAA		Clean Air Act
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
Chevron		Chevron Products Company, a fuel oil supplier
CIP		Campbell Industrial Park
CIS		Customer Information System
Company		When used in Hawaiian Electric Industries, Inc. sections and in the Notes to Consolidated Financial Statements, “Company” refers to 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); Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities - dissolved and terminated in 2015); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). When used in Hawaiian Electric Company, Inc. sections, “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries.
Consolidated Financial Statements		HEI’s and Hawaiian Electric's combined Consolidated Financial Statements, including notes, in Item 8 of this Form 10-K
Consumer Advocate		Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
CT-1		Combustion turbine No. 1
D&O		Decision and order
DBEDT		State of Hawaii Department of Business Economic Development and Tourism
DBF		State of Hawaii Department of Budget and Finance
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
EEPS		Energy Efficiency Portfolio Standards
EGU		Electrical generating unit
EIP		2010 Executive Incentive Plan, as amended
EPA		Environmental Protection Agency - federal
EPS		Earnings per share
ERISA		Employee Retirement Income Security Act of 1974, as amended
ERL		Environmental Response Law of the State of Hawaii
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
FDIC		Federal Deposit Insurance Corporation
FDICIA		Federal Deposit Insurance Corporation Improvement Act of 1991
federal		U.S. Government

GLOSSARY OF TERMS (continued)



Terms		Definitions

FERC		Federal Energy Regulatory Commission
FHLB		Federal Home Loan Bank
FHLMC		Federal Home Loan Mortgage Corporation
FICO		Financing Corporation
Fitch		Fitch Ratings, Inc.
FNMA		Federal National Mortgage Association
FRB		Federal Reserve Board
GAAP		Accounting principles generally accepted in the United States of America
GHG		Greenhouse gas
GNMA		Government National Mortgage Association
Gramm Act		Gramm-Leach-Bliley Act of 1999
HC&S		Hawaiian Commercial & Sugar Company, a division of A&B-Hawaii, Inc.
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.
Hawaiian Electric’s MD&A		Hawaiian Electric Company, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K
HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., ASB Hawaii, Inc., HEI Properties, Inc. (dissolved in 2015), Hawaiian Electric Industries Capital Trust II (dissolved and terminated in 2015), Hawaiian Electric Industries Capital Trust III (dissolved and terminated in 2015) and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
HEI's 2016 Proxy Statement		Selected sections of Proxy Statement for the 2016 Annual Meeting of Shareholders of Hawaiian Electric Industries, Inc. to be filed after the date of this Form 10-K, which are incorporated in this Form 10-K by reference
HEI’s MD&A		Hawaiian Electric Industries, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K
HEIPI		HEI Properties, Inc. (dissolved in 2015), a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
HEIRSP		Hawaiian Electric Industries Retirement Savings Plan
HEP		Hamakua Energy Partners, L.P., formerly known as Encogen Hawaii, L.P.
HTB		Hawaiian Tug & Barge Corp. On November 10, 1999, HTB sold substantially all of its operating assets and the stock of its subsidiary, Young Brothers, Limited, and changed its name to The Old Oahu Tug Services, Inc.
HPower		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP		Independent power producer
IRP		Integrated resource plan
IRR		Interest rate risk
Kalaeloa		Kalaeloa Partners, L.P.
kV		Kilovolt
kW		Kilowatt/s (as applicable)
KWH		Kilowatthour/s (as applicable)
LNG		Liquefied natural gas
LSFO		Low sulfur fuel oil
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.
MBtu		Million British thermal unit
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
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

iii

GLOSSARY OF TERMS (continued)



Terms		Definitions

Merger Sub II		NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE
Moody’s		Moody’s Investors Service’s
MSFO		Medium sulfur fuel oil
MOU		Memorandum of Understanding
MW		Megawatt/s (as applicable)
NA		Not applicable
NAAQS		National Ambient Air Quality Standard
NEE		NextEra Energy, Inc.
NEM		Net energy metering
NII		Net interest income
NM		Not meaningful
NPBC		Net periodic benefits costs
NQSO		Nonqualified stock options
O&M		Other operation and maintenance
OCC		Office of the Comptroller of the Currency
OPEB		Postretirement benefits other than pensions
OTS		Office of Thrift Supervision, Department of Treasury
OTTI		Other-than-temporary impairment
PBO		Projected benefit obligation
PCB		Polychlorinated biphenyls
PGV		Puna Geothermal Venture
PPA		Power purchase agreement
PPAC		Purchased power adjustment clause
PSD		Prevention of Significant Deterioration
PSIPs		Power Supply Improvement Plans
PUC		Public Utilities Commission of the State of Hawaii
PURPA		Public Utility Regulatory Policies Act of 1978
QF		Qualifying Facility under the Public Utility Regulatory Policies Act of 1978
QTL		Qualified Thrift Lender
RAM		Rate adjustment mechanism
RBA		Revenue balancing account
Registrant		Each of Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc.
REIP		Renewable Energy Infrastructure Program
RFP		Request for proposals
RHI		Renewable Hawaii, Inc., a wholly-owned nonregulated subsidiary of Hawaiian Electric Company, Inc.
ROA		Return on assets
ROACE		Return on average common equity
RORB		Return on rate base
RPS		Renewable portfolio standards
S&P		Standard & Poor’s
SAR		Stock appreciation right
SEC		Securities and Exchange Commission
See		Means the referenced material is incorporated by reference (or means refer to the referenced section in this document or the referenced exhibit or other document)
SLHCs		Savings & Loan Holding Companies
SOIP		1987 Stock Option and Incentive Plan, as amended. Shares of HEI common stock reserved for issuance under the SOIP were deregistered and delisted in 2015.
Spin-Off		The distribution to HEI shareholders of all of the common stock of ASB Hawaii immediately prior to the Merger
SPRBs		Special Purpose Revenue Bonds
ST		Steam turbine
state		State of Hawaii
TDR		Troubled debt restructuring

GLOSSARY OF TERMS (continued)



Terms		Definitions

Tesoro		Tesoro Hawaii Corporation dba BHP Petroleum Americas Refining Inc., a fuel oil supplier
TOOTS		The Old Oahu Tug Service, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.
Trust III		HECO Capital Trust III
UBC		Uluwehiokama Biofuels Corp., a wholly-owned nonregulated subsidiary of Hawaiian Electric Company, Inc.
Utilities		Hawaiian Electric Company, Inc., Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited
VIE		Variable interest entity

Forward-Looking Statements

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

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

•

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


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

•

international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by ASB, which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii, the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, unrest, the conflict in Syria, terrorist acts by ISIS or others, potential conflict or crisis with North Korea and potential pandemics);


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


•	weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes, lava flows and the potential effects of climate change, such as more severe storms and rising sea levels), including their impact on the Company's and Utilities' operations and the economy;


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


•	the ability of the Company and the Utilities to access the credit and capital markets (e.g., to obtain commercial paper and other short-term and long-term debt financing, including lines of credit, and, in the case of HEI, to issue common stock) under volatile and challenging market conditions, and the cost of such financings, if available;


•	the risks inherent in changes in the value of the Company’s pension and other retirement plan assets and ASB’s securities available for sale;


•	changes in laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;


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


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

•

the potential delay by the Public Utilities Commission of the State of Hawaii (PUC) in considering (and potential disapproval of actual or proposed) renewable energy proposals and related costs; reliance by the Utilities on outside parties such as the state, independent power producers (IPPs) and developers; and uncertainties surrounding technologies, solar power, wind power, proposed undersea cables, biofuels, environmental assessments required to meet renewable portfolio standards (RPS) goals and the impacts of implementation of the renewable energy proposals on future costs of electricity;


•	the ability of the Utilities to develop, implement and recover the costs of implementing the Utilities’ action plans and business model changes proposed and being developed in response to the four orders that the PUC issued

in April 2014, in which the PUC: directed the Utilities to develop, among other things, Power Supply Improvement Plans, a Demand Response Portfolio Plan and a Distributed Generation Interconnection Plan; described the PUC’s inclinations on the future of Hawaii’s electric utilities and the vision, business strategies and regulatory policy changes required to align the Utilities’ business model with customer interests and the state’s public policy goals; and emphasized the need to “leap ahead” of other states in creating a 21st century generation system and modern transmission and distribution grids;


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


•	fuel oil price changes, delivery of adequate fuel by suppliers and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);


•	the continued availability to the electric utilities or modifications of other cost recovery mechanisms, including the purchased power adjustment clauses (PPACs), rate adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from sales to mitigate the effects of declining kilowatthour sales;


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


•	the risks associated with increasing reliance on renewable energy, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;


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


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


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


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


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


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


•	cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and the Utilities (including at ASB branches and electric utility plants) and incidents at data processing centers they use, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls;

•

federal, state, county and international governmental and regulatory actions, such as existing, new and changes in laws, rules and regulations applicable to HEI, the Utilities and ASB (including changes in taxation, increases in capital requirements, regulatory policy changes, environmental laws and regulations (including resulting compliance costs and risks of fines and penalties and/or liabilities), the regulation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);


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


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


•	decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs as a result of adverse regulatory audit reports or otherwise);


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

•

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


•	the ability of the Utilities to recover increasing costs and earn a reasonable return on capital investments not covered by RAMs;


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


•	changes in accounting principles applicable to HEI, the Utilities and ASB, including the adoption of new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of variable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;


•	changes by securities rating agencies in their ratings of the securities of HEI and Hawaiian Electric and the results of financing efforts;


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


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


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


•	the final outcome of tax positions taken by HEI, the Utilities and ASB;


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


•	other risks or uncertainties described elsewhere in this report (e.g., Item 1A. Risk Factors) and in other reports previously and subsequently filed by HEI and/or Hawaiian Electric with the Securities and Exchange Commission (SEC).

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

vii

PART I



ITEM 1.	BUSINESS

HEI Consolidated

HEI and subsidiaries and lines of business. HEI was incorporated in 1981 under the laws of the State of Hawaii and is a holding company with its principal subsidiaries engaged in electric utility and banking businesses operating primarily in the State of Hawaii. HEI’s predecessor, Hawaiian Electric, was incorporated under the laws of the Kingdom of Hawaii (now the State of Hawaii) on October 13, 1891. As a result of a 1983 corporate reorganization, Hawaiian Electric became an HEI subsidiary and common shareholders of Hawaiian Electric became common shareholders of HEI.

Hawaiian Electric and its operating utility subsidiaries, Hawaii Electric Light Company, Inc. (Hawaii Electric Light) and Maui Electric Company, Limited (Maui Electric), are regulated electric public utilities. Hawaiian Electric also owns all the common securities of HECO Capital Trust III (a Delaware statutory trust), which was formed to effect the issuance of $50 million of cumulative quarterly income preferred securities in 2004, for the benefit of Hawaiian Electric, Hawaii Electric Light and Maui Electric. In December 2002, Hawaiian Electric formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects, but it has made no investments and currently is inactive. In September 2007, Hawaiian Electric formed another subsidiary, Uluwehiokama Biofuels Corp. (UBC), to invest in a biodiesel refining plant to be built on the island of Maui, which project has been terminated.

Besides Hawaiian Electric and its subsidiaries, HEI also currently owns directly or indirectly the following subsidiaries: ASB Hawaii, Inc. (ASB Hawaii) (a holding company, formerly known as American Savings Holdings, Inc.) and its subsidiary, American Savings Bank, F.S.B. (ASB); HEI Properties, Inc. (HEIPI), which was dissolved on December 11, 2015; Hawaiian Electric Industries Capital Trusts II and III (both formed in 1997 to be available for trust securities financings, but both were dissolved and terminated on December 14, 2015); and The Old Oahu Tug Service, Inc. (TOOTS).

ASB, acquired by HEI in 1988, is one of the largest financial institutions in the State of Hawaii with assets of $6.0 billion as of December 31, 2015.

HEIPI, whose predecessor company was formed in February 1998, held venture capital investments. HEIPI was dissolved on December 11, 2015.

TOOTS administers certain employee and retiree-related benefit programs and monitors matters related to its predecessor’s former maritime freight transportation operations.

The proposed Merger and Merger Agreement. On December 3, 2014, HEI, NextEra Energy, Inc., a Florida corporation (NEE), NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE (Merger Sub II) and NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE (Merger Sub I), entered into an Agreement and Plan of Merger (the Merger Agreement). The Merger Agreement provides for Merger Sub I to merge with and into HEI, with HEI surviving, and then for HEI to merge with and into Merger Sub II, with Merger Sub II surviving (the Merger). The Merger Agreement provides that, prior to completion of the Merger, HEI will distribute to its shareholders, on a pro-rata basis, all of the issued and outstanding shares of ASB Hawaii, Inc., a Hawaii corporation and wholly owned subsidiary of HEI and direct parent company of ASB (the Spin-Off). The closing of the Merger is subject to various conditions, including federal and state regulatory approvals. For additional information concerning the proposed Merger, see Note 2 of the Consolidated Financial Statements.

Additional information. For additional information about the Company required by this item, see HEI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (HEI’s MD&A), HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and HEI’s Consolidated Financial Statements.

The Company’s website address is www.hei.com. The information on the Company’s website is not incorporated by reference in this annual report on Form 10-K unless, and except to the extent, specifically incorporated herein by reference. HEI and Hawaiian Electric currently make available free of charge through this website their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports (since 1994) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. HEI and Hawaiian Electric intend to continue to use HEI’s website as a means of disclosing additional information. Such disclosures will be included on HEI’s website in the Investor Relations section. Accordingly, investors should routinely monitor such portions of HEI’s website, in addition to following HEI’s, Hawaiian Electric’s and ASB’s press releases, SEC filings and public conference calls and webcasts. Investors may also wish to refer to the PUC website at dms.puc.hawaii.gov/dms in order to review documents filed with and issued by the PUC. No information at the PUC website is incorporated herein by reference.

Commitments and contingencies. See “HEI Consolidated—Liquidity and capital resources –Selected contractual obligations and commitments” in HEI’s MD&A, Hawaiian Electric’s “Commitments and contingencies” below and Notes 2 and 5 of the Consolidated Financial Statements.

Regulation. HEI and Hawaiian Electric are each holding companies within the meaning of the Public Utility Holding Company Act of 2005 and implementing regulations, which requires holding companies and their subsidiaries to grant the Federal Energy Regulatory Commission (FERC) access to books and records relating to FERC’s jurisdictional rates. FERC granted HEI and Hawaiian Electric a waiver from its record retention, accounting and reporting requirements, effective May 2006.

HEI is subject to an agreement entered into with the PUC (the PUC Agreement) which, among other things, requires PUC approval of any change in control of HEI, including the proposed Merger. See “PUC application” in Note 2 to the Consolidated Financial Statements. The PUC Agreement also requires HEI to provide the PUC with periodic financial information and other reports concerning intercompany transactions and other matters. It also prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common stock of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the electric utility subsidiaries to pay dividends on their common stock. See “Restrictions on dividends and other distributions” and “Electric utility—Regulation” below.

HEI and ASB Hawaii are subject to Federal Reserve Board (FRB) registration, supervision and reporting requirements as savings and loan holding companies. As a result of the enactment of the Dodd-Frank Act, 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 Office of the Comptroller of the Currency (OCC) in July 2011. In the event the OCC has reasonable cause to believe that any activity of HEI or ASB Hawaii constitutes a serious risk to the financial safety, soundness or stability of ASB, the OCC is authorized to impose certain restrictions on HEI, ASB Hawaii and/or any of their subsidiaries. Possible restrictions include precluding or limiting: (i) the payment of dividends by ASB; (ii) transactions between ASB, HEI or ASB Hawaii, and their subsidiaries or affiliates; and (iii) any activities of ASB that might expose ASB to the liabilities of HEI and/or ASB Hawaii and their other affiliates. See “Restrictions on dividends and other distributions” below.

Bank regulations generally prohibit savings and loan holding companies and their nonthrift subsidiaries from engaging in activities other than those which are specifically enumerated in the regulations. However, the unitary savings and loan holding company relationship among HEI, ASB Hawaii and ASB is “grandfathered” under the Gramm-Leach-Bliley Act of 1999 (Gramm Act) so that HEI and its subsidiaries are able to continue to engage in their current activities so long as ASB satisfies the qualified thrift lender (QTL) test discussed under “Bank—Regulation—Qualified thrift lender test.” ASB met the QTL test at all times during 2015; however, the failure of ASB to satisfy the QTL test in the future could result in a need for HEI to divest ASB. If the Spin-Off and Merger are completed, these regulatory limitations will be eliminated since ASB Hawaii and ASB will no longer be affiliated with HEI and will not become affiliates of NextEra.

HEI is also affected by provisions of the Dodd-Frank Act relating to corporate governance and executive compensation, including provisions requiring shareholder “say on pay” and “say on pay frequency” votes, mandating additional disclosures concerning executive compensation and compensation consultants and advisors and further restricting proxy voting by brokers in the absence of instructions. See “Bank—Legislation and regulation” in HEI’s MD&A for a discussion of effects of the Dodd-Frank Act on HEI and ASB.

Restrictions on dividends and other distributions. HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, HEI’s principal sources of funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The rights of HEI and, consequently, its creditors and shareholders, to participate in any distribution of the assets of any of its subsidiaries are subject to the prior claims of the creditors and preferred shareholders of such subsidiary, except to the extent that claims of HEI in its capacity as a creditor are recognized as primary.

The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of the total capitalization of the electric utilities (including the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would, absent PUC approval, be restricted in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also provides that the foregoing dividend restriction shall not be construed as relinquishing any right the PUC may have to review the dividend policies of the electric utility subsidiaries. As of December 31, 2015, the consolidated common stock equity of HEI’s electric utility subsidiaries was 57% of their total capitalization (as calculated for purposes of the PUC Agreement). As of December 31, 2015, Hawaiian Electric and its subsidiaries had common stock equity of $1.7 billion of which approximately $711 million was not available for transfer to HEI without regulatory approval.

The ability of ASB to make capital distributions to HEI and other affiliates is restricted under federal law. Subject to a limited exception for stock redemptions that do not result in any decrease in ASB’s capital and would improve ASB’s financial condition, ASB is prohibited from declaring any dividends, making any other capital distributions, or paying a management fee to a controlling person if, following the distribution or payment, ASB would be deemed to be undercapitalized, significantly undercapitalized or critically undercapitalized. See “Bank—Regulation—Prompt corrective action.” All capital distributions are subject to prior approval by the OCC and FRB. Also see Note 14 to the Consolidated Financial Statements.

HEI and its subsidiaries are also subject to debt covenants, preferred stock resolutions and the terms of guarantees that could limit their respective abilities to pay dividends. The Company does not expect that the regulatory and contractual restrictions applicable to HEI and/or its subsidiaries will significantly affect the operations of HEI or its ability to pay dividends on its common stock, including the special dividend expected to be paid to shareholders of HEI if the Merger is consummated.

Environmental regulation. HEI and its subsidiaries are subject to federal and state statutes and governmental regulations pertaining to water quality, air quality and other environmental factors. See the “Environmental regulation” discussions in the “Electric utility” and “Bank” sections below.

Securities ratings. See the Fitch Ratings, Inc. (Fitch), Moody’s Investors Service’s (Moody’s) and Standard & Poor’s (S&P) ratings of HEI’s and Hawaiian Electric’s securities and discussion under “Liquidity and capital resources” (both “HEI Consolidated” and “Electric utility”) in HEI’s MD&A. These ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency from whom an explanation of the significance of such ratings may be obtained. There is no assurance that any such credit rating will remain in effect for any given period of time or that such rating will not be lowered, suspended or withdrawn entirely by the applicable rating agency if, in such rating agency’s judgment, circumstances so warrant. Any such lowering, suspension or withdrawal of any rating may have an adverse effect on the market price or marketability of HEI’s and/or Hawaiian Electric’s securities, which could increase the cost of capital of HEI and Hawaiian Electric, and could affect costs, including interest charges, under HEI's and/or Hawaiian Electric's debt securities and credit facilities. Neither HEI nor Hawaiian Electric management can predict future rating agency actions or their effects on the future cost of capital of HEI or Hawaiian Electric.

Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii for the benefit of Hawaiian Electric and its subsidiaries, but the source of their repayment are the unsecured obligations of Hawaiian Electric and its subsidiaries under loan agreements and notes issued to the Department, including Hawaiian Electric’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on revenue bonds currently outstanding and issued prior to 2009 are insured, but the ratings of these insurers have been withdrawn—see “Electric Utility—Liquidity and capital resources” in HEI’s MD&A.

Employees. The Company had full-time employees as follows:



December 31	2015	2014	2013	2012	2011
HEI	39	44	43	42	40
Hawaiian Electric and its subsidiaries	2,727	2,759	2,764	2,658	2,518
ASB and its subsidiaries	1,152	1,162	1,159	1,170	1,096
	3,918	3,965	3,966	3,870	3,654

The employees of HEI and its direct and indirect subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement. The International Brotherhood of Electrical Workers Local 1260 represents roughly half of the Utilities' workforce covered by a collective bargaining agreement that expires on October 31, 2018.

Properties. HEI leases office space from nonaffiliated lessors in downtown Honolulu under leases that expire in March 2016 and December 2017. See the discussions under “Electric Utility” and “Bank” below for a description of properties owned by HEI subsidiaries.

Electric utility

Hawaiian Electric and subsidiaries and service areas. Hawaiian Electric, Hawaii Electric Light and Maui Electric (Utilities) are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, respectively. Hawaiian Electric acquired Maui Electric in 1968 and Hawaii Electric Light in 1970. In 2015, the electric utilities’ revenues and net income amounted to approximately 90% and 85%, respectively, of HEI’s consolidated revenues and net income, compared to approximately 92% and 82% in 2014 and approximately 92% and 76% in 2013, respectively.

The islands of Oahu, Hawaii, Maui, Lanai and Molokai have a combined population estimated at 1.3 million, or approximately 95% of the total population of the State of Hawaii, and comprise a service area of 5,815 square miles. The principal communities served include Honolulu (on Oahu), Hilo and Kona (on Hawaii) and Wailuku and Kahului (on Maui). The service areas also include numerous suburban communities, resorts, U.S. Armed Forces installations and agricultural operations. The state has granted Hawaiian Electric, Hawaii Electric Light and Maui Electric nonexclusive franchises, which authorize the Utilities to construct, operate and maintain facilities over and under public streets and sidewalks. Each of these franchises will continue in effect for an indefinite period of time until forfeited, altered, amended or repealed.

Sales of electricity.



Years ended December 31	2015			2014			2013
(dollars in thousands)	Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues
Hawaiian Electric	302,958	$	1,636,245	301,953	$	2,134,094	299,528	$	2,116,214
Hawaii Electric Light	84,309	343,843		83,421	420,647		82,637	430,272
Maui Electric	70,533	343,722		70,042	420,734		69,577	422,205
	457,800	$	2,323,810	455,416	$	2,975,475	451,742	$	2,968,691

* As of December 31.

Seasonality. Kilowatthour (KWH) sales of the Utilities follow a seasonal pattern, but they do not experience extreme seasonal variations due to extreme weather variations experienced by some electric utilities on the U.S. mainland. KWH sales in Hawaii tend to increase in the warmer, more humid months, probably as a result of increased demand for air conditioning.

Significant customers. The Utilities derived approximately 11%, 12% and 11% of their operating revenues in 2015, 2014 and 2013 respectively, from the sale of electricity to various federal government agencies.

Under the Energy Policy Act of 2005, the Energy Independence and Security Act of 2007 and/or executive orders: (1) federal agencies must establish energy conservation goals for federally funded programs, (2) goals were set to reduce federal agencies’ energy consumption by 3% per year up to 30% by fiscal year 2015 relative to fiscal year 2003, and (3) renewable energy goals were established for electricity consumed by federal agencies. Hawaiian Electric continues to work with various federal agencies to implement measures that will help them achieve their energy reduction and renewable energy objectives.

State of Hawaii and U.S. Department of Energy MOU. On September 15, 2014, the State of Hawaii and the U.S. Department of Energy executed a Memorandum of Understanding (MOU) recognizing that Hawaii is embarking on the next phase of its clean energy future. The MOU provides the framework for a comprehensive, sustained effort to better realize its vast renewable energy potential and allow Hawaii to push forward in three main areas: the power sector, transportation and energy efficiency. This next phase will focus on stimulating deployment of clean energy infrastructure as a catalyst for economic growth, energy system innovation and test bed investments.

The PUC issued a decision and order (D&O) on January 3, 2012 approving a framework for Energy Efficiency Portfolio Standards (EEPS) that set 2008 as the initial base year for evaluation and linearly allocated the 2030 goal to interim incremental reduction goals of 1,375 GWH by 2015 and 975 GWH by each of the years 2020, 2025 and 2030. These goals may be revised through goal evaluations scheduled every five years or as the result of recommendations by an EEPS technical working group (TWG) for consideration by the PUC. The interim and final reduction goals will be allocated among contributing entities by the EEPS TWG. The PUC may establish penalties in the future for failure to meet the goals. Another of the initiatives under the Energy Agreement was advanced when the PUC approved the implementation of revenue decoupling for the Utilities under which they are allowed to recover PUC-approved revenue requirements that are not based on the amount of electricity sold. Both the EEPS and the implementation of revenue decoupling could have an impact on sales.

The statewide Energy Efficiency Potential Study issued in December 2013 indicated that Hawaii was on track to meet the 2015 interim EEPS target, and that available untapped energy efficiency resources in Hawaii exceed the EEPS goal of 4,300 GWH. The PUC convened a meeting of the EEPS Technical Working Group in January 2014 to review the results of the statewide Energy Efficiency Potential Study. Although the results of the potential study indicate that available untapped energy efficiency resources in Hawaii exceed the overall goal, no changes were made to the goals or Framework that govern the achievement of EEPS. Neither HEI nor Hawaiian Electric management can predict with certainty the impact of these or other governmental mandates or the September 2014 MOU on HEI’s or Hawaiian Electric’s future results of operations, financial condition or liquidity.

Selected consolidated electric utility operating statistics.



Years ended December 31	2015		2014		2013		2012		2011
KWH sales (millions)
Residential	2,396.5		2,379.7		2,450.9		2,582.0		2,769.7
Commercial	2,977.8		3,022.0		3,105.9		3,074.4		3,203.8
Large light and power	3,532.9		3,524.5		3,462.7		3,499.8		3,503.4
Other	49.3		50.0		50.0		49.8		50.0
	8,956.5		8,976.2		9,069.5		9,206.0		9,526.9
KWH net generated and purchased (millions)
Net generated	5,124.5		5,131.3		5,352.0		5,601.7		6,022.2
Purchased	4,308.3		4,306.7		4,195.2		4,093.2		4,009.7
	9,432.8		9,438.0		9,547.2		9,694.9		10,031.9
Losses and system uses (%)	4.8		4.7		4.8		4.8		4.8
Energy supply (December 31)
Net generating capability—MW	1,669		1,787		1,787		1,787		1,787
Firm purchased capability—MW	551		575		567		545		540
Other purchased capability—MW	4		—		—		—		—
	2,224		2,362		2,354		2,332		2,327
Net peak demand—MW¹	1,610		1,554		1,535		1,535		1,530
Btu per net KWH generated	10,632		10,613		10,570		10,533		10,609
Average fuel oil cost per Mbtu (cents)	1,206.5		2,087.6		2,103.2		2,210.4		1,986.7
Customer accounts (December 31)
Residential	400,655		398,256		394,910		392,025		390,133
Commercial	54,878		54,924		54,616		54,005		53,904
Large light and power	659		596		556		577		567
Other	1,608		1,640		1,660		1,636		1,625
	457,800		455,416		451,742		448,243		446,229
Electric revenues (thousands)
Residential	$	709,886	$	879,605	$	892,438	$	952,159	$	946,653
Commercial	798,202		1,027,588		1,044,166		1,060,983		1,024,725
Large light and power	802,366		1,051,119		1,015,079		1,062,226		976,949
Other	13,356		17,163		17,008		17,392		16,172
	$	2,323,810	$	2,975,475	$	2,968,691	$	3,092,760	$	2,964,499
Average revenue per KWH sold (cents)	25.90		33.15		32.73		33.60		31.12
Residential	29.62		36.93		36.41		36.88		34.18
Commercial	26.81		34.00		33.62		34.51		31.99
Large light and power	22.71		29.82		29.31		30.35		27.89
Other	27.05		34.36		34.02		34.93		32.37
Residential statistics
Average annual use per customer account (KWH)	5,996		6,000		6,220		6,596		7,117
Average annual revenue per customer account	$	1,776	$	2,218	$	2,265	$	2,432	$	2,433
Average number of customer accounts	399,674		396,640		394,024		391,437		389,160


¹	Sum of the net peak demands on all islands served, noncoincident and nonintegrated.

Generation statistics. The following table contains certain generation statistics as of and for the year ended December 31, 2015. The net generating and firm purchased capability available for operation at any given time may be more or less than shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.



	Island of Oahu- Hawaiian Electric			Island of Hawaii- Hawaii Electric Light		Island of Maui- Maui Electric		Island of Lanai- Maui Electric		Island of Molokai- Maui Electric		Total
Net generating and firm purchased capability (MW) as of December 31, 2015¹
Conventional oil-fired steam units	999.5			49.4		35.9		—		—		1,084.8
Diesel	8.0		²	27.0		96.8		10.1		9.6		151.5
Combustion turbines (peaking units)	214.8			—		—		—		—		214.8
Other combustion turbines	—			46.3		—		—		2.2		48.5
Combined-cycle unit	—			56.3		113.6		—		—		169.9
Firm contract power³	456.5			94.6		—		—		—		551.1
Other purchased capability⁵	—			—		4.0		—		—		4.0
	1,678.8			273.6		250.3		10.1		11.8		2,224.6

Net peak demand (MW)	1,206.0			191.5		202.2		5.1		5.6		1,610.4		⁴
Reserve margin	39.2	%		42.9	%	24.3	%	98.0	%	110.7	%	40.4	%
Annual load factor	67.1	%		68.2	%	64.6	%	60.5	%	64.1	%	66.9	%
KWH net generated and purchased (millions)	7,086.1			1,143.3		1,144.9		27.0		31.5		9,432.8


¹	Hawaiian Electric units at normal ratings; Maui Electric and Hawaii Electric Light units at reserve ratings.


²	Airport Dispatchable Standby Generation 8 MW.


³	Nonutility generators— Hawaiian Electric: 208 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired), and 68.5 MW (HPower, refuse-fired); Hawaii Electric Light: 34.6 MW (Puna Geothermal Venture, geothermal) and 60 MW (Hamakua Energy Partners, L.P., oil-fired).


⁴	Noncoincident and nonintegrated.


⁵	In October 2015, the PPA between Maui Electric and HC&S was amended, changing the pricing structure and rates for energy and eliminated the capacity payment to Hawaiian Commercial & Sugar Company (HC&S) and Maui Electric's minimum purchase obligation. Maui Electric may still request up to 4 MW of scheduled energy during certain months and may be provided up to 16 MW of emergency power.

Generating reliability and reserve margin. Hawaiian Electric serves the island of Oahu and Hawaii Electric Light serves the island of Hawaii. Maui Electric has three separate electrical systems—one each on the islands of Maui, Molokai and Lanai. Hawaiian Electric, Hawaii Electric Light and Maui Electric have isolated electrical systems that are not currently interconnected to each other or to any other electrical grid and, thus, each maintains a higher level of reserve generation than is typically carried by interconnected mainland U.S. utilities, which are able to share reserve capacity. These higher levels of reserve margins are required to meet peak electric demands, to provide for scheduled maintenance of generating units (including the units operated by IPPs relied upon for firm capacity) and to allow for the forced outage of the largest generating unit in the system.

See “Adequacy of supply” in HEI’s MD&A under “Electric utility.”

Nonutility generation. The Company has supported state and federal energy policies which encourage the development of renewable energy sources that reduce the use of fuel oil as well as the development of qualifying facilities. The Company’s renewable energy sources and potential sources range from wind, solar, photovoltaic, geothermal, wave and hydroelectric power to energy produced by the burning of bagasse (sugarcane waste), municipal waste and other biofuels.

The rate schedules of the electric utilities contain ECACs and PPACs that allow them to recover costs of fuel and purchase power expenses. The PUC approved the PPACs for the first time for Hawaiian Electric, Hawaii Electric Light and Maui Electric in March 2011, February 2012 and May 2012, respectively.

In addition to the firm capacity PPAs described below, the electric utilities also purchase energy on an as-available basis directly from nonutility generators and through its Feed-In Tariff programs. The electric utilities also receive renewable energy from customers under its Net Energy Metering programs.

The PUC has allowed rate recovery for the firm capacity and purchased energy costs for the electric utilities’ approved firm capacity and as-available energy PPAs.

Hawaiian Electric firm capacity PPAs. Hawaiian Electric currently has three major PPAs that provide a total of 456.5 MW of firm capacity, representing 27% of Hawaiian Electric’s total net generating and firm purchased capacity on Oahu as of December 31, 2015. In March 1988, Hawaiian Electric entered into a PPA with AES Barbers Point, Inc. (now known as AES Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended (through Amendment No. 2), provides that, for a period of 30 years beginning September 1992, Hawaiian Electric will purchase 180 megawatts (MW) of firm capacity. The AES Hawaii 180 MW coal-fired cogeneration plant utilizes a “clean coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). 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, extend the PPA term until September 2032, and amend the energy pricing formula in the PPA. The PUC approved the exemption in April 2013. In November 2015, Hawaiian Electric entered into Amendment No. 3 to the PPA, subject to PUC approval. See “Commitments and contingencies, Power purchase agreements, AES Hawaii, Inc.” in Note 4 to the Consolidated Financial Statements.

In October 1988, Hawaiian Electric entered into an agreement with Kalaeloa Partners, L.P. (Kalaeloa), a limited partnership, which, through affiliates, contracted to design, build, operate and maintain a QF. The agreement with Kalaeloa, as amended, provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991 and terminating in May 2016. The Kalaeloa facility is a combined-cycle operation, consisting of two oil-fired combustion turbines burning low sulfur fuel oil (LSFO) and a steam turbine that utilizes waste heat from the combustion turbines. Following two additional amendments, effective in 2005, Kalaeloa currently supplies Hawaiian Electric with 208 MW of firm capacity. In January 2011, Hawaiian Electric initiated renegotiation of the agreement with Kalaeloa (exempt from the PUC’s Competitive Bidding Framework).

Hawaiian Electric also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 with the City and County of Honolulu with respect to a refuse-fired plant (HPower). Under the amended PPA, the HPower facility supplied Hawaiian Electric with 46 MW of firm capacity. In May 2012, Hawaiian Electric entered into an amended and restated PPA with the City and County of Honolulu to purchase additional firm capacity (including the then existing 46 MW) from the expanded HPower facility for a term of 20 years from the commercial operation date (April 2, 2013). Under the amended and restated PPA, which the PUC approved, Hawaiian Electric purchases 68.5 MW of firm capacity.

Hawaii Electric Light and Maui Electric firm capacity PPAs. As of December 31, 2015, Hawaii Electric Light has PPAs for 119.5 MW (of which 94.6 MW are currently available, 3.4 MW are pending and 21.5 MW are expected to be added in 2016) and Maui Electric has a PPA for up to 4 MW of scheduled energy and up to 16 MW of emergency power.

Hawaii Electric Light has a 35-year PPA with Puna Geothermal Venture (PGV) for 30 MW of firm capacity from its geothermal steam facility, which will expire on December 31, 2027. In February 2011, Hawaii Electric Light and PGV amended the PPA for the pricing on a portion of the energy payments and entered into a new PPA for Hawaii Electric Light to acquire an additional 8 MW of firm, dispatchable capacity. The PUC approved the amendment and the new PPA in December 2011. PGV’s expansion became commercially operational in March 2012 for a total facility capacity of 34.6 MW.

In October 1997, Hawaii Electric Light entered into an agreement with Encogen, which has been succeeded by Hamakua Energy Partners, L. P. (HEP). The agreement requires Hawaii Electric Light to purchase up to 60 MW (net) of firm capacity for a period of 30 years, expiring on December 31, 2030. The dual-train combined-cycle DTCC facility, which primarily burns naphtha, consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines. In December 2015, Hawaii Electric Light signed an agreement to purchase the 60 MW HEP generating plant, subject to PUC approval. In February 2016, Hawaii Electric Light and Hawaiian Electric filed an application with the PUC requesting approval of Hawaii Electric Light’s purchase of the HEP Facility, the parties’ proposed financing plan, the recovery of revenue requirements for the plant additions associated with the purchase through Hawaii Electric Light’s Decoupling Rate Adjustment Mechanism above the RAM Cap, the inclusion of the costs under certain fuel contracts through Hawaii Electric Light’s ECAC and termination of the existing PPA.

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, has failed to meet its current obligations under the PPA and failed to provide adequate assurances that it can perform or has the financial means to perform. Absent compelling changes in circumstances, Hawaii Electric Light currently intends to terminate the PPA effective March 1, 2016.

Maui Electric had a PPA with HC&S for 16 MW of firm capacity. Subsequently, HC&S decreased firm capacity to 8 MW effective January 1, 2015. In October 2015, following PUC approval, an amended PPA between Maui Electric and HC&S became effective, which changed the pricing structure and rates for energy sold to Maui Electric, eliminated the capacity payment to HC&S and Maui Electric’s minimum purchase obligation, provided 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 extended the term of the PPA from 2014 to 2017. The HC&S generating units primarily burn bagasse (sugar cane waste) along with secondary fuels of diesel oil or coal. In January 2016, HC&S announced it will discontinue the growing and harvesting of sugar cane, and provided Maui Electric with a notice of termination of the amended PPA effective January 6, 2017 since it will discontinue the growing and harvesting of sugar cane.

Fuel oil usage and supply. The rate schedules of the Company’s electric utility subsidiaries include ECACs under which electric rates (and consequently the revenues of the electric utility subsidiaries generally) are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. See discussion of rates and issues relating to the ECAC below under “Rates,” and “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates” and “Electric utility—Material estimates and critical accounting policies–Revenues” in HEI’s MD&A.

Hawaiian Electric’s steam generating units consume LSFO and Hawaiian Electric’s combustion turbine peaking units consume diesel fuel (diesel), except for CIP CT-1 which operates exclusively on B99 grade biodiesel. A Hawaiian Electric steam unit has successfully completed a co-firing project to test burn mixtures of LSFO and biofuel.

Maui Electric’s and Hawaii Electric Light’s steam generating units burn medium sulfur fuel oil (MSFO) and Hawaii Electric Light’s and Maui Electric’s Maui combustion turbine generating units burn diesel. Hawaii Electric Light’s and Maui Electric’s Maui, Molokai and Lanai diesel engine generating units burn ultra-low-sulfur diesel and biodiesel. A Maui Electric diesel generating unit has successfully completed a biodiesel test fire project.

See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 4 of the Consolidated Financial Statements.

The following table sets forth the average cost of fuel oil used by Hawaiian Electric, Hawaii Electric Light and Maui Electric to generate electricity in 2015, 2014 and 2013:



	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
2015	71.86	1,144.8	79.03	1,307.3	84.38	1,425.7	74.71	1,206.5
2014	130.71	2,075.4	121.49	2,002.5	130.51	2,198.9	129.65	2,087.6
2013	130.85	2,068.2	125.81	2,064.7	135.57	2,286.3	131.10	2,103.2

The average per-unit cost of fuel oil consumed to generate electricity for Hawaiian Electric, Hawaii Electric Light and Maui Electric reflects a different volume mix of fuel types and grades as follows:



	Hawaiian Electric				Hawaii Electric Light				Maui Electric
	LSFO		Diesel/Biodiesel		MSFO		Diesel		MSFO		Diesel/Biodiesel
2015	96	%	4	%	43	%	57	%	16	%	84	%
2014	97		3		47		53		20		80
2013	98		2		53		47		18		82

In December 2000, Hawaii Electric Light and Maui Electric executed contracts of private carriage with Hawaiian Interisland Towing, Inc. for the employment of a double-hull tank barge for the shipment of MSFO and diesel supplies from their fuel suppliers’ facilities on Oahu to storage locations on the islands of Hawaii and Maui, respectively, commencing January 1, 2002. The contracts have been extended through December 31, 2016. In July 2011, the carriage contracts were assigned to Kirby Corporation (Kirby), which provides refined petroleum and other products for marine transportation, distribution and logistics services in the U.S. domestic marine transportation industry.

Kirby never takes title to the fuel oil or diesel fuel, but does have custody and control while the fuel is in transit from Oahu. If there were an oil spill in transit, Kirby is generally contractually obligated to indemnify Hawaii Electric Light and/or Maui Electric for resulting clean-up costs, fines and damages. Kirby maintains liability insurance coverage for an amount in excess of $1 billion for oil spill related damage. State law provides a cap of $700 million on liability for releases of heavy fuel oil transported interisland by tank barge. In the event of a release, Hawaii Electric Light and/or Maui Electric may be responsible for any clean-up, damages, and/or fines that Kirby and its insurance carrier do not cover.

The prices that Hawaiian Electric, Hawaii Electric Light and Maui Electric pay for purchased energy from certain older nonutility generators are generally linked to the price of oil. The AES Hawaii energy prices vary primarily with an inflation index. The energy prices for Kalaeloa, which purchases LSFO from Hawaii Independent Energy (formerly Tesoro Hawaii Corporation), vary primarily with the price of Asian crude oil. A portion of PGV energy prices are based on the electric utilities’ respective short-run avoided energy cost rates (which vary with their composite fuel costs), subject to minimum floor rates specified in their approved PPA. HEP energy prices vary primarily with Hawaii Electric Light’s diesel costs.

The Utilities estimate that 67% of the net energy they generate or purchase will come from fossil fuel oil in 2016 compared to 70% in 2015. Hawaiian Electric generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. Hawaii Electric Light and Maui Electric generally maintain an average system fuel inventory level equivalent to approximately one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and HEP require that they maintain certain minimum fuel inventory levels.

Rates. Hawaiian Electric, Hawaii Electric Light and Maui Electric are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation” below.

Rate schedules of Hawaiian Electric and its subsidiaries contain ECACs and PPACs. Under current law and practices, specific and separate PUC approval is not required for each rate change pursuant to automatic rate adjustment clauses previously approved by the PUC. All other rate increases require the prior approval of the PUC after public and contested case hearings. PURPA requires the PUC to periodically review the ECACs of electric and gas utilities in the state, and such clauses, as well as the rates charged by the utilities generally, are subject to change.

See “Electric utility–Most recent rate proceedings, “Electric utility–Certain factors that may affect future results and financial condition–Regulation of electric utility rates” and “Electric utility–Material estimates and critical accounting policies–Revenues” in HEI’s MD&A and “Interim increases” and “Utility projects” under “Commitments and contingencies” in Note 4 of the Consolidated Financial Statements.

Public Utilities Commission and Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii. Randall Y. Iwase is the Chair of the PUC (for a term that will expire in June 2020) and was formerly a state legislator, Honolulu city council member, supervising deputy attorney general, and Chair of the Hawaii State Tax Review Commission. The other commissioners are Michael E. Champley (for a term that will expire in June 2016), who previously was a senior energy consultant and a senior executive with DTE Energy, and Lorraine H. Akiba (for a term that will expire in June 2018), who previously was an attorney in private practice who earlier served as the Director of the State Department of Labor and Industrial Relations.

The Executive Director of the Division of Consumer Advocacy is Jeffrey T. Ono, previously an attorney in private practice.

Competition. See “Electric utility–Certain factors that may affect future results and financial condition–Competition” in HEI’s MD&A.

Electric and magnetic fields. The generation, transmission and use of electricity produces low-frequency (50Hz-60Hz) electrical and magnetic fields (EMF). While EMF has been classified as a possible human carcinogen by more than one public health organization and remains the subject of ongoing studies and evaluations, no definite causal relationship between EMF and health risks has been clearly demonstrated to date and there are no federal standards in the U.S. limiting occupational or residential exposure to 50Hz-60Hz EMF. The Utilities are continuing to monitor the ongoing research and continue to participate in utility industry funded studies on EMF and, where technically feasible and economically reasonable, continue to pursue a policy of prudent avoidance in the design and installation of new transmission and distribution facilities. Management cannot predict the impact, if any, the EMF issue may have on the Utilities in the future.

Global climate change and greenhouse gas (GHG) emissions reduction. The Company shares the concerns of many regarding the potential effects of global climate changes and the human contributions to this phenomenon, including burning of fossil fuels for electricity production, transportation, manufacturing and agricultural activities, as well as deforestation. Recognizing that effectively addressing global climate changes requires commitment by the private sector, all levels of government, and the public, the Company is committed to taking direct action to mitigate GHG emissions from its operations. See “Environmental regulation–Global climate change and greenhouse gas emissions reduction” under “Commitments and contingencies” in Note 4 of the Consolidated Financial Statements.

Legislation. See “Electric utility–Legislation and regulation” in HEI’s MD&A.

Commitments and contingencies. See “Selected contractual obligations and commitments” in Hawaiian Electric’s MD&A and “Electric utility–Certain factors that may affect future results and financial condition–Other regulatory and permitting

contingencies” in HEI’s MD&A, Item 1A. Risk Factors, and Note 4 of the Consolidated Financial Statements for a discussion of important commitments and contingencies.

Regulation. The PUC regulates the rates, issuance of securities, accounting and certain other aspects of the operations of Hawaiian Electric and its electric utility subsidiaries. See the previous discussion under “Rates” and the discussions under “Electric utility–Results of operations–Most recent rate proceedings” and “Electric utility–Certain factors that may affect future results and financial condition–Regulation of electric utility rates” in HEI’s MD&A.

Any adverse decision or policy made or adopted by the PUC, or any prolonged delay in rendering a decision, could have a material adverse effect on consolidated Hawaiian Electric’s and the Company’s results of operations, financial condition or liquidity.

In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger. See “PUC application” in Note 2 to the Consolidated Financial Statements

On September 15, 2014, the State of Hawaii and the U.S. Department of Energy executed a MOU recognizing that Hawaii is embarking on the next phase of its clean energy future. The MOU provides the framework for a comprehensive, sustained effort to better realize Hawaii's vast renewable energy potential and allow it to push forward in three main areas: the power sector, transportation and energy efficiency. This next phase will focus on stimulating deployment of clean energy infrastructure as a catalyst for economic growth, energy system innovation and test bed investments.

In 2015, Hawaii’s RPS law was amended to require 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 energy efficiency programs do not count toward the RPS since 2014 (only electrical generation using renewable energy as a source counts).

Certain transactions between HEI’s electric public utility subsidiaries (Hawaiian Electric, Hawaii Electric Light and Maui Electric) and HEI and affiliated interests (as defined by statute) are subject to regulation by the PUC. All contracts of $300,000 or more in a calendar year for management, supervisory, construction, engineering, accounting, legal, financial and similar services and for the sale, lease or transfer of property between a public utility and affiliated interests must be filed with the PUC to be effective, and the PUC may issue cease and desist orders if such contracts are not filed. All such “affiliated contracts” for capital expenditures (except for real property) must be accompanied by comparative price quotations from two nonaffiliates, unless the quotations cannot be obtained without substantial expense. Moreover, all transfers of $300,000 or more of real property between a public utility and affiliated interests require the prior approval of the PUC and proof that the transfer is in the best interest of the public utility and its customers. If the PUC, in its discretion, determines that an affiliated contract is unreasonable or otherwise contrary to the public interest, the utility must either revise the contract or risk disallowance of payments under the contract for rate-making purposes. In rate-making proceedings, a utility must also prove the reasonableness of payments made to affiliated interests under any affiliated contract of $300,000 or more by clear and convincing evidence.

In December 1996, the PUC issued an order in a docket that had been opened to review the relationship between HEI and Hawaiian Electric and the effects of that relationship on the operations of Hawaiian Electric. The order adopted the report of the consultant the PUC had retained and ordered Hawaiian Electric to continue to provide the PUC with periodic status reports on its compliance with the PUC Agreement (pursuant to which HEI became the holding company of Hawaiian Electric). Hawaiian Electric files such status reports annually. In the order, the PUC also required the Utilities to present a comprehensive analysis of the impact that the holding company structure and investments in nonutility subsidiaries have on a case-by-case basis on the cost of capital to each utility in future rate cases and remove any such effects from the cost of capital. The Utilities have made presentations in their subsequent rate cases to support their positions that there was no evidence that would modify the PUC’s finding that Hawaiian Electric’s access to capital did not suffer as a result of HEI’s involvement in nonutility activities and that HEI’s diversification did not permanently raise or lower the cost of capital incorporated into the rates paid by Hawaiian Electric’s utility customers.

The Utilities are not subject to regulation by the FERC under the Federal Power Act, except under Sections 210 through 212 (added by Title II of PURPA and amended by the Energy Policy Act of 1992), which permit the FERC to order electric utilities to interconnect with qualifying cogenerators and small power producers, and to wheel power to other electric utilities. Title I of PURPA, which relates to retail regulatory policies for electric utilities, and Title VII of the Energy Policy Act of 1992, which addresses transmission access, also apply to the Utilities. The Utilities are also required to file various operational reports with the FERC.

Because they are located in the State of Hawaii, Hawaiian Electric and its subsidiaries are exempt by statute from limitations set forth in the Powerplant and Industrial Fuel Use Act of 1978 on the use of petroleum as a primary energy source.

See also “HEI–Regulation” above.

Environmental regulation. Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, are subject to periodic inspections by federal, state and, in some cases, local environmental regulatory agencies, including agencies responsible for the regulation of water quality, air quality, hazardous and other waste and hazardous materials. These inspections may result in the identification of items needing corrective or other action. Except as otherwise disclosed in this report (see “Certain factors that may affect future results and financial condition–Environmental matters” for HEI Consolidated, the Electric utility and the Bank sections in HEI’s MD&A and Note 4 of the Consolidated Financial Statements, which are incorporated herein by reference), the Company believes that each subsidiary has appropriately responded to environmental conditions requiring action and that, as a result of such actions, such environmental conditions will not have a material adverse effect on the Company or Hawaiian Electric.

Water quality controls. The generating stations, substations and other utility facilities operate under federal and state water quality regulations and permits, including but not limited to the Clean Water Act National Pollution Discharge Elimination System (governing point source discharges, including wastewater and storm water discharges), Underground Injection Control (regulating disposal of wastewater into the subsurface), the Spill Prevention, Control and Countermeasure (SPCC) program, the Oil Pollution Act of 1990 (OPA) (governing actual or threatened oil releases and imposing strict liability on responsible parties for clean-up costs and damages to natural resources and property), and other regulations associated with discharges of oil and other substances to surface water. The federal Environmental Protection Agency (EPA) regulations under OPA also require certain facilities that use or store petroleum to prepare and implement SPCC Plans in order to prevent releases of petroleum to navigable waters of the U.S. The Utilities' facilities that are subject to SPCC Plan requirements, including most power plants, base yards, and certain substations, have prepared and are implementing SPCC Plans.

In 2014 and 2015, the Utilities did not experience any significant petroleum releases. The Company believes that each subsidiary’s costs of responding to petroleum releases to date will not have a material adverse effect on the respective subsidiary or the Company.

Air quality controls. The Clean Air Act (CAA) amendments of 1990, among other things, established the federal Title V Operating Permit Program (in Hawaii known as the Covered Source Permit program) and greatly expanded the regulatory requirements for monitoring and controlling hazardous air pollutants from mission sources. Under Title V, more stringent National Ambient Air Quality Standards (NAAQS) affect new or modified generating units by requiring a permit to construct under the CAA Prevention of Significant Deterioration (PSD) program and the controls necessary to meet the NAAQS.

Title V operating permits have been issued for all of the Utilities’ affected generating units.

Hazardous waste and toxic substances controls. The operations of the electric utility and former freight transportation subsidiaries of HEI are subject to EPA regulations that implement provisions of the Resource Conservation and Recovery Act (RCRA), the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA, also known as Superfund), the Superfund Amendments and Reauthorization Act (SARA), and the Toxic Substances Control Act (TSCA).

RCRA underground storage tank (UST) regulations require all facilities that use USTs for storing petroleum products to comply with established leak detection, spill prevention, standards for tank design and retrofits, financial assurance, and tank decommissioning and closure requirements. All of the Utilities’ USTs currently meet the applicable requirements.

The Emergency Planning and Community Right-to-Know Act under SARA Title III requires the Utilities to report potentially hazardous chemicals present in their facilities in order to provide the public with information so that emergency procedures can be established to protect the public in the event of hazardous chemical releases. All of the Utilities' facilities are in compliance with applicable annual reporting requirements to the State Emergency Planning Commission, the Local Emergency Planning Committee and local fire departments. Since January 1, 1998, the steam electric industry category has been subject to Toxics Release Inventory (TRI) reporting requirements. All of the Utilities' facilities are in compliance with TRI reporting requirements.

The TSCA regulations specify procedures for the handling and disposal of polychlorinated biphenyls (PCBs), a compound found in some transformer and capacitor dielectric fluids. The TSCA regulations also apply to responses to releases of PCBs to the environment. The Utilities have instituted procedures to monitor compliance with these regulations and have implemented a program to identify and replace PCB transformers and capacitors in their systems. Management believes that all of the Utilities' facilities are currently in compliance with PCB regulations. In April 2010, the EPA issued an Advance Notice of Proposed Rule Making announcing its intent to reassess PCB regulations. The EPA projects that it will publish a notice of proposed rule making in March 2016.

Hawaii’s Environmental Response Law, as amended (ERL), governs releases of hazardous substances, including oil, to the environment in areas within the state’s jurisdiction. Responsible parties under the ERL are jointly, severally, and strictly liable for a release of a hazardous substance. Responsible parties include owners or operators of a facility where a hazardous

substance is located and any person who at the time of disposal of the hazardous substance owned or operated any facility at which such hazardous substance was disposed.

The Utilities periodically identify leaking petroleum-containing equipment such as USTs, piping, and transformers. In a few instances, small amounts of PCBs have been identified in the leaking equipment. Each subsidiary reports releases from such equipment when and as required by applicable law and addresses in all material respects impacts due to the releases in compliance with applicable regulatory requirements.

Research and development. The Utilities expensed approximately $3.3 million, $2.9 million and $3.4 million in 2015, 2014 and 2013, respectively, for research and development (R&D). In 2015, 2014 and 2013, the electric utilities’ contributions to the Electric Power Research Institute accounted for approximately 67%, 76% and 64% of R&D expenses, respectively. Included in the R&D expenses were amounts related to new and emerging technologies, biofuels, energy storage, demand response, environmental compliance, power quality, electric and hybrid plug in vehicles and other renewables (e.g., integration of distributed energy resources onto the utility grid, grid modernization, solar resource evaluation, advanced inverter testing, and modeling of high PV penetration circuits).

Additional information. For additional information about Hawaiian Electric, see Hawaiian Electric’s MD&A, Hawaiian Electric’s “Quantitative and Qualitative Disclosures about Market Risk” and Hawaiian Electric’s Consolidated Financial Statements.

Properties. Hawaiian Electric owns and operates four generating plants on the island of Oahu at Honolulu, Waiau, Kahe and Campbell Industrial Park (CIP). These plants have an aggregate net generating capability of 1,214 MW as of December 31, 2015. Hawaiian Electric's generating plant in Honolulu was deactivated in 2014, and the City and County of Honolulu is seeking to condemn a portion of the plant site for its rail project. The four plants are situated on Hawaiian Electric-owned land having a combined area of 535 acres and three parcels of land totaling 5.5 acres under leases expiring between June 30, 2016 and December 31, 2018, with options to extend to June 30, 2026. In addition, Hawaiian Electric owns a total of 132 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located.

Hawaiian Electric owns buildings and approximately 11.6 acres of land located in Honolulu which house its operating and engineering departments. It also leases an office building and certain office spaces in Honolulu, and a warehousing center in Kapolei. The lease for the office building expires in November 2021, with an option to extend through November 2024. Leases for certain office and warehouse spaces expire on various dates from March 31, 2016 through July 31, 2025, some with options to extend to various dates through December 31, 2034.

Hawaiian Electric's Barbers Point Tank Farm (BPTF) has three storage tanks with an aggregate of 1 million barrels of storage for LSFO. The BPTF is located in Campbell Industrial Park, on the same property as the CIP Generating Station, and is the central fuel storage facility where LSFO purchased by Hawaiian Electric is received and stored. From the BPTF, LSFO is transported via Hawaiian Electric owned underground pipelines to the Kahe and Waiau Power Plants. Hawaiian Electric also has fuel storage facilities at each of its plant sites with a nominal aggregate capacity of 770,000 barrels for LSFO storage, 44,000 barrels for diesel storage, and 88,000 barrels for biodiesel storage. Hawaiian Electric also owns a fuel storage facility at Iwilei that was used to provide fuel to the Honolulu Power Plant. The Honolulu Power Plant was deactivated on January 31, 2014 and any future fuel supplies will be delivered directly to the plant by truck. The Iwilei fuel storage facility's tanks and pumping infrastructure are being removed, and the facility is being reconfigured for other purposes.

Hawaii Electric Light owns and operates four generating plants on the island of Hawaii in Hilo, Waimea, Keahole and Puna, along with distributed generators at substation sites. These plants have an aggregate net generating capability of 179 MW as of December 31, 2015 (excluding several small run-of-river hydro units). Hawaii Electric Light's Shipman plant in Hilo was deactivated in 2014 and retired in 2015. The plants (including a baseyard on the same parcel as the Hilo plant) are situated on Hawaii Electric Light-owned land having a combined area of approximately 44 acres. The distributed generators are located within Hawaii Electric Light-owned substation sites having a combined area of approximately 4 acres. Hawaii Electric Light also owns fuel storage facilities at these sites with a usable storage capacity of 48,000 barrels of bunker oil and 81,802 barrels of diesel. There are an additional 19,200 barrels of diesel and 22,770 barrels of bunker oil storage capacity for Hawaii Electric Light-owned fuel off-site at Chevron Products Company (Chevron)-owned terminalling facilities. Hawaii Electric Light pays a storage fee to Chevron and has no other interest in the property, tanks or other infrastructure situated on Chevron’s property. Hawaii Electric Light also owns 6 acres of land in Kona, which is used for a baseyard, and one acre of land in Hilo, which houses its accounting, customer services and administrative offices. Hawaii Electric Light also leases 3.7 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addition, Hawaii Electric Light owns a total of approximately 100 acres of land, and leases a total of approximately 8.5 acres of land, on which hydro facilities, substations and switching stations, microwave facilities, and transmission lines are located. The deeds to the sites located in Hilo contain certain restrictions, but the restrictions do not materially interfere with the use of the sites for public utility purposes.

Maui Electric owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 244.3 MW as of December 31, 2015. The plants are situated on Maui Electric-owned land having a combined area of 28.6 acres. Maui Electric’s administrative offices and engineering and distribution departments are located on 9.1 acres of Maui Electric-owned land in Kahului. Maui Electric also owns fuel oil storage facilities at these sites with a total maximum usable capacity of 81,272 barrels of bunker oil, and 94,586 barrels of diesel. There are an additional 56,358 barrels of diesel oil storage capacity for Maui Electric-owned fuel off-site at Aloha Petroleum, Ltd. (Aloha Petroleum)-owned terminalling facilities and 5,000 barrels of diesel oil storage capacity for Maui Electric-owned fuel off-site at Chevron Products Company (Chevron)-owned terminalling facilities. Maui Electric pays storage fees to Aloha Petroleum and Chevron. Maui Electric owns two 1 MW stand-by diesel generators and a 6,000 gallon fuel storage tank located in Hana. Maui Electric owns 65.7 acres of undeveloped land at Waena. Most of this Waena land is currently used for agricultural purposes by the former landowner.

Maui Electric also owns and operates smaller distribution systems, generation systems (with an aggregate net capability of 21.9 MW as of December 31, 2015) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by Maui Electric.

Other properties. The Utilities own overhead transmission and distribution lines, underground cables, poles (some jointly) and metal high voltage towers. Electric lines are located over or under public and nonpublic properties. Lines are added when needed to serve increased loads and/or for reliability reasons. In some design districts on Oahu, lines must be placed underground. Under Hawaii law, the PUC generally must determine whether new 46 kilovolt (kV), 69 kV or 138 kV lines can be constructed overhead or must be placed underground.

See “Hawaiian Electric and subsidiaries and service areas” above for a discussion of the nonexclusive franchises of Hawaiian Electric and subsidiaries. Most of the leases, easements and licenses for Hawaiian Electric’s, Hawaii Electric Light’s and Maui Electric’s lines have been recorded.

See “Generation statistics” above and “Limited insurance” in HEI’s MD&A for a further discussion of some of the electric utility properties.

Bank

General. ASB was granted a federal savings bank charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & Loan Association of Salt Lake City, Utah. As of December 31, 2015, ASB was one of the largest financial institutions in the State of Hawaii based on total assets of $6.0 billion and deposits of $5.0 billion. In 2015, ASB’s revenues and net income amounted to approximately 10% and 34% of HEI’s consolidated revenues and net income, respectively, compared to approximately 8% and 31% in 2014 and approximately 8% and 36% in 2013, respectively.

At the time of HEI’s acquisition of ASB in 1988, HEI agreed with the OTS’ predecessor regulatory agency that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital to ensure that ASB would have the capital level required by the OTS was limited to a maximum aggregate amount of approximately $65.1 million. As of December 31, 2015, as a result of certain HEI contributions of capital to ASB, HEI’s maximum obligation under the agreement to contribute additional capital has been reduced to approximately $28.3 million. ASB is subject to OCC regulations on dividends and other distributions and ASB must receive a letter of non-objection from the OCC and FRB before it can declare and pay a dividend to HEI.

The following table sets forth selected data for ASB (average balances calculated using the average daily balances):



Years ended December 31	2015		2014		2013
Common equity to assets ratio
Average common equity divided by average total assets	9.53	%	9.87	%	9.88	%
Return on assets
Net income for common stock divided by average total assets	0.95		0.95		1.13
Return on common equity
Net income for common stock divided by average common equity	9.93		9.60		11.43

Asset/liability management. See HEI’s “Quantitative and Qualitative Disclosures about Market Risk.”

Consolidated average balance sheet and interest income and interest expense. See “Bank—Results of operations—Average balance sheet and net interest margin” in HEI’s MD&A.

The following table shows the effect on net interest income of (1) changes in interest rates (change in weighted-average interest rate multiplied by prior year average balance) and (2) changes in volume (change in average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a prorata basis.



	2015 vs. 2014									2014 vs. 2013
(in thousands)	Rate			Volume			Total			Rate			Volume			Total
Interest income
Other investments	$	188		$	(27	)	$	161		$	70		$	1		$	71
Securities purchased under resale agreements	(10		)	(10		)	(20		)	1			(24		)	(23		)
Available-for-sale investment securities
Taxable	(158		)	3,471			3,313			—			144			144
Non-taxable	(214		)	(215		)	(429		)	60			(2,125		)	(2,065		)
Total available-for-sale investment securities	(372		)	3,256			2,884			60			(1,981		)	(1,921		)
Loans
Residential 1-4 family	(2,451		)	1,793			(658		)	(5,112		)	2,410			(2,702		)
Commercial real estate	(1,831		)	4,485			2,654			(636		)	4,993			4,357
Home equity line of credit	(402		)	1,197			795			1,791			3,483			5,274
Residential land	(73		)	68			(5		)	111			(313		)	(202		)
Commercial	(552		)	540			(12		)	(2,106		)	2,212			106
Consumer	1,933			734			2,667			(113		)	(348		)	(461		)
Total loans	(3,376		)	8,817			5,441			(6,065		)	12,437			6,372
Total increase (decrease) in interest income	(3,570		)	12,036			8,466			(5,934		)	10,433			4,499
Interest expense
Savings	—			(123		)	(123		)	—			(82		)	(82		)
Interest-bearing checking	—			(13		)	(13		)	—			(20		)	(20		)
Money market	—			9			9			10			8			18
Time certificates	—			(144		)	(144		)	(48		)	147			99
Advances from Federal Home Loan Bank	—			—			—			459			(1,173		)	(714		)
Securities sold under agreements to repurchase	672			(919		)	(247		)	107			(139		)	(32		)
Total (increase) decrease in interest expense	672			(1,190		)	(518		)	528			(1,259		)	(731		)
Increase (decrease) in net interest income	$	(2,898	)	$	10,846		$	7,948		$	(5,406	)	$	9,174		$	3,768

See “Bank—Results of operations” in HEI’s MD&A for an explanation of significant changes in earning assets and costing liabilities.

Noninterest income. In addition to net interest income, ASB has various sources of noninterest income, including fee income from credit and debit cards, fee income from deposit liabilities, mortgage banking income and other financial products and services. See “Bank—Results of operations” in HEI’s MD&A for an explanation of significant changes in noninterest income.

Lending activities.

General. The following table sets forth the composition of ASB’s loans receivable held for investment:



December 31	2015				2014				2013				2012				2011
(dollars in thousands)	Balance			% of total	Balance			% of total	Balance			% of total	Balance			% of total	Balance			% of total
Real estate: ¹
Residential 1-4 family	$	2,069,665		44.8	$	2,044,205		46.0	$	2,006,007		48.2	$	1,866,450		49.2	$	1,926,774		52.2
Commercial real estate	690,561			14.9	531,917			12.0	440,443			10.6	375,677			9.9	331,931			9.0
Home equity line of credit	846,294			18.3	818,815			18.4	739,331			17.8	630,175			16.6	535,481			14.5
Residential land	18,229			0.4	16,240			0.4	16,176			0.4	25,815			0.7	45,392			1.2
Commercial construction	100,796			2.2	96,438			2.2	52,112			1.3	43,988			1.2	41,950			1.1
Residential construction	14,089			0.3	18,961			0.4	12,774			0.3	6,171			0.2	3,327			0.1
Total real estate	3,739,634			80.9	3,526,576			79.4	3,266,843			78.6	2,948,276			77.8	2,884,855			78.1
Commercial	758,659			16.4	791,757			17.8	783,388			18.8	721,349			19.0	716,427			19.4
Consumer	123,775			2.7	122,656			2.8	108,722			2.6	121,231			3.2	93,253			2.5
Total loans	4,622,068			100.0	4,440,989			100.0	4,158,953			100.0	3,790,856			100.0	3,694,535			100.0
Less: Deferred fees and discounts	(6,249		)		(6,338		)		(8,724		)		(11,638		)		(13,811		)
Allowance for loan losses	(50,038		)		(45,618		)		(40,116		)		(41,985		)		(37,906		)
Total loans, net	$	4,565,781			$	4,389,033			$	4,110,113			$	3,737,233			$	3,642,818


¹	Includes renegotiated loans.

The increase in the loans receivable balance in 2015 was primarily due to growth in commercial real estate, home equity lines of credit (HELOC) and residential 1-4 family loan portfolios, partly offset by a decrease in the commercial loan portfolio. The growth in the commercial real estate, HELOC and residential loan portfolios was driven by demand for this loan type and was consistent with ASB's loan growth strategy.

The increase in the loans receivable balance in 2014 was primarily due to growth in commercial real estate, HELOC, commercial construction and residential 1-4 family loan portfolios. The growth in the commercial real estate and commercial construction loan portfolios were driven by demand for these loan types as the Hawaii economy continues to improve. The growth in the HELOC and residential loan portfolios were consistent with ASB’s mix target and loan growth strategy.

The increase in the loans receivable balance in 2013 was primarily due to growth in the residential, HELOC, commercial and commercial real estate loan portfolios. The growth in these portfolios was consistent with ASB’s mix target and loan growth strategy.

The increase in the loans receivable balance in 2012 and 2011 was primarily due to growth in commercial, commercial real estate, consumer and HELOC loans as ASB targeted these portfolios because of their shorter duration and/or variable rates. Offsetting these 2012 and 2011 loan portfolio increases was a decrease in the residential loan portfolio. Although ASB produced nearly $1.0 billion of new, long-term residential loans in 2012, nearly double the level for 2011, it sold more than half those loans to control interest rate risk and repayments were also higher than in 2011.

The following table summarizes our loans receivable held for investment based upon contractually scheduled principal payments allocated to the indicated maturity categories:



December 31	2015
Due	In 1 year or less		After 1 year through 5 years		After 5 years		Total
(in millions)
Commercial – Fixed	$	47	$	119	$	18	$	184
Commercial – Adjustable	216		306		53		575
Total commercial	263		425		71		759
Commercial construction – Fixed	6		—		—		6
Commercial construction – Adjustable	30		65		—		95
Total commercial construction	36		65		—		101
Residential construction – Fixed	14		—		—		14
Residential construction – Adjustable	—		—		—		—
Total residential construction	14		—		—		14
Total loans – Fixed	67		119		18		204
Total loans – Adjustable	246		371		53		670
Total loans	$	313	$	490	$	71	$	874

Origination, purchase and sale of loans. Generally, residential and commercial real estate loans originated by ASB are collateralized by real estate located in Hawaii. For additional information, including information concerning the geographic distribution of ASB’s mortgage-related securities portfolio and the geographic concentration of credit risk, see Note 15 to the Consolidated Financial Statements. The demand for loans is primarily dependent on the Hawaii real estate market, business conditions, interest rates and loan refinancing activity.

Residential mortgage lending. ASB originates fixed rate and adjustable rate loans secured by single family residential property, including investor-owned properties, with maturities of up to 30 years. ASB’s general policy is to require private mortgage insurance when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For non-owner-occupied residential properties, the loan-to-value ratio may not exceed 80% of the lower of the appraised value or purchase price at origination.

Construction and development lending. ASB provides fixed rate loans for the construction of one-to-four unit residential and commercial properties. Construction loan projects are typically short term in nature. Construction and development financing generally involves a higher degree of credit risk than long-term financing on improved, occupied real estate. Accordingly, construction and development loans are generally priced higher than loans collateralized by completed structures. ASB’s underwriting, monitoring and disbursement practices with respect to construction and development financing are designed to ensure sufficient funds are available to complete construction projects. See “Loan portfolio risk elements” and “Multifamily residential and commercial real estate lending” below.

Multifamily residential and commercial real estate lending. ASB provides permanent financing and construction and development financing collateralized by multifamily residential properties (including apartment buildings) and collateralized by commercial and industrial properties (including office buildings, shopping centers and warehouses) for its own portfolio as well as for participation with other lenders. Commercial real estate lending typically involves long lead times to originate and fund. As a result, production results can vary significantly from period to period.

Consumer lending. ASB offers a variety of secured and unsecured consumer loans. Loans collateralized by deposits are limited to 90% of the available account balance. ASB offers home equity lines of credit, clean energy loans, secured and unsecured VISA cards (through a third party issuer), checking account overdraft protection and other general purpose consumer loans.

Commercial lending. ASB provides both secured and unsecured commercial loans to business entities. This lending activity is designed to diversify ASB’s asset structure, shorten maturities, improve rate sensitivity of the loan portfolio and attract commercial checking deposits. ASB offers commercial loans with terms up to ten years.

Loan origination fee and servicing income. In addition to interest earned on residential mortgage loans, ASB receives income from servicing loans, for late payments and from other related services. Servicing fees are received on loans originated and subsequently sold by ASB where ASB acts as collection agent on behalf of third-party purchasers.

ASB charges the borrower at loan settlement a loan origination fee. See “Loans receivable” in Note 1 of the Consolidated Financial Statements.

Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of real estate secured loans. In a foreclosure action, the property collateralizing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold. As of December 31, 2015, 2014 and 2013, ASB had $1.0 million, $0.9 million and $1.2 million, respectively, of real estate acquired in settlement of loans.

In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (troubled debt restructured loans). ASB loans that were 90 days or more past due on which interest was being accrued as of December 31, 2015, 2014, 2013, 2012 and 2011 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and troubled debt restructured loans:



December 31	2015		2014		2013		2012		2011
(dollars in thousands)
Nonaccrual loans—
Real estate
Residential 1-4 family	$	20,554	$	19,253	$	19,679	$	26,721	$	28,298
Commercial real estate	1,188		5,112		4,439		6,750		3,436
Home equity line of credit	2,254		1,087		2,060		2,349		2,258
Residential land	970		720		3,161		8,561		14,535
Residential construction	—		—		—		—		—
Total real estate	24,966		26,172		29,339		44,381		48,527
Commercial	20,174		10,053		18,781		20,222		17,946
Consumer	895		661		401		284		281
Total nonaccrual loans	$	46,035	$	36,886	$	48,521	$	64,887	$	66,754
Troubled debt restructured loans not included above—
Real estate
Residential 1-4 family	$	13,962	$	13,525	$	9,744	$	6,759	$	5,029
Commercial real estate	—		—		—		—		—
Home equity line of credit	2,467		480		171		—		—
Residential land	4,713		7,130		7,476		11,090		24,828
Total real estate	21,142		21,135		17,391		17,849		29,857
Commercial	1,104		2,972		1,649		43		15,386
Total troubled debt restructured loans	$	22,246	$	24,107	$	19,040	$	17,892	$	45,243

Impact of nonperforming loans on interest income. The following table presents the gross interest income for both nonaccrual and restructured loans that would have been recognized if such loans had been current in accordance with their original contractual terms, and had been outstanding throughout the period or since origination if held for only part of the period. The table also presents the interest income related to these loans that was actually recognized for the period.



(dollars in millions)	Year ended December 31, 2015
Gross amount of interest income that would have been recorded in accordance with original contractual terms, and had been outstanding throughout the period or since origination, if held for only part of the period¹	$	3
Interest income actually recognized	1
Total interest income foregone	$	2


¹	Based on the contractual rate that was being charged at the time the loan was restructured or placed on nonaccrual status.

In 2015, nonaccrual loans increased $9.1 million primarily due to higher nonaccrual commercial loans of $10.1 million. ASB evaluates a restructured loan transaction to determine if the borrower is in financial difficulty and if the restructured terms are considered concessions—typically terms that are out of market, beyond normal or reasonable standards, or otherwise not available to a non-troubled borrower in the normal market place. A loan classified as TDR must meet both criteria of financial difficulty and concession. TDR loans decreased $1.9 million in 2015 primarily due to decreases of $2.4 million and $1.9 million of residential land and commercial loans, respectively, classified as TDR. HELOC loans classified as TDR increased by $2.0 million.

In 2014, nonaccrual loans decreased $11.6 million primarily due to the payoff of commercial loans that were on nonaccrual status and repayments in the residential land portfolio. TDR loans increased $5.1 million in 2014 primarily due to increases of $3.8 million and $1.3 million of residential 1-4 and commercial loans, respectively, classified as TDR.

In 2013, nonaccrual loans decreased $16.4 million due to improved credit quality in the residential 1-4 family, commercial real estate and commercial loans, and repayments in the residential land portfolio. The improvement is attributed to the continued stabilization or increase of property values, more financial flexibility of borrowers, and overall general economic improvement in the State of Hawaii. TDR loans increased $1.1 million in 2013 primarily due to increases of $3.0 million and $1.6 million of residential 1-4 and commercial loans, respectively, classified as TDR, partly offset by a $3.6 million decrease in residential land loans classified as TDR.

In 2012, nonaccrual loans decreased by $1.9 million due to improved credit quality in the residential 1-4 family and consumer portfolios (residential 1-4 family lower by $1.6 million and residential land loans lower by $5.9 million), partially offset by higher nonaccrual commercial real estate and commercial loans of $5.6 million. The improvement was attributed to stabilized or increasing property values, more financial flexibility of borrowers and overall general economic improvement in the State of Hawaii. TDR loans decreased by $27.4 million in 2012 due to decreases of $15.3 million and $13.7 million of commercial loans and residential land loans, respectively, classified as TDR.

Allowance for loan losses. See “Allowance for loan losses” in Note 1 of the Consolidated Financial Statements.

The following table presents the changes in the allowance for loan losses:



(dollars in thousands)	2015			2014			2013			2012			2011
Allowance for loan losses, January 1	$	45,618		$	40,116		$	41,985		$	37,906		$	40,646
Provision for loan losses	6,275			6,126			1,507			12,883			15,009
Charge-offs
Residential 1-4 family	356			987			1,162			3,183			5,528
Home equity line of credit	205			196			782			716			1,439
Residential land	—			81			485			2,808			4,071
Total real estate	561			1,264			2,429			6,707			11,038
Commercial	1,074			1,872			3,056			3,606			5,335
Consumer	4,791			2,414			2,717			2,517			3,117
Total charge-offs	6,426			5,550			8,202			12,830			19,490
Recoveries
Residential 1-4 family	226			1,180			1,881			1,328			110
Home equity line of credit	80			752			358			108			25
Residential land	507			469			868			1,443			170
Total real estate	813			2,401			3,107			2,879			305
Commercial	2,773			1,636			1,089			649			869
Consumer	985			889			630			498			567
Total recoveries	4,571			4,926			4,826			4,026			1,741
Allowance for loan losses, December 31	$	50,038		$	45,618		$	40,116		$	41,985		$	37,906
Ratio of allowance for loan losses to loans receivable held for investment	1.08		%	1.03		%	0.97		%	1.11		%	1.03		%
Ratio of provision for loan losses during the year to average total loans	0.14		%	0.14		%	0.04		%	0.35		%	0.42		%
Ratio of net charge-offs during the year to average total loans	0.04		%	0.01		%	0.09		%	0.24		%	0.49		%

The following table sets forth the allocation of ASB’s allowance for loan losses and the percentage of loans in each category to total loans:



December 31	2015				2014				2013
(dollars in thousands)	Allow-ance balance		Allowance to loan receivable %	Loan receivable % of total	Allow-ance balance		Allowance to loan receivable %	Loan receivable % of total	Allow-ance balance		Allowance to loan receivable %	Loan receivable % of total
Real estate
Residential 1-4 family	$	4,186	0.20	44.8	$	4,662	0.23	46.0	$	5,534	0.28	48.2
Commercial real estate	11,342		1.64	14.9	8,954		1.68	12.0	5,059		1.15	10.6
Home equity line of credit	7,260		0.86	18.3	6,982		0.85	18.4	5,229		0.71	17.8
Residential land	1,671		9.17	0.4	1,875		11.55	0.4	1,817		11.23	0.4
Commercial construction	4,461		4.43	2.2	5,471		5.67	2.2	2,397		4.60	1.3
Residential construction	13		0.09	0.3	28		0.15	0.4	19		0.15	0.3
Total real estate	28,933		0.77	80.9	27,972		0.79	79.4	20,055		0.61	78.6
Commercial	17,208		2.27	16.4	14,017		1.77	17.8	15,803		2.02	18.8
Consumer	3,897		3.15	2.7	3,629		2.96	2.8	2,367		2.18	2.6
	50,038		1.08	100.0	45,618		1.03	100.0	38,225		0.92	100.0
Unallocated	—				—				1,891
Total allowance for loan losses	$	50,038			$	45,618			$	40,116



December 31	2012				2011
(dollars in thousands)	Allowance balance		Allowance to loan receivable %	Loan receivable % of total	Allowance balance		Allowance to loan receivable %	Loan receivable % of total
Real estate
Residential 1-4 family	$	6,068	0.33	49.2	$	6,500	0.34	52.2
Commercial real estate	2,965		0.79	9.9	1,688		0.51	9.0
Home equity line of credit	4,493		0.71	16.6	4,354		0.81	14.5
Residential land	4,275		16.56	0.7	3,795		8.36	1.2
Commercial construction	2,023		4.60	1.2	1,888		4.50	1.1
Residential construction	9		0.15	0.2	4		0.12	0.1
Total real estate	19,833		0.67	77.8	18,229		0.63	78.1
Commercial	15,931		2.21	19.0	14,867		2.08	19.4
Consumer	4,019		3.32	3.2	3,806		4.08	2.5
	39,783		1.05	100.0	36,902		1.00	100.0
Unallocated	2,202				1,004
Total allowance for loan losses	$	41,985			$	37,906

In 2015, ASB's allowance for loan losses increased by $4.4 million primarily due to growth in the commercial real estate loan portfolio ($159 million or 29.8% growth in outstanding balances) and increases in reserves for commercial loans. Overall loan quality remained strong as total delinquencies of $26.1 million at December 31, 2015 was a slight increase of $0.6 million compared to total delinquencies of $25.5 million at December 31, 2014 primarily due to an increase in delinquent consumer loans. The ratio of delinquent loans to total loans decreased slightly from 0.58% of total loans outstanding at December 31,2014 to 0.57% of total loans outstanding at December 31, 2015. Net charge-offs for 2015 were $1.9 million, an increase of $1.3 million compared to $0.6 million for 2014 primarily due to an increase in consumer loan charge-offs as result of the strategic expansion of ASB's unsecured consumer loan product offering with risk-based pricing. ASB's provision for loan losses was $6.3 million for 2015, an increase of $0.2 million compared to the provision for loan losses of $6.1 million for 2014.

In 2014, ASB’s allowance for loan losses increased by $5.5 million primarily due to growth in the loan portfolio ($282 million or 6.8% growth in outstanding balances) and increases in the loss rates of loan portfolios with higher risk such as commercial real estate and unsecured personal loans. Overall loan quality continued to improve as total delinquencies of $25.5 million at December 31, 2014 was a decrease of $8.3 million compared to total delinquencies of $33.8 million at December 31, 2013 due to a decrease in delinquent commercial, commercial real estate and residential land loans. The ratio of delinquent

loans to total loans decreased from 0.81% of total loans outstanding at December 31, 2013 to 0.58% of total loans outstanding at December 31, 2014. Net charge-offs for 2014 were $0.6 million, a decrease of $2.8 million compared to $3.4 million for 2013 primarily due to a decrease in commercial, HELOC and residential land loan charge-offs as a result of the strong economic growth in Hawaii and partially due to the sale of the credit card portfolio in 2013. ASB’s provision for loan losses was $6.1 million for 2014, an increase of $4.6 million compared to provision for loan losses of $1.5 million for 2013 primarily due to growth in the loan portfolio.

In 2013, ASB’s allowance for loan losses decreased by $1.9 million, despite the increase in the loan portfolios (9.7% growth or $368.1 million increase in outstanding balances) primarily due to the release of reserves as a result of repayments in the higher risk purchased loan and residential land loans portfolios and the sale of the credit card portfolio. Overall loan quality has improved as delinquencies decreased significantly in 2013, primarily in the residential 1-4 family, residential land and commercial real estate portfolios. Net loan charge-offs for 2013 were $3.4 million compared to $8.8 million in 2012 as the Hawaii economy in general and the housing market in particular continued to improve. ASB’s provision for loan losses was $1.5 million in 2013, compared to $12.9 million in 2012.

In 2012, ASB’s allowance for loan losses increased by $4.1 million due to growth in the loan portfolios (2.6% growth or $96.3 million increase in outstanding balances) and higher impairment reserves for the commercial and commercial real estate loan portfolios. Although overall loan quality improved, a number of commercial borrowers experienced financial stress during the year. A loan is deemed impaired when it is probable (more likely than not) that the bank will be unable to collect all amounts due according to the loan’s original contractual terms. In 2012, delinquencies significantly improved in the residential 1-4 family and consumer loan portfolios, while total bank net loan charge-offs of $8.8 million were about half the level in 2011, reflecting the gradual improvement in the local economy including a recovery of the housing market. ASB’s provision for loan losses was $12.9 million in 2012, compared to $15.0 million in 2011.

Investment activities. Currently, ASB’s investment portfolio consists of mortgage-related securities, stock of the FHLB of Des Moines and U.S. Treasury and federal agency obligations. ASB owns mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) and federal agency obligations. The weighted-average yield on investments during 2015, 2014 and 2013 was 2.06%, 1.91% and 2.01%, respectively. ASB did not maintain a portfolio of securities held for trading during 2015, 2014 and 2013.

As of December 31, 2015, 2014 and 2013, ASB’s stock in FHLB amounted to $11 million, $69 million and $93 million, respectively. The amount that ASB is required to invest in FHLB stock is determined by FHLB requirements. Since the third quarter of 2012, the FHLB of Seattle was granted authority to repurchase excess stock from its members. As of December 31, 2014, ASB's FHLB stock balance was $55 million in excess of the requirement. With the merger of the FHLB of Seattle and the FHLB of Des Moines in the second quarter of 2015, all of ASB's excess stock was repurchased. The amount of stock repurchased in 2015, 2014 and 2013 was $59 million, $23 million and $3 million, respectively. See “Stock in FHLB” in HEI’s MD&A. Also, see “Regulation–Federal Home Loan Bank System” below.

ASB does not have any exposure to securities backed by subprime mortgages. See “Investment securities” in Note 5 of the Consolidated Financial Statements for a discussion of other-than-temporarily impaired securities.

The following table summarizes the current amortized cost of ASB’s investment portfolio (excluding stock of the FHLB of Des Moines, which has no contractual maturity) and weighted average yields as of December 31, 2015. Mortgage-related securities are shown separately because they are typically paid in monthly installments over a number of years.



	In 1 year or less			After 1 year through 5 years			After 5 years through 10 years			After 10 years			Mortgage-Related Securities			Total
(dollars in millions)
U.S. Treasury and federal agency obligations	$	—		$	86		$	72		$	55		$	—		$	213
Mortgage-related securities - FNMA, FHLMC and GNMA	—			—			—			—			611			611
	$	—		$	86		$	72		$	55		$	611		$	824
Weighted average yield ²	—		%	1.96		%	2.18		%	2.34		%	2.19		%	2.17		%


¹	As of December 31, 2015, no investment exceeded 10% of stockholder's equity.


²	There are no tax exempt obligations.

Deposits and other sources of funds.

General. Deposits traditionally have been the principal source of ASB’s funds for use in lending, meeting liquidity requirements and making investments. ASB also derives funds from the receipt of interest and principal on outstanding loans receivable and mortgage-related securities, borrowings from the FHLB of Des Moines, securities sold under agreements to repurchase and other sources. ASB borrows on a short-term basis to compensate for seasonal or other reductions in deposit flows. ASB also may borrow on a longer-term basis to support expanded lending or investment activities. Advances from the FHLB and securities sold under agreements to repurchase continue to be a source of funds, but they are a higher cost source than deposits.

Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow or outflow, measured as the year-over-year difference in year-end deposits, was an inflow of $402 million in 2015, compared to an inflow of $251 million in 2014 and $143 million in 2013.

The following table presents the average deposits and average rates by type of deposit. Average balances have been calculated using the average daily balances.



Years ended December 31	2015						2014						2013
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %
Interest-bearing deposit liabilities
Savings	$	1,980,151	58.6	%	0.06	%	$	1,879,373	58.3	%	0.06	%	$	1,805,363	58.1	%	0.06	%
Checking	782,811		23.2		0.02		738,651		22.9		0.02		665,941		21.4		0.02
Money market	164,568		4.9		0.12		171,889		5.3		0.12		182,343		5.9		0.13
Certificate	449,179		13.3		0.83		434,934		13.5		0.83		454,021		14.6		0.82
Total interest-bearing deposit liabilities	$	3,376,709	100.0	%	0.16	%	$	3,224,847	100.0	%	0.16	%	$	3,107,668	100.0	%	0.16	%
Total noninterest-bearing demand deposit liabilities	1,426,962						1,285,964						1,179,559
Total deposit liabilities	$	4,803,671					$	4,510,811					$	4,287,227

The following table presents the amount of time certificates of deposit of $100,000 or more, segregated by time remaining until maturity:



(in thousands)	Amount
Three months or less	$	18,835
Greater than three months through six months	10,061
Greater than six months through twelve months	23,485
Greater than twelve months	110,807
	$	163,188

Deposit-insurance premiums and regulatory developments. For a discussion of changes to the deposit insurance system, premiums and Financing Corporation (FICO) assessments, see “Regulation–Deposit insurance coverage” below.

Other borrowings. See “Other borrowings” in Note 5 of the Consolidated Financial Statements. ASB may obtain advances from the FHLB of Des Moines provided that certain standards related to creditworthiness have been met. Advances are collateralized by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral pledged to the FHLB of Des Moines, the excess must be covered by qualified marketable securities held under the control of and at the FHLB of Des Moines or at an approved third-party custodian. FHLB advances generally are available to meet seasonal and other withdrawals of deposit accounts, to expand lending and to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to time by the FHLB of Des Moines.

The increase in other borrowings in 2015 compared to 2014 was due to an increase in public repurchase agreements. The increase in other borrowings in 2014 compared to 2013 was due to an increase in repurchase agreements with the State of Hawaii. The increase in other borrowings in 2013 compared to 2012 was due to $50 million of additional FHLB advances taken out in 2013. The decrease in other borrowings in 2012 compared to 2011 was due to a decrease in retail repurchase agreements.

Competition. See “Bank—Executive overview and strategy” and “Bank—Certain factors that may affect future results and financial condition—Competition” in HEI’s MD&A.

The banking industry in Hawaii is highly competitive. At December 31, 2015, there were 8 financial institutions insured by the FDIC headquartered in the State of Hawaii. While ASB is one of the largest financial institutions in Hawaii, based on total assets, ASB faces vigorous competition for deposits and loans from two larger banking institutions based in Hawaii and from smaller institutions that heavily promote their services in niche areas, such as providing financial services to small and medium-sized businesses, as well as national financial services organizations. Competition for loans and deposits comes primarily from other savings institutions, commercial banks, credit unions, securities brokerage firms, money market and mutual funds and other investment alternatives. ASB faces additional competition in seeking deposit funds from various types of corporate and government borrowers, including insurance companies. Competition for origination of mortgage loans comes primarily from mortgage banking and brokerage firms, commercial banks, other savings institutions, insurance companies and real estate investment trusts.

To remain competitive and continue building core franchise value, ASB continues to develop and introduce new products and services to meet the needs of its consumer and commercial customers. Additionally, the banking industry is constantly changing and ASB is making the investment in its people and technology necessary to adapt and remain competitive. ASB competes for deposits primarily on the basis of the variety of types of savings and checking accounts it offers at competitive rates, the quality of the services it provides, the convenience of its branch locations and business hours, and convenient automated teller machines. The primary factors in ASB’s competition for mortgage and other loans are the competitive interest rates and loan origination fees it charges, the wide variety of loan programs it offers and the quality and efficiency of the services it provides to borrowers and the business community.

Regulation. ASB, a federally chartered savings bank, and its holding companies are subject to the regulatory supervision of the OCC and FRB, respectively, and in certain respects, the FDIC. See “HEI–Regulation” above and “Bank–Certain factors that may affect future results and financial condition–Regulation” in HEI’s MD&A. In addition, ASB must comply with FRB reserve requirements.

Deposit insurance coverage. The Federal Deposit Insurance Act, as amended, and regulations promulgated by the FDIC, governs insurance coverage of deposit accounts. In July 2010, the Dodd-Frank Act permanently raised the current standard maximum deposit insurance amount to $250,000. Generally, the amount of all deposits held by a depositor in the same capacity (even if held in separate accounts) is aggregated for purposes of applying the insurance limit.

See “Federal Deposit Insurance Corporation assessment” in Note 5 of the Consolidated Financial Statements for a discussion of FDIC deposit insurance assessment rates. FICO will continue to impose an assessment on average total assets minus average tangible equity to service the interest on FICO bond obligations. As of December 31, 2015, ASB’s annual FICO assessment was 0.59 cents per $100 of average total assets minus average tangible equity.

Federal thrift charter. See “Bank–Certain factors that may affect future results and financial condition—Regulation—Unitary savings and loan holding company” in HEI’s MD&A, including the discussion of previously proposed legislation that would abolish the charter.

Recent legislation and issuances. See “Bank–Legislation and regulation” in HEI’s MD&A.

Capital requirements. The OCC has set four capital requirements for financial institutions. As of December 31, 2015, ASB was in compliance with all of the minimum capital requirements with a Tier 1 leverage ratio of 8.8% (compared to a 4.0% requirement), a common equity Tier 1 ratio of 12.1% (compared to a 4.5% requirement), a Tier 1 capital ratio of 12.1% (compared to a 6.0% requirement) and a total capital ratio of 13.3% (compared to a 8.0% requirement).

In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, a financial institution must 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) which is phased-in through 2019. As of December 31, 2015, ASB met the applicable capital requirements, including the fully phased-in capital conservation buffer.

See “Bank-Legislation and regulation” in HEI’s MD&A for the final capital rules under the Basel III regulatory capital framework.

Affiliate transactions. Significant restrictions apply to certain transactions between ASB and its affiliates, including HEI and its direct and indirect subsidiaries. For example, ASB is prohibited from making any loan or other extension of credit to an entity affiliated with ASB unless the affiliate is engaged exclusively in activities which the FRB has determined to be permissible for bank holding companies. There are also various other restrictions which apply to certain transactions between ASB and certain executive officers, directors and insiders of ASB. ASB is also barred from making a purchase of or any investment in securities issued by an affiliate, other than with respect to shares of a subsidiary of ASB.

Financial Derivatives and Interest Rate Risk. ASB is subject to OCC rules relating to derivatives activities, such as interest rate swaps, interest rate lock commitments and forward commitments. See “Derivative financial instruments” in Note 5 of the Consolidated Financial Statements for a description of interest rate lock commitments and forward commitments used by ASB. Currently ASB does not use interest rate swaps to manage interest rate risk (IRR), but may do so in the future. Generally speaking, the OCC rules permit financial institutions to engage in transactions involving financial derivatives to the extent these transactions are otherwise authorized under applicable law and are safe and sound. The rules require ASB to have certain internal procedures for handling financial derivative transactions, including involvement of the ASB Board of Directors.

With the transfer of the regulatory jurisdiction from the OTS to the OCC, ASB has adopted terminology and IRR assessment, measurement and management practices consistent with OCC guidelines. Management believes ASB’s IRR processes are aligned with the Interagency Advisory on Interest Rate Risk Management and appropriate with earnings and capital levels, balance sheet complexity, business model and risk tolerance.

Liquidity. OCC regulations require ASB to maintain sufficient liquidity to ensure safe and sound operations. ASB’s principal sources of liquidity are customer deposits, borrowings, the maturity and repayment of portfolio loans and securities and the sale of loans into secondary market channels. ASB’s principal sources of borrowings are advances from the FHLB of Des Moines and securities sold under agreements to repurchase from broker/dealers. ASB is approved by the FHLB of Des Moines to borrow an amount of up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB of Des Moines stock. As of December 31, 2015, ASB’s unused FHLB of Des Moines borrowing capacity was approximately $1.7 billion. ASB utilizes growth in deposits, advances from the FHLB of Des Moines and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. As of December 31, 2015, ASB had loan commitments, undisbursed loan funds and unused lines and letters of credit of $1.8 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

Supervision. Pursuant to the Federal Deposit Insurance Corporation Improvement Act of 1991 (the FDICIA), the federal banking agencies promulgated regulations which apply to the operations of ASB and its holding companies. Such regulations address, for example, standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders.

Prompt corrective action. The FDICIA establishes a statutory framework that is triggered by the capital level of a financial institution and subjects it to progressively more stringent restrictions and supervision as capital levels decline. The OCC rules implement the system of prompt corrective action. In particular, the rules define the relevant capital measures for the categories of “well capitalized”, “adequately capitalized”, “undercapitalized”, “significantly undercapitalized” and “critically undercapitalized.”

A financial institution that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OCC determines that any of the actions is necessary to resolve the problems of the association at the least possible long-term cost to the Deposit Insurance Fund. A financial institution that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless the OCC and the FDIC concur that other action would be more appropriate. As of December 31, 2015, ASB was “well-capitalized.”

Interest rates. FDIC regulations restrict the ability of financial institutions that are undercapitalized to offer interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2015, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

Qualified thrift lender test. In order to satisfy the QTL test, ASB must maintain 65% of its assets in “qualified thrift investments” on a monthly average basis in 9 out of the previous 12 months. Failure to satisfy the QTL test would subject ASB to various penalties, including limitations on its activities, and would also bring into operation restrictions on the activities that may be engaged in by HEI, ASB Hawaii and their other subsidiaries, which could effectively result in the required divestiture of ASB. At all times during 2015, ASB was in compliance with the QTL test. See “HEI Consolidated–Regulation.”

Federal Home Loan Bank System. ASB is a member of the FHLB System, which consists of 11 regional FHLBs, and ASB’s regional bank is the FHLB of Des Moines. The FHLB System provides a central credit facility for member institutions. Historically, the FHLBs have served as the central liquidity facilities for savings associations and sources of long-term funds for financing housing. At such time as an advance is made to ASB or renewed, it must be collateralized by collateral from one of the following categories: (1) fully disbursed, whole first mortgages on improved residential property, or securities representing a whole interest in such mortgages; (2) securities issued, insured or guaranteed by the U.S. Government or any agency thereof; (3) FHLB deposits; and (4) other real estate-related collateral that has a readily ascertainable value and with respect to which a security interest can be perfected. The aggregate amount of outstanding advances collateralized by such other real estate-related collateral may not exceed 30% of ASB’s capital.

As mandated by the Gramm Act, the Federal Housing Finance Board (Board) regulations require each FHLB to maintain three capital ratios: (1) risk-based capital greater than or equal to the sum of its credit, market and operational risk capital requirements; (2) a minimum capital-to-assets ratio of 4%; and (3) a minimum total capital leverage ratio of 5% of total assets. At September 30, 2015, the FHLB of Des Moines was in compliance with all three of the regulatory capital requirements. ASB's required holding in the stock of the FHLB is both membership and and activity-based. Membership is based on a percentage of total assets (0.12%) while the portion related to activity is based on a percentage of outstanding activity, mainly advances (4%). As of December 31, 2015, ASB was required and owned capital stock in the FHLB of Des Moines in the amount of $11 million. See “Stock in FHLB” in HEI’s MD&A section for recent developments regarding the FHLB of Des Moines.

Community Reinvestment. The Community Reinvestment Act (CRA) requires financial institutions to help meet the credit needs of their communities, including low- and moderate-income areas, consistent with safe and sound lending practices. The OCC will consider ASB’s CRA record in evaluating an application for a new deposit facility, including the establishment of a branch, the relocation of a branch or office, or the acquisition of an interest in another bank. ASB currently holds an “outstanding” CRA rating.

Other laws. ASB is subject to federal and state consumer protection laws which affect deposit and lending activities, such as the Truth in Lending Act (TILA), the Truth in Savings Act, the Equal Credit Opportunity Act, the Real Estate Settlement Procedures Act (RESPA), the Home Mortgage Disclosure Act and several federal and state financial privacy acts intended to protect consumers’ personal information and prevent identity theft, such as the Gramm Act and the Fair and Accurate Transactions Act. ASB is also subject to federal laws regulating certain of its lending practices, such as the Flood Disaster Protection Act, and laws requiring reports to regulators of certain customer transactions, such as the Currency and Foreign Transactions Reporting Act and the International Money Laundering Abatement and Anti-Terrorist Financing Act. ASB’s relationship with LPL Financial LLP is also governed by regulations adopted by the FRB under the Gramm Act, which regulate “networking” relationships under which a financial institution refers customers to a broker-dealer for securities services and employees of the financial institution are permitted to receive a nominal fee for the referrals. These laws may provide for substantial penalties in the event of noncompliance.

The TILA-RESPA Integrated Disclosure rule became effective on October 3, 2015. The rule requires easier-to-use mortgage disclosure forms that clearly lay out the terms of a mortgage for a homebuyer. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd Frank Act) mandated that the Bureau of Consumer Financial Protection (the Bureau) establish a single disclosure scheme for use by lenders and creditors in complying with the disclosure requirements of both RESPA and TILA. The Dodd-Frank Act amended RESPA to require that the Bureau publish a single, integrated disclosure for mortgage loan transactions. The first new form - the Loan Estimate - is designed to provide disclosures that will be helpful to consumers in understanding the key features, costs, and risks of the mortgage for which they are applying. This form is provided to consumers within three business days after they submit a loan application. The second form - the Closing Disclosure - is designed to provide disclosures that will be helpful to consumers in understanding all of the costs of the transaction. This form is provided to consumers three business days before they close on the loan. The rule applies to most closed-end consumer mortgages.

ASB believes that it currently is in compliance with these laws and regulations in all material respects.

Proposed legislation. See the discussion of proposed legislation in “Bank–Legislation and regulation” in HEI’s MD&A.

Environmental regulation. ASB may be subject to the provisions of Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), Hawaii Environmental Response Law (ERL) and regulations promulgated thereunder, which impose liability for environmental cleanup costs on certain categories of responsible parties. CERCLA and ERL exempt persons whose ownership in a facility is held primarily to protect a security interest, provided that they do not participate in the management of the facility. Although there may be some risk of liability for ASB for environmental cleanup costs in the event ASB forecloses on, and becomes the owner of, property with environmental problems, the Company believes the risk is not as great for ASB as it may be for other depository institutions that have a larger portfolio of commercial loans.

Additional information. For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of the Consolidated Financial Statements.

Properties. ASB owns or leases several office buildings in downtown Honolulu and owns land and an operations center in the Mililani Technology Park on the island of Oahu.

The following table sets forth the number of bank branches owned and leased by ASB by island:



	Number of branches
December 31, 2015	Owned	Leased	Total
Oahu	7	32	39
Maui	3	4	7
Hawaii	3	2	5
Kauai	2	2	4
Molokai	—	1	1
	15	41	56

As of December 31, 2015, the net book value (NBV) of branches and office facilities was $68 million ($61 million NBV of the land and improvements for the branches and office facilities owned by ASB and $7 million represents the NBV of ASB’s leasehold improvements) compared to the NBV of branches and office facilities of $71 million ($64 million NBV of the land and improvements for the branches and office facilities owned by ASB and $7 million represents the NBV of ASB’s leasehold improvements) as of December 31, 2014. The decrease in the NBV of branches and office facilities was primarily due to the sale of a real estate property. The leases expire on various dates through February 2033, but many of the leases have extension provisions.

As of December 31, 2015, ASB owned 116 automated teller machines.



ITEM 1A.	RISK FACTORS

The businesses of HEI and its subsidiaries involve numerous risks which, if realized, could have a material and adverse effect on the Company’s financial statements. In addition, there are numerous risks relating to the Merger and Spin-Off. For additional information for certain risk factors enumerated below and other risks of the Company and its operations, see “Forward-Looking Statements” above and HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk”, the Notes to the Consolidated Financial Statements, Hawaiian Electric’s MD&A, Hawaiian Electric’s “Quantitative and Qualitative Disclosures About Market Risk.”

Risk Factors Relating to the Merger.

Failure to complete the Merger could negatively impact the stock price and the future business and financial results of HEI. If the Merger is not completed, the ongoing business of HEI may be adversely affected as a result of several risks, including the following:


•	having to pay certain costs relating to the proposed Merger and the Spin-Off, such as legal, accounting, financial advisor, filing, printing and mailing fees;

•

having had HEI’s management being focused on the Merger, which may have led, or could lead, to the disruption of HEI’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies, any of which could adversely affect the ability of HEI to maintain relationships with customers, regulators, vendors and employees, or could otherwise adversely affect the business and financial results of HEI, without realizing any of the benefits of having the Merger completed; and


•	having had HEI’s management focused on the Merger instead of on pursuing other opportunities that could be beneficial to HEI, without realizing any of the benefits of having the Merger completed.

If the Merger is not completed, HEI cannot assure its shareholders that these risks will not materialize and will not materially affect its business, financial results and stock price.

The pendency of the Merger could adversely affect the business and operations of HEI. In connection with the pending Merger, some customers or vendors of HEI’s utilities may delay or defer decisions, which could negatively impact the revenues, earnings, cash flows and expenses of HEI, regardless of whether the Merger is completed. Similarly, current and prospective employees of HEI and its utilities may experience uncertainty about their future roles following the Merger, which may materially adversely affect the ability of HEI and its utilities to attract and retain key personnel during the pendency of the Merger. In addition, due to operating covenants in the Merger Agreement, HEI and its utilities may be unable, during the pendency of the Merger, to pursue strategic transactions, undertake significant capital projects, undertake certain significant financing or other specified transactions or pursue actions that are not in the ordinary course of business, even if such actions would prove beneficial.

If the Merger is completed, NEE may be unable to successfully integrate HEI’s business. NEE and HEI currently operate as independent public companies. After the Merger, NEE will be required to devote significant management attention and

resources to integrating HEI’s business. Potential difficulties NEE may encounter in the integration process include the following:


•	the complexities associated with integrating HEI and its utility business, while at the same time continuing to provide consistent, high quality services;


•	the additional complexities of integrating a company with different core services, markets and customers;


•	the inability to retain key employees;


•	unknown liabilities and unforeseen expenses, delays or onerous regulatory conditions associated with the Merger; and


•	performance shortfalls as a result of the diversion of management’s attention caused by completing the Merger and integrating HEI’s utility business.

For these reasons, the integration process following the Merger could result in the distraction of NEE’s management, the disruption of NEE’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies, any of which could adversely affect the ability of NEE to maintain relationships with customers, vendors and employees or could otherwise adversely affect the business and financial results of NEE.

HEI may be materially adversely affected by negative publicity related to the proposed Merger and in connection with other matters. From time to time, political and public sentiment in connection with the proposed Merger and in connection with other matters may result in a significant amount of adverse press coverage and other adverse public statements affecting NEE and HEI. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceeding, can divert the time and effort of senior management from the management of HEI’s businesses.

Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on HEI’s reputation, on the morale and performance of its employees and on its relationships with its regulators. It may also have a negative impact on HEI’s ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on HEI’s business, financial condition, results of operations and prospects.

Pending litigation against HEI and NEE could result in an injunction preventing completion of the merger, the payment of damages in the event the merger is completed and/or may adversely affect the combined company's business, financial condition or results of operations following the Merger.

Holding Company and Company-Wide Risks.

HEI is a holding company that derives its income from its operating subsidiaries and depends on the ability of those subsidiaries to pay dividends or make other distributions to HEI and on its own ability to raise capital. HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, HEI’s cash flows and consequent ability to service its obligations and pay dividends on its common stock is dependent upon its receipt of dividends or other distributions from its operating subsidiaries and its ability to issue common stock or other equity securities and to incur additional debt. The ability of HEI’s subsidiaries to pay dividends or make other distributions to HEI, in turn, is subject to the risks associated with their operations and to contractual and regulatory restrictions, including:


•	the provisions of an HEI agreement with the PUC, which could limit the ability of HEI’s principal electric public utility subsidiary, Hawaiian Electric, to pay dividends to HEI in the event that the consolidated common stock equity of the Utilities falls below 35% of total capitalization of the electric utilities;

•

the provisions of an HEI agreement entered into with federal bank regulators in connection with its acquisition of its bank subsidiary, ASB, which require HEI to contribute additional capital to ASB (up to a maximum amount of additional capital of $28.3 million as of December 31, 2015) upon request of the regulators in order to maintain ASB’s regulatory capital at the level required by regulation;


•	the minimum capital and capital distribution regulations of the OCC that are applicable to ASB and capital regulations that become applicable to HEI and ASB Hawaii;


•	the receipt of a letter of non-objection or prior approval from the OCC and FRB to the payment of any dividend ASB proposes to declare and pay to ASB Hawaii and HEI; and


•	the provisions of preferred stock resolutions and debt instruments of HEI and its subsidiaries.

The Company is subject to risks associated with the Hawaii economy (in the aggregate and on an individual island basis), volatile U.S. capital markets and changes in the interest rate and credit market environment that have and/or could result in higher retirement benefit plan funding requirements, declines in ASB’s interest rate margins and investment values, higher delinquencies and charge-offs in ASB’s loan portfolio and restrictions on the ability of HEI or its subsidiaries to borrow money or issue securities. The two largest components of Hawaii’s economy are tourism and the federal government (including the

military). Because the core businesses of HEI’s subsidiaries are providing local public electric utility services (through Hawaiian Electric and its subsidiaries) and banking services (through ASB) in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates on the construction and real estate industries and by the impact of world conditions (e.g., U.S. withdrawal of troops from Afghanistan) on federal government spending in Hawaii. For example, the turmoil in the financial markets and declines in the national and global economies had a negative effect on the Hawaii economy in 2009. In 2009, declines in the Hawaii, U.S. and Asian economies in part led to declines in HEI's share price, an increase in uncollected billings of the Utilities, higher delinquencies in ASB’s loan portfolio, declines in the Company's pension plan asset values and other adverse effects on HEI’s businesses. Also, the decline in the stock market in 2016 to date has resulted in lower pension plan asset values, which could increase future pension contributions and decrease the funded status of the plans.

If Fitch, Moody's or S&P were to downgrade HEI’s or Hawaiian Electric’s long-term debt ratings because of past adverse effects, or if future events were to adversely affect the availability of capital to the Company, HEI’s and Hawaiian Electric’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase with resulting reductions in HEI’s consolidated net income in future periods. Further, if HEI’s or Hawaiian Electric’s commercial paper ratings were to be downgraded, HEI and Hawaiian Electric might not be able to sell commercial paper and might be required to draw on more expensive bank lines of credit or to defer capital or other expenditures.

Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected by the market performance of the assets in the master pension trust maintained for pension plans, and by the discount rate used to estimate the service and interest cost components of net periodic pension cost and value obligations. The Utilities’ pension tracking mechanisms help moderate pension expense; however, the significant decline in 2008 in the value of the Company’s defined benefit pension plan assets resulted in a substantial gap between the projected benefit obligations under the plans and the value of plan assets, resulting in increases in funding requirements. The increases have moderated in recent years as investment performance has improved.

Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. HEI and the Utilities are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric utilities’ rates of return. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.

Interest rate risk 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 values of those instruments, respectively. Disruptions in the credit markets, a liquidity crisis in the banking industry or increased levels of residential mortgage delinquencies and defaults may result in decreases in the fair value of ASB’s investment securities and an impairment that is other-than-temporary, requiring ASB to write down its investment securities. As of December 31, 2015, all of ASB’s investment securities were securities and obligations issued by a federal agency or government sponsored entity that have an implicit guarantee from the U.S. government.

HEI and Hawaiian Electric and their subsidiaries may incur higher retirement benefits expenses and have and will likely continue to recognize substantial liabilities for retirement benefits. Retirement benefits expenses and cash funding requirements could increase in future years depending on numerous factors, including the performance of the U.S. equity markets, trends in interest rates and health care costs, plan amendments, new laws relating to pension funding and changes in accounting principles. For the Utilities, however, retirement benefits expenses, as adjusted by the pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, have been an allowable expense for rate-making purposes.

The Company is subject to the risks associated with the geographic concentration of its businesses and current lack of interconnections that could result in service interruptions at the Utilities or higher default rates on loans held by ASB. The business of the Utilities is concentrated on the individual islands they serve in the State of Hawaii. Their operations are more vulnerable to service interruptions than are many U.S. mainland utilities because none of the systems of the Utilities are interconnected with the systems on the other islands they serve. Because of this lack of interconnections, it is necessary to maintain higher generation reserve margins than are typical for U.S. mainland utilities to help ensure reliable service. Service interruptions, including in particular extended interruptions that could result from a natural disaster or terrorist activity, could adversely impact the KWH sales of some or all of the Utilities.

Substantially all of ASB’s consumer loan customers are Hawaii residents. A significant portion of the commercial loan customers are located in Hawaii. While a majority of customers are on Oahu, ASB also has customers on the neighbor islands (whose economies have been weaker than Oahu during the recent economic downturn). Substantially all of the real estate

underlying ASB’s residential and commercial real estate loans are located in Hawaii. These assets may be subject to a greater risk of default than other comparable assets held by financial institutions with other geographic concentrations in the event of adverse economic, political or business developments or natural disasters affecting Hawaii and the ability of ASB’s customers to make payments of principal and interest on their loans.

Increasing competition and technological advances could cause HEI’s businesses to lose customers or render their operations obsolete. The banking industry in Hawaii, and certain aspects of the electric utility industry, are competitive. The success of HEI’s subsidiaries in meeting competition and responding to technological advances will continue to have a direct impact on HEI’s consolidated financial performance. For example:

•

ASB, one of the largest financial institutions in the state, is in direct competition for deposits and loans not only with two larger institutions that have substantial capital, technology and marketing resources, but also with smaller Hawaii institutions and other U.S. institutions, including credit unions, mutual funds, mortgage brokers, finance companies and investment banking firms. Larger financial institutions may have greater access to capital at lower costs, which could impair ASB’s ability to compete effectively. Significant advances in technology could render the operations of ASB less competitive or obsolete.

•

The Utilities face competition from IPPs; customer self-generation, with or without cogeneration; customer energy storage; and the potential formation of community-based, cooperative ownership structures for electrical service on the neighbor islands. With the exception of certain identified projects, the Utilities are required to use competitive bidding to acquire a future generation resource unless the PUC finds competitive bidding to be unsuitable. The PUC set policies for distributed generation (DG) interconnection agreements and standby rates, and established conditions under which electric utilities can provide DG services on customer-owned sites as a regulated service. The results of competitive bidding, competition from IPPs, customer self-generation, and potential cooperative ownership structures for electric utility service, and the rate at which technological developments facilitating nonutility generation of electricity and customer energy storage occur may adversely affect the Utilities and the results of their operations.


•	New technological developments, such as the commercial development of energy storage and microgrids, may render the operations of the Utilities less competitive or outdated.

The Company may be subject to information technology system failures, network disruptions and breaches in data security that could adversely affect its businesses and reputation. The Company is subject to cyber security risks and the potential for cyber incidents, including potential incidents at ASB branches and at the the Utilities' plants and the related electricity transmission and distribution infrastructure, 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. ASB and the Utilities are highly dependent on their ability to process, on a daily basis, a large number of transactions. ASB and the Utilities rely heavily on numerous data processing systems. If any of these systems fails to operate properly or becomes disabled even for a brief period of time, the Company could suffer financial loss, business disruptions, liability to customers, regulatory intervention or damage to its reputation. The Utilities and ASB have disaster recovery plans in place to protect their businesses against natural disasters, security breaches, military or terrorist actions, power or communication failures or similar events. The disaster recovery plans, however, may not be successful in preventing the loss of customer data, service interruptions, disruptions to operations or damage to important facilities.

HEI’s businesses could suffer losses that are uninsured due to a lack of affordable insurance coverage, unavailability of insurance coverage or limitations on the insurance coverage the Company does have. In the ordinary course of business, HEI and its subsidiaries purchase insurance coverages (e.g., property and liability coverages) to protect against loss of, or damage to, their properties and against claims made by third parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. Certain of the insurance has substantial deductibles or has limits on the maximum amounts that may be recovered. For example, the Utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $6 billion and are largely not insured against loss or damage because the amount of transmission and distribution system insurance available is limited and the premiums are cost prohibitive. Similarly, the Utilities have no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the Utilities are not interconnected to other systems. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the affected Utilities to recover from ratepayers restoration costs and revenues lost from business interruption, the lost revenues and repair expenses could result in a significant decrease in HEI’s consolidated net income or in significant net losses for the affected periods.

ASB generally does not obtain credit enhancements, such as mortgagor bankruptcy insurance, but does require standard hazard and hurricane insurance and may require flood insurance for certain properties. ASB is subject to the risks of borrower defaults and bankruptcies, special hazard losses not covered by the required insurance and the insurance company’s inability to pay claims on existing policies.

Increased federal and state environmental regulation will require an increasing commitment of resources and funds and could result in construction delays or penalties and fines for non-compliance. HEI and its subsidiaries are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, hazardous substances, waste management, natural resources and health and safety, which regulate, among other matters, the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous and toxic wastes and substances. HEI or its subsidiaries are currently involved in investigatory or remedial actions at current, former or third-party sites and there is no assurance that the Company will not incur material costs relating to these sites. In addition, compliance with these legal requirements requires the Utilities to commit significant resources and funds toward, among other things, environmental monitoring, installation of pollution control equipment and payment of emission fees. These laws and regulations, among other things, require that certain environmental permits be obtained in order to construct or operate certain facilities, and obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance. For example, emission and/or discharge limits may be tightened, more extensive permitting requirements may be imposed and additional substances may become regulated. In addition, significant regulatory uncertainty exists regarding the impact of federal or state greenhouse gas (GHG) emission limits and reductions.

If HEI or its subsidiaries fail to comply with environmental laws and regulations, even if caused by factors beyond their control, that failure may result in civil or criminal penalties and fines or the cessation of operations.

Adverse tax rulings or developments could result in significant increases in tax payments and/or expense. Governmental taxing authorities could challenge a tax return position taken by HEI or its subsidiaries and, if the taxing authorities prevail, HEI’s consolidated tax payments and/or expense, including applicable penalties and interest, could increase significantly.

The Company could be subject to the risk of uninsured losses in excess of its accruals for litigation matters. HEI and its subsidiaries are involved in routine litigation in the ordinary course of their businesses, most of which is covered by insurance (subject to policy limits and deductibles). However, other litigation may arise that is not routine (such as the litigation related to the proposed Merger) or involves claims that may not be covered by insurance. Because of the uncertainties associated with litigation, there is a risk that litigation against HEI or its subsidiaries, even if vigorously defended, could result in costs of defense and judgment or settlement amounts not covered by insurance and in excess of reserves established in HEI’s consolidated financial statements.

Changes in accounting principles and estimates could affect the reported amounts of the Company’s assets and liabilities or revenues and expenses. HEI’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the U.S. Changes in accounting principles (including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards), or changes in the Company’s application of existing accounting principles, could materially affect the financial statement presentation of HEI’s or the Utilities’ consolidated results of operations and/or financial condition. Further, in preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant change include the amounts reported for pension and other postretirement benefit obligations; contingencies and litigation; income taxes; property, plant and equipment; regulatory assets and liabilities; electric utility revenues; allowance for loan losses; nonperforming loans; troubled debt restructurings; and fair value.

The Utilities' financial statements reflect assets and costs based on cost-based rate-making regulations. Continued accounting in this manner requires that certain criteria relating to the recoverability of such costs through rates be met. If events or circumstances should change so that the criteria are no longer satisfied, the Utilities’ expect that their regulatory assets (amounting to $897 million as of December 31, 2015), net of regulatory liabilities (amounting to $372 million as of December 31, 2015), would be charged to the statement of income in the period of discontinuance.

Changes in accounting principles can also impact HEI’s consolidated financial statements. For example, if management determines that a PPA requires the consolidation of the IPP in the Consolidated Financial Statements, the consolidation could have a material effect on Hawaiian Electric’s and HEI’s 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. Also, if management determines that a PPA requires the classification of the agreement as a capital lease, a material effect on HEI’s consolidated balance sheet may result, including the recognition of significant capital assets and lease obligations.

A proposed standard on accounting for expected credit losses was issued by the FASB which would replace existing impairment models, including replacing an “incurred loss” model for loans with a “current expected credit loss” model. There are a number of questions and issues around the expected credit loss model. ASB cannot predict whether or when a final

standard will be issued, when it will be effective or what it its final provisions will be. It is possible that the final standard could have a material adverse impact on the bank’s results of operations once it is issued and becomes effective.

A standard on accounting for revenues from contracts with customers was issued by the FASB in May 2014. The Company plans to adopt this standard in the first quarter of 2017, but has not determined the impact of adoption on its financial statements.

The Company has identified a material weakness in its internal control over financial reporting. If the Company fails to maintain effective internal control over financial reporting at a reasonable assurance level, HEI and Hawaiian Electric may not be able to accurately report their financial results, which could have a material adverse effect on their operations, investor confidence in their businesses and the trading prices of their securities. HEI’s and Hawaiian Electric’s management is responsible for establishing and maintaining adequate internal control over their financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.

In connection with the preparation of HEI’s and Hawaiian Electric’s consolidated financial statements for the nine months ended September 30, 2015, management along with its independent registered public accounting firm identified a material weakness in the internal control over financial reporting.

The material weakness management identified specifically related to the fact that controls were not designed to ensure that non-cash transactions were properly identified and recorded, and management’s review process was not effective. The deficiency resulted in restatements of HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and 2014, the six months ended June 30, 2015 and 2014, and the years ended December 31, 2013 and 2012 and revisions of HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and the year ended December 31, 2014.

The Company and Hawaiian Electric are actively engaged in remediation efforts to address the material weakness in the internal control over financial reporting. The remediation includes, but is not limited to, a roll forward reconciliation and review of the capital expenditures amount included in the Consolidated Statements of Cash Flows, and enhancing templates to facilitate the preparation and review of cash flows. New controls relating to the preparation and review of the Statement of Cash Flows (including improved spreadsheet templates, a reconciliation of cash capital expenditures, enhanced procedures to identify noncash items, and an additional level of management review) have been implemented and will continue to be tested for operational effectiveness

If the Company’s remediation efforts are insufficient to address the identified material weakness or if additional material weaknesses in internal controls are discovered in the future, they may adversely affect the Company’s ability to record, process, summarize and report financial information timely and accurately and, as a result, the Company’s financial statements may contain material misstatements or omissions.

Electric Utility Risks.

Actions of the PUC are outside the control of the Utilities and could result in inadequate or untimely rate increases, in rate reductions or refunds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects. The rates the Utilities are allowed to charge for their services and the timeliness of permitted rate increases are among the most important items influencing the Utilities’ results of operations, financial condition and liquidity. The PUC has broad discretion over the rates that the Utilities charge their customers. As part of the decoupling mechanism that the Utilities have implemented, each of the Utilities will file a rate case once every three years. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts that may be included in rate base, the returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on Hawaiian Electric’s consolidated results of operations, financial condition and liquidity.

To improve the timing and certainty of the recovery of their costs, the Utilities have proposed and received approval of various cost recovery mechanisms including an ECAC and pension and OPEB tracking mechanisms, as well as a decoupling mechanism, a PPAC, and a renewable energy infrastructure program (REIP) surcharge. A change in, or the elimination of, any of these cost recovery mechanisms, including in the current proceeding in which the PUC is examining the decoupling mechanism, could have a material adverse effect on the Utilities.

The Utilities could be required to refund to their customers, with interest, revenues that have been or may be received under interim rate orders in their rate case proceedings, integrated resource plan cost recovery dockets and other proceedings, if and to the extent they exceed the amounts allowed in final orders.

Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any

adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if the PUC disallows 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. For example, in January 2013, the Utilities and the Consumer Advocate signed a settlement agreement to write off $40 million of costs in lieu of conducting PUC-ordered regulatory audits of the CIP CT-1 and the CIS projects.

Energy cost adjustment clauses. The rate schedules of each of the Utilities include ECACs under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power.

ECACs are subject to periodic review by the PUC. In the most recent rate cases, the PUC allowed the current ECAC to continue. However, in the decoupling reexamination proceeding, certain parties recommended modifying the ECAC to allow only partial pass-through of fuel costs and eventual phasing out of the ECAC. The Consumer Advocate stated that there should be no significant change to the existing ECAC without first undertaking a new regulatory proceeding that would provide time and resources for the careful study of the potential effects of each ECAC change considered, but that there should be significantly greater ECAC audit and regulatory review of the Utilities’ incurred fuel costs should be implemented to encourage cost control and to identify and deny recovery of any imprudently incurred energy costs through the ECAC. The Utilities suggested ways of improving the ECAC but stated that permitting only the partial pass through of fuel costs would not be proper regulatory policy since the Utilities have no control over world oil markets, 42 of the 50 states provide dollar-for-dollar pass through of market-driven changes in fuel or purchase power costs and modifying the ECAC to allow only partial pass-through of fuel costs could severely impact the Utilities’ credit rating. A change in, or the elimination of, the ECAC could have a material adverse effect on the Utilities.

In approving Hawaii Electric Light’s request to file a rate case by the end of December 30,2016, the PUC required Hawaii Electric Light to propose for PUC consideration potential modifications to its ECAC mechanism in order to provide appropriate economic incentives to accelerate reductions in fuel and purchased power expenses.

Electric utility operations are significantly influenced by weather conditions. The Utilities’ results of operations can be affected by the weather. Weather conditions, particularly temperature and humidity, directly influence the demand for electricity. In addition, severe weather and natural disasters, such as hurricanes, earthquakes, tsunamis and lightning storms, which may become more severe or frequent as a result of global climate changes, can cause outages and property damage and require the Utilities to incur significant additional expenses that may not be recoverable.

Electric utility operations depend heavily on third-party suppliers of fuel and purchased power. The Utilities rely on fuel oil suppliers and shippers and IPPs to deliver fuel oil and power, respectively, in accordance with contractual agreements. Approximately 70% of the net energy generated or purchased by the Utilities in 2015 was generated from the burning of fossil fuel oil, and purchases of power by the Utilities provided about 46% of their total net energy generated and purchased for the same period. Failure or delay by oil suppliers and shippers to provide fuel pursuant to existing contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could disrupt the ability of the Utilities to deliver electricity and require the Utilities to incur additional expenses to meet the needs of their customers that may not be recoverable. In addition, as the 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. Also, as these contractual agreements end, the Utilities may not be able to purchase fuel and power on terms equivalent to the current contractual agreements. As the use of biofuels in generating units increases, the same risks will exist with suppliers of biofuels.

Electric utility generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated and/or increased operation and maintenance expenses and increased power purchase costs. Operation of electric generating facilities involves certain risks which can adversely affect energy output and efficiency levels. Included among these risks are facility shutdowns or power interruptions due to insufficient generation or a breakdown or failure of equipment or processes. In January 2015, Hawaiian Electric experienced a generation shortfall event due to unexpected concurrent outages of a utility generating unit and several IPPs. In addition, operations could be negatively impacted by interruptions in fuel supply, inability to negotiate satisfactory collective bargaining agreements when existing agreements expire or other labor disputes, inability to comply with regulatory or permit requirements, disruptions in delivery of electricity, operator error and catastrophic events such as earthquakes, tsunamis, hurricanes, fires, explosions, floods or other similar occurrences affecting the Utilities’ generating facilities or transmission and distribution systems.

The Utilities may be adversely affected by new legislation. Congress, the Hawaii legislature and governmental agencies periodically consider legislation and other initiatives that could have uncertain or negative effects on the Utilities and their customers. Congress, the Hawaii legislature and governmental agencies have adopted, or are considering adopting, a number of measures that will significantly affect the Utilities, as described below.

Renewable Portfolio Standards law. In 2015, Hawaii’s RPS law was amended to require 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 energy efficiency programs do not count toward the RPS after 2014. The Utilities are committed to achieving these goals and met the 2015 RPS; however, due to the exclusion of energy savings in calculating RPS after 2014 and risks such as potential delays in IPPs being able to deliver contracted renewable energy, it is possible the Utilities may not attain the required renewable percentages in the future, and management cannot predict the future consequences of failure to do so (including potential penalties to be assessed by the PUC). On December 19, 2008, the PUC approved a penalty of $20 for every MWh that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated, as described in the RPS law and in an RPS framework adopted by the PUC. In addition, the PUC ordered that the Utilities will be prohibited from recovering any RPS penalty costs through rates.

Renewable energy. In 2007, a measure was passed by the Hawaii legislature stating that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source is more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source, resulting in higher costs.

Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to 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 rules required to implement Act 234 and these rules went into effect on June 30, 2014. In general, Act 234 and the 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 State requirements, the Utilities submitted an Emissions Reduction Plan (EmRP) to the DOH on June 30, 2015. Hawaiian Electric, Maui Electric, and Hawaii Electric Light have a total of 11 facilities affected by the state GHG rule. Hawaiian Electric made use of the partnering provisions in the GHG rule to prepare one EmRP for all 11 of the Utilities’ affected facilities. In this plan, 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 EmRP. The State GHG rule requires affected sources to pay an annual fee that is based on tons per year of GHG emissions. The Utilities’ GHG emissions fee is 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.

On September 22, 2009, the EPA issued its “Final Mandatory Reporting of Greenhouse Gases Rule,” which requires that sources emitting GHGs above certain threshold levels monitor and report their GHG emissions. Following these requirements, the Utilities have submitted the required reports for 2010 through 2014 to the EPA; the 2015 report will be submitted in the first quarter of 2016. Since 2009, the EPA has issued rules to address GHG emissions from stationary sources, like the Utilities’ EGUs.

On June 3, 2010, the EPA’s final GHG Tailoring Rule was published. It created a new threshold for GHG emissions from new and existing facilities and required certain facilities to obtain PSD and Title V operating permits. On June 23, 2014, the U.S. Supreme Court issued a decision that invalidated the GHG Tailoring Rule, to the extent it regulated sources based solely on their GHG emissions. It also invalidated the GHG emissions threshold for regulation. On December 19, 2014, EPA released two memorandums outlining its plan for addressing the U.S. Supreme Court’s decision. Hawaiian Electric, Hawaii Electric Light and Maui Electric are evaluating the potential impacts of the EPA’s plan on utility operations and permitting. The current status of the GHG Tailoring Rule and any further action the EPA may take in light of this recent decision remain uncertain.

On January 8, 2014, the EPA published in the Federal Register its new proposal for New Source Performance Standards for GHG from new generating units. The proposed rule on GHG from new EGUs does not apply to oil-fired combustion turbines or diesel engine generators, and is not otherwise expected to have significant impacts on the Utilities.

As part of President Obama’s Climate Action Plan, the EPA issued the final federal rule for GHG emission reductions from existing EGUs on August 3, 2015. This rule is also known as the Clean Power Plan. This rule sets interim state-wide emissions limits for existing EGUs operating in the 48 contiguous states that must be met on average from 2022 through 2029; final limits will apply from 2030. The EPA did not issue final guidelines for Alaska, Hawaii, Puerto Rico, or Guam because the Best System of Emission Reduction established for the contiguous states is not appropriate for these locations. The EPA has said it

will work with the state and territorial governments for Alaska, Hawaii, Puerto Rico, and Guam and other stakeholders to gather additional information regarding the emissions reduction measures available in these jurisdictions, particularly with respect to renewable generation. Hawaiian Electric plans to participate in this process. The Utilities’ latest assessment of the Clean Power Plan is that the continued growth of renewable power generation in the future will significantly reduce the compliance costs and risk for the Utilities. To date, no timetable has been established by the EPA to develop GHG emission limits for Alaska, Hawaii, Puerto Rico, or Guam.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.

The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in Hawaiian Electric’s CIP CT-1, using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. The Utilities are also working with the State of Hawaii and other entities to pursue the use of liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. Management is unable to evaluate the ultimate impact on the Utilities of these various measures to reduce GHG emissions.

The foregoing legislation or legislation that now is, or may in the future be, proposed present risks and uncertainties for the Utilities.

The Utilities may be subject to increased operational challenges and their results of operations, financial condition and liquidity may be adversely impacted in meeting the commitments and objectives of clean energy initiatives and Renewable Portfolio Standards (RPS). The far-reaching nature of the Utilities' renewable energy commitments and the RPS goals present risks to the Company. Among such risks are: (1) the dependence on third party suppliers of renewable purchased energy, which if the Utilities are unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the Utilities’ achievement of their commitments to RPS goals and/or the Utilities’ ability to deliver reliable service; (2) delays in acquiring or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not installed or does not operate effectively; (4) the likelihood that the Utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the Utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the Utilities depending on their design and implementation.

Bank Risks.

Fluctuations in interest rates could result in lower net interest income, impair ASB’s ability to originate new loans or impair the ability of ASB’s adjustable-rate borrowers to make increased payments. Interest rate risk is a significant risk of ASB’s operations. ASB’s net interest income consists primarily of interest income received on fixed-rate and adjustable-rate loans, mortgage-related securities and investments and interest expense consisting primarily of interest paid on deposits and other borrowings. Interest rate risk arises when earning assets mature or when their interest rates change in a time frame different from that of the costing liabilities. Changes in market interest rates, including changes in the relationship between short-term and long-term market interest rates or between different interest rate indices, can impact ASB’s net interest margin.

Although ASB pursues an asset-liability management strategy designed to mitigate its risk from changes in market interest rates, unfavorable movements in interest rates could result in lower net interest income. Residential 1-4 family fixed-rate mortgage loans comprised about 41% of ASB’s loan portfolio as of December 31, 2015 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. Interest rates remained low in 2015 and new loan production rates remained at historically low levels and below ASB's loan portfolio yields. This placed additional pressure on ASB's asset yields and net interest margin. The degree to which compression of ASB's margin continues is uncertain if interest rates rise.

Increases in market interest rates could have an adverse impact on ASB’s cost of funds. Higher market interest rates could lead to higher interest rates paid on deposits and other borrowings. Significant increases in market interest rates, or the

perception that an increase may occur, could adversely affect ASB’s ability to originate new loans and grow. An increase in market interest rates, especially a sudden increase, could also adversely affect the ability of ASB’s adjustable-rate borrowers to meet their higher payment obligations. If this occurred, it could cause an increase in nonperforming assets and charge-offs. Conversely, a decrease in interest rates or a mismatching of maturities of interest sensitive financial instruments could result in an acceleration in the prepayment of loans and mortgage-related securities and impact ASB’s ability to reinvest its liquidity in similar yielding assets.

ASB’s operations are affected by factors that are beyond its control, that could result in lower revenues, higher expenses or decreased demand for its products and services. ASB’s results of operations depend primarily on the income generated by the supply of and demand for its products and services, which primarily consist of loans and deposit services. ASB’s revenues and expenses may be adversely affected by various factors, including:


•	local, regional, national and other economic and political conditions that could result in declines in employment and real estate values, which in turn could adversely affect the ability of borrowers to make loan payments and the ability of ASB to recover the full amounts owing to it under defaulted loans;


•	the ability of borrowers to obtain insurance and the ability of ASB to place insurance where borrowers fail to do so, particularly in the event of catastrophic damage to collateral securing loans made by ASB;


•	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 profiles and asset quality, which may increase or decrease the required level of allowance for loan losses;


•	technological disruptions affecting ASB’s operations or financial or operational difficulties experienced by any outside vendor on whom ASB relies to provide key components of its business operations, such as business processing, network access or internet connections;


•	the impact of legislative and regulatory changes, including changes affecting capital requirements, increasing oversight of and reporting by banks, or affecting the lending programs or other business activities of ASB;


•	additional legislative changes regulating the assessment of overdraft, interchange and credit card fees, which can have a negative impact on noninterest income;


•	public opinion about ASB and financial institutions in general, which, if negative, could impact the public’s trust and confidence in ASB and adversely affect ASB’s ability to attract and retain customers and expose ASB to adverse legal and regulatory consequences;


•	increases in operating costs (including employee compensation expense and benefits and regulatory compliance costs), inflation and other factors, that exceed increases in ASB’ s net interest, fee and other income; and


•	the ability of ASB to maintain or increase the level of deposits, ASB’s lowest costing funds.

Banking and related regulations could result in significant restrictions being imposed on ASB’s business or in a requirement that HEI divest ASB. ASB is subject to examination and comprehensive regulation by the Department of Treasury, the OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. In addition, the FRB is responsible for regulating ASB’s holding companies, HEI and ASB Hawaii. The regulatory authorities have extensive discretion in connection with their supervisory and enforcement activities and examination policies to address not only ASB’s compliance with applicable banking laws and regulations, but also capital adequacy, asset quality, management ability and performance, earnings, liquidity and various other factors.

Under certain circumstances, including any determination that ASB’s relationship with HEI results in an unsafe and unsound banking practice, these regulatory authorities have the authority to restrict the ability of ASB to transfer assets and to make distributions to its shareholders (including payment of dividends to HEI), or they could seek to require HEI to sever its relationship with or divest its ownership of ASB. Payment by ASB of dividends to HEI may also be restricted by the OCC and FRB under its prompt corrective action regulations or its capital distribution regulations if ASB’s capital position deteriorates. In order to maintain its status as a QTL, ASB is required to maintain at least 65% of its assets in “qualified thrift investments.” Institutions that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI and HEI’s other subsidiaries would also be subject to restrictions, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. Federal legislation has also been proposed in the past that could result in a required divestiture of ASB. In the event of a required divestiture, federal law substantially limits the types of entities that could potentially acquire ASB.

Recent legislative and regulatory initiatives could have an adverse effect on ASB’s business. The Dodd-Frank Act, which became law in July 2010, has had a substantial impact on the financial services industry. The Dodd-Frank Act establishes a framework through which regulatory reform will be written and changes to statutes, regulations or regulatory policies could affect HEI and ASB in substantial and unpredictable ways. A major component of the Dodd-Frank Act is the creation of the Consumer Financial Protection Bureau that has the responsibility for setting and enforcing clear, consistent rules relating to consumer financial products and services and has the authority to prohibit practices it finds to be unfair, deceptive or abusive.

Compliance with any such directives could have adverse effects on ASB’s revenues or operating costs. Failure to comply with laws, regulations or policies could result in sanctions by regulatory agencies, civil money penalties and/or reputation damage, which could have a material adverse effect on ASB’s business, results of operations, financial condition and liquidity.

A large percentage of ASB’s loans and securities are collateralized by real estate, and adverse changes in the real estate market and/or general economic or other conditions may result in loan losses and adversely affect the Company’s profitability. As of December 31, 2015 approximately 81% of ASB’s loan portfolio was comprised of loans primarily collateralized by real estate, most of which was concentrated in the State of Hawaii. Growth has been in the commercial real estate loan portfolio which now comprises 18% of total real estate loans. ASB’s financial results may be adversely affected by changes in prevailing economic conditions, either nationally or in the state of Hawaii, including decreases in real estate values, adverse employment conditions, the monetary and fiscal policies of the federal and state government and other significant external events. Adverse changes in the economy may have a negative effect on the ability of borrowers to make timely repayments of their loans. A deterioration of the economic environment in Hawaii, including a material decline in the real estate market, further declines in home resales, or a material external shock, or any environmental clean-up obligation, may also significantly impair the value of ASB’s collateral and ASB’s ability to sell the collateral upon foreclosure. In the event of a default, amounts received upon sale of the collateral may be insufficient to recover outstanding principal and interest. In addition, if poor economic conditions result in decreased demand for real estate loans, ASB’s profits may decrease if its alternative investments earn less income than real estate loans.

ASB’s strategy to expand its commercial and commercial real estate lending activities may result in higher service costs and greater credit risk than residential lending activities due to the unique characteristics of these markets. ASB has been aggressively pursuing a strategy that includes expanding its commercial and commercial real estate lines of business. ASB's commercial real estate loan portfolio grew by 30% during 2015 and now comprises 15% of total loans. These types of loans generally entail higher underwriting and other service costs and present greater credit risks than traditional residential mortgages.

Generally, both commercial and commercial real estate loans have shorter terms to maturity and earn higher spreads than residential mortgage loans. Only the assets of the business typically secure commercial loans. In such cases, upon default, any collateral repossessed may not be sufficient to repay the outstanding loan balance. In addition, loan collections are dependent on the borrower’s continuing financial stability and, thus, are more likely to be affected by current economic conditions and adverse business developments.

ASB has grown its national syndicated lending portfolio where ASB is a participant in credit facilities agented by established and reputable national lenders. Management selectively chooses each deal based on conservative credit criteria to ensure a high quality, well diversified portfolio.

Commercial real estate properties tend to be unique and are more difficult to value than residential real estate properties. Commercial real estate loans may not be fully amortizing, meaning that they may have a significant principal balance or “balloon” payment due at maturity. In addition, commercial real estate properties, particularly industrial and warehouse properties, are generally subject to relatively greater environmental risks than noncommercial properties and to the corresponding burdens and costs of compliance with environmental laws and regulations. Also, there may be costs and delays involved in enforcing rights of a property owner against tenants in default under the terms of leases with respect to commercial properties. For example, a tenant may seek the protection of bankruptcy laws, which could result in termination of the tenant’s lease.



ITEM 1B.	UNRESOLVED STAFF COMMENTS

HEI: None.

Hawaiian Electric: Not applicable.



ITEM 2.	PROPERTIES

HEI and Hawaiian Electric: See the “Properties” sections under “HEI,” “Electric utility” and “Bank” in Item 1. Business above.



ITEM 3.	LEGAL PROCEEDINGS

HEI and Hawaiian Electric: HEI subsidiaries (including Hawaiian Electric and its subsidiaries and ASB) may be involved in ordinary routine PUC proceedings, environmental proceedings and/or litigation incidental to their respective businesses. The Company is involved in PUC proceedings and litigation related to the proposed Merger. See the descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in “Item 1. Business,” in HEI’s MD&A and in the Notes 2 (which includes a discussion of PUC proceedings and litigation related to the Merger), 4 and 5 of the Consolidated Financial Statements. The outcomes of litigation and administrative proceedings are necessarily uncertain and there is a risk that the outcome of such matters could have a material adverse effect on the financial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a particular period in the future.



ITEM 4.	MINE SAFETY DISCLOSURES

HEI and Hawaiian Electric: Not applicable.

PART II



ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

HEI:

Certain of the information required by this item is incorporated herein by reference to Note 14, “Regulatory restrictions on net assets” and Note 18, “Quarterly information (unaudited)” of the Consolidated Financial Statements and "Item 6. Selected Financial Data” and “Equity compensation plan information” under "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" of this Form 10-K. Certain restrictions on dividends and other distributions of HEI are described in this report under “Item 1. Business—HEI—Regulation—Restrictions on dividends and other distributions” and that description is incorporated herein by reference. HEI’s common stock is traded on the New York Stock Exchange and the total number of holders of record of HEI common stock (i.e., registered shareholders) as of February 12, 2016, was 6,885.

Purchases of HEI common shares were made during the fourth quarter to satisfy the requirements of certain plans as follows:

ISSUER PURCHASES OF EQUITY SECURITIES



Period*	(a) Total Number of Shares Purchased **	(b) Average Price Paid per Share **		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to 31, 2015	17,262	$	29.34	—	NA
November 1 to 30, 2015	13,883	$	28.71	—	NA
December 1 to 31, 2015	240,274	$	28.35	—	NA

NA Not applicable.

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

** The purchases were made to satisfy the requirements of the DRIP, the HEIRSP and the ASB 401(k) Plan for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP, the HEIRSP and the ASB 401(k) Plan. Of the shares listed in column (a), 16,262 of the 17,262 shares, all of the 13,883 shares and 214,474 of the 240,274 shares were purchased for the DRIP; 21,600 of the 240,274 shares were purchased for the HEIRSP; and 1,000 of the 17,262 shares and 4,200 of the 240,274 shares were purchased for the ASB 401(k) Plan. The repurchased shares were issued for the accounts of the participants under registration statements registering the shares issued under these plans.

Hawaiian Electric:

Since a corporate restructuring on July 1, 1983, all the common stock of Hawaiian Electric has been held solely by its parent, HEI, and is not publicly traded. Accordingly, information required with respect to “Market information” and “holders” is not applicable to Hawaiian Electric.

The dividends declared and paid on Hawaiian Electric’s common stock for the quarters of 2015 and 2014 were as follows:



Quarters ended	2015		2014
March 31	$	22,601,504	$	22,706,842
June 30	22,601,504		21,539,126
September 30	22,601,504		22,122,984
December 31	22,601,503		22,122,984

Also, see “Liquidity and capital resources” in HEI’s MD&A.

See the discussion of regulatory and other restrictions on dividends or other distributions under “Item 1. Business—HEI—Regulation—Restrictions on dividends and other distributions” and in Note 14 of the Consolidated Financial Statements.



ITEM 6.	SELECTED FINANCIAL DATA

HEI:



Selected Financial Data
Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 31	2015			2014			2013			2012			2011
(dollars in thousands, except per share amounts)
Results of operations
Revenues	$	2,602,982		$	3,239,542		$	3,238,470		$	3,374,995		$	3,242,335
Net income for common stock	$	159,877		$	168,129		$	161,709		$	138,705		$	137,808
Basic earnings per common share	$	1.50		$	1.65		$	1.63		$	1.43		$	1.44
Diluted earnings per common share	$	1.50		$	1.63		$	1.62		$	1.42		$	1.44
Return on average common equity	8.6		%	9.6		%	9.7		%	8.9		%	9.2		%
Financial position *
Total assets	$	11,790,196		$	11,185,142		$	10,340,906		$	10,150,055		$	9,595,310
Deposit liabilities	5,025,254			4,623,415			4,372,477			4,229,916			4,070,032
Other bank borrowings	328,582			290,656			244,514			195,926			233,229
Long-term debt, net	1,586,546			1,506,546			1,492,945			1,422,872			1,340,070
Preferred stock of subsidiaries – not subject to mandatory redemption	34,293			34,293			34,293			34,293			34,293
Common stock equity	1,927,640			1,790,573			1,726,406			1,593,008			1,527,802
Common stock
Book value per common share *	$	17.94		$	17.46		$	17.05		$	16.27		$	15.91
Market price per common share
High	34.86			35.00			28.30			29.24			26.79
Low	27.02			22.71			23.84			23.65			20.59
December 31	28.95			33.48			26.06			25.14			26.48
Dividends per common share	1.24			1.24			1.24			1.24			1.24
Dividend payout ratio	82		%	75		%	76		%	87		%	86		%
Market price to book value per common share *	161		%	192		%	153		%	155		%	166		%
Price earnings ratio **	19.3x			20.3		x	16.0		x	17.6		x	18.4		x
Common shares outstanding (thousands) *	107,460			102,565			101,260			97,928			96,038
Weighted-average	106,418			101,968			98,968			96,908			95,510
Shareholders ***	27,927			29,415			30,653			31,349			32,004
Employees *	3,918			3,965			3,966			3,870			3,654


*	At December 31.


**	Calculated using December 31 market price per common share divided by basic earnings per common share. The principal trading market for HEI’s common stock is the New York Stock Exchange (NYSE).


***	At December 31. Represents registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) who are not registered shareholders. As of February 12, 2016, HEI had 6,885 registered shareholders (i.e., holders of record of HEI common stock), 24,611 DRIP participants and total shareholders of 27,829.

Financial data for prior periods has been updated to reflect the retrospective application of Accounting Standards Update (ASU) No. 2014-01. See Note 1 for a discussion of, and the impact to certain prior period financial data of, the adoption of ASU No. 2014-01. See Note 2 and “Commitments and contingencies” in Note 4 of the Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions of certain contingencies that could adversely affect future results of operations and factors that affected reported results of operations.

For 2014, 2013, 2012 and 2011, under the two-class method of computing basic earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.41, $0.39, $0.19 and $0.21 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For 2014, 2013, 2012 and 2011, under the two-class method of computing diluted earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.40, $0.38, $0.18 and $0.20 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. There were no restricted stock awards outstanding during 2015.

Hawaiian Electric:

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013			2012			2011
(in thousands)
Results of operations
Revenues	$	2,335,166		$	2,987,323		$	2,980,172		$	3,109,439		$	2,978,690
Net income for common stock	135,714			137,641			122,929			99,276			99,986

Financial position *
Utility plant	$	6,543,799		$	6,220,397		$	5,896,991		$	5,567,346		$	5,242,379
Accumulated depreciation	(2,266,004		)	(2,175,510		)	(2,111,229		)	(2,040,789		)	(1,966,894		)
Net utility plant	$	4,277,795		$	4,044,887		$	3,785,762		$	3,526,557		$	3,275,485
Total assets	$	5,680,054		$	5,557,542		$	5,066,427		$	5,108,793		$	4,674,007
Current portion of long-term debt	$	—		$	—		$	11,400		$	—		$	57,500
Long-term debt, net	1,286,546			1,206,546			1,206,545			1,147,872			1,000,570
Common stock equity	1,728,325			1,682,144			1,593,564			1,472,136			1,402,841
Cumulative preferred stock-not subject to mandatory redemption	34,293			34,293			34,293			34,293			34,293
Capital structure	$	3,049,164		$	2,922,983		$	2,845,802		$	2,654,301		$	2,495,204
Capital structure ratios (%)
Debt (short-term debt, which is nil, and long-term debt, net, including current portion)	42.2			41.3			42.8			43.2			42.4
Cumulative preferred stock	1.1			1.2			1.2			1.3			1.4
Common stock equity	56.7			57.5			56			55.5			56.2


*	At December 31.

HEI owns all of Hawaiian Electric’s common stock. Therefore, per share data is not meaningful.

See Note 1 for a discussion of, and the impact to certain prior period financial data of, the adoption of ASU No. 2015-17.

See "Forward-Looking Statements" above, the “electric utility” sections and all information related to, or including, Hawaiian Electric and its subsidiaries in HEI’s MD&A and Note 2 and “Commitments and contingencies” in Note 4 of the Consolidated Financial Statements for discussions of certain contingencies that could adversely affect future results of operations, financial condition and cash flows.



ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

HEI and Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries):

The following discussion should be read in conjunction with the Consolidated Financial Statements. The general discussion of HEI’s consolidated results should be read in conjunction with the electric utility and bank segment discussions that follow.

HEI Consolidated

Proposed Merger. On December 3, 2014, HEI, NEE, Merger Sub II and Merger Sub I entered into an Agreement and Plan of Merger. The Merger Agreement provides for Merger Sub I to merge with and into HEI, with HEI surviving, and then for HEI to merge with and into Merger Sub II, with Merger Sub II surviving as a wholly owned subsidiary of NEE (the Merger). The Merger Agreement provides that, prior to completion of the Merger, HEI will distribute to its shareholders, on a pro-rata basis, all of the issued and outstanding shares of ASB Hawaii, Inc. (ASB Hawaii), parent company of ASB (the Spin-Off). The closing of the Merger is subject to various conditions, including federal and state regulatory approvals. For additional information concerning the proposed merger, see Note 2 of the Consolidated Financial Statements.

Executive overview and strategy. HEI is a holding company that operates subsidiaries (collectively, the Company), principally in Hawaii’s electric utility and banking sectors. HEI’s strategy is to build fundamental earnings and profitability of its electric utilities and bank in a controlled risk manner to support its current dividend and improve operating and capital efficiency in order to build shareholder value.

HEI, through its electric utility subsidiaries (Hawaiian Electric and its subsidiaries, Hawaii Electric Light and Maui Electric), provides the only electric public utility service to approximately 95% of Hawaii’s population. HEI also provides a wide array of banking and other financial services to consumers and businesses through its bank subsidiary, ASB, one of Hawaii’s largest financial institutions based on total assets. Together, HEI’s unique combination of electric utilities and a bank continues to provide the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries while providing an attractive dividend for investors.

In 2015, net income for HEI common stock was $160 million, down 5% from $168 million in 2014 primarily due to the $10 million higher net loss at the “other” segment resulting from higher merger-related costs and the Utilities’ 1% lower net income. ASB had 7% higher net income in 2015 compared to 2014. Basic earnings per share were $1.50 per share in 2015, down 9% from $1.65 per share in 2014.

The Utilities’ strategic focus has been to meet Hawaii’s energy needs by modernizing and adding needed infrastructure through capital investment, placing emphasis on energy efficiency and conservation, pursuing renewable energy generation and taking the necessary steps to secure regulatory support for their plans. Electric utility net income for common stock in 2015 of $136 million, decreased from the prior year by 1% due primarily to higher depreciation expense (as a result of increasing investments for the integration of more renewable energy, improved customer reliability and greater system efficiency) and higher O&M expenses (impacted by a regulatory decision denying recovery of enterprise resource planning software costs, additional reserves for environmental costs and higher employee benefit costs, partly offset by higher 2014 costs for initial phase smart grid installations), partly offset by the recovery of costs for clean energy and reliability investments

ASB continues to develop and introduce new products and services in order to meet the needs of both consumer and commercial customers. Additionally, ASB is making investments in electronic banking platforms, data and risk management capabilities and process improvements to deliver a continuously better experience for its customers, healthy growth and a more efficient bank. ASB’s earnings in 2015 of $55 million increased $3 million compared to prior year net income due primarily to higher net interest income and higher noninterest income, partly offset by higher noninterest expenses. In 2015, ASB earnings benefited from higher net interest income as interest income from loan and investment growth were funded primarily by low cost deposit liabilities, higher mortgage banking income and higher deposit-related fee initiatives. These increases were partly offset by higher noninterest expenses due primarily to higher pension and benefits expenses. ASB’s future financial results will continue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio.

HEI’s “other” segment had a net loss in 2015 of $30.6 million, compared to a net loss of $20.8 million in 2014. In 2015, HEI incurred $10 million higher expenses related to the proposed merger (net of taxes).

Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, Hawaiian Electric, have paid dividends continuously since 1901. The dividend has been stable at $1.24

per share annually since 1998. The indicated dividend yield as of December 31, 2015 was 4.3%. The dividend payout ratios based on net income for common stock for 2015, 2014 and 2013 were 82%, 75% and 76%, respectively. The HEI Board of Directors considers many factors in determining the dividend quarterly, 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.

HEI’s subsidiaries from time to time consider various strategies designed to enhance their competitive positions and to maximize shareholder value. Management cannot predict whether any of these strategies or transactions will be carried out or, if so, whether they will be successfully implemented. See "Proposed merger" above.

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 2015 with record highs in both visitor spending and arrivals for the fourth consecutive year. Visitor expenditures increased 2.3% and arrivals increased 4.1% compared to the same time period in 2014. Looking ahead, the Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the first quarter of 2016 to increase by 2.4% over the first quarter of 2015 driven primarily by a 4.2% increase in domestic seats.

Hawaii’s unemployment rate continued to decline to 3.2% in December 2015, lower than the state’s 4.0% rate in December 2014 and the December 2015 national unemployment rate of 5.0%.

Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices in 2015. Median sales prices for single family residential homes and condominiums on Oahu increased 3.7% and 2.9%, respectively, over 2014. The number of closed sales also increased from 2014. Closed sales for both single family residential homes and condominiums were up compared to 2014, 5.2% and 4.5% respectively.

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 second quarter of 2015, prices of all petroleum fuels recovered from an initial decline during the first quarter of 2015. However, prices then subsequently declined during the third and fourth quarters of 2015, falling sharply to levels not seen since 2009.

At its December 2015 meeting, the Federal Open Market Committee (FOMC) increased the federal funds rate target from 0.25% to 0.5% for the first time in seven years. The FOMC stated there had been considerable positive improvement in labor market conditions which lead to the rate adjustment. They will continue to assess the timing and size of future adjustments in light of its objectives of a continued improved labor market and a movement back to 2% inflation.

Overall, Hawaii’s economy is expected to see positive growth in 2016. Tourism had another record year in 2015, and added service by Virgin America will expand capacity through 2016. However, continued weakening in the Canadian dollar and the yen could negatively affect both spending and visitors, dampening any impact from expanded domestic capacity. Lower energy costs could also provide a boost to the economy if energy costs remain near the low levels experienced in the latter part of 2015. Conversely, military troop reductions stationed in Hawaii could negatively impact the economy. Near-term, known reductions are mostly offset by transfers from other military bases in the Pacific region. Further reductions in the military are planned in 2017 and 2018, but it is not yet known if those reductions will negatively impact Hawaii bases. Additional risks to local economic growth include volatility to global economies and their impact on the local real estate and construction markets.

Recent tax developments. See Note 12 and Hawaiian Electric's consolidated income taxes refunded in Note 13 of the Consolidated Financial Statements.

Results of operations.



(dollars in millions, except per share amounts)	2015			% change		2014			% change		2013
Revenues	$	2,603		(20	)	$	3,240		—		$	3,238
Operating income	323			(3	)	333			5		318
Net income for common stock	160			(5	)	168			4		162
Net income (loss) by segment:
Electric utility	$	136		(1	)	$	138		12		$	123
Bank	55			7		51			(11	)	58
Other	(31		)	NM		(21		)	NM		(19		)
Net income for common stock	$	160		(5	)	$	168		4		$	162
Basic earnings per share	$	1.50		(9	)	$	1.65		1		$	1.63
Diluted earnings per share	$	1.50		(8	)	$	1.63		1		$	1.62
Dividends per share	$	1.24		—		$	1.24		—		$	1.24
Weighted-average number of common shares outstanding (millions)	106.4			4		102.0			3		99.0
Dividend payout ratio	82		%			75		%			76		%


NM	Not meaningful.

See “Executive overview and strategy” above and the “Other segment,” “Electric utility” and “Bank” sections below for discussions of results of operations.

Retirement benefits. The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions about future experience. For example, retirement benefits costs are impacted by actual employee demographics (including age and compensation levels), the level of contributions to the plans, plus earnings and realized and unrealized gains and losses on plan assets, and changes made to the provisions of the plans. (See Note 10 of the Consolidated Financial Statements.) Costs may also be significantly affected by changes in key actuarial assumptions, including the expected return on plan assets, the discount rate and mortality. The Company’s accounting for retirement benefits under the plans in which the employees of the Utilities participate is also adjusted to account for the impact of decisions by the Public Utilities Commission of the State of Hawaii (PUC). Changes in obligations associated with the factors noted above may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants.

The assumptions used by management in making benefit and funding calculations are based on current economic conditions. Changes in economic conditions will impact the underlying assumptions in determining retirement benefits costs on a prospective basis.

For 2015, the Company’s retirement benefit plans’ assets generated a loss of 1.2%, including investment management fees, resulting in net losses and unrealized losses of $17 million, compared to net earnings and unrealized gains of $90 million for 2014 and $223 million for 2013. The market value of the retirement benefit plans’ assets for December 31, 2015 and 2014 was $1.4 billion.

The Company intends to make contributions to the qualified pension plan for HEI and Hawaiian Electric equal to the calculated net periodic pension cost for the year. However, if the minimum required contribution determined under the Employee Retirement Income Security Act of 1974 (ERISA), as amended by the Pension Protection Act of 2006, for the year is greater than the net periodic pension cost, then the Company will contribute the minimum required contribution and the Utilities’ difference between the minimum required contribution and the net periodic pension cost will increase their regulatory asset. In the next rate case, the regulatory asset will be amortized over five years and used to reduce the cash funding requirement based on net periodic pension cost. The regulatory asset may not be applied against the ERISA minimum required contribution.

The net periodic pension cost is expected to be higher than the ERISA minimum required contribution for 2016. Therefore, to satisfy the requirements of the electric utilities’ pension tracking mechanism, net periodic pension cost will be the basis of the cash funding for 2016. Based on plan assets as of December 31, 2015 and various assumptions in Note 10 of the Consolidated Financial Statements, the Company estimates the net periodic pension cost contribution for 2016 will be $65 million ($1 million for HEI and $64 million for the Utilities).

Based on various assumptions in Note 10 of the Consolidated Financial Statements and assuming no further changes in retirement benefit plan provisions, information regarding consolidated HEI’s and consolidated Hawaiian Electric’s retirement benefits was, or is estimated to be, as follows, and constitutes “forward-looking statements:”



	AOCI debit/(credit), net of taxes (benefits), related to retirement benefits liability					Retirement benefits expense, net of tax benefits								Retirement benefits paid and plan expenses
	December 31					Years ended December 31								Years ended December 31
(in millions)	2015			2014		(Estimated) 2016		2015		2014		2013		2015		2014		2013
Consolidated HEI	$	24		$	28	$	20	$	22	$	20	$	21	$	76	$	71	$	70
Consolidated Hawaiian Electric	(1		)	—		18		18		19		18		71		66		65

Based on various assumptions in Note 10 of the Consolidated Financial Statements, sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2015, associated with a change in certain actuarial assumptions, were as follows and constitute “forward-looking statements.”



Actuarial assumption	Change in assumption in basis points	Impact on HEI Consolidated PBO or APBO	Impact on Consolidated Hawaiian Electric PBO or APBO
(dollars in millions)
Pension benefits
Discount rate	'+/- 50	$(129)/$146	$(119)/$135
Other benefits
Discount rate	'+/- 50	(14)/16	(14)/15
Health care cost trend rate	'+/- 100	4/(4)	4/(4)

See Note 10 of the Consolidated Financial Statements for further retirement benefits information.

Other segment.



(dollars in millions)	2015		% change	2014		% change	2013
Revenues	$ –		NM	$ –		NM	$ –
Operating loss	(35	)	NM	(22	)	NM	(17	)
Net loss	(31	)	NM	(21	)	NM	(19	)


NM	Not meaningful.

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

HEI corporate-level operating, general and administrative expenses were $34 million in 2015 compared to $21 million in 2014 and $16 million in 2013. In 2015 and 2014, HEI had approximately $17 million (including $7 million of legal expenses and $5 million of investment banking fees) and $5 million, respectively, of expenses related to the proposed merger.

The “other” segment’s interest expenses were $11 million in 2015, $12 million in 2014 and $16 million in 2013. In 2015 and 2014, HEI had lower average interest rates, partly offset by the impact of higher average borrowings, than 2013. In 2015, HEI had lower average borrowings than 2014 and a $125 million Eurodollar term loan was amended at improved pricing. In 2014, a 6.51% medium-term note of $100 million was paid off and a $125 million Eurodollar term loan (at rates ranging from 1.12% to 1.14% through December 31, 2014) was drawn. The “other” segment’s income tax benefits were $16 million in 2015, $13 million in 2014 and $14 million in 2013.

Effects of inflation. U.S. inflation, as measured by the U.S. Consumer Price Index (CPI), averaged 0.1% in 2015, 1.6% in 2014 and 1.5% in 2013. Hawaii inflation, as measured by the Honolulu CPI, was 1.0% in 2015, 1.4% in 2014 and 1.8% in 2013.

Inflation continues to have an impact on HEI’s operations. Inflation increases operating costs and the replacement cost of assets. Subsidiaries with significant physical assets, such as the electric utilities, replace assets at much higher costs and must

request and obtain rate increases to maintain adequate earnings. In the past, the PUC has granted rate increases in part to cover increases in construction costs and operating expenses due to inflation.

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of the Consolidated Financial Statements.

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 Company’s total assets were $11.8 billion as of December 31, 2015 and $11.2 billion as of December 31, 2014.

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



December 31	2015				2014
(dollars in millions)
Short-term borrowings—other than bank	$	103	3	%	$	119	3	%
Long-term debt, net—other than bank	1,587		43		1,506		44
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,928		53		1,791		52
	$	3,652	100	%	$	3,450	100	%

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



	Year ended December 31, 2015
(in millions)	Average balance		End-of-period balance		December 31, 2014
Short-term borrowings ¹
Commercial paper	$	58	$	103	$	119
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility	150		150		150

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.” At February 12, 2016, HEI’s outstanding commercial paper balance was $95 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2015 was $134 million.

HEI utilizes short-term debt, typically commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt, to pay dividends and for other temporary requirements. HEI also periodically makes short-term loans to Hawaiian Electric to meet Hawaiian Electric’s cash requirements, including the funding of loans by Hawaiian Electric to Hawaii Electric Light and Maui Electric, but no such short-term loans to Hawaiian Electric were outstanding as of December 31, 2015. HEI periodically utilizes long-term debt, historically consisting of medium-term notes and other unsecured indebtedness, to fund investments in and loans to its subsidiaries to support their capital improvement or other requirements, to repay long-term and short-term indebtedness and for other corporate purposes.

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 9 of the Consolidated Financial Statements. In March 2015, HEI issued the 4.7 million shares remaining under the equity forward transaction 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. See Note 8 of the Consolidated Financial Statements for a brief description of the loan agreement.

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

HEI has a line of credit facility, as amended and restated on April 2, 2014, of $150 million. See Note 7 of the Consolidated Financial Statements.

The rating of HEI’s commercial paper and debt securities could significantly impact the ability of HEI to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities.

In January 2015, S&P reported the ratings of HEI (BBB-/Watch positive/A-3). S&P indicated that “[g]iven the proposed funding for the transaction (all equity and the assumption of existing debt), along with opportunities for growth for NextEra Energy, we expect to view HEI as a core subsidiary of NextEra Energy and therefore to raise the issuer credit rating (ICR) on HEI to be in line with that of NextEra Energy.”

In August 2015, Moody’s changed HEI’s rating outlook from stable to negative “due to concerns about the execution risk inherent in transforming its oil-dominated generation base to renewables.” Moody's stated that they could reevaluate HEI's rating or outlook upon the closing of the pending merger with NEE.

In December 2015, Fitch maintained HEI’s Issuer Default Rating (IDR) at BBB on Rating Watch Positive. “Fitch expects to resolve the Rating Watch on the conclusion of the merger transaction with NextEra Energy, Inc. (NEE), which is expected in the first half of 2016.” Fitch stated that “[o]nce the transaction is completed, HEI (or its successor within NEE) would become a first-tier holding company under NextEra Energy Capital Holdings, Inc. Fitch expects to equalize the IDR of HEI with that of HECO once the bank is spun off and the acquisition with NEE is completed. Over the long term, Fitch sees a bias toward positive rating actions for HECO and HEI under NEE’s ownership. In the event that the merger is not completed (not anticipated by Fitch), Fitch believes the credit profile of HECO and HEI remains robust.”

As of February 12, 2016, the Fitch, Moody's and S&P ratings of HEI were as follows:



	Fitch	Moody’s	S&P
Long-term issuer default and senior unsecured; senior unsecured; and corporate credit; respectively	BBB	Baa2	BBB-
Commercial paper	F3	P-2	A-3
Outlook	Watch-Positive	Negative	Watch-Positive

The above ratings reflect only the view, at the time the ratings are issued, 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.

Management believes that, if HEI’s commercial paper ratings were to be downgraded, or if credit markets for commercial paper with HEI’s ratings or in general were to tighten, it could be more difficult and/or expensive for HEI to sell commercial paper or HEI might not be able to sell commercial paper in the future. Such limitations could cause HEI to draw on its syndicated credit facility instead, and the costs of such borrowings could increase under the terms of the credit agreement as a result of any such ratings downgrades. Similarly, if HEI’s long-term debt ratings were to be downgraded, it could be more difficult and/or expensive for HEI to issue long-term debt. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of HEI and its subsidiaries.

Issuances of common stock through the Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan (DRIP), Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan provided new capital of $3 million (approximately 0.1 million shares) in 2014 and $48 million (approximately 1.8 million shares) in 2013. From March 6, 2014 through January 5, 2016, HEI satisfied the share purchase requirements of the DRIP, HEIRSP and ASB 401(k) Plan through open market purchases of its common stock rather than new issuances.

Operating activities provided net cash of $356 million in 2015, $325 million in 2014 and $362 million in 2013. Investing activities used net cash of $706 million in 2015, $592 million in 2014 and $598 million in 2013. In 2015, net cash used in investing activities was primarily due to a net increase in loans held for investment, Hawaiian Electric’s consolidated capital expenditures (net of contributions in aid of construction) and ASB's purchases of investment securities, partly offset by the repayments of investment securities, redemption of stock from Federal Home Loan Bank and sale of real estate held for sale. Financing activities provided net cash of $475 million in 2015, $223 million in 2014 and $237 million in 2013. In 2015, net cash provided by financing activities included net increases in deposits, retail repurchase agreements and long-term debt and proceeds from the issuance of common stock, partly offset by a decrease in short-term borrowings and payment of common and preferred stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), Hawaiian Electric’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective

“Financial condition–Liquidity and capital resources” sections below.) During 2015, Hawaiian Electric and ASB (through ASB Hawaii) paid cash dividends to HEI of $90 million and $30 million, respectively.

A portion of the net assets of Hawaiian Electric and ASB is not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval. One of the conditions to the PUC’s approval of the Merger and corporate restructuring of Hawaiian Electric and HEI requires that Hawaiian Electric maintain a consolidated common equity to total capitalization ratio of not less than 35% (actual ratio of 57% at December 31, 2015), and restricts Hawaiian Electric from making distributions to HEI to the extent it would result in that ratio being less than 35%. In the absence of an unexpected material adverse change in the financial condition of the electric utilities or ASB, such restrictions are not expected to significantly affect the operations of HEI, its ability to pay dividends on its common stock or its ability to meet its debt or other cash obligations. See Note 14 of the Consolidated Financial Statements.

Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2016 through 2018 consists primarily of the net capital expenditures of the Utilities. In addition to the funds required for the Utilities’ construction programs (see “Electric utility–Liquidity and capital resources”), approximately $200 million will be required during 2016 through 2018 to repay HEI senior notes of $75 million maturing in March 2016 and and HEI’s $125 million two-year term loan maturing in October 2017, which are expected to be repaid with the proceeds from the issuance of commercial paper, bank borrowings, other medium- or long-term debt, common stock and/or dividends from subsidiaries (assuming that the proposed Merger has not closed by the maturity dates). Additional debt and/or equity financing may be utilized to invest in the Utilities and bank; to pay down commercial paper or other short-term borrowings; or to fund unanticipated expenditures not included in the 2016 through 2018 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the Utilities, unanticipated utility capital expenditures that may be required by the HCEI or new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if certain tax positions taken by the Company do not prevail or if taxes are increased by federal or state legislation. In addition, existing debt may be refinanced prior to maturity with additional debt or equity financing (or both). Further, in anticipation of the possible completion of the Merger, the Company will make financing arrangements for the funding of additional transaction advisory fees and contingent payments through additional debt.

As further explained in “Retirement benefits” above and Notes 1 and 10 of the Consolidated Financial Statements, the Company maintains pension and OPEB plans. The Company’s contributions to the retirement benefit plans totaled $88 million in 2015 ($86 million by the Utilities, $2 million by HEI and nil by ASB), $60 million in 2014 ($59 million by the Utilities, $1 million by HEI and nil by ASB) and $83 million in 2013 ($81 million by the Utilities, $2 million by HEI and nil by ASB) and are expected to total $65 million in 2016 ($64 million by the Utilities, $1 million by HEI and nil by ASB). These contributions satisfied the minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006, and the requirements of the electric utilities’ pension and OPEB tracking mechanisms. In addition, the Company paid directly $1 million of benefits in 2015, $2 million in 2014 and $2 million in 2013 and expects to pay $2 million of benefits in 2016. With an increase in the discount rate at December 31, 2015 to 4.60% (from 4.22%) and a downward revision to the Mortality Improvement Scale used in calculating net periodic pension cost, it is estimated that the net periodic pension cost for 2016 will decline to $65 million (from $87 million in 2015) for the HEI Retirement Plan. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The Company believes it will have adequate cash flow or access to capital resources to support any necessary funding requirements.

Selected contractual obligations and commitments. Information about payments under the specified contractual obligations and commercial commitments of HEI and its subsidiaries was as follows:



December 31, 2015
(in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Contractual obligations
Investment in qualifying affordable housing projects	$	6	$	4	$	—	$	—	$	10
Time certificates	197		137		138		3		475
Other bank borrowings	215		114		—		—		329
Long-term debt	75		175		96		1,241		1,587
Interest on certificates of deposit, other bank borrowings and long-term debt	80		148		138		798		1,164
Operating leases, service bureau contract, maintenance and ASB construction-related agreements	35		43		26		29		133
Hawaiian Electric open purchase order obligations¹	89		12		2		1		104
Hawaiian Electric fuel oil purchase obligations (estimate based on December 31, 2015 fuel oil prices)	245		4		—		—		249
Hawaiian Electric power purchase obligations–minimum fixed capacity charges	107		190		194		497		988
Liabilities for uncertain tax positions	—		4		—		—		4
Total (estimated)	$	1,049	$	831	$	594	$	2,569	$	5,043


¹	Includes contractual obligations and commitments for capital expenditures and expense amounts.

The tables above do not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans, obligations that may arise under indemnities provided to purchasers of discontinued operations, potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism) and additional transaction advisory fees and contingent payments related to the proposed merger (approximately $24 million). As of December 31, 2015, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the tables above; however, see “Retirement benefits” above for estimated minimum required contributions for 2016.

See Note 4 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments. See Note 5 of the Consolidated Financial Statements for a further discussion of ASB's commitments.

Off-balance sheet arrangements. Although the Company has off-balance sheet arrangements, management has determined that it has no off-balance sheet arrangements that either have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors, including the following types of off-balance sheet arrangements:


1.	obligations under guarantee contracts,


2.	retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serve as credit, liquidity or market risk support to that entity for such assets,


3.	obligations under derivative instruments, and


4.	obligations under a material variable interest held by the Company in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.

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 its control and could cause future results of operations to differ materially from historical results. The following is a discussion of certain of these factors. Also see “Forward-Looking Statements” and “Risk Factors” above and “Certain factors that may affect future results and financial condition” in each of the electric utility and bank segment discussions below.

Proposed Merger. On December 3, 2014, HEI, NEE, Merger Sub II and Merger Sub I entered into an Agreement and Plan of Merger. The Merger Agreement provides that, prior to completion of the Merger, HEI will distribute to its shareholders, on a pro-rata basis, all of the issued and outstanding shares of ASB Hawaii (parent company of ASB). In addition, the Merger Agreement contemplates that, immediately prior to the closing of the Merger, HEI will pay its shareholders a special dividend of $0.50 per share. At the effective time of the Merger, shares of HEI common stock will be converted into shares of NEE

common stock and HEI shareholders will become stockholders of NEE. The closing of the Merger is subject to various conditions, including federal and state regulatory approvals. See Note 2 of the Consolidated Financial Statements and “Risk Factors Related to the Merger” above.

Economic conditions, U.S. capital markets and credit and interest rate environment. Because the core businesses of HEI’s subsidiaries are providing local electric public utility services and banking services in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates, particularly on the construction and real estate industries, and by the impact of world conditions on federal government spending in Hawaii. The two largest components of Hawaii’s economy are tourism and the federal government (including the military).

If Fitch, Moody's or S&P were to downgrade HEI’s or Hawaiian Electric’s debt ratings, or if future events were to adversely affect the availability of capital to the Company, HEI’s and Hawaiian Electric’s ability to borrow and raise capital could be constrained and their future borrowing costs would likely increase.

Changes in the U.S. capital markets can also have significant effects on the Company. For example, pension funding requirements are affected by the market performance of the assets in the master pension trust and by the discount rate used to estimate the service and interest cost components of net periodic pension cost and value obligations. The Utilities’ pension tracking mechanisms help moderate pension expense; however, a decline in the value of the Company’s defined benefit pension plan assets may increase the unfunded status of the Company’s pension plans and result in increases in future funding requirements.

Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. Changes in interest rates and credit spreads also affect the fair value of ASB’s investment securities. HEI and its electric utility subsidiaries are also exposed to interest rate risk primarily due to their periodic borrowing requirements, the discount rate used to determine pension funding requirements and the possible effect of interest rates on the electric utilities’ rates of return and overall economic activity. Interest rates are sensitive to many factors, including general economic conditions and the policies of government and regulatory authorities. HEI cannot predict future changes in interest rates, nor be certain that interest rate risk management strategies it or its subsidiaries have implemented will be successful in managing interest rate risk.

Limited insurance. In the ordinary course of business, the Company purchases insurance coverages (e.g., property and liability coverages) to protect itself against loss of or damage to its properties and against claims made by third-parties and employees for property damage or personal injuries. However, the protection provided by such insurance is limited in significant respects and, in some instances, the Company has no coverage. The Utilities’ transmission and distribution systems (excluding substation buildings and contents) have a replacement value roughly estimated at $7 billion and are largely uninsured. Similarly, the Utilities have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the Utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations, financial condition and liquidity could be materially adversely impacted. Certain of the Company’s insurance has substantial “deductibles” or has limits on the maximum amounts that may be recovered. Insurers also have exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business each of which were subject to an insurance deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the Company could incur uninsured losses in amounts that would have a material adverse effect on the Company’s results of operations, financial condition and liquidity.

Environmental matters. HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. These laws and regulations, among other things, may require that certain environmental permits be obtained and maintained as a condition to constructing or operating certain facilities. Obtaining such permits can entail significant expense and cause substantial construction delays. Also, these laws and regulations may be amended from time to time, including amendments that increase the burden and expense of compliance.

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.

Material estimates that are particularly susceptible to significant change include the amounts reported for pension and other postretirement benefit obligations; contingencies and litigation; income taxes; property, plant and equipment; regulatory assets and liabilities; electric utility revenues; allowance for loan losses; nonperforming loans; troubled debt restructurings; and fair

value. Management considers an accounting estimate to be material if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the assumptions selected could have a material impact on the estimate and on the Company’s results of operations or financial condition.

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 the policies discussed below 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. The policies affecting both of the Company’s two principal segments are discussed below and the policies affecting just one segment are discussed in the respective segment’s section of “Material estimates and critical accounting policies.” Management has reviewed the material estimates and critical accounting policies with the HEI Audit Committee and, as applicable, the Hawaiian Electric Audit Committee.

For additional discussion of the Company’s accounting policies, see Note 1 of the Consolidated Financial Statements and for additional discussion of material estimates and critical accounting policies, see the electric utility and bank segment discussions below under the same heading.

Pension and other postretirement benefits obligations. For a discussion of material estimates related to pension and other postretirement benefits (collectively, retirement benefits), including costs, major assumptions, plan assets, other factors affecting costs, accumulated other comprehensive income (loss) (AOCI) charges and sensitivity analyses, see “Retirement benefits” in “Consolidated—Results of operations” above and Notes 1 and 10 of the Consolidated Financial Statements.

Contingencies and litigation. The Company is subject to proceedings (including PUC proceedings), lawsuits and other claims. Management assesses the likelihood of any adverse judgments in or outcomes of these matters as well as potential ranges of probable losses, including costs of investigation. A determination of the amount of reserves required, if any, for these contingencies is based on an analysis of each individual case or proceeding often with the assistance of outside counsel. The required reserves may change in the future due to new developments in each matter or changes in approach in dealing with these matters, such as a change in settlement strategy.

In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered through future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale.

See Notes 2, 4 and 5 of the Consolidated Financial Statements.

Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities using tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Management evaluates its potential exposures from tax positions taken that have or could be challenged by taxing authorities. These potential exposures result because taxing authorities may take positions that differ from those taken by management in the interpretation and application of statutes, regulations and rules. Management considers the possibility of alternative outcomes based upon past experience, previous actions by taxing authorities (e.g., actions taken in other jurisdictions) and advice from its tax advisors. Management believes that the Company’s provision for tax contingencies is reasonable. However, the ultimate resolution of tax treatments disputed by governmental authorities may adversely affect the Company’s current and deferred income tax amounts.

See Note 12 of the Consolidated Financial Statements.

Following are discussions of the electric utility and bank segments. Additional segment information is shown in Note 2 of the Consolidated Financial Statements. The discussion concerning Hawaiian Electric should be read in conjunction with its consolidated financial statements and accompanying notes.

Electric utility

Executive overview and strategy. The Utilities provide electricity on all the principal islands in the state other than Kauai and operate on five separate grids. The Utilities’ strategic focus is meeting Hawaii’s energy needs in a reliable, economical and environmentally sound way by modernizing the electric grid, maximizing the use of low-cost, clean energy sources, sustaining an effective asset management program and promoting smart use of energy by customers through information and choices. The Utilities are focused on helping Hawaii achieve its statutory goal of 40% of electricity from clean, locally-generated sources by 2030.

Utility strategic progress. The Utilities continue to make significant progress in implementing their renewable energy strategies to support Hawaii’s efforts to reduce its dependence on oil. The PUC issued several important regulatory decisions during the last few years, including a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below).

On August 26, 2014, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed proposed power supply improvement and interconnection plans 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). Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), and switch from high-priced oil to lower cost liquefied natural gas.

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

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

The Utilities are pursuing the transition to renewable energy in a manner that will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel, ensure reliable service as more intermittent renewables are integrated to the grid and enable more options for customers as distributed technologies advance. To achieve 100% renewables by 2045, the Utilities seek to achieve a diversified mix of renewable resources, including utility scale and distributed resources. Under the state’s renewable energy strategy, there has been exponential growth in recent years in variable generation (e.g. solar and wind) on Hawaii’s island grids. As more generating resources are added to the Utilities' electric systems and as customers reduce their energy usage, the ability to accommodate additional generating resources and to accept energy from existing resources is becoming more challenging. As a result, there is a growing risk that energy production from generating resources may need to be curtailed and the interconnection of additional resources will need to be closely evaluated. Much of this variable generation is in the form of distributed generators interconnected at distribution circuits that cannot be directly controlled by system operators. As a consequence, grid resiliency in response to events that cause significant frequency and/or voltage excursions has weakened, and the prospects for larger and more frequent service outages have increased. As part of its transition, the Utilities have been progressively making changes in their operating practices, are making investments in grid modernization technologies, and are working with the solar industry to mitigate these risks and continue the integration of more renewable energy.

The Utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas (LNG) as a cleaner and lower cost fuel as transition fuel for some generation as the Utilities move from oil to renewable energy. Since 2014 the Utilities have been evaluating delivering LNG in specialized shipping containers to their generating stations on a transitional basis, an approach that requires minimal on-island infrastructure. In March 2014, Hawaiian Electric issued a RFP for the supply of containerized LNG and is currently in negotiations to resolve key contractual provisions with the preferred bidder. In August 2015, Hawaii State Governor Ige voiced his opposition to LNG as a replacement fuel for power generation citing (a) the high infrastructure costs, (b) permitting requirements as primary obstacles and (c) the potential to distract Hawaii from achieving the State's renewable energy goals. The Utilities are working to align their containerized LNG

plans with the State’s directives and plan on finalizing LNG fuel agreements in the first quarter of 2016. The Utilities would seek approval from the PUC for the fuel agreement(s) and for the commitment of funds for related capital improvements shortly thereafter.

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. The Utilities are planning to seek approval from the PUC in the first quarter of 2016 to commit funds for an expansion of the smart grid project, including at Hawaii Electric Light and Maui Electric.

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



%	Return on rate base (RORB)*						ROACE**						Rate-making ROACE***
Year ended December 31, 2015	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric
Utility returns	7.39		6.58		7.19		8.02		7.22		8.52		9.20		7.49		8.76
PUC-allowed returns	8.11		8.31		7.34		10.00		10.00		9.00		10.00		10.00		9.00
Difference	(0.72	)	(1.73	)	(0.15	)	(1.98	)	(2.78	)	(0.48	)	(0.80	)	(2.51	)	(0.24	)

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

** Recorded net income divided by average common equity.

*** ROACE adjusted to remove items not included by the PUC in establishing rates, such as incentive compensation and certain advertising.

The approval of decoupling by the PUC has helped the Utilities to gradually improve their ROACEs when compared to the period prior to the implementation of decoupling. This in turn will facilitate the Utilities’ ability to effectively raise capital for needed infrastructure investments. However, the Utilities continue to expect an ongoing structural gap between their PUC-allowed ROACEs and the ROACEs actually achieved due to the following:

•the timing of general rate case decisions,


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

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


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

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

The structural gap in 2016 is expected to be 90 to 110 basis points. Factors which impact the range of the structural gap include the actual sales impacting the size of the RBA regulatory asset, the actual level of plant additions in any given year relative to the amount recoverable through the RAM, the 2015 RAM Revenue adjustment pursuant to PUC Order, 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 will credit $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 2015 annual decoupling filings.

Results of operations.


•	2015 vs. 2014



2015			2014			Increase (decrease)						(dollars in millions, except per barrel amounts)
$	2,335		$	2,987		$	(652	)				Revenues. Decrease largely due to:
									$	(520	)	lower fuel prices
									(134		)	lower purchased power energy costs
									2			higher KWH purchased
655			1,132			(477		)				Fuel oil expense. Decrease largely due to lower fuel costs and lower KWH generated
594			722			(128		)				Purchased power expense. Decrease due to lower purchased power energy prices offset by higher KWH purchased
413			411			2						Operation and maintenance expense. Net increase due to:
									5			ERP software costs write off resulting from PUC ERP/EAM decision
									4			additional reserves for environmental costs¹
									3			higher employee benefit costs
									(9		)	higher 2014 smart grid initial phase costs
399			447			(48		)				Other expenses. Decrease in revenue taxes due to lower revenue offset by higher depreciation expense for plant investments
274			276			(2		)				Operating income. Decrease due to lower revenues
136			138			(2		)				Net income for common stock. Decrease due to lower operating income
8.0		%	8.4		%	(0.4		)%				Return on average common equity
74.71			129.65			(54.94		)				Average fuel oil cost per barrel ²
8,957			8,976			(19		)				Kilowatthour sales (millions) ³
5,082			4,909			173						Cooling degree days (Oahu)
2,727			2,759			(32		)				Number of employees (at December 31)


•	2014 vs. 2013



2014			2013			Increase (decrease)						(dollars in millions, except per barrel amounts)
$	2,987		$	2,980		$	7					Revenues. Increase largely due to:
									$	52		higher rate base and O&M RAM
									8			higher purchased power costs
									5			Maui Electric refund in 2013 due to final 2012 rate case decision
									(32		)	lower KWH generated
									(28		)	lower fuel prices
1,132			1,186			(54		)				Fuel oil expense. Decrease largely due to lower KWHs generated and lower fuel costs
722			711			11						Purchased power expense. Increase due to higher KWHs purchased as a result of decreased availability of AES in 2013 and expanded capacity of HPower in 2014, partly offset by lower purchased energy costs due to lower fuel prices
411			403			8						Operation and maintenance expense. Increase largely due to:
									8			smart grid initial phase
									8			consultant costs associated with energy transformation plans
									4			storm restoration
									4			customer information system upgrade
									(9		)	lower customer service costs that were elevated in 2013 during the stabilization period for the new customer information system
									(5		)	lower overhaul costs due to reduced scope of overhauls
									(5		)	lower production costs due to deactivation of HPP
447			435			12						Other expenses. Increase primarily due to depreciation expense for plant investments
276			246			30						Operating income. Increase due to higher revenues and a decrease in overall expenses
138			123			15						Net income for common stock. Increase due to higher operating income
8.4		%	8.0		%	0.4		%				Return on average common equity
129.65			131.10			(1.45		)				Average fuel oil cost per barrel ²
8,976			9,070			(94		)				Kilowatthour sales (millions) ³
4,909			4,506			403						Cooling degree days (Oahu)
2,759			2,764			(5		)				Number of employees (at December 31)


¹	Costs to complete Waiau Power Plant's onshore and offshore investigations and the remediation of PCB contamination in the offshore sediment.


²	The rate schedules of the electric utilities currently contain energy cost adjustment clauses (ECACs) through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.


³	KWH sales were lower in 2015 and 2014 when compared to the prior year due largely to continued energy efficiency and conservation efforts by customers and increasing levels of customer-sited renewable generation.

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

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



Test year (dollars in millions)	Date (filed/ implemented)	Amount		% over rates in effect	ROACE (%)	RORB (%)	Rate base		Common equity %	Stipulated agreement reached with Consumer Advocate
Hawaiian Electric
2011 (1)
Request	7/30/10	$	113.5	6.6	10.75	8.54	$	1,569	56.29	Yes
Interim increase	7/26/11	53.2		3.1	10.00	8.11	1,354		56.29
Interim increase (adjusted)	4/2/12	58.2		3.4	10.00	8.11	1,385		56.29
Interim increase (adjusted)	5/21/12	58.8		3.4	10.00	8.11	1,386		56.29
Final increase	9/1/12	58.1		3.4	10.00	8.11	1,386		56.29
2014 (2)	6/27/14
Hawaii Electric Light
2010 (3)
Request	12/9/09	$	20.9	6.0	10.75	8.73	$	487	55.91	Yes
Interim increase	1/14/11	6.0		1.7	10.50	8.59	465		55.91
Interim increase (adjusted)	1/1/12	5.2		1.5	10.50	8.59	465		55.91
Final increase	4/9/12	4.5		1.3	10.00	8.31	465		55.91
2013 (4)
Request	8/16/12	$	19.8	4.2	10.25	8.30	$	455	57.05
Closed	3/27/13
2016 (5)	6/17/15
Maui Electric
2012 (6)
Request	7/22/11	$	27.5	6.7	11.00	8.72	$	393	56.85	Yes
Interim increase	6/1/12	13.1		3.2	10.00	7.91	393		56.86
Final increase	8/1/13	5.3		1.3	9.00	7.34	393		56.86
2015 (7)	12/30/14

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

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

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

(2) See “Hawaiian Electric 2014 test year rate case” below.

(3)

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

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


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

(6)

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


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

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

On January 28, 2013, the Utilities and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects, with the remaining recoverable costs for the projects of $52 million to be included in rate base as of December 31, 2012. The parties agreed that Hawaii Electric Light would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and Hawaiian Electric would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that, starting in 2014, Hawaiian Electric will be allowed to record RAM revenues starting on January 1 (instead of the prior start date of June 1) for the years 2014, 2015 and 2016. For 2015 and 2014, Hawaiian Electric had additional net RAM revenues of $4 million and $12 million, respectively.

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

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

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

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

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

Maui Electric 2015 test year rate case. On December 30, 2014, Maui Electric filed its abbreviated 2015 test year rate case filing. In recognition that its customers have been enduring a high bill environment, Maui Electric proposed no change to its base rates, thereby foregoing the opportunity to seek a general rate increase. If Maui Electric were to seek an increase in base rates, its requested increase in revenue, based on its revenue requirement for a normalized 2015 test year, would have been $11.6 million, or 2.8%, over revenues at current effective rates with estimated 2015 RAM revenues. The normalized 2015 test

year revenue requirement is based on an estimated cost of common equity of 10.75%. Management cannot predict any actions by the PUC as a result of this filing.

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

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

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

•

In July 2011, the PUC directed Hawaiian Electric to submit a draft RFP for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, Hawaiian Electric filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200-MW RFP, ordering that Hawaiian Electric shall amend its current draft of the Oahu 200-MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order.

•

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii. Bids were received in January 2015, and in February 2015, Ormat Technologies, Inc. was selected to provide 25 MW of additional geothermal energy, subject to successful contract negotiations and PUC approval of the final agreement. In February 2016, Hawaii Electric Light provided the PUC with a status update notifying the PUC that the selected bidder had determined the proposed project was not economically and financially viable, resulting in conclusion of PPA negotiations.

•

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

•

In August 2012, the PUC approved a waiver from the competitive bidding framework to allow Hawaiian Electric to negotiate with the U.S. Army for construction of a 50-MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu. In September 2015, the PUC approved Hawaiian Electric's application with conditions and limitations. See "Schofield Generating Station Project" in Note 4 of the Consolidated Financial Statement.

•

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.


•	In October 2013, the PUC approved Hawaiian Electric’s 20-year contract with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at the Kahe Power Plant; however, in January 2016, Hawaiian Electric terminated the contract due to Hawaii BioEnergy’s inability to meet its contractual obligations/milestones.

•

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

•

In July 2015, the PUC issued orders approving (with conditions) four PPAs for a combined 137 MW of solar projects. Hawaiian Electric expects to manage curtailment levels of these projects. In August 2015, the PUC issued orders denying Hawaiian Electric’s applications to approve three other solar projects. In January 2016, two of the four approved projects received notices of default from Hawaiian Electric for failure to meet guaranteed project milestones, and in February 2016 a third project received a notice of failure to meet a substantial commitment milestone. On January 28, 2016, the PUC reopened proceedings for the three projects requesting Hawaiian Electric to file a status report. On February 12, 2016, Hawaiian Electric filed updates with the PUC regarding the status of the projects. On this same day, Hawaiian Electric terminated these three PPAs totaling 109.6 MW of the four approved PPAs totaling 137 MW. The developer of the terminated PPAs and the Consumer Advocate have until February 23, 2016 to file a response with the PUC regarding Hawaiian Electric’s status report.


•	In July 2015, Maui Electric signed two PPAs, with Kuia Solar and South Maui Renewable Resources, each for a 2.87-MW solar facility. In February 2016, the PUC approved both PPAs, subject to certain conditions and modifications.

•

In September 2015, the PUC approved Hawaiian Electric’s 2-year biodiesel supply contract with Pacific Biodiesel Technologies, LLC to supply 2 million to 3 million gallons of biodiesel at CIP CT-1 and the Honolulu International Airport Emergency Power Facility beginning in November 2015. Renewable Energy Group has supplied 3 million to 7 million gallons per year to CIP CT-1 under its contract with Hawaiian Electric originally set to expire November 2015. The contract has been extended from November 2015 to November 2016 as a contingency supply contract with no volume purchase requirements.

•

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


•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2015, there were 14 MW, 3 MW and 4 MW of installed feed-in tariff capacity from renewable energy technologies at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.


•	As of December 31, 2015, there were approximately 258 MW, 60 MW and 64 MW of installed NEM capacity from renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively.

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

Adequacy of supply.

Hawaiian Electric. In January 2016, Hawaiian Electric filed its 2016 Adequacy of Supply (AOS) letter, which indicated that based on its May 2015 sales and peak forecast for the 2016 to 2017 time period, Hawaiian Electric’s generation capacity will be sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2017.

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

Hawaii Electric Light. In January 2016, Hawaii Electric Light filed its 2016 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2018 is sufficient to meet reasonably expected demands for service and provide for reasonable reserves for emergencies. The 2016 AOS letter also indicated that the Company's Shipman plant in Hilo was retired in 2015.

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

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

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

Legislation and regulation. Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the Utilities and their customers. Also see “Environmental regulation” in Note 4 of the Consolidated Financial Statements and “Recent tax developments” above.

Renewable energy. In 2011, a Hawaii law was enacted that gives the PUC the authority to allow those electric utilities (including the Utilities) that aggregate their renewable portfolios in measuring whether they achieve the renewable portfolio standards under the Hawaii RPS law discussed above under "Renewable energy strategy" to distribute the costs and expenses of renewable energy projects among those utilities. The bill also allows the PUC to establish a surcharge for such costs and expenses without a rate case filing. Also passed in 2011, Act 10 provides for continued inclusion of customer-sited, grid-connected renewable energy generation in the RPS calculations after 2015. This is the current practice in calculating RPS levels, which provides electric utility ratepayers with a clear value from a program such as net energy metering.

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

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of the Consolidated Financial Statements.

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:



December 31	2015				2014
(dollars in millions)
Long-term debt, net	$	1,287	42	%	$	1,207	41	%
Preferred stock	34		1		34		1
Common stock equity	1,728		57		1,682		58
	$	3,049	100	%	$	2,923	100	%

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



	Year ended December 31, 2015
(in millions)	Average balance		End-of-period balance		December 31, 2014
Short-term borrowings¹
Commercial paper	$	47	$	—	$	—
Line of credit draws	—		—		—
Borrowings from HEI	—		—		—
Undrawn capacity under line of credit facility	200		200		200

The maximum amount of external short-term borrowings in 2015 was $126 million. At December 31, 2015, Hawaiian Electric had short-term borrowings from Hawaii Electric Light and Maui Electric of $15.5 million and $7.5 million, respectively, which intercompany borrowings are eliminated in consolidation. At February 12, 2016, Hawaiian Electric had $61 million of outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had short-term borrowings from Hawaii Electric Light and Maui Electric of $5.5 million and $1.5 million, respectively.

Hawaiian Electric utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. Hawaiian Electric also borrows short-term from HEI for itself and on behalf of Hawaii Electric Light and Maui Electric, and Hawaiian Electric may borrow from or loan to Hawaii Electric Light and Maui Electric short-term. The intercompany borrowings among the Utilities, but not the borrowings from HEI, are eliminated in the consolidation of Hawaiian Electric’s financial statements. The Utilities periodically utilize long-term debt, historically borrowings of the proceeds of special purpose revenue bonds (SPRBs) issued by the Department of Budget and Finance of the State of Hawaii (DBF) and more recently the issuance of privately placed taxable unsecured senior notes, to finance the Utilities’ capital improvement projects, or to repay short-term borrowings used to finance such projects. The PUC must approve issuances, if any, of equity and long-term debt securities by the Utilities.

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 7 of the Consolidated Financial Statements.

The ratings of Hawaiian Electric’s commercial paper and debt securities could significantly impact the ability of Hawaiian Electric to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (e.g., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of Hawaiian Electric securities.

In January 2015, S&P reported the ratings of Hawaiian Electric (BBB-/Watch Positive/A-3). S&P indicated that “[g]iven the proposed funding for the transaction (all equity and the assumption of existing debt), along with opportunities for growth for NextEra Energy, we expect to view HEI as a core subsidiary of NextEra Energy and therefore to raise the issuer credit rating (ICR) on HEI and HECO to be in line with that of NextEra Energy.”

In August 2015, Moody’s changed Hawaiian Electric’s rating outlook from stable to negative “due to concerns about the execution risk inherent in transforming its oil-dominated generation base to renewables.” Moody’s stated that they could reevaluate Hawaiian Electric’s rating or outlook upon the closing of the pending merger with NEE.

In December 2015, Fitch affirmed the Issuer Default Rating for Hawaiian Electric at BBB+ with a Stable Outlook. Fitch also maintained HEI’s outlook as Watch Positive. Fitch stated that “[o]nce the transaction is completed, HEI (or its successor within NEE) would become a first-tier holding company under NextEra Energy Capital Holdings, Inc. Fitch expects to equalize the IDR of HEI with that of HECO once the bank is spun off and the acquisition with NEE is completed. The acquisition would not result in any change in rating of HECO. The structural weakness in HECO’s service territory due to rising penetration of rooftop solar, the concessions offered for merger approval and the uncertainty regarding the fleet modernization plan until the Power Supply Improvement Plan (PSIP) is approved by the regulators offset the positives of NEE’s ownership and a sharp decline in oil prices over last year. Over the long term, Fitch sees a bias toward positive rating actions for HECO and HEI under NEE’s ownership.”

As of February 12, 2016, the Fitch, Moody’s and S&P ratings of Hawaiian Electric were as follows:



	Fitch	Moody’s	S&P
Long-term issuer default, long-term issuer and corporate credit, respectively	BBB+	Baa1	BBB-
Commercial paper	F2	P-2	A-3
Special purpose revenue bonds	A-¹	Baa1	BBB-
Hawaiian Electric-obligated preferred securities of trust subsidiary	*	Baa2	BB
Cumulative preferred stock (selected series)	*	Baa3	*
Senior unsecured debt	A-	Baa1	*
Subordinated debt	BBB	*	*
Outlook	Stable	Negative	Watch-Positive

* Not rated.

¹ Rated only for SPRB issued in 2015.

Management believes that, if Hawaiian Electric’s commercial paper ratings were to be downgraded or if credit markets were to further tighten, it could be more difficult and/or expensive to sell commercial paper or secure other short-term borrowings. Similarly, 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 for DBF and/or the Company to sell SPRBs and other debt securities, respectively, for the benefit of the Utilities in the future. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and liquidity of the Utilities.

SPRBs have been issued by the 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.

The PUC approved the use of an expedited approval procedure for the approval of long-term debt financings or refinancings (including the issuance of taxable debt) by the Utilities, up to specified amounts, during the period 2013 through 2015, subject to certain conditions. On October 3, 2013, after obtaining such expedited approvals, the Utilities issued, through a private placement, non-collateralized senior notes bearing taxable interest in an aggregate principal amount of $236 million.

In September 2014, the Utilities filed a request with the PUC under the expedited approval procedure for approval to issue unsecured obligations bearing taxable interest through December 31, 2015 of up to $80 million (Hawaiian Electric $50 million, Hawaii Electric Light $25 million and Maui Electric $5 million). In May 2015, the PUC approved the Utilities’ request. On October 15, 2015, the Utilities issued, through a private placement, unsecured senior notes bearing taxable interest in the aggregate principal amount of $80 million. See Note 8 of the Consolidated Financial Statements.

In June 2015, the Utilities refiled with the PUC a letter request to refinance outstanding revenue bonds with refunding revenue bonds totaling $47 million. Following the PUC's approval of the Utilities' request, on December 15, 2015, the Department issued, at par, Refunding Series 2015 SPRBs in the aggregate principal amount of $47 million with a maturity of January 1, 2025. See Note 8 of the Consolidated Financial Statements.

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

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

million and $45 million, respectively), and the purchase of the Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric in 2016.

Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from) net income. In 2015 and 2014, net cash provided by operating activities increased by $26 million and decreased by $20 million, respectively, compared to the prior year. In 2015, noncash depreciation and amortization amounted to $186 million due to an increase in plant and equipment and deferred income taxes increased $76 million. Further, net cash provided by operating activities included a decrease of $64 million in accounts receivable and accrued unbilled revenues due largely to the decrease in customer bills as a result of lower fuel oil prices included in rates, a $35 million decrease in fuel oil stock, offset by a $55 million decrease in accounts payable due to the decrease in the fuel oil prices and timing of vendor payments. In 2014, noncash depreciation and amortization amounted to $176 million due to an increase in plant and equipment and deferred income taxes increased $83 million. Further, net cash provided by operating activities included a decrease of $33 million in accounts receivable and accrued unbilled revenues due to result of timing of customer payments, a $28 million decrease in fuel oil stock, offset by a $66 million decrease in accounts payable due to timing of vendor payments.

In 2015 and 2014, net cash used in investing activities increased by $15 million and decreased by $51 million, respectively, compared to the prior year. In 2015 and 2014, capital expenditures amounted to $350 million and $337 million, respectively, offset by contributions in aid of construction of $40 million and $42 million, respectively.

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. In 2015 and 2014, cash flows from financing activities changed by a positive $48 million and a negative $126 million, respectively, compared to the prior year. In 2015, cash used in financing activities consisted primarily of the payment of $92 million of common and preferred stock dividends offset by the proceeds received from the issuance of $80 million of taxable unsecured senior notes. In 2014, cash used in financing activities consisted primarily of the payment of $90 million of common and preferred stock dividends and the redemption of $11 million of special purpose revenue bonds, partially offset by net proceeds received from the issuance of $40 million of common stock.

For 2016, the Utilities forecast $450 million of net capital expenditures (including the purchase of HEP), which could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and 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 existing cash and cash equivalents are expected to provide the forecasted $450 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.

Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generation units, the availability of generating sites and transmission and distribution corridors, the need for fuel infrastructure investments, the ability to obtain adequate and timely rate increases, escalation in construction costs, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.

For a discussion of funding for the electric utilities’ retirement benefits plans, see Notes 1 and 10 of the Consolidated Financial Statements and “Retirement benefits” above. The electric utilities were required to make contributions of $9 million for 2015, $56 million for 2014 and $61 million for 2013 to the qualified pension plans to meet minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006. The electric utilities made additional voluntary contributions in 2015, 2014 and 2013. Contributions by the electric utilities to the retirement benefit plans for 2015, 2014 and 2013 totaled $86 million, $59 million and $81 million, respectively, and are expected to total $64 million in 2016. In addition, the electric utilities paid directly $0.4 million of benefits in 2015, $1 million of benefits in 2014 and $1 million of benefits in 2013 and expect to pay $1 million of benefits in 2016. Depending on the performance of the assets held in the plans’ trusts and numerous other factors, additional contributions may be required in the future to meet the minimum funding requirements of ERISA or to pay benefits to plan participants. The electric utilities believe they will have adequate cash flow or access to capital resources to support any necessary funding requirements.

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



December 31, 2015	Payments due by period
(in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total

Long-term debt	$	—	$	50	$	96	$	1,141	$	1,287
Interest on long-term debt	64		128		126		793		1,111
Operating leases	8		10		6		10		34
Open purchase order obligations ¹	89		12		2		1		104
Fuel oil purchase obligations (estimate based on December 31, 2015 fuel oil prices)	245		4		—		—		249
Purchase power obligations-minimum fixed capacity charges	107		190		194		497		988
Liabilities for uncertain tax positions	—		4		—		—		4
Total (estimated)	$	513	$	398	$	424	$	2,442	$	3,777

¹ Includes contractual obligations and commitments for capital expenditures and expense amounts.

The table above does not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2015, the fair value of the assets held in trusts to satisfy the obligations of the Utilities’ retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the table above, but retirement benefit plan obligations, including estimated minimum required contributions for 2016 are discussed in the section “Retirement benefits” in Hawaiian Electric’s MD&A and Note 10 of the Consolidated Financial Statements.

See Note 4 of the Consolidated Financial Statements for a discussion of fuel and power purchase commitments.

Certain factors that may affect future results and financial condition. Also see “Forward-Looking Statements” and “Certain factors that may affect future results and financial condition” for Consolidated HEI above.

Clean energy initiatives and Renewable Portfolio Standards (RPS). The far-reaching nature of the Utilities’ renewable energy commitments and the RPS goals presents risks to the Company. Among such risks are: (1) the dependence on third party suppliers of renewable purchased energy, which if the Utilities are unsuccessful in negotiating purchased power agreements with such IPPs or if a major IPP fails to deliver the anticipated capacity in its purchased power agreement, could impact the Utilities’ achievement of their commitments to RPS goals and/or the Utilities’ ability to deliver reliable service; (2) delays in acquiring or unavailability of non-fossil fuel supplies for renewable generation; (3) the impact of intermittent power to the electrical grid and reliability of service if appropriate supporting infrastructure is not installed or does not operate effectively; (4) the likelihood that the Utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the Utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the Utilities depending on their design and implementation. These initiatives include, but are not limited to, removing the system-wide caps on net energy metering (but studying distributed generation interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. The implementation of these or other programs may adversely impact the results of operations, financial condition and liquidity of the Utilities.

Regulation of electric utility rates. The rates the electric utilities are allowed to charge for their services, and the timeliness of permitted rate increases, are among the most important items influencing their results of operations, financial condition and liquidity. The PUC has broad discretion over the rates the electric utilities charge and other matters. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts permitted to be included in rate base, the authorized returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on the Company’s and Hawaiian Electric’s consolidated results of operations, financial condition and liquidity. Upon a showing of probable entitlement, the PUC is required to issue an interim D&O in a rate case within 10 months from the date of filing a completed application if the evidentiary hearing is completed (subject to extension for 30 days if the evidentiary hearing is not completed). There is no time limit for rendering a final D&O and interim rate increases are subject to refund with interest if the interim increase is greater than the increase approved in the final D&O.

Fuel oil and purchased power. The electric utilities rely on fuel oil suppliers and IPPs to deliver fuel oil and power, respectively. See “Fuel contracts” and “Power purchase agreements” in Note 4 of the Consolidated Financial Statements. The Company estimates that 67% of the net energy the Utilities generate and purchase in 2016 will be from the burning of fossil

fuel oil as compared to 70% in 2015. Purchased KWHs provided approximately 46%, 46% and 44% of the total net energy generated and purchased in 2015, 2014 and 2013, respectively.

Failure or delay by the electric utilities’ oil suppliers and shippers to provide fuel pursuant to existing supply contracts, or failure by a major IPP to deliver the firm capacity anticipated in its PPA, could interrupt the ability of the electric utilities to deliver electricity, thereby materially adversely affecting the Company’s results of operations and financial condition. Hawaiian Electric generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. Hawaii Electric Light and Maui Electric generally maintain an inventory level equivalent to one month’s supply of both medium sulfur fuel oil and diesel fuel. Some, but not all, of the Utilities’ PPAs require that the IPPs maintain minimum fuel inventory levels and all of the firm capacity PPAs include provisions imposing substantial penalties for failure to produce the firm capacity anticipated by those agreements.

Other operation and maintenance expenses. O&M expenses increased by 1% in 2015, 2% in 2014 and 1% in 2013 when compared to the prior year. O&M expenses (excluding expenses covered by surcharges or by third parties) increased by 1% each year for 2015, 2014 and 2013 when compared to the prior year. O&M expenses (excluding expenses covered by surcharges or by third parties) for 2016 are projected to be up to 5% lower than the 2015 level as 2015 included significant write-offs and reserves that are not expected to recur in 2016. In addition, the Utilities expect to realize the benefits of the cost management strategies that began in 2015.

Other regulatory and permitting contingencies. Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other agencies. Delays in obtaining PUC approval or permits can result in increased costs. If a project does not proceed or if the PUC disallows costs of the project, the project costs may need to be written off in amounts that could have a material adverse effect on the Company. For example, two major capital improvement utility projects, the Keahole project (consisting of CT-4, CT-5 and ST-7) and the East Oahu Transmission Project (EOTP), encountered opposition and were seriously delayed before being placed in service, with a writedown being required for both the Keahole and EOTP projects in 2007 and 2011, respectively. More recently, the Utilities and the Consumer Advocate signed a settlement agreement, subject to approval by the PUC, to write off $40 million of costs in 2012 in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects. See Note 4 of the Consolidated Financial Statements for a discussion of additional regulatory contingencies.

Competition. Although competition in the generation sector in Hawaii is moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, the PUC has promoted a more competitive electric industry environment through its decisions concerning competitive bidding and distributed generation (DG). An increasing amount of generation is provided by IPPs and customer distributed generation.

Competitive bidding. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the framework does not apply in certain situations identified in the framework; (3) waivers from competitive bidding for certain circumstances will be considered; (4) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders); (5) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP; and (6) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.

The Kalaeloa Solar Two photovoltaic energy PPA and the Kawailoa Wind windfarm PPA are two renewable projects that resulted from Hawaiian Electric’s Renewable Energy RFP under the Competitive Bidding Framework.

The Utilities received PUC approval for exemptions from the competitive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources, including the City & County of Honolulu’s HPower facility expansion and the Puna Geothermal Venture geothermal facility expansion. Also, certain renewable energy projects were “grandfathered” from the competitive bidding process, including the Kahuku Wind Power, Auwahi Wind Energy LLC, and Kaheawa Wind Power II wind farms. The PUC can also grant waivers to renewable energy projects that are not exempt from the Competitive Bidding Framework.

Distributed generation. In January 2006, the PUC issued a D&O indicating that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system. The D&O affirmed the ability of the Utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. The D&O allows the utility to provide DG services on a

customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

Environmental matters. The Utilities' generating stations operate under air pollution control permits issued by the Hawaii Department of Health (DOH) and, in a limited number of cases, by the federal Environmental Protection Agency (EPA). Hawaii law requires an environmental assessment for proposed waste-to-energy facilities, landfills, oil refineries, power-generating facilities greater than 5 MW and wastewater facilities, except individual wastewater systems. Meeting this requirement for environmental assessments results in increased project costs.

The 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone and adoption of a NAAQS for fine particulate matter resulted in substantial changes for the electric utility industry such as the installation of additional emissions controls, retirements of older generating units and switches to lower-emissions fuels. Further, significant impacts may occur under newly adopted rules (e.g., one-hour NAAQS for sulfur dioxide and nitrogen dioxide; control of GHGs under the GHG PSD Rule; and the Clean Power Plan, which currently exempts non-continental electric utilities); under rules deemed applicable to the Utilities’ facilities (e.g., the Regional Haze Rule); or if new legislation, rules or standards are adopted in the future. Similarly, the rules governing cooling water intakes may significantly impact Hawaiian Electric’s steam generating facilities on Oahu.

Management believes that the recovery through rates of most, if not all, of any costs incurred by the Utilities in complying with environmental requirements would be allowed by the PUC, but no assurance can be given that this will in fact be the case. In addition, there can be no assurance that a significant environmental liability will not be incurred by the Utilities or that the related costs will be recoverable through rates. See “Environmental regulation” in Note 4 of the Consolidated Financial Statements.

Technological developments. New technological developments (e.g., the commercial development of energy storage, fuel cells, DG and generation from renewable sources) may impact the Utilities’ future competitive position, results of operations, financial condition and liquidity.

Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” for Consolidated HEI above.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, and administrative and general costs, and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Upon the retirement or sale of electric utility plant, no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

The Utilities evaluate the impact of applying lease accounting standards to their new PPAs, PPA amendments and other arrangements they enter into. A possible outcome of the evaluation is that an arrangement results in its classification as a capital lease, which could have a material effect on Hawaiian Electric’s consolidated balance sheet if a significant amount of capital assets of the IPP and lease obligations needed to be recorded.

Management believes that the PUC will allow recovery of property, plant and equipment in its electric rates. If the PUC does not allow recovery of any such costs, the electric utility would be required to write off the disallowed costs at that time. See the discussion under “Utility projects” in Note 4 of the Consolidated Financial Statements concerning costs of major projects that have not yet been approved for inclusion in the applicable utility’s rate base.

Regulatory assets and liabilities. The Utilities are regulated by the PUC. In accordance with accounting standards for regulatory operations, the Company’s financial statements reflect assets, liabilities, revenues and costs of the Utilities based on current cost-based rate-making regulations. The actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities.

Regulatory liabilities represent amounts collected from customers for costs that are expected to be incurred in the future. Regulatory assets represent incurred costs that have been deferred because their recovery in future customer rates is probable. As of December 31, 2015, the consolidated regulatory liabilities and regulatory assets of the Utilities amounted to $372 million and $897 million, respectively, compared to $345 million and $905 million as of December 31, 2014, respectively. Regulatory liabilities and regulatory assets are itemized in Note 4 of the Consolidated Financial Statements. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable

regulatory environment. Because current rates include the recovery of regulatory assets existing as of the last rate case and rates in effect allow the Utilities to earn a reasonable rate of return, management believes that the recovery of the regulatory assets as of December 31, 2015 is probable. This determination assumes continuation of the current political and regulatory climate in Hawaii, and is subject to change in the future.

Management believes that the operations of the Utilities currently satisfy the criteria for regulatory accounting. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company's results of operations, financial condition and liquidity.

Revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period, but not yet billed to customers, and RBA revenues or refunds for the difference between PUC-approved target revenues and recorded adjusted revenues, which delinks revenues from kilowatthour sales. As of December 31, 2015, revenues applicable to energy consumed, but not yet billed to customers, amounted to $96 million and the RBA revenues recognized in 2015 amounted to $62 million.

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. The rate schedules of the Utilities include ECACs under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. The rate schedules of the Utilities also include PPACs under which electric rates are more closely aligned with purchase power costs incurred. Management believes that a material adverse effect on the Company’s results of operations, financial condition and liquidity may result if the ECACs, PPACs or RBAs were lost or adversely modified.

Consolidation of variable interest entities. A business enterprise must evaluate whether it should consolidate a variable interest entity (VIE). The Company evaluates the impact of applying accounting standards for consolidation to its relationships with IPPs with whom the Utilities execute new PPAs or execute amendments of existing PPAs. A possible outcome of the analysis is that Hawaiian Electric or its subsidiaries may be found to meet the definition of a primary beneficiary of a VIE which finding may result in the consolidation of the IPP in the Consolidated Financial Statements. The consolidation of IPPs 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. The Utilities do not know how the consolidation of IPPs would be treated for regulatory or credit ratings purposes. See Notes 1 and 6 of the Consolidated Financial Statements.

Bank

Executive overview and strategy. When ASB was acquired by HEI in 1988, it was a traditional thrift with assets of $1 billion and net income of about $13 million. ASB has grown by both acquisition and internal growth, but has been optimizing its balance sheet in recent years as a result of its multi-year performance improvement project, which has resulted in a reduction in asset size and a concomitant improvement in profitability and capital efficiency. ASB ended 2015 with assets of $6.0 billion and net income of $55 million, compared to assets of $5.6 billion as of December 31, 2014 and net income of $51 million in 2014.

ASB is a full-service community bank serving both consumer and commercial customers. In order to remain competitive and continue building core franchise value, ASB continues to develop and introduce new products and services in order to meet the needs of those markets such as mobile banking. Additionally, the banking industry is constantly changing and ASB is making the investments in people and technology necessary to adapt and remain competitive. ASB’s ongoing challenge is to continue to increase revenues and control expenses.

The interest rate environment and the quality of ASB’s assets will continue to impact its financial results.

ASB continues to face a challenging interest rate environment. The persistent, low level of interest rates and excess liquidity in the financial system have impacted new loan production rates and made it challenging to find investments with adequate risk-adjusted returns, which resulted in a negative impact on ASB’s asset yields and net interest margin. The potential for compression of ASB’s margin when interest rates rise is an ongoing concern.

As part of its interest rate risk management process, ASB uses simulation analysis to measure net interest income sensitivity to changes in interest rates (see “Quantitative and Qualitative Disclosures about Market Risk”). ASB then employs strategies to limit the impact of changes in interest rates on net interest income. ASB’s key strategies include:


1.	attracting and retaining low-cost, core deposits, particularly those in non-interest bearing transaction accounts;


2.	reducing the overall exposure to fixed-rate residential mortgage loans and diversifying the loan portfolio with higher-spread, shorter-maturity loans and/or variable-rate loans such as commercial, commercial real estate and consumer loans;


3.	managing costing liabilities to optimize cost of funds and manage interest rate sensitivity; and


4.	focusing new investments on shorter duration or variable rate securities.

ASB’s loan quality remained strong in 2015 as a result of stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the state of Hawaii. ASB’s annualized net charge-offs as a percentage of total average loans was 0.04% for 2015 compared to 0.01% for 2014. ASB’s provision for loan losses for 2015 was $6.3 million compared to $6.1 million for 2014 primarily due to loan loss reserves needed for growth in the loan portfolio.

Effective July 2013, ASB became non-exempt from the Durbin Amendment to the Dodd-Frank Act which resulted in lower debit card interchange fees. For 2015, 2014 and 2013, the estimated net income impact of the lower debit card interchange fees was $6 million, $6 million and $3 million, respectively. If the Spin-off of ASB occurs as contemplated by the Merger Agreement, ASB expects to be exempt from the Durbin Amendment.

Results of operations.


•	2015 vs. 2014



(in millions)	2015			2014			Increase (decrease)			Primary reason(s)
Interest income	$	200		$	191		$	9		The impact of higher average earning asset balances was partly offset by lower yields on earning assets. ASB’s average loan portfolio balance for 2015 was $213 million higher than 2014 as the average commercial real estate, residential, HELOC and commercial loan balances increased by $111 million, $40 million, $37 million and $15 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix targets and loan growth strategy. The loan portfolio yield continued to be impacted by the interest rate environment as new loan production yields were lower than the average portfolio yield. The average investment and mortgage-related securities portfolio balance increased by $150 million as ASB purchased investments with liquidity in excess of loan growth funding.
Noninterest income	67			61			6			Higher noninterest income was due to an increase in gain on sale of loans as loan sales increased by $119 million as a result of ASB's decision to sell a larger portion of its low rate residential loan production, higher deposit related fee initiatives and gains on sales of real estate and mortgage servicing rights. 2014 noninterest income included the gain on sale of the municipal bond portfolio with no similar security sales in 2015.
Revenues	267			252			15
Interest expense	12			11			1			Higher interest expense was due to an increase in average interest-bearing liabilities. Average deposit balances for 2015 increased by $293 million compared to 2014 due to an increase in core deposits and term certificates of $279 million and $14 million, respectively. The other borrowings average balance increased by $64 million due to an increase in public repurchase agreements.
Provision for loan losses	6			6			—			The provision for loan losses for 2015 and 2014 were used primarily to establish loan loss reserves for the growth in the loan portfolio and cover net loan charge-offs. The provision for loan losses in 2015 also included higher reserve levels for the commercial loan portfolio.
Noninterest expense	166			156			10			Higher noninterest expense was primarily due to higher compensation and benefits expense as a result of an increase in retail delivery compensation cost, higher performance-based incentive cost and higher benefits expenses related to the frozen defined benefit plan and medical insurance premium costs.
Expenses	184			173			11
Operating income	83			79			4			Higher interest and noninterest income, partly offset by higher noninterest expenses.
Net income	55			51			4			Higher operating income, partly offset by higher taxes.
Return on average common equity¹	9.9		%	9.6		%	0.3		%


•	2014 vs. 2013



(in millions)	2014			2013			Increase (decrease)			Primary reason(s)
Interest income	$	191		$	186		$	5		The impact of higher average earning asset balances was partly offset by lower yields on earning assets. ASB’s average loan portfolio balance for 2014 was $327 million higher than 2013 as the average HELOC, residential, commercial real estate and commercial loan balances increased by $110 million, $53 million, $116 million and $57 million, respectively. The growth in these loan portfolios was consistent with ASB’s portfolio mix targets and loan growth strategy. The loan portfolio yield continued to be impacted by the interest rate environment as new loan production yields were lower than the average portfolio yield. The average investment and mortgage-related securities portfolio balance decreased by $51 million as ASB sold its $79 million municipal bond portfolio. ASB used excess liquidity to fund the loan growth.
Noninterest income	61			72			(11		)	Lower debit card interchange fees as a result of ASB being non-exempt from the Durbin Amendment and lower mortgage banking income as a result of a slowdown in refinance activity. 2013 noninterest income included the gain from the sale of the credit card portfolio of $2.3 million.
Revenues	252			258			(6		)
Interest expense	11			10			1			The impact of higher average interest-bearing liabilities was partly offset by lower rates resulting from the low interest rate environment. Average deposit balances for 2014 increased by $224 million compared to 2013 due to an increase in core deposits of $243 million, partly offset by a decrease in term certificates of $19 million. Also, the other borrowings average balance increased by $44 million.
Provision for loan losses	6			1			5			Loan loss reserves established for the growth in the loan portfolio. The 2013 provision for loan losses included the release of loan loss reserves related to the sale of ASB’s credit card portfolio.
Noninterest expense	156			158			(2		)	Higher printing expenses as the printing function was outsourced beginning in the fourth quarter of 2013 and additional consulting expenses for ASB’s mobile banking product and technology security, offset by lower compensation and benefits expense related to the frozen defined benefit plan and lower payroll taxes.
Expenses	173			169			4
Operating income	79			89			(10		)	Lower noninterest income.
Net income	51			58			(7		)	Lower operating income, partly offset by lower taxes.
Return on average common equity¹	9.6		%	11.4		%	(1.8		)%


¹	Calculated using the average daily balances.

See Note 5 of the Consolidated Financial Statements for a discussion of guarantees and further information about ASB.

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



	2015						2014						2013
(dollars in thousands)	Average balance			Interest¹ income/ expense		Yield/ rate (%)	Average balance			Interest¹income/ expense		Yield/ rate (%)	Average balance			Interest¹income/ expense		Yield/ rate (%)
Assets:
Other investments ²	$	157,014		$	471	0.30	$	171,142		$	310	0.18	$	170,695		$	239	0.14
Securities purchased under resale agreements	—			—		—	5,096			20		0.39	11,370			43		0.38
Available-for-sale investment securities
Taxable	687,215			14,649		2.13	525,949			11,336		2.16	519,220			11,192		2.16
Non-taxable	—			—		—	11,600			429		3.69	69,377			2,494		3.60
Total available-for-sale investment securities	687,215			14,649		2.13	537,549			11,765		2.19	588,597			13,686		2.33
Loans
Residential 1-4 family	2,064,170			89,933		4.36	2,023,816			90,591		4.48	1,970,918			93,293		4.73
Commercial real estate	669,184			26,558		3.97	557,924			23,904		4.28	441,734			19,547		4.42
Home equity line of credit	828,129			26,511		3.20	790,701			25,716		3.25	680,445			20,442		3.00
Residential land	17,304			1,101		6.36	16,276			1,106		6.79	20,985			1,308		6.23
Commercial	798,182			29,282		3.67	783,670			29,294		3.74	726,597			29,188		4.02
Consumer	119,267			11,397		9.56	110,440			8,730		7.90	114,871			9,191		8.00
Total loans ^3,4	4,496,236			184,782		4.11	4,282,827			179,341		4.19	3,955,550			172,969		4.37
Total interest-earning assets	5,340,465			199,902		3.74	4,996,614			191,436		3.83	4,726,212			186,937		3.96
Allowance for loan losses	(46,881		)				(42,242		)				(42,114		)
Non-interest-earning assets	490,187						459,513						425,238
Total Assets	$	5,783,771					$	5,413,885					$	5,109,336
Liabilities and Stockholder’s Equity:
Savings	$	1,980,151		1,257		0.06	$	1,879,373		1,134		0.06	$	1,805,363		1,052		0.06
Interest-bearing checking	782,811			139		0.02	738,651			126		0.02	665,941			106		0.02
Money market	164,568			205		0.12	171,889			214		0.12	182,343			232		0.13
Time certificates	449,179			3,747		0.83	434,934			3,603		0.83	454,021			3,702		0.82
Total interest-bearing deposits	3,376,709			5,348		0.16	3,224,847			5,077		0.16	3,107,668			5,092		0.16
Advances from Federal Home Loan Bank	100,438			3,146		3.13	100,389			3,146		3.13	64,630			2,432		3.76
Securities sold under agreements to repurchase	219,351			2,832		1.29	155,012			2,585		1.67	146,758			2,553		1.74
Total interest-bearing liabilities	3,696,498			11,326		0.31	3,480,248			10,808		0.31	3,319,056			10,077		0.30
Non-interest bearing liabilities:
Deposits	1,426,962						1,285,964						1,179,559
Other	109,386						113,401						105,802
Stockholder’s equity	550,925						534,272						504,919
Total Liabilities and Stockholder’s Equity	$	5,783,771					$	5,413,885					$	5,109,336
Net interest income				$	188,576					$	180,628					$	176,860
Net interest margin (%)⁵						3.53						3.62						3.74


¹	Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $nil, $0.2 million and $0.9 million for 2015, 2014 and 2013, respectively.


²	Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank ($32 million, $83 million and $95 million as of December 31, 2015, 2014 and 2013, respectively).


³	Includes loans held for sale, at lower of cost or fair value, of $5.6 million, $3.1 million and $8.1 million as of December 31, 2015, 2014 and 2013, respectively.


⁴	Includes recognition of net deferred loan fees of $2.7 million, $3.7 million and $5.2 million for 2015, 2014 and 2013, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.


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

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

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

Loan portfolio. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. See Note 5 of the Consolidated Financial Statements for the composition of ASB’s loans receivable.

The increase in the total loan portfolio from $4.4 billion at the end of 2014 to $4.6 billion at the end of 2015 was primarily due to growth in the commercial real estate, HELOC and residential 1-4 family loan portfolios, which was consistent with ASB’s portfolio mix targets and loan growth strategy.

Home equity — key credit statistics.



December 31	2015			2014
Outstanding balance (in thousands)	$	846,294		$	818,815
Percent of portfolio in first lien position	42.9		%	40.9		%
Net charge-off ratio	0.02		%	(0.07		)%
Delinquency ratio	0.25		%	0.25		%



							End of draw period – interest only									Current
December 31, 2015	Total			Interest only			2015-2016			2017-2019			Thereafter			amortizing
Outstanding balance (in thousands)	$	846,294		$	650,613		$	137		$	128,882		$	521,594		$	195,681
% of total	100		%	77		%	—		%	15		%	62		%	23		%

The home equity line of credit (HELOC) portfolio makes up 18% of the total loan portfolio and is generally an interest-only revolving loan for a 10-year period, after which time the HELOC outstanding balance converts to a fully amortizing variable rate term loan with a 20-year amortization period. This product type comprises 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 December 31, 2015, approximately 19% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option. Nearly all originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older vintage equity lines represent 4% of the portfolio and are included in the amortizing balances identified in the table above.

Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of secured loans. In a foreclosure action, the property securing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold.

See “Allowance for loan losses” in Note 5 of the Consolidated Financial Statements for information with respect to nonperforming assets. The level of nonperforming loans has continued to decrease with the improving Hawaii economy.

Allowance for loan losses. See “Allowance for loan losses” in Note 5 of the Consolidated Financial Statements for the tables which sets forth the allocation of ASB’s allowance for loan losses. For 2015, the allowance for loan losses increased by $4.4 million primarily due to loan loss reserves for the growth in the loan portfolio and an increase in commercial loan loss reserves.

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



December 31	2015				2014
(dollars in thousands)	Balance		% of total		Balance		% of total
U.S. Treasury and federal agency obligations	$	212,959	26	%	$	119,560	22	%
Mortgage-related securities — FNMA, FHLMC and GNMA	607,689		74		430,834		78
Total available-for-sale investment securities	$	820,648	100	%	$	550,394	100	%

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. government. U.S. Treasury securities are also backed by the full faith of the U.S. government. The increase in investment securities was due to the purchase of federal agency obligations and mortgage-related securities with excess liquidity.

The net unrealized losses on ASB’s investment securities were primarily caused by movements in interest rates. All contractual cash flows of those investments are guaranteed by an agency of the U.S. government. Based upon ASB's evaluation at December 31, 2015 and 2014, there was no indicated impairment as the bank expects to collect the contractual cash flows for these investments. See “Investment securities” in Note 1 for a discussion of securities impairment assessment.

As of December 31, 2015, 2014 and 2013, ASB did not have any private-issue mortgage-related securities.

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 December 31, 2015 and 2014, ASB’s costing liabilities consisted of 94% deposits and 6% other borrowings. See Note 5 of the Consolidated Financial Statements for the composition of ASB’s deposit liabilities and other borrowings.

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

As of December 31, 2015 and 2014, ASB had an unrealized loss, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $1.9 million compared to an unrealized gain, net of taxes, of $0.5 million as of December 31, 2014. See “Quantitative and qualitative disclosures about market risk.”

Legislation and regulation. ASB is subject to extensive regulation, principally by the Office of the Comptroller of the Currency (OCC) and the Federal Deposit Insurance Corporation (FDIC). Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.” Also see “Federal Deposit Insurance Corporation restoration plan” and “Deposit insurance coverage” in Note 5 of the Consolidated Financial Statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Regulation of the financial services industry, including regulation of HEI, ASB Hawaii and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI, ASB Hawaii and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision (OTS) transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASB Hawaii, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, OCC and the Bureau. In addition, HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. If the Spin-Off of ASB Hawaii occurs as contemplated by the Merger Agreement, HEI (or its successor) will no longer be required to serve as a source of strength to ASB. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.

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

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

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

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

Also, the Dodd-Frank Act directs the Bureau to publish rules and forms that combine certain disclosures that consumers receive in connection with applying for and closing on a mortgage loan under the Truth in Lending Act and the Real Estate Settlement Procedures Act. Consistent with this requirement, the Bureau amended Regulation X (Real Estate Settlement Procedures Act) and Regulation Z (Truth in Lending) to establish new disclosure requirements and forms in Regulation Z for most closed-end consumer credit transactions secured by real property. In addition to combining the existing disclosure requirements and implementing new requirements, the final rule provides extensive guidance regarding compliance with those requirements. This rule 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 December 31, 2015, ASB met the new capital requirements with a Common equity Tier-1 ratio of 12.1%, a Tier-1 capital ratio of 12.1%, a Total capital ratio of 13.3% and a Tier-1 leverage ratio of 8.8%.

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

Stock in FHLB. 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.

As of December 31, 2015, ASB’s stock in FHLB of Des Moines of $10.7 million was carried at cost because it can only be redeemed at par. There is a minimum required investment in such stock based on measurements of ASB’s capital, assets and/or borrowing levels. Prior to the merger, ASB had FHLB stock in excess of the required investment amount. With the merger, all of ASB's excess stock of $58.6 million was repurchased. In 2015, 2014 and 2013, ASB received cash dividends of $147,000, $88,000 and $47,000, respectively, on its FHLB Stock.

Mortgage Servicing Rights. As of December 31, 2015 and 2014, ASB's mortgage servicing rights had a net carrying amount of $8.9 million and $11.5 million, respectively. The decrease in the net carrying amount was due to the sale of a portion of the mortgage servicing rights portfolio. In November 2015, ASB sold certain mortgage servicing rights for approximately 1,500 underlying fully amortizing, conventional residential mortgage loans with an unpaid principal balance of $419 million and a net carrying amount of $3.3 million.

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

Potential impact of lava flows. In June 2014, lava from the Kilauea Volcano on the island of Hawaii began flowing toward the town of Pahoa. ASB has been monitoring its loan exposure on properties most likely to be impacted by the projected path of the lava flow. At March 31, 2015, the outstanding amount of the residential, commercial real estate and home equity lines of credit loans collateralized by property in areas most likely affected by the lava flow totaled $13 million. For residential 1-4 mortgages in the area, ASB required lava insurance to cover the dwelling replacement cost as a condition of making the loan. As of December 31, 2014, ASB provided $1.8 million reserves for a commercial real estate loan impacted by the lava flows. Although the lava threat was downgraded from a warning to a watch in March 2015 and the immediate threat to homes and businesses in Pahoa has receded, the lava flow remains active upslope and the reserves for the commercial real estate loan remained in place 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.

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of the Consolidated Financial Statements.

Liquidity and capital resources.



December 31	2015		% change	2014		% change
(dollars in millions)
Total assets	$	6,015	8	$	5,566	6
Available-for-sale investment securities	821		49	550		4
Loans receivable held for investment, net	4,566		4	4,389		7
Deposit liabilities	5,025		9	4,623		6
Other bank borrowings	329		13	291		19

As of December 31, 2015, ASB was one of Hawaii’s largest financial institutions based on assets of $6.0 billion and deposits of $5.0 billion.

ASB’s principal sources of liquidity are customer deposits, borrowings and the maturity and repayment of portfolio loans and securities. ASB’s deposits as of December 31, 2015 were $402 million higher than December 31, 2014. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers and commercial account holders. As of December 31, 2015, FHLB borrowings totaled $100 million, representing 1.7% of assets. ASB is approved to borrow from the FHLB up to 35% of ASB’s assets to the extent it provides qualifying collateral and holds sufficient FHLB stock. As of December 31, 2015, ASB’s unused FHLB borrowing capacity was approximately $1.7 billion. As of December 31, 2015, securities sold under agreements to repurchase totaled $229 million, representing 3.8% of assets. ASB utilizes deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawn deposits, repay maturing borrowings, fund existing and future loans and purchase investment and mortgage-related securities. As of December 31, 2015, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.8 billion, including commitments to lend $0.1 million to borrowers whose loan terms have been impaired or modified in troubled debt restructurings. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

As of December 31, 2015 and 2014, ASB had $46.0 million and 36.9 million of loans on nonaccrual status, respectively, or 1.0% and 0.8% of net loans outstanding, respectively. As of December 31, 2015 and 2014, ASB had $1.0 million and $0.9 million, respectively, of real estate acquired in settlement of loans

In 2015, operating activities provided cash of $46 million. Net cash of $397 million was used by investing activities primarily due to purchases of investment securities of $429 million, a net increase in loans held for investment of $181 million, and capital expenditures of $13 million, partly offset by repayments of investment securities of $153 million, redemption of FHLB stock of $60 million, proceeds from the sales of real estate of $7 million, proceeds from the sale of mortgage servicing rights of $3 million and proceeds from the sale of premises and equipment of $4 million. Financing activities provided net cash of $410 million primarily due to a net increase in deposits of $402 million and a net increase in retail repurchase agreements of $38 million, partly offset by the payment of common stock dividends of $30 million.

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 December 31, 2015, ASB was well-capitalized (see “Regulation—Capital requirements” below for ASB’s capital ratios).

For a discussion of ASB dividends, see “Common stock equity” in Note 5 of the Consolidated Financial Statements.

Competition. The banking industry in Hawaii is highly competitive. ASB is one of Hawaii’s largest financial institutions, based on total assets, and is in direct competition for deposits and loans, not only with larger institutions, but also with smaller institutions that are heavily promoting their services in certain niche areas, such as providing financial services to small- and medium-sized businesses, and national organizations offering financial services. ASB’s main competitors are banks, savings associations, credit unions, mortgage brokers, finance companies and securities brokerage firms. These competitors offer a variety of lending, deposit and investment products to retail and business customers.

The primary factors in competing for deposits are interest rates, the quality and range of services offered, marketing, convenience of locations, hours of operation and perceptions of the institution’s financial soundness and safety. To meet

competition, ASB offers a variety of savings and checking accounts at competitive rates, convenient business hours, convenient branch locations with interbranch deposit and withdrawal privileges at each branch and convenient automated teller machines. ASB also conducts advertising and promotional campaigns.

The primary factors in competing for first mortgage and other loans are interest rates, loan origination fees and the quality and range of lending and other services offered. ASB believes that it is able to compete for such loans primarily through the competitive interest rates and loan fees it charges, the type of mortgage loan programs it offers and the efficiency and quality of the services it provides to individual borrowers and the business community.

ASB is a full-service community bank serving both consumer and commercial customers and has been diversifying its loan portfolio from single-family home mortgages to higher-spread, shorter-duration consumer, commercial and commercial real estate loans. The origination of consumer, commercial and commercial real estate loans involves risks and other considerations different from those associated with originating residential real estate loans. For example, the sources and level of competition may be different and credit risk is generally higher than for residential mortgage loans. These different risk factors are considered in the underwriting and pricing standards and in the allowance for loan losses established by ASB for its consumer, commercial and commercial real estate loans.

U.S. capital markets and credit and interest rate environment. Volatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB. As of December 31, 2015, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.8 billion.

Interest rate risk is a significant risk of ASB’s operations. ASB actively manages this risk, including managing the relationship of its interest-sensitive assets to its interest-sensitive liabilities. Persistent low levels of interest rates have made it challenging to find investments with adequate risk-adjusted returns and had a negative impact on ASB’s asset yields and net interest margin. If the current interest rate environment persists, the potential for compression of ASB’s net interest margin will continue. ASB also manages the credit risk associated with its lending and securities portfolios, but a deep and prolonged recession led by a material decline in housing prices could materially impair the value of its portfolios. See “Quantitative and Qualitative Disclosures about Market Risk” below.

Technological developments. New technological developments (e.g., significant advances in internet banking) may impact ASB’s future competitive position, results of operations and financial condition.

Environmental matters. Prior to extending a loan collateralized by real property, ASB conducts due diligence to assess whether or not the property may present environmental risks and potential cleanup liability. In the event of default and foreclosure of a loan, ASB may become the owner of the mortgaged property. For that reason, ASB seeks to avoid lending upon the security of, or acquiring through foreclosure, any property with significant potential environmental risks; however, there can be no assurance that ASB will successfully avoid all such environmental risks.

Regulation. ASB is subject to examination and comprehensive regulation by the Department of Treasury, OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. Regulation by these agencies focuses in large measure on the adequacy of ASB’s capital and the results of periodic “safety and soundness” examinations conducted by the OCC.

Capital requirements. The OCC, which is ASB’s principal regulator, administers two sets of capital standards—minimum regulatory capital requirements and prompt corrective action requirements. The FDIC also has prompt corrective action capital requirements. As of December 31, 2015, ASB was in compliance with OCC minimum regulatory capital requirements and was “well-capitalized” within the meaning of OCC prompt corrective action regulations and FDIC capital regulations, as follows:


•	ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 2015 with a Tier 1 leverage ratio of 8.8% (4.0%), a common equity Tier 1 capital ratio of 12.1% (4.5%), a Tier 1 capital ratio of 12.1% (6.0%) and a total capital ratio of 13.3% (8.0%).


•	ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2015 with a Tier 1 leverage ratio of 8.8% (5.0%), a common equity Tier 1 capital ratio of 12.1% (6.5%), a Tier-1 capital ratio of 12.1% (8.0%) and a total capital ratio of 13.3% (10.0%).

The purpose of the prompt corrective action capital requirements is to establish thresholds for varying degrees of oversight and intervention by regulators. Declines in levels of capital, depending on their severity, will result in increasingly stringent mandatory and discretionary regulatory consequences. Capital levels may decline for any number of reasons, including reductions that would result if there were losses from operations, deterioration in collateral values or the inability to dispose of real estate owned (typically acquired by foreclosure). The regulators have substantial discretion in the corrective actions they

might direct and could include restrictions on dividends and other distributions that ASB may make to HEI (through ASB Hawaii) and the requirement that ASB develop and implement a plan to restore its capital. Under an agreement with regulators entered into by HEI when it acquired ASB, HEI currently could be required to contribute to ASB up to an additional $28.3 million of capital, if necessary, to maintain ASB’s capital position.

Examinations. ASB is subject to periodic “safety and soundness” examinations and other examinations by the OCC. In conducting its examinations, the OCC utilizes the Uniform Financial Institutions Rating System adopted by the Federal Financial Institutions Examination Council, which system utilizes the “CAMELS” criteria for rating financial institutions. The six components in the rating system are: Capital adequacy, Asset quality, Management, Earnings, Liquidity and Sensitivity to market risk. The OCC examines and rates each CAMELS component. An overall CAMELS rating is also given, after taking into account all of the component ratings. A financial institution may be subject to formal regulatory or administrative direction or supervision such as a “memorandum of understanding” or a “cease and desist” order following an examination if its CAMELS rating is not satisfactory. An institution is prohibited from disclosing the OCC’s report of its safety and soundness examination or the component and overall CAMELS rating to any person or organization not officially connected with the institution as an officer, director, employee, attorney or auditor, except as provided by regulation. The OCC also regularly examines ASB’s information technology practices and its performance under Community Reinvestment Act measurement criteria.

The Federal Deposit Insurance Act, as amended, addresses the safety and soundness of the deposit insurance system, supervision of depository institutions and improvement of accounting standards. Pursuant to this Act, federal banking agencies have promulgated regulations that affect the operations of ASB and its holding companies (e.g., standards for safety and soundness, real estate lending, accounting and reporting, transactions with affiliates and loans to insiders). FDIC regulations restrict the ability of financial institutions that fail to meet relevant capital measures to engage in certain activities, such as offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2015, ASB was “well-capitalized” and thus not subject to these restrictions.

Qualified Thrift Lender status. ASB is a “qualified thrift lender” (QTL) under its federal thrift charter and, in order to maintain this status, ASB is required to maintain at least 65% of its assets in “qualified thrift investments,” which include housing-related loans (including mortgage-related securities) as well as certain small business loans, education loans, loans made through credit card accounts and a basket (not exceeding 20% of total assets) of other consumer loans and other assets. Institutions that fail to maintain QTL status are subject to various penalties, including limitations on their activities. In ASB’s case, the activities of HEI, ASB Hawaii and HEI’s other subsidiaries would also be subject to restrictions if ASB failed to maintain its QTL status, and a failure or inability to comply with those restrictions could effectively result in the required divestiture of ASB. As of December 31, 2015, ASB was a qualified thrift lender.

Unitary savings and loan holding company. The Gramm-Leach-Bliley Act of 1999 (Gramm Act) permitted banks, insurance companies and investment firms to compete directly against each other, thereby allowing “one-stop shopping” for an array of financial services. Although the Gramm Act further restricted the creation of so-called “unitary savings and loan holding companies” (i.e., companies such as HEI whose subsidiaries include one or more savings associations and one or more nonfinancial subsidiaries), the unitary savings and loan holding company relationship among HEI, ASB Hawaii and ASB is “grandfathered” under the Gramm Act so that HEI and its subsidiaries will be able to continue to engage in their current activities so long as ASB maintains its QTL status. Under the Gramm Act, any proposed sale of ASB would have to satisfy applicable statutory and regulatory requirements and potential acquirers of ASB would most likely be limited to companies that are already qualified as, or capable of qualifying as, either a traditional savings and loan association holding company or a bank holding company, or as one of the authorized financial holding companies permitted under the Gramm Act. There have been legislative proposals in the past which would operate to eliminate the thrift charter or the grandfathered status of HEI as a unitary thrift holding company and effectively require the divestiture of ASB.

Material estimates and critical accounting policies. Also see “Material estimates and critical accounting policies” for Consolidated HEI above.

Allowance for loan losses. See Note 1 of the Consolidated Financial Statements and the discussion above under “Earning assets, costing liabilities and other factors.” ASB maintains an allowance for loan losses believed to be adequate to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (for example, economic conditions, real estate market conditions and interest rate environment). The allowance for loan losses is allocated to loan types using both a formula-based approach applied to groups of loans and an analysis of certain individual loans for impairment. The formula-based approach emphasizes loss factors primarily derived from actual historical default and loss rates, which are combined with an assessment of certain qualitative factors to determine the allowance amounts allocated to the various loan categories. Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.

ASB disaggregates the loan portfolio into loan segments for purposes of determining the allowance for loan losses. Commercial and commercial real estate loans are defined as non-homogeneous loans. ASB utilizes a risk rating system for evaluating the credit quality of such loans. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. Values are applied separately to the probability of default (borrower risk) and loss given default (transaction risk). ASB's credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Non-homogeneous loans are categorized into the regulatory asset quality classifications: Pass, Special Mention, Substandard, Doubtful, and Loss based on credit quality. For loans classified as substandard, an analysis is done to determine if the loan is impaired. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the contractual terms of the loan agreement. Once a loan is deemed impaired, ASB applies a valuation methodology to determine whether there is an impairment shortfall. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sale of the underlying collateral property, ASB measures impairment by utilizing the fair value of the collateral, net of costs to sell; for other loans that are not considered collateral dependent, generally the discounted cash flow method is used to measure impairment. For loans collateralized by real estate that are classified as troubled debt restructured ("TDR") loans, the present value of the expected future cash flows of the loans may also be used to measure impairment as these loans are expected to perform according to their restructured terms. Impairment shortfalls are charged to the provision for loan losses and included in the allowance for loan losses. However, impairment shortfalls that are deemed to be confirmed losses (uncollectible) are charged off, with the loan written down by the amount of the confirmed loss.

Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. The homogeneous loan portfolios are stratified into individual products with common risk characteristics and segmented into various secured and unsecured loan product types. For the homogeneous portfolio, the quality of the loan is best indicated by the repayment performance of an individual borrower. ASB supplements performance data with an 11-risk rating retail credit model that assigns a probability of default to each borrower based primarily on the borrower's current Fair Isaac Corporation ("FICO") score and for HELOC and unsecured consumer products, the bankruptcy score. Current FICO and bankruptcy data is purchased and appended to all homogeneous loans on a quarterly basis and used to estimate the borrower’s probability of default and the loss given default.

ASB's methodology for determining the allowance for loan losses was generally based on historic loss rates using various look-back periods. During the second quarter of 2014, ASB implemented enhancements to the loss rate calculation for estimating the allowance for loan losses that included several refinements to determining the probability of default and the loss given default for the various segments of the loan portfolio that are more statistically sound than those previously employed. The result is an estimated loss rate established for each loan. ASB believes that these enhancements improve the precision in estimating the allowance for loan losses. The enhancement did not have a material effect on the total allowance for loan losses or the provision for loan losses for 2014 and did result in the full allocation of the previously unallocated portion of the allowance for loan losses.

In conjunction with the above enhancement, management also adopted an enhanced risk rating system for monitoring and managing credit risk in the non-homogenous loan portfolios that measures general creditworthiness at the borrower level. The numerical-based, risk rating “PD Model” takes into consideration fiscal year-end financial information of the borrower and identified financial attributes including retained earnings, operating cash flows, interest coverage, liquidity and leverage that demonstrate a strong correlation with default to assign default probabilities at the borrower level. In addition, a loss given default value is assigned to each loan to measure loss in the event of default based on loan specific features such as collateral that mitigates the amount of loss in the event of default. Together the PD Model and loss given default construct provide a more quantitative, data driven and consistent framework for measuring risk within the portfolio, on a loan by loan basis and for the ultimate collectability of each loan. Additionally, qualitative factors may be included in the estimation process.

The reserve for unfunded commitments is maintained at a level believed by management to be sufficient to absorb estimated probable losses related to unfunded credit facilities and is included in accounts payable and other liabilities in the consolidated balance sheets. The determination of the adequacy of the reserve is based upon an evaluation of the unfunded credit facilities, including an assessment of historical commitment utilization experience, credit risk grading and historical loss rates. This process takes into consideration the same risk elements that are analyzed in the determination of the adequacy of the allowance for loan losses, as discussed above. Net adjustments to the reserve for unfunded commitments are included in other noninterest expense in the consolidated statements of income.

required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could differ from management’s estimates, and these differences and subsequent adjustments could be material.

Nonperforming loans. Loans are generally placed on nonaccrual status when contractually past due 90 days or more, or earlier if management believes that the probability of collection is insufficient to warrant further accrual. All interest that is accrued but not collected is reversed. A loan may be returned to accrual status if (i) principal and interest payments have been brought current and ASB expects repayment of the remaining contractual principal and interest, (ii) the loan has otherwise become well-secured and collection efforts are reasonably expected to result in repayment of the debt, or (iii) the borrower has been making regularly scheduled payments in full for the prior six months and it is reasonably assured that the loan will be brought fully current within a reasonable period. Cash receipts on nonaccruing loans are generally applied to reduce the unpaid principal balance.

Loans considered to be uncollectible are charged-off against the allowance. The amount and timing of charge-offs on loans includes consideration of the loan type, length of delinquency, insufficiency of collateral value, lien priority and the overall financial condition of the borrower. Recoveries on loans previously charged-off are credited back to the allowance. Loans that have been charged-off against the allowance are periodically monitored to evaluate whether further adjustments to the allowance are necessary.

Loans in the commercial and commercial real estate portfolio are charged-off when the loan is risk rated “doubtful” or “loss”. The loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 90 days or more; (b) significant improvement in the borrower’s repayment capacity is doubtful; and/or (c) collateral value is insufficient to cover outstanding indebtedness and no other viable assets exist.

Loans in the residential mortgage and home equity portfolios are charged-off when the loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 180 days or more; (b) it is probable that collateral value is insufficient to cover outstanding indebtedness and no other viable assets exist; (c) notification of the borrower’s bankruptcy is received; or (d) in cases where ASB is in a subordinate position to other debt, the senior lien holder has foreclosed and extinguished the junior lien.

Other consumer loans are generally charged-off when the balance becomes 120 days delinquent.

See "Nonperforming loans" in Note 1 of the Consolidated Financial Statements for additional information regarding ASB's nonperforming loans.

Troubled debt restructurings. A loan modification is deemed to be a TDR when ASB grants a concession ASB would not otherwise consider if it were 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 their financial position to eventually be able to repay the loan fully, 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 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 TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period or interest only payments for a period of time. 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 payments. Commercial loan modifications generally involve extensions of maturity dates, extending the amortization period and temporary deferral of principal payments. ASB generally do not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.

Certain TDRs that are current in payment status are classified as nonaccrual in accordance with regulatory guidance. These nonaccruing TDRs can be returned to accrual status when principal and interest have been current for at least six months and a well-documented evaluation of the borrower’s financial condition has been performed and indicates future payments are reasonably assured.

impairment amount is an increase to the allowance for loan losses 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.

Fair value. Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent third party sources. However, in certain cases, ASB uses its own assumptions based on the best information available in certain 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 ASB were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of its 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.

ASB classifies its financial assets and liabilities that are measured at fair value in accordance with the three level valuation hierarchy 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 t 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.

Significant assets measured at fair value on a recurring basis include ASB's mortgage-related securities available for sale. These instruments are priced using an external pricing service and are classified as Level 2 within the fair value hierarchy. The third-party pricing services use a variety of methods to determine fair value including 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 compares 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 the investment manager 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.

See "Investment securities" and "Derivative financial instruments" in Note 5 and Note 16 of the Consolidated Financial Statements for additional information regarding ASB's fair value measurements.



ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI and Hawaiian Electric (in the case of Hawaiian Electric, only the information related to Hawaiian Electric and its subsidiaries is applicable):

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk. The Company believes the electric utility and the “other” segment’s exposures to these two risks are not material as of December 31, 2015.

Credit risk for ASB is the risk that borrowers or issuers of securities will not be able to repay their obligations to the bank. Credit risk associated with ASB’s lending portfolios is controlled through its underwriting standards, loan rating of commercial and commercial real estate loans, on-going monitoring by loan officers, credit review and quality control functions in these lending areas and adequate allowance for loan losses. Credit risk associated with the securities portfolio is mitigated through investment portfolio limits, experienced staff working with analytical tools, monthly fair value analysis and on-going monitoring and reporting such as investment watch reports and loss sensitivity analysis. See “Allowance for loan losses” above and in Note 5 of the Consolidated Financial Statements.

Liquidity risk for ASB is the risk that the bank will not meet its obligations when they become due. Liquidity risk is mitigated by ASB’s asset/liability management process, on-going analytical analysis, monitoring and reporting information such as weekly cash-flow analyses and maintenance of liquidity contingency plans.

The Utilities are exposed to some commodity price risk primarily related to their fuel supply and IPP contracts. The Utilities' commodity price risk is substantially mitigated so long as they have their current ECACs in their rate schedules. The Utilities currently have no hedges against its commodity price risk.

The Company currently has no direct exposure to market risk from trading activities nor foreign currency exchange rate risk.

The Company considers interest rate risk to be a very significant market risk as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity, especially as it relates to ASB, but also as it may affect the discount rate used to determine retirement benefit liabilities, the market value of retirement benefit plans’ assets and the Utilities’ allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.

Bank interest rate risk

The Company’s success is dependent, in part, upon ASB’s ability to manage interest rate risk (IRR). ASB’s interest-rate risk profile is strongly influenced by its primary business of making fixed-rate residential mortgage loans and taking in retail deposits. Large mismatches in the amounts or timing between the maturity or repricing of interest sensitive assets or liabilities could adversely affect ASB’s earnings and the market value of its interest-sensitive assets and liabilities in the event of significant changes in the level of interest rates. Many other factors also affect ASB’s exposure to changes in interest rates, such as general economic and financial conditions, customer preferences and competition for loans or deposits.

ASB’s Asset/Liability Management Committee (ALCO), whose voting members are officers and employees of ASB, is responsible for managing interest rate risk and carrying out the overall asset/liability management objectives and activities of ASB as approved by the ASB Board of Directors. ALCO establishes policies under which management monitors and coordinates ASB’s assets and liabilities.

See Note 5 of the Consolidated Financial Statements for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential loan sale program.

Management of ASB measures interest-rate risk using simulation analysis with an emphasis on measuring changes in net interest income (NII) and the market value of interest-sensitive assets and liabilities in different interest-rate environments. The simulation analysis is performed using a dedicated asset/liability management software system enhanced with a mortgage prepayment model and a collateralized mortgage obligation database. The simulation software is capable of generating scenario-specific cash flows for all instruments using the specified contractual information for each instrument and product specific prepayment assumptions for mortgage loans and mortgage-related securities.

NII sensitivity analysis measures the change in ASB’s twelve-month, pretax NII in alternate interest rate scenarios. NII sensitivity is measured as the change in NII in the alternate interest-rate scenarios as a percentage of the base case NII. The base case interest-rate scenario is established using the current yield curve and assumes interest rates remain constant over the next

twelve months. The alternate scenarios are created by assuming “rate ramps” or gradual interest changes and accomplished by moving the yield curve in a parallel fashion, over the next twelve month period, in increments of +/- 100 basis points. The simulation model forecasts scenario-specific principal and interest cash flows for the interest-bearing assets and liabilities, and the NII is calculated for each scenario. Key balance sheet modeling assumptions used in the NII sensitivity analysis include: the size of the balance sheet remains relatively constant over the simulation horizon and maturing assets or liabilities are reinvested in similar instruments in order to maintain the current mix of the balance sheet. In addition, assumptions are made about the prepayment behavior of mortgage-related assets, future pricing spreads for new assets and liabilities and the speed and magnitude with which deposit rates change in response to changes in the overall level of interest rates. Other NII sensitivity analysis may include scenarios such as yield curve twists or non-static balance sheet changes (such as changes to key balance sheet drivers).

Consistent with OCC guidelines, the market value or economic capitalization of ASB is measured as economic value of equity (EVE). EVE represents the theoretical market value of ASB’s net worth and is defined as the present value of expected net cash flows from existing assets minus the present value of expected cash flows from existing liabilities plus the present value of expected net cash flows from existing off-balance sheet contracts. Key assumptions used in the calculation of ASB’s EVE include the prepayment behavior of loans and investments, the possible distribution of future interest rates, pricing spreads for assets and liabilities in the alternate scenarios and the rate and balance behavior of deposit accounts with indeterminate maturities. EVE is calculated in multiple scenarios. As with the NII simulation, the base case is represented by the current yield curve. Alternate scenarios are created by assuming immediate parallel shifts in the yield curve in increments of +/- 100 basis points (bp) up to + 300 bp. The change in EVE is measured as the change in EVE in a given rate scenario from the base case and expressed as a percentage. To gain further insight into the IRR profile, additional analysis is periodically performed in alternate scenarios including rate shifts of greater magnitude and changes in key balance sheet drivers.

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



	Change in NII (gradual change in interest rates)				Change in EVE (instantaneous change in interest rates)
Change in interest rates (basis points)	December 31, 2015		December 31, 2014		December 31, 2015		December 31, 2014
+300	1.6	%	1.9	%	(9.3	)%	(6.1	)%
+200	0.6		0.7		(5.3	)	(2.9	)
+100	(0.1	)	0.1		(1.9	)	(0.7	)
-100	(0.5	)	(0.5	)	(1.2	)	(2.5	)

Management believes that ASB’s interest rate risk position as of December 31, 2015 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was slightly liability sensitive for small rate increases and less asset sensitive for larger rate increases as of December 31, 2015 compared to December 31, 2014. Assets grew by $450 million with the increase in commercial real estate loans and interest-bearing deposits which have short-term repricing horizons. Also, with the increase in the Prime index, the equity express loans reprice to higher rates compared to a year ago. The growth in assets and shift in mix was offset by the change in the liability mix. Savings deposits grew by $108 million with the mix shifting to higher rate sensitive products. In addition, retail repurchase agreements, which have short-term repricing horizons, increased by $38 million. The net change in the balance sheet mix lessened ASB’s asset sensitivity.

ASB’s base EVE increased to $974 million as of December 31, 2015 compared to $947 million as of December 31, 2014 due to growth in capital.

The change in EVE to rising rates became more sensitive as of December 31, 2015 compared to December 31, 2014 as the duration of assets lengthened while the duration of liabilities shortened. The upward shift in the yield curve caused mortgage rates to increase, led to slower prepayment expectations and lengthened the duration of the fixed rate mortgage portfolio. In addition, the investment portfolio grew by $270 million with purchases consisting of longer duration securities and callable agency notes which have the potential to extend in average life as rates rise. Offsetting some of this increased sensitivity was the growth of $357 million in core deposit balances with the mix shifting to longer duration products.

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.

Other than bank interest rate risk

The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt (currently fixed-rate debt) and preferred securities. As of December 31, 2015, management believes the Company is exposed to “other than bank” interest rate risk because of its periodic borrowing requirements, the impact of interest rates on the discount rate and the market value of plan assets used to determine retirement benefits expenses and obligations (see “Retirement benefits” in HEI’s MD&A and Note 10 of the Consolidated Financial Statements) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates”). Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material. The Company’s longer-term debt, in the form of borrowings of proceeds of revenue bonds, privately-placed Senior Notes, and bank term loans, is at fixed rates (see Note 16 of the Consolidated Financial Statements for the fair value of long-term debt, net-other than bank).



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI and Hawaiian Electric:



Index to Consolidated Financial Statements	Page
Report of Independent Registered Public Accounting Firm - HEI	84
Report of Independent Registered Public Accounting Firm - Hawaiian Electric	85
Consolidated Financial Statements	86
HEI
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	86
Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013	87
Consolidated Balance Sheets at December 31, 2015 and 2014	88
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2015, 2014 and 2013	89
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	90
Hawaiian Electric
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	92
Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013	92
Consolidated Balance Sheets at December 31, 2015 and 2014	93
Consolidated Statements of Capitalization at December 31, 2015 and 2014	94
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2015, 2014 and 2013	96
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	97
Notes to Consolidated Financial Statements	98

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Hawaiian Electric Industries, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and its subsidiaries at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2)present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the preparation and review of the consolidated statement of cash flows existed as of that date. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2015 consolidated financial statements and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 23, 2016

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Hawaiian Electric Company, Inc.

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the financial statements, the Company changed the manner in which it classifies deferred taxes in 2015.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 23, 2016

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
(in thousands, except per share amounts)
Revenues
Electric utility	$	2,335,166		$	2,987,323		$	2,980,172
Bank	267,733			252,497			258,147
Other	83			(278		)	151
Total revenues	2,602,982			3,239,542			3,238,470
Expenses
Electric utility	2,061,050			2,711,555			2,734,659
Bank	183,921			173,202			169,001
Other	35,458			22,185			17,302
Total expenses	2,280,429			2,906,942			2,920,962
Operating income (loss)
Electric utility	274,116			275,768			245,513
Bank	83,812			79,295			89,146
Other	(35,375		)	(22,463		)	(17,151		)
Total operating income	322,553			332,600			317,508
Interest expense, net – other than on deposit liabilities and other bank borrowings	(77,150		)	(76,352		)	(75,479		)
Allowance for borrowed funds used during construction	2,457			2,579			2,246
Allowance for equity funds used during construction	6,928			6,771			5,561
Income before income taxes	254,788			265,598			249,836
Income taxes	93,021			95,579			86,237
Net income	161,767			170,019			163,599
Preferred stock dividends of subsidiaries	1,890			1,890			1,890
Net income for common stock	$	159,877		$	168,129		$	161,709
Basic earnings per common share	$	1.50		$	1.65		$	1.63
Diluted earnings per common share	$	1.50		$	1.63		$	1.62
Dividends per common share	$	1.24		$	1.24		$	1.24
Weighted-average number of common shares outstanding	106,418			101,968			98,968
Net effect of potentially dilutive shares	303			969			655
Adjusted weighted-average shares	106,721			102,937			99,623

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

Consolidated Statements of Comprehensive Income

Hawaiian Electric Industries, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
(in thousands)
Net income for common stock	$	159,877		$	168,129		$	161,709
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 $1,541, $(3,856) and $9,037 for 2015, 2014 and 2013, respectively	(2,334		)	5,840			(13,686		)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, $1,132 and $488 for 2015, 2014 and 2013, respectively	—			(1,715		)	(738		)
Derivatives qualified as cash flow hedges:
Less: reclassification adjustment to net income, net of tax benefits of $150, $150 and $150 for 2015, 2014 and 2013, respectively	235			236			235
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of ($3,753), $149,364 and ($142,478) for 2015, 2014 and 2013, respectively	5,889			(234,166		)	223,177
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $14,344, $7,245 and $14,870 for 2015, 2014 and 2013, respectively	22,465			11,344			23,280
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $16,011, ($132,373) and $141,777 for 2015, 2014 and 2013, respectively	(25,139		)	207,833			(222,595		)
Other comprehensive income (loss), net of taxes	1,116			(10,628		)	9,673
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	160,993		$	157,501		$	171,382

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

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries



December 31				2015						2014
(dollars in thousands)
ASSETS
Cash and cash equivalents				$	300,478					$	175,542
Accounts receivable and unbilled revenues, net				242,766						313,696
Available-for-sale investment securities, at fair value				820,648						550,394
Stock in Federal Home Loan Bank, at cost				10,678						69,302
Loans receivable held for investment, net				4,565,781						4,389,033
Loans held for sale, at lower of cost or fair value				4,631						8,424
Property, plant and equipment, net
Land	$	90,890					$	94,093
Plant and equipment	6,444,214						6,137,417
Construction in progress	181,873						168,214
	6,716,977						6,399,724
Less – accumulated depreciation	(2,339,319		)	4,377,658			(2,250,950		)	4,148,774
Regulatory assets				896,731						905,264
Other				488,635						542,523
Goodwill				82,190						82,190
Total assets				$	11,790,196					$	11,185,142
LIABILITIES AND SHAREHOLDERS’ EQUITY
Liabilities
Accounts payable				$	138,523					$	186,425
Interest and dividends payable				26,042						25,336
Deposit liabilities				5,025,254						4,623,415
Short-term borrowings—other than bank				103,063						118,972
Other bank borrowings				328,582						290,656
Long-term debt, net—other than bank				1,586,546						1,506,546
Deferred income taxes				680,877						633,570
Regulatory liabilities				371,543						344,849
Contributions in aid of construction				506,087						466,432
Defined benefit pension and other postretirement benefit plans liability				589,918						632,845
Other				471,828						531,230
Total liabilities				9,828,263						9,360,276
Preferred stock of subsidiaries - not subject to mandatory redemption				34,293						34,293
Commitments and contingencies (Notes 4 and 5)
Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none				—						—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 107,460,406 shares and 102,565,266 shares at December 31, 2015 and 2014, respectively				1,629,136						1,521,297
Retained earnings				324,766						296,654
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains (losses) on securities	$	(1,872	)				$	462
Unrealized losses on derivatives	(54		)				(289		)
Retirement benefit plans	(24,336		)	(26,262		)	(27,551		)	(27,378		)
Total shareholders’ equity				1,927,640						1,790,573
Total liabilities and shareholders’ equity				$	11,790,196					$	11,185,142

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

Consolidated Statements of Changes in Shareholders’ Equity

Hawaiian Electric Industries, Inc. and Subsidiaries



	Common stock				Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount			earnings			income (loss)			Total
Balance, December 31, 2012	97,928	$	1,403,484		$	215,947		$	(26,423	)	$	1,593,008
Net income for common stock	—	—			161,709			—			161,709
Other comprehensive income, net of taxes	—	—			—			9,673			9,673
Issuance of common stock:
Partial settlement of equity forward	1,300	33,409			—			—			33,409
Dividend reinvestment and stock purchase plan	1,612	41,692			—			—			41,692
Retirement savings and other plans	420	9,203			—			—			9,203
Expenses and other, net	—	338			—			—			338
Common stock dividends ($1.24 per share)	—	—			(122,626		)	—			(122,626		)
Balance, December 31, 2013	101,260	1,488,126			255,030			(16,750		)	1,726,406
Net income for common stock	—	—			168,129			—			168,129
Other comprehensive loss, net of tax benefits	—	—			—			(10,628		)	(10,628		)
Issuance of common stock:
Partial settlement of equity forward	1,000	24,873			—			—			24,873
Dividend reinvestment and stock purchase plan	95	2,461			—			—			2,461
Retirement savings and other plans	210	6,816			—			—			6,816
Expenses and other, net	—	(979		)	—			—			(979		)
Common stock dividends ($1.24 per share)	—	—			(126,505		)	—			(126,505		)
Balance, December 31, 2014	102,565	1,521,297			296,654			(27,378		)	1,790,573
Net income for common stock	—	—			159,877			—			159,877
Other comprehensive income, net of taxes	—	—			—			1,116			1,116
Issuance of common stock:
Partial settlement of equity forward	4,700	109,183			—			—			109,183
Retirement savings and other plans	195	5,578			—			—			5,578
Expenses and other, net	—	(6,922		)	—			—			(6,922		)
Common stock dividends ($1.24 per share)	—	—			(131,765		)	—			(131,765		)
Balance, December 31, 2015	107,460	$	1,629,136		$	324,766		$	(26,262	)	$	1,927,640

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

Consolidated Statements of Cash Flows

Hawaiian Electric Industries, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
(in thousands)
Cash flows from operating activities
Net income	$	161,767		$	170,019		$	163,599
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	183,966			172,762			160,061
Other amortization	11,619			10,282			7,324
Provision for loan losses	6,275			6,126			1,507
Impairment of utility assets	6,021			1,866			—
Other	1,672			758			—
Loans receivable originated and purchased, held for sale	(268,279		)	(155,755		)	(249,022		)
Proceeds from sale of loans receivable, held for sale	275,296			155,030			273,775
Gain on sale of credit card portfolio	—			—			(2,251		)
Increase in deferred income taxes	41,433			104,226			80,145
Share-based compensation expense	6,542			9,287			7,780
Excess tax benefits from share-based payment arrangements	(978		)	(277		)	(430		)
Allowance for equity funds used during construction	(6,928		)	(6,771		)	(5,561		)
Change in cash overdraft	—			(1,038		)	1,038
Changes in assets and liabilities
Decrease in accounts receivable and unbilled revenues, net	62,304			33,089			16,038
Decrease in fuel oil stock	34,830			28,041			27,332
Increase in regulatory assets	(24,182		)	(17,000		)	(65,461		)
Increase (decrease) in accounts, interest and dividends payable	(52,663		)	(67,189		)	12,406
Change in prepaid and accrued income taxes and utility revenue taxes	(42,596		)	(39,091		)	(19,406		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	852			22,251			(33,014		)
Change in other assets and liabilities	(41,071		)	(101,196		)	(14,292		)
Net cash provided by operating activities	355,880			325,420			361,568
Cash flows from investing activities
Available-for-sale investment securities purchased	(429,262		)	(183,778		)	(112,654		)
Principal repayments on available-for-sale investment securities	153,271			91,013			158,558
Proceeds from sale of available-for-sale investment securities	—			79,564			71,367
Purchase of stock from Federal Home Loan Bank	(1,600		)	—			—
Redemption of stock from Federal Home Loan Bank	60,223			23,244			3,476
Net increase in loans held for investment	(181,343		)	(283,810		)	(398,426		)
Proceeds from sale of real estate acquired in settlement of loans	1,329			3,213			9,212
Proceeds from sale of real estate held for sale	7,283			—			—
Capital expenditures	(363,804		)	(364,826		)	(389,438		)
Contributions in aid of construction	40,239			41,806			32,160
Proceeds from sale of credit card portfolio	—			—			26,386
Other	7,940			1,125			1,177
Net cash used in investing activities	(705,724		)	(592,449		)	(598,182		)

(continued)

Consolidated Statements of Cash Flows (continued)

Hawaiian Electric Industries, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
Cash flows from financing activities
Net increase in deposit liabilities	401,839			250,938			142,561
Net increase (decrease) in short-term borrowings with original maturities of three months or less	(15,909		)	13,490			21,789
Net increase (decrease) in retail repurchase agreements	37,925			(9,465		)	(1,418		)
Proceeds from other bank borrowings	50,000			130,601			130,000
Repayments of other bank borrowings	(50,000		)	(75,000		)	(80,000		)
Proceeds from issuance of long-term debt	80,000			125,000			286,000
Repayment of long-term debt	—			(111,400		)	(216,000		)
Excess tax benefits from share-based payment arrangements	978			277			430
Net proceeds from issuance of common stock	104,435			26,898			55,086
Common stock dividends	(131,765		)	(126,458		)	(98,383		)
Preferred stock dividends of subsidiaries	(1,890		)	(1,890		)	(1,890		)
Other	(833		)	(456		)	(1,187		)
Net cash provided by financing activities	474,780			222,535			236,988
Net increase (decrease) in cash and cash equivalents	124,936			(44,494		)	374
Cash and cash equivalents, January 1	175,542			220,036			219,662
Cash and cash equivalents, December 31	$	300,478		$	175,542		$	220,036

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

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
(in thousands)
Revenues	$	2,335,166		$	2,987,323		$	2,980,172
Expenses
Fuel oil	654,600			1,131,685			1,185,552
Purchased power	594,096			722,008			710,681
Other operation and maintenance	413,089			410,612			403,270
Depreciation	177,380			166,387			154,025
Taxes, other than income taxes	221,885			280,863			281,131
Total expenses	2,061,050			2,711,555			2,734,659
Operating income	274,116			275,768			245,513
Allowance for equity funds used during construction	6,928			6,771			5,561
Interest expense and other charges, net	(66,370		)	(64,757		)	(59,279		)
Allowance for borrowed funds used during construction	2,457			2,579			2,246
Income before income taxes	217,131			220,361			194,041
Income taxes	79,422			80,725			69,117
Net income	137,709			139,636			124,924
Preferred stock dividends of subsidiaries	915			915			915
Net income attributable to Hawaiian Electric	136,794			138,721			124,009
Preferred stock dividends of Hawaiian Electric	1,080			1,080			1,080
Net income for common stock	$	135,714		$	137,641		$	122,929

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

Consolidated Statements of Comprehensive Income

Hawaiian Electric Company, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
(in thousands)
Net income for common stock	$	135,714		$	137,641		$	122,929
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of ($3,590), $139,236 and ($129,601) for 2015, 2014 and 2013, respectively	5,638			(218,608		)	203,479
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $12,981, $6,504 and $13,180 for 2015, 2014 and 2013, respectively	20,381			10,212			20,694
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $16,011, ($132,373) and $141,777 for 2015, 2014 and 2013, respectively	(25,139		)	207,833			(222,595		)
Other comprehensive income (loss), net of taxes	880			(563		)	1,578
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	136,594		$	137,078		$	124,507

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

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2015			2014
(in thousands)
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	52,792		$	52,299
Plant and equipment	6,315,698			6,009,482
Less accumulated depreciation	(2,266,004		)	(2,175,510		)
Construction in progress	175,309			158,616
Utility property, plant and equipment, net	4,277,795			4,044,887
Nonutility property, plant and equipment, less accumulated depreciation of $1,229 and $1,227 at respective dates	7,272			6,563
Total property, plant and equipment, net	4,285,067			4,051,450
Current assets
Cash and cash equivalents	24,449			13,762
Customer accounts receivable, net	132,778			158,484
Accrued unbilled revenues, net	84,509			137,374
Other accounts receivable, net	10,408			4,283
Fuel oil stock, at average cost	71,216			106,046
Materials and supplies, at average cost	54,429			57,250
Prepayments and other	36,640			33,468
Regulatory assets	72,231			71,421
Total current assets	486,660			582,088
Other long-term assets
Regulatory assets	824,500			833,843
Unamortized debt expense	8,341			8,323
Other	75,486			81,838
Total other long-term assets	908,327			924,004
Total assets	$	5,680,054		$	5,557,542
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,728,325		$	1,682,144
Cumulative preferred stock – not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (Note 4)
Long-term debt, net	1,286,546			1,206,546
Total capitalization	3,049,164			2,922,983
Current liabilities
Accounts payable	114,846			163,934
Interest and preferred dividends payable	23,111			22,316
Taxes accrued	191,084			250,402
Regulatory liabilities	2,204			632
Other	54,079			61,664
Total current liabilities	385,324			498,948
Deferred credits and other liabilities
Deferred income taxes	654,806			573,439
Regulatory liabilities	369,339			344,217
Unamortized tax credits	84,214			79,492
Defined benefit pension and other postretirement benefit plans liability	552,974			595,395
Other	78,146			76,636
Total deferred credits and other liabilities	1,739,479			1,669,179
Contributions in aid of construction	506,087			466,432
Total capitalization and liabilities	$	5,680,054		$	5,557,542

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

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2015		2014
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding:
2015, 15,805,327 shares and 2014, 15,805,327 shares	$	105,388	$	105,388
Premium on capital stock	578,930		578,938
Retained earnings	1,043,082		997,773
Accumulated other comprehensive income, net of taxes - retirement benefit plans	925		45
Common stock equity	1,728,325		1,682,144
Cumulative preferred stock not subject to mandatory redemption
Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value.



Series	Par Value		Par Value	Shares outstanding December 31, 2015 and 2014	2015		2014
(dollars in thousands, except par value and shares outstanding)
C-4 1/4%	$	20	(Hawaiian Electric)	150,000	$	3,000	$	3,000
D-5%	20		(Hawaiian Electric)	50,000	1,000		1,000
E-5%	20		(Hawaiian Electric)	150,000	3,000		3,000
H-5 1/4%	20		(Hawaiian Electric)	250,000	5,000		5,000
I-5%	20		(Hawaiian Electric)	89,657	1,793		1,793
J-4 3/4%	20		(Hawaiian Electric)	250,000	5,000		5,000
K-4.65%	20		(Hawaiian Electric)	175,000	3,500		3,500
G-7 5/8%	100		(Hawaii Electric Light)	70,000	7,000		7,000
H-7 5/8%	100		(Maui Electric)	50,000	5,000		5,000
				1,234,657	34,293		34,293

(continued)

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

Consolidated Statements of Capitalization (continued)

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2015		2014
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds (subsidiary obligations unconditionally guaranteed by Hawaiian Electric):
Hawaiian Electric, 3.25%, refunding series 2015, due 2025	$	40,000	$	—
Hawaii Electric Light, 3.25%, refunding series 2015, due 2025	5,000		—
Maui Electric, 3.25%, refunding series 2015, due 2025	2,000		—
Hawaiian Electric, 6.50%, series 2009, due 2039	90,000		90,000
Hawaii Electric Light, 6.50%, series 2009, due 2039	60,000		60,000
Hawaiian Electric, 4.60%, refunding series 2007B, due 2026	62,000		62,000
Hawaii Electric Light, 4.60%, refunding series 2007B, due 2026	8,000		8,000
Maui Electric, 4.60%, refunding series 2007B, due 2026	55,000		55,000
Hawaiian Electric, 4.65%, series 2007A, due 2037	100,000		100,000
Hawaii Electric Light, 4.65%, series 2007A, due 2037	20,000		20,000
Maui Electric, 4.65%, series 2007A, due 2037	20,000		20,000
Hawaiian Electric, 4.80%, refunding series 2005A, paid in 2015	—		40,000
Hawaii Electric Light, 4.80%, refunding series 2005A, paid in 2015	—		5,000
Maui Electric, 4.80%, refunding series 2005A, paid in 2015	—		2,000
Total obligations to the State of Hawaii	462,000		462,000
Other long-term debt – unsecured:
Taxable senior notes:
Hawaiian Electric, 5.23%, Series 2015A, due 2045	50,000		—
Hawaii Electric Light, 5.23%, Series 2015A, due 2045	25,000		—
Maui Electric, 5.23%, Series 2015A, due 2045	5,000		—
Hawaii Electric Light, 3.83%, Series 2013A, due 2020	14,000		14,000
Hawaiian Electric, 4.45%, Series 2013A, due 2022	40,000		40,000
Hawaii Electric Light, 4.45%, Series 2013B, due 2022	12,000		12,000
Hawaiian Electric, 4.84%, Series 2013B, due 2027	50,000		50,000
Hawaii Electric Light, 4.84%, Series 2013C, due 2027	30,000		30,000
Maui Electric, 4.84%, Series 2013A, due 2027	20,000		20,000
Hawaiian Electric, 5.65%, Series 2013C, due 2043	50,000		50,000
Maui Electric, 5.65%, Series 2013B, due 2043	20,000		20,000
Hawaiian Electric, 3.79%, Series 2012A, due 2018	30,000		30,000
Hawaii Electric Light, 3.79%, Series 2012A, due 2018	11,000		11,000
Maui Electric, 3.79%, Series 2012A, due 2018	9,000		9,000
Hawaiian Electric, 4.03%, Series 2012B, due 2020	62,000		62,000
Maui Electric, 4.03%, Series 2012B, due 2020	20,000		20,000
Hawaiian Electric, 4.55%, Series 2012C, due 2023	50,000		50,000
Hawaii Electric Light, 4.55%, Series 2012B, due 2023	20,000		20,000
Maui Electric, 4.55%, Series 2012C, due 2023	30,000		30,000
Hawaiian Electric, 4.72%, Series 2012D, due 2029	35,000		35,000
Hawaiian Electric, 5.39%, Series 2012E, due 2042	150,000		150,000
Hawaiian Electric, 4.53%, Series 2012F, due 2032	40,000		40,000
Total taxable senior notes	773,000		693,000
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034	51,546		51,546
Total other long-term debt – unsecured	824,546		744,546
Total long-term debt	1,286,546		1,206,546
Less unamortized discount	—		—
Less current portion long-term debt	—		—
Long-term debt, net	1,286,546		1,206,546
Total capitalization	$	3,049,164	$	2,922,983

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

Consolidated Statements of Changes in Common Stock Equity

Hawaiian Electric Company, Inc. and Subsidiaries



	Common stock			Premium on capital			Retained			Accumulated other comprehensive
(in thousands)	Shares	Amount		stock			earnings			income (loss)			Total
Balance, December 31, 2012	14,665	$	97,788	$	468,045		$	907,273		$	(970	)	$	1,472,136
Net income for common stock	—	—		—			122,929			—			122,929
Other comprehensive income, net of tax benefits	—	—		—			—			1,578			1,578
Issuance of common stock, net of expenses	764	5,092		73,407			—			—			78,499
Common stock dividends	—	—		—			(81,578		)	—			(81,578		)
Balance, December 31, 2013	15,429	102,880		541,452			948,624			608			1,593,564
Net income for common stock	—	—		—			137,641			—			137,641
Other comprehensive loss, net of taxes	—	—		—			—			(563		)	(563		)
Issuance of common stock, net of expenses	376	2,508		37,486			—			—			39,994
Common stock dividends	—	—		—			(88,492		)	—			(88,492		)
Balance, December 31, 2014	15,805	105,388		578,938			997,773			45			1,682,144
Net income for common stock	—	—		—			135,714			—			135,714
Other comprehensive income, net of tax benefits	—	—		—			—			880			880
Common stock issuance expense	—	—		(8		)	—			—			(8		)
Common stock dividends	—	—		—			(90,405		)	—			(90,405		)
Balance, December 31, 2015	15,805	$	105,388	$	578,930		$	1,043,082		$	925		$	1,728,325

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

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries



Years ended December 31	2015			2014			2013
(in thousands)
Cash flows from operating activities
Net income	$	137,709		$	139,636		$	124,924
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	177,380			166,387			154,025
Other amortization	8,939			9,897			7,734
Impairment of utility assets	6,021			1,866			—
Other	1,672			758			—
Increase in deferred income taxes	75,626			82,947			64,507
Change in tax credits, net	4,844			6,062			7,017
Allowance for equity funds used during construction	(6,928		)	(6,771		)	(5,561		)
Change in cash overdraft	—			(1,038		)	1,038
Changes in assets and liabilities
Decrease in accounts receivable	23,727			26,743			49,445
Decrease (increase) in accrued unbilled revenues	40,093			6,750			(9,826		)
Decrease in fuel oil stock	34,830			28,041			27,332
Decrease (increase) in materials and supplies	2,821			(72		)	(7,959		)
Increase in regulatory assets	(24,182		)	(17,000		)	(65,461		)
Increase (decrease) in accounts payable	(54,555		)	(65,527		)	14,731
Change in prepaid and accrued income taxes and revenue taxes	(63,096		)	(4,036		)	(2,028		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	1,125			(961		)	2,240
Change in other assets and liabilities	(32,620		)	(66,687		)	(35,293		)
Net cash provided by operating activities	333,406			306,995			326,865
Cash flows from investing activities
Capital expenditures	(350,161		)	(336,679		)	(378,044		)
Contributions in aid of construction	40,239			41,806			32,160
Other	1,140			1,164			907
Net cash used in investing activities	(308,782		)	(293,709		)	(344,977		)
Cash flows from financing activities
Common stock dividends	(90,405		)	(88,492		)	(81,578		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,995		)	(1,995		)	(1,995		)
Proceeds from issuance of common stock	—			40,000			78,500
Proceeds from issuance of long-term debt	80,000			—			236,000
Repayment of long-term debt	—			(11,400		)	(166,000		)
Other	(1,537		)	(462		)	(1,149		)
Net cash (used in) provided by financing activities	(13,937		)	(62,349		)	63,778
Net increase (decrease) in cash and cash equivalents	10,687			(49,063		)	45,666
Cash and cash equivalents, January 1	13,762			62,825			17,159
Cash and cash equivalents, December 31	$	24,449		$	13,762		$	62,825

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

Notes to Consolidated Financial Statements

1 · Summary of significant accounting policies

General

Hawaiian Electric Industries, Inc. (HEI) is a holding company with direct and indirect subsidiaries principally engaged in electric utility and banking businesses, primarily in the State of Hawaii. HEI is the parent holding company of Hawaiian Electric Company, Inc. (Hawaiian Electric) and indirect parent holding company of American Savings Bank, F. S. B. (ASB). HEI’s common stock is traded on the New York Stock Exchange.

Hawaiian Electric and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (Hawaii Electric Light) and Maui Electric Company, Limited (Maui Electric), are regulated public electric utilities (collectively, the Utilities) in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai. Hawaiian Electric also owns Renewable Hawaii, Inc. (RHI), Uluwehiokama Biofuels Corp. (UBC) and HECO Capital Trust III. See Note 3.

ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii.

Basis of presentation. In preparing the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP), management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

Material estimates that are particularly susceptible to significant change for HEI and its subsidiaries (collectively, the Company) include the amounts reported for investment and mortgage-related securities (ASB only); property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities (Utilities only); electric utility revenues (Utilities only); and allowance for loan losses (ASB only).

Consolidation. The HEI consolidated financial statements include the accounts of the Company. The Hawaiian Electric consolidated financial statements include the accounts of Hawaiian Electric and its subsidiaries. The consolidated financial statements exclude subsidiaries which are variable interest entities (VIEs) when the Company or the Utilities are not the primary beneficiaries. Investments in companies over which the Company or the Utilities have the ability to exercise significant influence, but not control, are accounted for using the equity method. See Note 6 for information regarding unconsolidated VIEs.

Cash and cash equivalents. The Utilities consider cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper of non-affiliates and liquid investments (with original maturities of three months or less) to be cash and cash equivalents. The Company considers the same items to be cash and cash equivalents as well as ASB’s deposits with the Federal Home Loan Bank (FHLB) of Seattle, federal funds sold (excess funds that ASB loans to other banks overnight at the federal funds rate) and securities purchased under resale agreements.

Equity method. Investments in up to 50%-owned affiliates over which the Company or the Utilities have the ability to exercise significant influence over the operating and financing policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses is reflected in operating revenues. Equity method investments are also evaluated for OTTI. Also see Note 6 below.

Property, plant and equipment. Property, plant and equipment are reported at cost. Self-constructed electric utility plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make utility plant more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

Depreciation. Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Electric utility plant additions in the current year are depreciated beginning January 1 of the following year in accordance with rate-making. Electric utility plant has lives ranging from 20 to 88 years for production plant, from 25 to 65 years for transmission and distribution plant and from 5 to 65 years for general plant. The Utilities’ composite annual depreciation rate, which includes a component for cost of removal, was 3.2%, 3.1% and 3.1% in 2015, 2014 and 2013, respectively.

Leases. HEI, the Utilities and ASB have entered into lease agreements for the use of equipment and office space. The provisions of some of the lease agreements contain renewal options.

HEI's consolidated operating lease expense was $18 million, $19 million and $19 million in 2015, 2014 and 2013, respectively. The Utilities' operating lease expense was $9 million, $9 million and $8 million in 2015, 2014 and 2013, respectively. HEI's consolidated and the Utilities' future minimum lease payments are as follows:



(in millions)	HEI		Hawaiian Electric
2016	$	11	$	5
2017	10		4
2018	7		3
2019	6		2
2020	4		2
Thereafter	10		6
	$	48	$	22

Retirement benefits. Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant (in the case of the Utilities). Funding for the Company’s qualified pension plans (Plans) is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary. The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA), including changes promulgated by the Pension Protection Act of 2006, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost during the year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the Public Utilities Commission of the State of Hawaii (PUC), the Utilities generally will make contributions to the pension fund at the greater of the minimum level required under the law or net periodic pension cost.

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

The Company and the Utilities recognize on their respective balance sheets the funded status of their defined benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.

Environmental expenditures. The Company and the Utilities are subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Financing costs. Financing costs related to the registration and sale of HEI common stock are recorded in shareholders’ equity.

HEI uses the straight-line method, which approximates the effective interest method, to amortize the long-term debt financing costs of the holding company over the term of the related debt.

The Utilities use the straight-line method, which approximates the effective interest method, to amortize long-term debt financing costs and premiums or discounts over the term of the related debt. Unamortized financing costs and premiums or discounts on the Utilities' long-term debt retired prior to maturity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

HEI and the Utilities use the straight-line method to amortize the fees and related costs paid to secure a firm commitment under their line-of-credit arrangements.

Income taxes. Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s and the Utilities' assets and liabilities at federal and state tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

The Company recognizes investment tax credits as a reduction of income tax expense in the period the assets giving rise to such credits are placed in service, except for the Utilities' investment tax credits, which are deferred and amortized over the estimated useful lives of the properties to which the credits relate, in accordance with Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”

The Utilities are included in the consolidated income tax returns of HEI. However, income tax expense has been computed for financial statement purposes as if the Utilities filed separate consolidated Hawaiian Electric income tax returns.

Governmental tax authorities could challenge a tax return position taken by the Company. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset might be impaired and charged to expense or an unanticipated tax liability might be incurred.

The Company and the Utilities use a “more-likely-than-not” recognition threshold and measurement standard for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

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.

100

Earnings per share (HEI only). Basic earnings per share (EPS) is computed by dividing net income for common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS is computed similarly, except that dilutive common shares for stock compensation and the equity forward transactions are added to the denominator. For 2014 and 2013, HEI used the two-class method of computing EPS as restricted stock grants included non-forfeitable rights to dividends and were participating securities.

Under the two-class method of computing EPS, HEI's EPS was comprised as follows for both participating securities (i.e., restricted shares that became fully vested in the fourth quarter of 2014) and unrestricted common stock:



	2014				2013
	Basic		Diluted		Basic		Diluted
Distributed earnings	$	1.24	$	1.24	$	1.24	$	1.24
Undistributed earnings	0.41		0.39		0.39		0.38
	$	1.65	$	1.63	$	1.63	$	1.62

As of December 31, 2015 there were no remaining share awards that could have been potentially antidilutive. As of December 31, 2014, there were no shares that were antidilutive. As of December 31, 2013, the antidilutive effect of stock appreciation rights (SARs) on 102,000 shares of HEI common stock (for which the exercise prices were greater than the closing market prices of HEI’s common stock on such dates), was not included in the computation of diluted EPS.

Share-based compensation. The Company and the Utilities apply the fair value based method of accounting to account for its stock compensation, including the use of a forfeiture assumption. See Note 11.

Impairment of long-lived assets and long-lived assets to be disposed of. The Company and the Utilities review long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.

Recent accounting pronouncements.

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

The Company retrospectively adopted ASU No. 2014-01 in the first quarter of 2015. For prior periods, pursuant to ASU No. 2014-01, (a) amortization expense related to ASB’s qualifying investments in low income housing tax credits was reclassified from noninterest expense to income taxes; and (b) additional amortization, net of associated tax benefits was recognized in income taxes as a result of the adoption. The cumulative effect to retained earnings as of January 1, 2013 of adopting this guidance was a reduction of $0.9 million. Amounts in the financial statements as of December 31, 2014, 2013 and 2012 and for the years ended December 31, 2014 and 2013, have been updated to reflect the retrospective application.

101

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



	HEI Consolidated												ASB
(in thousands)	As previously filed			Adjust-ment from adoption of ASU No. 2014-01			Reclassi-fications			As currently reported			As previously filed		Adjust-ment from adoption of ASU No. 2014-01			As currently reported

HEI Consolidated Income Statements/ASB Statements of Income Data
Year ended December 31, 2014
Bank expenses/Noninterest expense	$	176,878		$	(3,676	)				$	173,202		$	159,944	$	(3,676	)	$	156,268
Bank operating income/Income before income taxes	75,619			3,676						79,295			75,619		3,676			79,295
Income taxes	91,712			3,867						95,579			24,127		3,867			27,994
Net income for common stock/Net income	168,320			(191		)				168,129			51,492		(191		)	51,301
Year ended December 31, 2013
Bank expenses/Noninterest expense	171,090			(2,089		)				169,001			159,504		(2,089		)	157,415
Bank operating income/Income before income taxes	87,057			2,089						89,146			87,059		2,089			89,148
Income taxes	84,341			1,896						86,237			29,525		1,896			31,421
Net income for common stock/Net income	161,516			193						161,709			57,534		193			57,727
HEI Consolidated Balance Sheet/ASB Balance Sheet Data
December 31, 2014
Other assets	541,542			981						542,523			304,435		981			305,416
Total assets and Total liabilities and shareholders’ equity	11,184,161			981						11,185,142			5,565,241		981			5,566,222
Deferred income taxes/Other liabilities	631,734			1,836						633,570			116,527		1,836			118,363
Total liabilities	9,358,440			1,836						9,360,276			5,030,598		1,836			5,032,434
Retained earnings	297,509			(855		)				296,654			212,789		(855		)	211,934
Total shareholders’ equity	1,791,428			(855		)				1,790,573			534,643		(855		)	533,788
HEI Consolidated Statements of Changes in Stockholders’ Equity
December 31, 2013
Retained earnings	255,694			(664		)				255,030
Total shareholders’ equity	1,727,070			(664		)				1,726,406
December 31, 2012
Retained earnings	216,804			(857		)				215,947
Total shareholders’ equity	1,593,865			(857		)				1,593,008
HEI Consolidated Statements of Cash Flows
Year ended December 31, 2014
Net income	170,210			(191		)				170,019
Increase in deferred income taxes	103,916			310						104,226
Change in other assets and liabilities	(94,966		)	(119		)	$	(6,111	)	(101,196		)
Year ended December 31, 2013
Net income	163,406			193						163,599
Increase in deferred income taxes	80,399			(254		)				80,145
Change in other assets and liabilities	(11,696		)	61			(2,657		)	(14,292		)

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

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

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

The Company plans to adopt ASU No. 2014-09 in the first quarter of 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.

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

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

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

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

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 plans to retrospectively adopt ASU No. 2015-07 in the first quarter 2016 and will adjust its disclosures on the fair value of retirement benefit plan assets accordingly.

Balance sheet classification of deferred taxes. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes,” which eliminates the current requirement for entities to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet and instead requires all deferred tax liabilities and assets be classified as noncurrent.

The Utilities retrospectively adopted ASU No. 2015-17 in the fourth quarter of 2015. Hawaiian Electric’s consolidated balance sheets as of December 31, 2015 and 2014, which are classified balance sheets, do not separate deferred tax liabilities and assets into a current amount and a noncurrent amount, but presents all deferred tax liabilities and assets as noncurrent amounts. The table below summarizes the impact to the prior period financial statements of the adoption of ASU No. 2015-17:

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(in thousands)	As previously filed		Adjustment from adoption of ASU No. 2015-17			As currently reported

December 31, 2014
Hawaiian Electric Consolidated Balance Sheet
Prepayments and other	$	66,383	$	(32,915	)	$	33,468
Total current assets	615,003		(32,915		)	582,088
Total assets and Total capitalization and liabilities	5,590,457		(32,915		)	5,557,542
Other current liabilities	65,146		(3,482		)	61,664
Total current liabilities	502,430		(3,482		)	498,948
Deferred income taxes	602,872		(29,433		)	573,439
Total deferred credits and other liabilities	1,698,612		(29,433		)	1,669,179
Note 4 - Hawaiian Electric Consolidating Balance Sheet
Hawaiian Electric (parent only)
Prepayments and other	44,680		(24,449		)	20,231
Total current assets	463,929		(24,449		)	439,480
Total assets and Total liabilities and shareholders’ equity	4,396,815		(24,449		)	4,372,366
Other current liabilities	48,282		(2,913		)	45,369
Total current liabilities	362,652		(2,913		)	359,739
Deferred income taxes	429,515		(21,536		)	407,979
Total deferred credits and other liabilities	1,215,441		(21,536		)	1,193,905
Hawaii Electric Light
Prepayments and other	8,611		1,526			10,137
Total current assets	77,561		1,526			79,087
Total assets and Total liabilities and shareholders’ equity	924,885		1,526			926,411
Other current liabilities	9,866		(279		)	9,587
Total current liabilities	85,631		(279		)	85,352
Deferred income taxes	90,119		1,805			91,924
Total deferred credits and other liabilities	265,993		1,805			267,798
Maui Electric
Prepayments and other	13,567		(9,992		)	3,575
Total current assets	98,911		(9,992		)	88,919
Total assets and Total liabilities and shareholders’ equity	832,977		(9,992		)	822,985
Other current liabilities	16,094		(290		)	15,804
Total current liabilities	79,646		(290		)	79,356
Deferred income taxes	83,238		(9,702		)	73,536
Total deferred credits and other liabilities	217,421		(9,702		)	207,719
December 31, 2013
Note 3 - Hawaiian Electric Consolidated assets	5,087,129		(20,702		)	5,066,427

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.

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

Reclassifications. Reclassifications made to prior years’ financial statements to conform to the 2015 presentation did not affect previously reported results of operations and include additional detail of noncash items in operating activities on the Company's and Hawaiian Electric's Consolidated Statements of Cash Flows.

Electric utility

Regulation by the Public Utilities Commission of the State of Hawaii (PUC). The Utilities are regulated by the PUC and account for the effects of regulation under FASB ASC Topic 980, “Regulated Operations.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes the Utilities’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that their regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance.

Accounts receivable. Accounts receivable are recorded at the invoiced amount. The Utilities generally assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Utilities’ best estimate of the amount of probable credit losses in the Utilities existing accounts receivable. At December 31, 2015 and 2014, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $1.7 million and $2.0 million, respectively.

Contributions in aid of construction. The Utilities receive contributions from customers for special construction requirements. As directed by the PUC, contributions are amortized on a straight-line basis over 30 to 55 years as an offset against depreciation expense.

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

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

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

The Utilities’ revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. However, the Utilities’ revenue tax payments to the taxing authorities are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For 2015, 2014 and 2013, the Utilities included approximately $209 million, $267 million and $266 million, respectively, of revenue taxes in “revenues” and in “taxes, other than income taxes” expense.

Power purchase agreements. If a power purchase agreement (PPA) falls within the scope of ASC Topic 840, “Leases,” and results in the classification of the agreement as a capital lease, the Utilities would recognize a capital asset and a lease obligation. Currently, none of the PPAs are required to be recorded as a capital lease.

The Utilities evaluate PPAs to determine if the PPAs are VIEs, if the Utilities are primary beneficiaries and if consolidation is required. See Note 6.

Repairs and maintenance costs. Repairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.

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Allowance for funds used during construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery.

The weighted-average AFUDC rate was 7.6% in 2015, 7.7% in 2014 and 7.6% in 2013, and reflected quarterly compounding.

Bank (HEI only)

Investment securities. Investments in debt and equity securities are classified as held-to-maturity (HTM), trading or available-for-sale (AFS). ASB determines the appropriate classification at the time of purchase. Debt and equity securities that ASB intends to and has the ability to hold to maturity are classified as HTM securities and reported at cost. Marketable debt and equity securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in earnings. Marketable debt and equity securities not classified as either HTM or trading securities are classified as AFS and reported at fair value. Unrealized gains and losses for AFS securities are excluded from earnings and reported on a net basis in accumulated other comprehensive income (AOCI) until realized.

Interest income is recorded on an accrual basis. Discounts and premiums on securities are accreted or amortized into interest income using the interest method over the remaining contractual lives of the agency obligation securities and the estimated lives of the mortgage-related securities adjusted for anticipated prepayments. ASB uses actual prepayment experience and estimates of future prepayments to determine the constant effective yield necessary to apply the interest method of income recognition. The discounts and premiums on the agency obligations portfolio are accreted or amortized on a prospective basis using expected contractual cash flows. The discounts and premiums on the mortgage-related securities portfolio are accreted or amortized on a retrospective basis using changes in anticipated prepayments. This method requires a retrospective adjustment of the effective yield each time ASB changes the estimated life as if the new estimate had been known since the original acquisition date of the securities. Estimates of future prepayments are based on the underlying collateral characteristics and historic or projected prepayment behavior of each security. The specific identification method is used in determining realized gains and losses on the sales of securities.

For securities that are not trading securities, individual securities are assessed for impairment at least on a quarterly basis, and more frequently when economic or market conditions warrant. A security is impaired if the fair value of the security is less than its carrying value at the financial statement date. When a security is impaired, ASB determines whether this impairment is temporary or other-than-temporary. If ASB does not expect to recover the entire amortized cost basis of the security or there is a change in the expected cash flows, an OTTI exists. If ASB intends to sell the security, or will more likely than not be required to sell the security before recovery of its amortized cost, the OTTI must be recognized in earnings. If ASB does not intend to sell the security, and it is not more likely than not that ASB will be required to sell the security before recovery of its amortized cost, the OTTI must be separated into the amount representing the credit loss and the amount related to all other factors. The amount of OTTI related to the credit loss is recognized in earnings, while the remaining OTTI is recognized in AOCI. Based on ASB's evaluation as of December 31, 2015 and 2014, there was no indicated impairment as the bank expects to collect the contractual cash flows for these investments.

Stock in Federal Home Loan Bank (FHLB) is carried at cost and is reviewed at least periodically for impairment, with valuation adjustments recognized in noninterest income.

Loans receivable. ASB carries loans receivable at amortized cost less the allowance for loan losses, loan origination fees (net of direct loan origination costs), commitment fees and purchase premiums and discounts. Interest on loans is credited to income as it is earned. Discounts and premiums are accreted or amortized over the life of the loans using the interest method.

Loan origination fees (net of direct loan origination costs) are deferred and recognized as an adjustment in yield over periods not exceeding the contractual life of the loan using the interest method or taken into income when the loan is paid off or sold. Nonrefundable commitment fees (net of direct loan origination costs, if applicable) received for commitments to originate or purchase loans are deferred and, if the commitment is exercised, recognized as an adjustment of yield over the life of the loan using the interest method. Nonrefundable commitment fees received for which the commitment expires unexercised are recognized as income upon expiration of the commitment.

Mortgage loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Premiums, discounts and net deferred loan fees are not amortized while a loan is classified as held for sale. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold.

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Allowance for loan losses. ASB maintains an allowance for loan losses that it believes is adequate to absorb losses inherent in its loan portfolio. The level of allowance for loan losses is based on a continuing assessment of existing risks in the loan portfolio, historical loss experience, changes in collateral values and current conditions (e.g., economic conditions, real estate market conditions and interest rate environment). The allowance for loan losses is allocated to loan types using both a formula-based approach applied to groups of loans and an analysis of certain individual loans for impairment. The formula-based approach emphasizes loss factors primarily derived from actual historical default and loss rates, which are combined with an assessment of certain qualitative factors to determine the allowance amounts allocated to the various loan categories. Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.

ASB disaggregates its portfolio loans into portfolio segments for purposes of determining the allowance for loan losses. Commercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a risk rating system for evaluating the credit quality of the loans. Loans are rated based on the degree of risk at origination and periodically thereafter, as appropriate. Values are applied separately to the probability of default (borrower risk) and loss given default (transaction risk). ASB’s credit review department performs an evaluation of these loan portfolios to ensure compliance with the internal risk rating system and timeliness of rating changes. Non-homogeneous loans are categorized into the regulatory asset quality classifications-Pass, Special Mention, Substandard, Doubtful, and Loss based on credit quality. For loans classified as substandard, an analysis is done to determine if the loan is impaired. A loan is deemed impaired when it is probable that ASB will be unable to collect all amounts due according to the original contractual terms of the loan agreement. Once a loan is deemed impaired, ASB applies a valuation methodology to determine whether there is an impairment shortfall. The measurement of impairment may be based on (i) the present value of the expected future cash flows of the impaired loan discounted at the loan’s original effective interest rate, (ii) the observable market price of the impaired loan, or (iii) the fair value of the collateral, net of costs to sell. For all loans collateralized by real estate whose repayment is dependent on the sale of the underlying collateral property, ASB measures impairment by utilizing the fair value of the collateral, net of costs to sell; for other loans that are not considered collateral dependent, generally the discounted cash flow method is used to measure impairment. For loans collateralized by real estate that are classified as troubled debt restructured loans, the present value of the expected future cash flows of the loans may also be used to measure impairment as these loans are expected to perform according to their restructured terms. Impairments are charged to the provision for loan losses and included in the allowance for loan losses. However, confirmed losses (uncollectible) are charged off, with the loan written down by the amount of the confirmed loss.

Residential, consumer and credit scored business loans are considered homogeneous loans, which are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. The homogeneous loan portfolios are stratified into individual products with common risk characteristics and segmented into various secured and unsecured loan product types. For the homogeneous portfolio, the quality of the loan is best indicated by the repayment performance of an individual borrower. ASB does supplement performance data with an 11-risk rating retail credit model that assigns a probability of default to each borrower based primarily on the borrower's current Fair Isaac Corporation (FICO) score and for the home equity line of credit (HELOC) and unsecured consumer products, the bankruptcy score (BK). Current FICO and BK data is purchased and appended to all homogeneous loans on a quarterly basis and used to estimate the borrower’s probability of default and the loss given default.

ASB also considers the following qualitative factors for all loans in estimating the allowance for loan losses:


•	changes in lending policies and procedures;


•	changes in economic and business conditions and developments that affect the collectability of the portfolio;


•	changes in the nature, volume and terms of the loan portfolio;


•	changes in lending management and other relevant staff;


•	changes in loan quality (past due, non-accrual, classified loans);


•	changes in the quality of the loan review system;


•	changes in the value of underlying collateral;


•	effect of, and changes in the level of, any concentrations of credit; and


•	effect of other external and internal factors.

ASB’s methodology for determining the allowance for loan losses was generally based on historic loss rates using various look-back periods. During the second quarter of 2014, ASB implemented enhancements to the loss rate calculation for estimating the allowance for loan losses that included several refinements to determining the probability of default and the loss given default for the various segments of the loan portfolio that are more statistically sound than those previously employed. The result is an estimated loss rate established for each borrower. ASB also updated its measurement of the loss emergence period in the calculation of the allowance for loan losses. The loss emergence period is broadly defined as the period that it takes, on average, for the lender to identify the specific borrower and amount of loss incurred by the bank for a loan that has

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suffered from a loss-causing event. In most cases, as credit quality and conditions improve, management has observed that the loss emergence period has extended and has incorporated this observed change in the estimate of the allowance for loan losses. Management believes these enhancements will improve the precision in estimating the allowance for loan losses. The enhancements did not have a material effect on the total allowance for loan losses or the provision for loan losses for 2014. The enhancements did result in the full allocation of the previously unallocated portion of the allowance for loan losses.

In conjunction with the above enhancement, management also adopted an enhanced risk rating system for monitoring and managing credit risk in the non-homogenous loan portfolios, that measures general creditworthiness at the borrower level. The numerical-based, risk rating “PD Model” takes into consideration fiscal year-end financial information of the borrower and identified financial attributes including retained earnings, operating cash flows, interest coverage, liquidity and leverage that demonstrate a strong correlation with default to assign default probabilities at the borrower level. In addition, a loss given default (LGD) value is assigned to each loan to measure loss in the event of default based on loan specific features such as collateral that mitigates the amount of loss in the event of default. Together the PD Model and LGD construct provide a more quantitative, data driven and consistent framework for measuring risk within the portfolio, on a loan by loan basis and for the ultimate collectability of each loan.

Management believes its allowance for loan losses adequately estimates actual loan losses that will ultimately be incurred. However, such estimates are based on currently available information and historical experience, and future adjustments may be required from time to time to the allowance for loan losses based on new information and changes that occur (e.g., due to changes in economic conditions, particularly in Hawaii). Actual losses could differ from management’s estimates, and these differences and subsequent adjustments could be material.

Nonperforming loans. Loans are generally placed on nonaccrual status when contractually past due 90 days or more, or earlier if management believes that the probability of collection is insufficient to warrant further accrual. All interest that is accrued but not collected is reversed. A loan may be returned to accrual status if (i) principal and interest payments have been brought current and repayment of the remaining contractual principal and interest is expected to be made, (ii) the loan has otherwise become well-secured and collection efforts are reasonably expected to result in repayment of the debt, or (iii) the borrower has been making regularly scheduled payments in full for the prior six months and it is reasonably assured that the loan will be brought fully current within a reasonable period. Cash receipts on nonaccruing loans are generally applied to reduce the unpaid principal balance.

Loans considered to be uncollectible are charged-off against the allowance for loan losses. The amount and timing of charge-offs on loans includes consideration of the loan type, length of delinquency, insufficiency of collateral value, lien priority and the overall financial condition of the borrower. Recoveries on loans previously charged-off are credited back to the allowance for loan losses. Loans that have been charged-off against the allowance for loan losses are periodically monitored to evaluate whether further adjustments to the allowance are necessary. Loans in the commercial and commercial real estate portfolio are charged-off when the loan is risk-rated “Doubtful” or “Loss”. The loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 90 days or more; (b) significant improvement in the borrower’s repayment capacity is doubtful; and/or (c) collateral value is insufficient to cover outstanding indebtedness and no other viable assets or repayment sources exist.

Loans in the residential mortgage and home equity portfolios are charged-off when the loan or a portion thereof is determined to be uncollectible after considering the borrower’s overall financial condition and collateral deficiency. A loan is considered uncollectible when: (a) the borrower is delinquent in principal or interest 180 days or more; (b) it is probable that collateral value is insufficient to cover outstanding indebtedness and no other viable assets or repayment sources exist; (c) borrower’s debt is discharged in bankruptcy and the loan is not reaffirmed; or (d) in cases where ASB is in a subordinate position to other debt, the senior lien holder has foreclosed and ASB's junior lien is extinguished.

Other consumer loans are generally charged-off when the balance becomes 120 days delinquent.

Loans modified in a troubled debt restructuring. Loans are considered to have been modified in a troubled debt restructuring (TDR) when, due to a borrower’s financial difficulties, ASB makes concessions to the borrower that it would not

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otherwise consider for a non-troubled borrower. Modifications may include interest rate reductions, interest only payments for an extended period of time, protracted terms such as amortization and maturity beyond the customary length of time found in the normal market place, and other actions intended to minimize economic loss and to provide alternatives to foreclosure or repossession of collateral. Generally, a nonaccrual loan that has been modified in a TDR remains on nonaccrual status until the borrower has demonstrated sustained repayment performance for a period of six consecutive months. However, performance prior to the modification, or significant events that coincide with the modification, are included in assessing whether the borrower can meet the new terms and may result in the loan being returned to accrual status at the time of loan modification or after a shorter performance period. If the borrower’s ability to meet the revised payment schedule is uncertain, or there is reasonable doubt over the full collectability of principal and interest, the loan remains on nonaccrual status.

Real estate acquired in settlement of loans. ASB records real estate acquired in settlement of loans at fair value, less estimated selling expenses. ASB obtains appraisals based on recent comparable sales to assist management in estimating the fair value of real estate acquired in settlement of loans. Subsequent declines in value are charged to expense through a valuation allowance. Costs related to holding real estate are charged to operations as incurred.

Goodwill. At December 31, 2015 and 2014, the amount of goodwill was $82.2 million. The goodwill is with respect to ASB and is the Company’s only intangible asset with an indefinite useful life and is tested for impairment annually at December 31 using data as of September 30.

FASB ASU No. 2011-8, “Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment”(ASU No. 2011-8) permits an entity to first assess qualitative factors (Step 0) to determine whether it is more likely than not (that is, a likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform Step 1 of a two-step goodwill impairment test. An entity has an unconditional option to bypass the qualitative assessment and proceed directly to performing the first step of the goodwill impairment test. In evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount under ASU No. 2011-8, an entity shall assess relevant events and circumstances such as:


•	macroeconomic conditions such as a deterioration in general economic conditions, limitations on accessing capital or other developments in equity and credit markets;


•	industry and market considerations such as a deterioration in the environment in which an entity operates, an increased competitive environment, a change in the market for an entity’s products or services or a regulatory or political development;


•	cost factors that have a negative effect on earnings and cash flows;


•	overall financial performance such as a decline in actual or planned revenues or earnings compared with actual and projected results of relevant prior periods;


•	other relevant entity-specific events such as changes in management, key personnel, strategy or customers; contemplation of bankruptcy or litigation;


•	events affecting a reporting unit such as a change in the composition or carrying amount of its net assets;


•	if applicable, a sustained decrease in share price (consider in both absolute terms and relative to peers).

If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then the first and second steps of the goodwill impairment test under ASC Topic 350, "Intangibles-Goodwill and Other" (ASC 350), are unnecessary. ASB management performed a Step 0 analysis by assessing the relevant circumstances listed above, including the proposed spin-off of the bank from HEI, and determined that it was not more likely than not that the fair value of ASB was less than its carrying value and a Step 1 goodwill impairment analysis was not considered necessary. The most recent Step 1 goodwill impairment analysis under ASC 350 was performed at December 31, 2013 and the estimated fair value of ASB exceeded its carrying value by 60%. No adjustment of the forecasted net income used in the Step 1 analysis done in 2013 is required at this time. For the three years ended December 31, 2015, there has been no impairment of goodwill.

Mortgage banking. Mortgage loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Premiums, discounts and net deferred loan fees are not amortized while a loan is classified as held for sale. A sale is recognized only when the consideration received is other than beneficial interests in the assets sold and control over the assets is transferred irrevocably to the buyer. Gains or losses on sales of loans are recognized at the time of sale and are determined by the difference between the net sales proceeds and the allocated basis of the loans sold. ASB is obligated to subsequently repurchase a loan if the purchaser discovers a standard representation or warranty violation such as noncompliance with eligibility requirements, customer fraud or servicing violations. This primarily occurs during a loan file review. ASB considers and records a reserve for loan repurchases if appropriate.

ASB recognizes a mortgage servicing asset when a mortgage loan is sold with servicing rights retained. This mortgage servicing right (MSR) is initially capitalized at its presumed fair value based on market data at the time of sale and accounted

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for in subsequent periods at the lower of amortized cost or fair value. Mortgage servicing assets or liabilities are included as a component of gain on sale of loans. Under ASC Topic 860, “Transfers and Servicing,” we amortize the MSRs in proportion to and over the period of estimated net servicing income and assess for impairment at each reporting date.

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 primarily 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. 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. Because observable market prices with exact terms and conditions may not be readily available, ASB compares the fair value of MSRs to an estimated value calculated by an independent third-party on a semi-annual basis. 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 fair value generated by the valuation model.

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.

Loan servicing fee income represents income earned for servicing mortgage loans owned by investors. It includes mortgage servicing fees and other ancillary servicing income, net of guaranty fees. Servicing fees are generally calculated on the outstanding principal balances of the loans serviced and are recorded as income when earned.

Tax Credit Investments. ASB invests in limited liability entities formed to operate qualifying affordable housing projects.

The affordable housing investments provide tax benefits to investors in the form of tax deductions from operating losses and tax credits. As a limited partner, ASB has no significant influence over the operations. These investments are initially recorded at the initial capital contribution with a liability recognized for the commitment to contribute additional capital over the term of the investment.

The Company uses the proportional method of accounting for its investments. Under the proportional method, the Company amortizes the cost of its investments in proportion to the tax credits and other tax benefits it receives. The amortization, tax credits and tax benefits are reported as a component of income tax expense. Cash contributions and payments made on commitments to low-income housing tax credit (LIHTC) investments are classified as operating activities in the Company’s consolidated statements of cash flows.

For these limited liability entities, ASB assesses whether it is the primary beneficiary of the limited liability entity, which is a variable interest entity (VIE). The primary beneficiary of a VIE is determined to be the party that meets both of the following criteria: (i) has the power to make decisions that most significantly affect the economic performance of the VIE; and (ii) has the obligation to absorb losses or the right to receive benefits that in either case could potentially be significant to the VIE. Generally, ASB, as a limited partner, is not deemed to be the primary beneficiary as it does not meet the power criterion, i.e., no power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and no direct ability to unilaterally remove the general partner.

All tax credit investments are evaluated for potential impairment at least annually, or more frequently, when events or conditions indicate that it is deemed probable that ASB will not recover its investment. Potential indicators of impairment might arise when there is evidence that some or all tax credits previously claimed would be recaptured, or that expected remaining credits would no longer be available to the limited liability entities. If an investment is determined to be impaired, it is written down to its estimated fair value and the new cost basis of the investment is not adjusted for subsequent recoveries in value. As of December 31, 2015, ASB did not have any impairment losses resulting from forfeiture or ineligibility of tax credits or other circumstances related to its LIHTC investments.

At December 31, 2015 and 2014, the carrying amount of qualifying affordable housing investments was $37.8 million and $33.4 million, respectively, and included in other assets in the consolidated balance sheets.

ASB’s unfunded commitments to fund to its qualifying affordable housing investments were $10.1 million and $14.8 million as of December 31, 2015 and 2014, respectively. These unfunded commitments are unconditional and legally binding and are recorded in accounts payable and other liabilities with an increase in other assets in the consolidated balance sheets.

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The table below summarizes the amounts in income tax expense related to ASB's investments in qualifying affordable housing projects:



Years ended December 31	2015			2014			2013
(in millions)
Amounts in income taxes related to investments in qualifying affordable housing projects
Amortization recognized in the provision for income taxes	$	(5.4	)	$	(3.6	)	$	(2.2	)
Tax credits and other tax benefits recognized in the provision for income taxes	8.0			5.4			3.6
Net benefit to income tax expense	$	2.6		$	1.8		$	1.4

2 · Proposed Merger

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

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

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

The closing of the Merger is subject to various conditions, including, among others, (i) the approval of holders of 75% of the outstanding shares of HEI common stock, (ii) effectiveness of the registration statement for the NEE common stock to be issued in the Initial Merger and the listing of such shares on the New York Stock Exchange, (iii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, (iv) receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission and the Hawaii Public Utilities Commission, (v) the absence of any law or judgment in effect or pending in which a governmental entity has imposed or is seeking to impose a legal restraint that would prevent or make illegal the closing of the Merger, (vi) the absence of any material adverse effect with respect to either HEI or NEE, (vii) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement, (viii) receipt by each of HEI and NEE of a tax opinion of its counsel regarding the tax treatment of the transactions contemplated by the Merger Agreement, (ix) effectiveness of the ASB Hawaii registration statement necessary to consummate the Spin-Off and (x) the determination by each of HEI and NEE that, upon completion of the Spin-Off, HEI will no longer be a savings and loan holding company or be deemed to control ASB for purposes of the Home Owners' Loan Act. The Spin-Off will be subject to various conditions, including, among others, the approval of the Federal Reserve Board (FRB). Some, but not all, of these conditions have been satisfied and certain of these conditions will only be satisfied shortly before closing.

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

The Merger Agreement contains certain termination rights for both HEI and NEE, including the right of either party to terminate the Merger Agreement if the Merger has not been consummated by June 3, 2016, and further provides that upon termination of the Merger Agreement under specified circumstances NEE would be required to pay HEI a termination fee of $90 million and reimburse HEI for up to $5 million of its documented out-of-pocket expenses incurred in connection with the Merger Agreement.

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

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On February 1, 2015, HEI submitted a letter to the FRB advising the FRB of its intent to seek deregistration as a Savings & Loan Holding Company (SLHC) to be effective upon the contemplated Spin-off of ASB Hawaii.

On March 26, 2015, NEE’s Form S-4, which registers NEE common stock expected to be issued in the Initial Merger, was declared effective.

On March 30, 2015, ASB Hawaii filed its Form 10, the registration statement for the ASB Hawaii shares expected to be distributed in the Spin-Off.

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

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

PUC application. In January 2015, NEE and Hawaiian Electric filed an application with the PUC requesting approval of the proposed Merger (under which Hawaiian Electric would become a wholly-owned indirect subsidiary of NEE). The application also requests modification of certain conditions agreed to by HEI and the PUC in 1982 for the merger and corporate restructuring of Hawaiian Electric, and confirmation that with approval of the Merger Agreement, the recommendations in the 1995 Dennis Thomas Report (resulting from a proceeding to review the relationship between HEI and Hawaiian Electric and any impact of HEI’s then diversified activities on the Utilities) will no longer be applicable. The application includes a commitment that, for at least four years following the completion of the transaction, Hawaiian Electric will not submit any applications seeking a general base rate increase and will reduce the RAM, which amounts to approximately $60 million in cumulative savings for customers, over the four-year base rate moratorium, subject to certain exceptions and conditions, including that the following remain in effect: the revenue balancing account (RBA) and RAM tariff provisions, the Renewable Energy Infrastructure Program, and Renewable Energy Infrastructure Surcharge, the integrated resource planning/DSM Recovery tariff provisions, the ECAC tariff provisions, the PPA tariff provision and the Pension and OPEB tracker mechanism. Various governmental, environmental and commercial interests groups have been allowed to intervene in the proceeding.

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

On August 31, 2015, the Applicants filed their responsive testimonies, offering a number of additional commitments, including:


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


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


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


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


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

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

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


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

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


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

In connection with the agreement, on November 27, 2015, DOD filed a motion to withdraw from the proceeding. Prior to this date, three other parties had withdrawn from the proceeding.

The initial round of evidentiary hearings were held from November 30 to December 16, 2015.

On January 4, 2016, the PUC issued an order granting the Applicants’ motion to admit revised stipulated commitments into evidence and permitting additional discovery and testimony by the other parties regarding the revised stipulated commitments, and denying DOD’s motion to withdraw.

Evidentiary hearings were reconvened and held from February 1 to 10, 2016. Further evidentiary hearings are scheduled to reconvene from February 29 to March 4, 2016.

Pending litigation and other matters.

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

Since the December 3, 2014 announcement of the merger agreement, eight purported class action complaints were filed in the Circuit Court of the First Circuit for the State of Hawaii by alleged stockholders of HEI against HEI, Hawaiian Electric (in one complaint), the individual directors of HEI, NEE and NEE's acquisition subsidiaries. The lawsuits are captioned as follows: Miller v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2531-12 KTN (December 15, 2014) (the Miller Action); Walsh v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2541-12 JHC (December 15, 2014) (the Walsh Action); Stein v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2555-12 KTN (December 17, 2014) (the Stein Action); Brown v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2643-12 RAN (December 30, 2014) (the Brown Action); Cohn v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2642-12 KTN (December 30, 2014) (the Cohn State Action); Guenther v. Watanabe, et al., Case No. 15-1-003-01 ECN (January 2, 2015) (the Guenther Action); Hudson v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0013-01 JHC (January 5, 2015) (the Hudson Action); Grieco v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0094-01 KKS (January 21, 2015) (the Grieco Action). On January 12, 2015, plaintiffs in the Miller Action, the Walsh Action, the Stein Action, the Brown Action, the Guenther Action, and the Hudson Action filed a motion to consolidate their actions and to appoint co-lead counsel. On January 23, 2015, the Cohn State Action was voluntarily dismissed. On January 27, 2015, Cohn filed a purported class action captioned Cohn v. Hawaiian Electric Industries, Inc., et al., Civil No. 15-00029-JMS-RLP in the United States District Court for the District of Hawaii against HEI, the individual directors of HEI, NEE, and NEE’s acquisition subsidiaries (the Cohn Federal Action). On February 13, 2015, the state court orally granted the plaintiffs’ motions to consolidate the seven state court actions and appoint co-lead counsel and entered a written order granting the motions on March 6, 2015. On March 10, 2015, plaintiffs filed a first consolidated complaint in state court that added as a defendant J.P. Morgan Securities, LLC (JP Morgan), the financial advisor to HEI for the Merger, and deleted Hawaiian Electric Company, Inc. as a defendant and concurrently served a first request for production of documents on HEI and the individual directors. On March 17, 2015, plaintiffs filed a motion for limited expedited discovery in the consolidated state action and thereafter on March 25, 2015 withdrew their request for limited discovery and first request for production of documents as a result of the parties’ agreement to conduct certain specified limited discovery which included a stipulated confidentiality agreement and protective order protecting the confidentiality of certain information exchanged between the parties in connection with discovery in the consolidated action that was filed on April 6, 2015. On April 15 and 17, 2015, a deposition of a representative of HEI and a representative of JP Morgan were taken, respectively. On April 21, 2015, plaintiffs confirmed the cancellation of the preliminary injunction hearing that had been scheduled for May 5, 2015 in the consolidated action and on April 23, 2015, the state court entered a stipulation and order to extend indefinitely the time to answer or otherwise respond to the first amended consolidated complaint. On April 30, 2015, the state court entered a consolidated case management order confirming the consolidated treatment of the state actions for purposes of case management, pretrial discovery, procedural and other matters. On May 27, 2015, the federal court entered a stipulation and order approving the stipulation of the parties to stay the Cohn Federal Action pending the resolution of the state court consolidated action and administratively closing the Cohn Federal Action without prejudice to any party. On May 29, 2015, the state court entered a stipulated order amending the consolidated caption to read IN RE Consolidated HEI Shareholder Cases, Master File No. Civil

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No. 1CC15-1-HEI, to add JP Morgan as a named defendant in each individual action, add the caption for the Grieco Action, and remove Hawaiian Electric Company, Inc. from the caption in the Brown Action. In October 2015, several depositions of HEI representatives were taken in the state consolidated action. On February 9, 2016, plaintiffs filed an ex parte motion for second extension of time to file the pretrial statement in the state consolidated action from February 15, 2016 to August 15, 2016.

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

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

3 · Segment financial information

The electric utility and bank segments are strategic business units of the Company that offer different products and services and operate in different regulatory environments. The accounting policies of the segments are the same as those described for the Company in the summary of significant accounting policies, except as otherwise indicated and except that federal and state income taxes for each segment are calculated on a “stand-alone” basis. HEI evaluates segment performance based on net income. Each segment accounts for intersegment sales and transfers as if the sales and transfers were to third parties, that is, at current market prices. Intersegment revenues consist primarily of interest, rent and preferred stock dividends.

Electric utility

Hawaiian Electric and its wholly-owned operating subsidiaries, Hawaii Electric Light and Maui Electric, are public electric utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the PUC. The Utilities have been aggregated into the electric utility segment primarily because all three entities: (1) are involved in the business of supplying electric energy in the same geographical location (i.e., the State of Hawaii), (2) have similar production processes that include electric generators (e.g., conventional oil-fired steam units and combustion turbines), (3) serve similar customers within their franchise territories (e.g., residential, commercial and industrial customers), (4) use similar electric grids to distribute the energy to their customers, (5) are regulated by the PUC and undergo similar rate-making processes, (6) have similar economic characteristics and (7) perform financial reporting oversight and management of the business at the consolidated level. Hawaiian Electric also owns the following nonregulated subsidiaries: Renewable Hawaii, Inc. (RHI), which was formed to invest in renewable energy projects; HECO Capital Trust III, which is a financing entity; and Uluwehiokama Biofuels Corp. (UBC), which was formed to own a new biodiesel refining plant to be built on the island of Maui, which project has been terminated.

Bank

ASB is a federally chartered savings bank providing a full range of banking services to individual and business customers through its branch system in Hawaii. ASB is subject to examination and comprehensive regulation by the Office of the Comptroller of the Currency (OCC) (previously by the Department of Treasury, Office of Thrift Supervision (OTS)) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System.

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Other

“Other” includes amounts for the holding companies (HEI and ASB Hawaii, Inc.), other subsidiaries not qualifying as reportable segments and intercompany eliminations.

Segment financial information was as follows:



(in thousands)	Electric utility		Bank		Other			Total
2015
Revenues from external customers	$	2,335,135	$	267,733	$	114		$	2,602,982
Intersegment revenues (eliminations)	31		—		(31		)	—
Revenues	2,335,166		267,733		83			2,602,982
Depreciation and amortization	186,319		7,928		1,338			195,585
Interest expense, net	66,370		11,326		10,780			88,476
Income (loss) before income taxes	217,131		83,812		(46,155		)	254,788
Income taxes (benefit)	79,422		29,082		(15,483		)	93,021
Net income (loss)	137,709		54,730		(30,672		)	161,767
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	135,714		54,730		(30,567		)	159,877
Capital expenditures	350,161		13,470		173			363,804
Assets (at December 31, 2015)	5,680,054		6,014,755		95,387			11,790,196
2014
Revenues from external customers	$	2,987,299	$	252,497	$	(254	)	$	3,239,542
Intersegment revenues (eliminations)	24		—		(24		)	—
Revenues	2,987,323		252,497		(278		)	3,239,542
Depreciation and amortization	176,284		5,399		1,361			183,044
Interest expense, net	64,757		10,808		11,595			87,160
Income (loss) before income taxes	220,361		79,295		(34,058		)	265,598
Income taxes (benefit)	80,725		27,994		(13,140		)	95,579
Net income (loss)	139,636		51,301		(20,918		)	170,019
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	137,641		51,301		(20,813		)	168,129
Capital expenditures	336,679		28,073		74			364,826
Assets (at December 31, 2014)	5,557,542		5,566,222		61,378			11,185,142
2013
Revenues from external customers	$	2,980,139	$	258,147	$	184		$	3,238,470
Intersegment revenues (eliminations)	33		—		(33		)	—
Revenues	2,980,172		258,147		151			3,238,470
Depreciation and amortization	161,759		4,230		1,396			167,385
Interest expense, net	59,279		10,077		16,200			85,556
Income (loss) before income taxes	194,041		89,148		(33,353		)	249,836
Income taxes (benefit)	69,117		31,421		(14,301		)	86,237
Net income (loss)	124,924		57,727		(19,052		)	163,599
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	122,929		57,727		(18,947		)	161,709
Capital expenditures	378,044		11,193		201			389,438
Assets (at December 31, 2013)	5,066,427		5,244,686		29,793			10,340,906

See Note 1 for the impact to prior period financial information of the adoptions of ASU No. 2014-01 and ASU No. 2015-17.

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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

Regulatory assets and liabilities. In accordance with ASC Topic 980, “Regulated Operations,” the Utilities’ financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Their continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes the Utilities’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Utilities expect that the regulatory assets, net of regulatory liabilities, would be charged to the statement of income in the period of discontinuance, which may result in a material adverse effect on the Company’s and the Utilities' financial condition, results of operations and/or liquidity.

Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, the Utilities do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base. Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, the Utilities include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. In the table below, noted in parentheses are the original PUC authorized amortization or recovery periods and, if different, the remaining amortization or recovery periods as of December 31, 2015 are noted.

Regulatory assets were as follows:



December 31	2015		2014
(in thousands)
Retirement benefit plans (balance primarily varies with plans’ funded statuses)	$	679,766	$	683,243
Income taxes, net (1 to 55 years)	88,039		86,836
Decoupling revenue balancing account and RAM regulatory asset (1 to 2 years)	74,462		91,353
Unamortized expense and premiums on retired debt and equity issuances (19 to 30 years; 6 to 18 years remaining)	14,089		15,569
Vacation earned, but not yet taken (1 year)	10,420		10,248
Postretirement benefits other than pensions (18 years; less than 1 year remaining)	—		18
Other (1 to 50 years; 1 to 46 years remaining)	29,955		17,997
	$	896,731	$	905,264
Included in:
Current assets	$	72,231	$	71,421
Long-term assets	824,500		833,843
	$	896,731	$	905,264

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Regulatory liabilities were as follows:



December 31	2015		2014
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	357,825	$	331,000
Retirement benefit plans (5 years beginning with respective utility’s next rate case)	9,835		12,413
Other (5 years; 1 to 2 years remaining)	3,883		1,436
	$	371,543	$	344,849
Included in:
Current liabilities	$	2,204	$	632
Long-term liabilities	369,339		344,217
	$	371,543	$	344,849

The regulatory asset and liability relating to retirement benefit plans was recorded as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for the Utilities in 2007 (see Note 10).

Major customers. The Utilities received 11% ($265 million), 12% ($350 million) and 11% ($340 million) of their operating revenues from the sale of electricity to various federal government agencies in 2015, 2014 and 2013, respectively.

Cumulative preferred stock. The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:



December 31, 2015	Voluntary liquidation price		Redemption price
Series
C, D, E, H, J and K (Hawaiian Electric)	$	20	$	21
I (Hawaiian Electric)	20		20
G (Hawaii Electric Light)	100		100
H (Maui Electric)	100		100

Hawaiian Electric is obligated to make dividend, redemption and liquidation payments on the preferred stock of each of its subsidiaries if the respective subsidiary is unable to make such payments, but this obligation is subordinated to Hawaiian Electric's obligation to make payments on its own preferred stock.

Related-party transactions. HEI charged the Utilities $6.5 million, $7.0 million and $6.2 million for general management and administrative services in 2015, 2014 and 2013, 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.

Hawaiian Electric’s short-term borrowings totaled nil at December 31, 2015 and 2014. The interest charged on short-term borrowings from HEI is based on the lower of HEI’s or Hawaiian Electric’s effective weighted average short-term external borrowing rate. If both HEI and Hawaiian Electric do not have short-term external borrowings, the interest is based on the average of the effective rate for 30-day dealer-placed commercial paper quoted by the Wall Street Journal plus 0.15%.

Borrowings among the Utilities are eliminated in consolidation. Interest charged by HEI to Hawaiian Electric was nil in each of 2015, 2014 and 2013.

Commitments and contingencies.

Fuel contracts. The Utilities have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through October 2017. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. West Coast and U.S. Midwest. Based on the average price per barrel as of December 31, 2015, the estimated cost of minimum purchases under the fuel supply contracts is $245 million in 2016, $4 million in 2017 and nil in 2018. The actual cost of purchases in 2016 and future years could vary substantially from this estimate of minimum purchases as a result of changes in market prices, quantities actually purchased, entry into new supply contracts and/or other factors. The Utilities purchased $0.6 billion, $1.1 billion and $1.1 billion of fuel under contractual agreements in 2015, 2014 and 2013, respectively.

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

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

The Utilities are also parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Hawaii Independent Energy, LLC, (HIE), respectively, which were scheduled to end December 31, 2015, but have been extended through December 31, 2016. Both agreements may be automatically renewed for annual terms thereafter unless earlier terminated by either of the respective parties.

In August 2014, Chevron and the Utilities entered into a third amendment to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract (Inter-island Fuel Supply Contract), which amendment extended the term of the contract through December 31, 2016 and provided for automatic renewal for annual terms thereafter unless earlier terminated by either party. In February 2015, Hawaiian Electric executed a similar extension, through December 31, 2016, of the corresponding Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract with HIE.

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

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

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

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

Power purchase agreements. As of December 31, 2015, the Utilities had five firm capacity PPAs for a total of 551 megawatts (MW) of firm capacity. Purchases from these five independent power producers (IPPs) and all other IPPs totaled $0.6 billion, $0.7 billion and $0.7 billion for 2015, 2014 and 2013, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term (and as amended) and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 2016 through 2020 and a total of $0.5 billion in the period from 2021 through 2035.

In general, the Utilities base their payments under the PPAs upon available capacity and actually supplied energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. The Utilities pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. The

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Utilities do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to Hawaiian Electric or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

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

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

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

Liquefied natural gas. On May 31, 2015, the previous August 2014 agreement with Fortis BC Energy Inc. (Fortis) for liquefaction capacity for liquefied natural gas (LNG) was superseded with a liquefaction Heads of Agreement by and between FortisBC Holdings Inc. and Hawaiian Electric. The agreement, which is subject to PUC approval, other regulatory approvals and permits and other conditions precedent before it becomes effective, provides for LNG liquefaction capacity purchases of 700,000 tonnes per year for the first five years, 600,000 tonnes per year for the next five years and 500,000 tonnes per year for the last ten years. Fortis must also obtain regulatory and other approvals for the agreement to become effective. The Fortis agreement is assignable and can be assigned to the selected bidder in the Utilities’ RFP for the supply of containerized LNG and will help ensure that liquefaction capacity is available at pricing that management believes will lower customer bills.

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

Renewable energy project matters. In November 2013, Hawaiian Electric and Maui Electric filed an application for recovery of its actual deferred costs totaling $405,000 (split evenly between Hawaiian Electric and Maui Electric) for outside contractor services for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) through the Renewable Energy Infrastructure Program (REIP) surcharge. In July 2015, the PUC approved recovery of the deferred costs for Hawaiian Electric over a four-month period, and over a two-year period for Maui Electric.

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.

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

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

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

In October 2015, the PUC issued a D&O (1) finding that there is a need to replace the existing ERP/EAM system, and (2) deferring any ruling on whether it is reasonable and in the public interest for the Utilities to commence with the project under Options B or A.

In the D&O, the PUC denied the Utilities request to defer the cost for the ERP software purchased in 2012. As a result, the Utilities expensed the ERP software costs of $4.8 million in the third quarter of 2015.

The D&O requires the Utilities to file their bottom-up low-level benefits analysis for both Options A and B, and specified additional information required as part of the their Cost/Benefit Analysis, which will be due by April 8, 2016.

Management cannot predict the further outcome of this proceeding.

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 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 is 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 cap of $157.3 million. The generating station is now expected to be placed in service in the first quarter of 2018.

Environmental regulation. The Utilities are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

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

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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.

On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at Hawaiian Electric’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, Hawaiian Electric has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date of April 16, 2016. Hawaiian Electric submitted to the EPA a Petition for Reconsideration and Stay dated April 16, 2012, which 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. Hawaiian Electric appealed the EPA’s denial of the Petition. On June 29, 2015, the U.S. Supreme Court found that the EPA’s determination that it was appropriate and “necessary” to regulate hazardous air pollutants from power plants was flawed because the EPA did not take the costs of compliance into account. The Supreme Court sent the MATS rule case back to the D.C. Circuit Court of Appeals for further proceedings. On December 15, 2015, the D.C. Circuit ordered the EPA to update its “appropriate and necessary” finding and ordered that the costs of compliance must be considered. The D.C. Circuit did not stay the MATS rule so all requirements of the MATS rule, including the April 16, 2016 compliance deadline remain in effect.

On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour sulfur dioxide (SO₂) National Ambient Air Quality Standard (NAAQS) implementation plans. In August 2015, the EPA published the final data requirements rule for states to characterize their air quality in relation to the one-hour SO₂ NAAQS. Under this rule, the EPA expects to designate areas as attaining, or not attaining, the one-hour SO₂ NAAQS in December 2017 or December 2020, depending on whether the area was characterized through modeling or monitoring. Hawaiian Electric will work with the DOH in implementing the one-hour SO₂NAAQS and in developing cost-effective strategies for NAAQS compliance, if needed.

Depending upon the rules and guidance developed for compliance with the more stringent NAAQS, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts and their timing are not determinable at this time. Additionally, the combined effects of the CWA 316(b) regulations, the MATS rule and the more stringent NAAQS may contribute to a decision to retire or deactivate certain generating units earlier than anticipated.

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

Potential Clean Air Act Enforcement. On July 1, 2013, Hawaii Electric Light and Maui Electric received a letter from the U.S. Department of Justice (DOJ) asserting potential violations of the Prevention of Significant Deterioration (PSD) and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The parties are continuing to negotiate toward a resolution of the DOJ’s claims. As part of the ongoing negotiations, the DOJ proposed in November 2014 entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities continue to have discussions with, and provide information to, the DOJ, but are unable to estimate the amount or effect of a consent decree, if any, at this time.

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

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of December 31, 2015 for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation. The final site investigation plan was submitted to the DOH and EPA in December 2014 for their approval. The DOH formally approved the investigation plan on September 14, 2015. The EPA determined that their formal approval is not required until the next phase of work that determines cleanup actions for the site. Sampling of the site per the investigation plan will proceed after securing required permits and access agreements.

Pearl Harbor sediment study. In July 2014, the U.S. Navy notified Hawaiian Electric of the Navy’s determination that Hawaiian Electric is responsible for cleanup of PCB contamination in sediment in the area offshore of the Waiau Power Plant. The Navy has also requested that Hawaiian Electric reimburse the costs incurred by the Navy to date to investigate the area, and is asking Hawaiian Electric to engage in negotiations regarding the financing and undertaking of future response actions to address the sediment contamination offshore from the Waiau Power Plant. The extent of the contamination, the appropriate remedial measures to address it, and Hawaiian Electric’s potential responsibility for any associated costs, including any past costs incurred by the Navy, have not yet been determined. The Navy has completed a remedial investigation and a feasibility study (FS) for the remediation of contaminated sediment at several locations in Pearl Harbor. The Navy’s study identified elevated levels of PCBs in the sediment in East Loch of Pearl Harbor, offshore from the Waiau Power Plant. The Navy issued its Final FS Report on June 29, 2015. The Navy has indicated that additional data collection is necessary and will be conducted as part of the remedial design, and that the results will be used to finalize the remediation plan and to better define the areas where remediation is necessary to reduce the potential environmental risks. Hawaiian Electric has requested to participate with the Navy in the preparation of the remedial design for the contaminated sediment offshore from the Waiau Power Plant, and in particular in the development of the work plan for additional data collection, and refinement of the environmental risk analysis, the final remedy, and the response costs for the offshore area. To date, Hawaiian Electric’s role in the development of the remedial design and response costs is uncertain.

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

As of December 31, 2015, the reserve account recorded by Hawaiian Electric to address the PCB contamination stands at $4.7 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.

Hawaiian Electric has also conducted a search for other potential sources of sediment contamination in the Waiau area that are unrelated to electric power generation at its Waiau Power Plant. Hawaiian Electric has identified a potential source east of the plant: a former Naval Reserve (a Formerly Used Defense Site (FUDS)) where a used drum storage area, a waste oil burning pit, and an oil/water separator were operated by the Navy from the 1940s until approximately 1962. This FUDS is located on the property currently occupied by the City and County (C&C) of Honolulu’s Neal S. Blaisdell Park. To further assess this former Naval Reserve site, Hawaiian Electric has requested environmental investigation reports, environmental data, and permits for this property and the adjacent Waimalu Stream (e.g., dredging permits and related environmental impact assessments and studies) from several federal and state agencies, as well as the C&C of Honolulu. The contribution of PCBs to sediment contamination in East Loch from this potential source has not yet been determined.

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.

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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.

On September 22, 2009, the EPA issued its “Final Mandatory Reporting of Greenhouse Gases Rule,” which requires sources that emit GHGs above certain threshold levels to monitor and report their GHG emissions. Following these requirements, the Utilities have submitted the required reports for 2010 through 2014 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules to address GHG emissions from stationary sources, like the Utilities’ EGUs.

As part of President Obama’s Climate Action Plan, the EPA has been directed to adopt GHG emission limits for new and existing EGUs. The EPA issued the final federal rule for GHG emission reductions from existing EGUs, also known as the Clean Power Plan, on August 3, 2015. The final federal GHG rule for existing EGUs sets interim state-wide emissions limits for EGUs operating in the 48 contiguous states that must be met on average from 2022 through 2029; final limits will apply from 2030. The EPA did not issue final guidelines for Alaska, Hawaii, Puerto Rico or Guam because the Best System of Emission Reduction established for the contiguous states is not appropriate for these locations. The EPA has said it will work with the state and territorial governments for Alaska, Hawaii, Puerto Rico and Guam and other stakeholders to gather additional information regarding the emissions reduction measures available in these jurisdictions, particularly with respect to renewable generation. Hawaiian Electric plans to participate in this process. Management’s latest assessment of the Clean Power Plan is that the continued growth of renewable power generation and the expected use of LNG as a transitional fuel by the Utilities in the future will significantly reduce the compliance costs and risk for the Utilities. To date, no timetable has been established by the EPA to develop GHG emission limits for Alaska, Hawaii, Puerto Rico or Guam, and such timing has become more uncertain in light of the decision of the U.S. Supreme Court on February 9, 2016, blocking implementation of the Clean Power Plan while it is being challenged in court.

The Utilities have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in Hawaiian Electric’s Campbell Industrial Park combustion turbine No. 1 (CIP CT-1), using biodiesel for startup and shutdown of selected Maui Electric generating units, and testing biofuel blends in other Hawaiian Electric and Maui Electric generating units. The Utilities are also working with the State of Hawaii and other entities to pursue the use of LNG as a cleaner and lower-cost fuel to replace, at least in part, the petroleum oil that would otherwise be used. Management is unable to evaluate the ultimate impact on the Utilities’ operations of more comprehensive GHG regulations that might be promulgated; however, the various initiatives that the Utilities are pursuing are likely to provide a sound basis for appropriately managing the Utilities’ carbon footprint and thereby meet both state and federal GHG reduction goals.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise. This effect could potentially result in impacts to coastal and other low-lying areas (where much of the Utilities’ electric infrastructure is sited), and result in increased flooding and storm damage due to heavy rainfall, increased rates of beach erosion, saltwater intrusion into freshwater aquifers and terrestrial ecosystems, and higher water tables in low-lying areas. The effects of climate change on the weather (for example, more intense or more frequent rain events, flooding, or hurricanes), sea levels, and freshwater availability and quality have the potential to materially adversely affect the results of operations, financial condition, and liquidity of the Utilities. For example, severe weather could cause significant harm to the Utilities’ physical facilities.

Asset retirement obligations. AROs represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The Utilities’ recognition of AROs have no impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by the Utilities relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

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

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



(in thousands)	2015			2014
Balance, January 1	$	29,419		$	43,106
Accretion expense	24			890
Liabilities incurred	—			—
Liabilities settled	(2,595		)	(14,577		)
Revisions in estimated cash flows	—			—
Balance, December 31	$	26,848		$	29,419

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 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 rate adjustment mechanism (RAM) and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments.

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for Hawaiian Electric, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. The PUC affirmed its support for the continuation of the sales decoupling (RBA) mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency, and whether the current interest rate applied to the outstanding RBA balance is reasonable. In October 2013, the PUC issued orders that bifurcated the proceeding (into Schedule A and Schedule B issues).

On February 7, 2014, the PUC issued a decision and order (D&O) on the Schedule A issues, which made certain modifications to the decoupling mechanism. Specifically, the D&O required:


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


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

As required, the Utilities have made available to the public, on the Utilities’ websites, performance metrics identified by the PUC. The Utilities are updating the performance metrics on a quarterly basis.

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

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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.

On May 28, 2015, the PUC issued an Order (the May Order) related to the Utilities’ revised annual decoupling filing for tariffed rates submitted on April 15, 2015. The May Order ruled on the specific matters identified by the PUC in its information requests and by the Consumer Advocate in its Statement of Position. As a result of the May Order, on June 3, 2015, the Utilities filed revised tariff rates reflecting a reduction to the RAM portion of the tariff filing. The revision was made primarily to adjust the RAM to reflect reduced operations and maintenance expenses associated with the Utilities’ change in estimate related to the allocation of indirect costs implemented in 2014, and to exclude the GDPPI factor on the depreciation expense portion for the calculation of the 2015 RAM Cap. The May Order also requires a one-time adjustment to customers for the impact of bonus tax depreciation enacted in December 2014 on the RAM revenues used for the 2014 tariff filing.

The revised 2015 annual incremental RAM revenues for the Utilities amounts to $11.1 million compared to the $26.2 million filed on April 15, 2015 and the $31.6 million filed on March 31, 2015 based on the methodology prior to its modification in the March Order. The tariffed rates, which became effective on June 8, 2015, also include the collection or refund of the accrued RBA balance and associated revenue taxes as of December 31, 2014 and any accrued earnings sharing mechanism credits. The net refund to be provided by the three Utilities under the revised tariffs amounts to $0.4 million, compared to a collection of $14.7 million under the tariffs filed on April 15, 2015. Below is a summary of the 2015 incremental impact by company.



($ in millions)	Hawaiian Electric			Hawaii Electric Light		Maui Electric
Annual incremental RAM adjusted revenues	$	8.1		$	1.5	$	1.5
Annual change in accrued earnings sharing credits to be refunded	$	—		$	—	$	(0.1	)
Annual change in accrued RBA balance as of December 31, 2015 (and associated revenue taxes) to be collected	$	(9.2	)	$	0.1	$	(2.2	)
Net annual incremental amount to be collected under the tariffs	$	(1.1	)	$	1.5	$	(0.8	)
Impact on typical residential customer monthly bill (in dollars) *	$	(0.09	)	$	0.88	$	(0.13	)

Note: Columns may not foot due to rounding

* 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 $0.11, based on a 400 KWH bill.

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 November 2015, the Consumer Advocate filed preliminary statements of position (PSOPs) on these two applications, recommending that the PUC reject the applications. In December 2015, the Utilities filed responses to the Consumer Advocate’s PSOPs, pointing out that the PUC had already

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authorized the filing of such applications for recovery of capital costs above the RAM Cap and requesting that the PUC proceed with review of the applications.

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

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

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

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


•	Distributed Generation Interconnection Plan - the Utilities’ Plan was filed in August 2014.


•	Plan to implement an on-going distribution circuit monitoring program to measure real-time voltage and other power quality parameters - the Utilities’ Plan was filed in June 2014.


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


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


•	Integrated interconnection queue for each distribution circuit for each island grid - the Utilities’ integrated interconnection queue plan was filed in August 2014 and the integrated interconnection queues were implemented in January 2015.

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

Policy Statement and Order Regarding Demand Response Programs. The PUC provided guidance concerning the objectives and goals for demand response programs, and ordered the Utilities to develop an integrated Demand Response Portfolio Plan that will enhance system operations and reduce costs to customers. The Utilities’ Plan was filed in July 2014. Subsequently, the Utilities submitted status updates and an update and supplemental report to the Plan. On July 28, 2015, the PUC issued an order appointing a special advisor to guide, monitor and review the Utility’s Plan design and implementation. On December 30, 2015, the Utilities filed applications with the PUC (1) for approval of their proposed DR Portfolio Tariff Structure, Reporting Schedule and Cost Recovery of Program Costs through the Demand-Side Management (DSM) Surcharge, and (2) for approval to defer and recover certain computer software and software development costs for a Demand Response Management System (DRMS) through the Renewable Energy Infrastructure Program (REIP) Surcharge.

Maui Electric Company 2012 Test Year Rate Case. The PUC acknowledged the extensive analyses provided by Maui Electric in its System Improvement and Curtailment Reduction Plan (SICRP) filed in September 2013. The PUC stated that it is encouraged by the changes in Maui Electric’s operations that have led to a significant reduction in the curtailment of renewables, but stated that Maui Electric has not set forth a clearly defined path that addresses integration and curtailment of additional renewables. The PUC directed Maui Electric to present a PSIP to address present and future system operations so as to not only reduce curtailment, but to optimize the operation of its system for its customers’ benefit. The Maui Electric PSIP

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was filed in August 2014, and is currently being reviewed by the PUC in a new docket along with the Hawaiian Electric and Hawaii Electric Light PSIPs. Maui Electric filed its second annual SICRP status update in September 2015.

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

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

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

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

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

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


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


(2)	technical standards for advanced inverters,


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


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


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


(6)	a streamlined and standardized PV application process.

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

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

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

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

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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 HECO Capital Trust III (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 (see Hawaiian Electric and Subsidiaries' Consolidated Statements of Capitalization) and (c) relating to the trust preferred securities of Trust III (see Note 6). 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.

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Consolidating statement of income

Year ended December 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	1,644,181		345,549		345,517		—	(81	)	[1]	$	2,335,166
Expenses
Fuel oil	458,069			71,851		124,680		—	—			654,600
Purchased power	440,983			97,503		55,610		—	—			594,096
Other operation and maintenance	284,583			63,098		65,408		—	—			413,089
Depreciation	117,682			37,250		22,448		—	—			177,380
Taxes, other than income taxes	156,871			32,312		32,702		—	—			221,885
Total expenses	1,458,188			302,014		300,848		—	—			2,061,050
Operating income	185,993			43,535		44,669		—	(81	)		274,116
Allowance for equity funds used during construction	5,641			604		683		—	—			6,928
Equity in earnings of subsidiaries	42,920			—		—		—	(42,920	)	[2]	—
Interest expense and other charges, net	(45,899		)	(10,773	)	(9,779	)	—	81		[1]	(66,370		)
Allowance for borrowed funds used during construction	1,967			215		275		—	—			2,457
Income before income taxes	190,622			33,581		35,848		—	(42,920	)		217,131
Income taxes	53,828			12,292		13,302		—	—			79,422
Net income	136,794			21,289		22,546		—	(42,920	)		137,709
Preferred stock dividends of subsidiaries	—			534		381		—	—			915
Net income attributable to Hawaiian Electric	136,794			20,755		22,165		—	(42,920	)		136,794
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—	—			1,080
Net income for common stock	$	135,714		20,755		22,165		—	(42,920	)		$	135,714

Consolidating statement of comprehensive income

Year ended December 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Net income for common stock	$	135,714		20,755		22,165		—	(42,920	)		$	135,714
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net gains (losses) arising during the period, net of tax benefits	5,638			(2,710	)	(1,352	)	—	4,062		[1]	5,638
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	20,381			2,728		2,503		—	(5,231	)	[1]	20,381
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(25,139		)	104		(1,107	)	—	1,003		[1]	(25,139		)
Other comprehensive income, net of tax benefits	880			122		44		—	(166	)		880
Comprehensive income attributable to common shareholder	$	136,594		20,877		22,209		—	(43,086	)		$	136,594

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Consolidating statement of income

Year ended December 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	2,142,245		422,200		422,965		—	(87	)	[1]	$	2,987,323
Expenses
Fuel oil	821,246			117,215		193,224		—	—			1,131,685
Purchased power	537,821			123,226		60,961		—	—			722,008
Other operation and maintenance	283,532			65,471		61,609		—	—			410,612
Depreciation	109,204			35,904		21,279		—	—			166,387
Taxes, other than income taxes	201,426			39,521		39,916		—	—			280,863
Impairment of utility assets	—			—		—		—	—			—
Total expenses	1,953,229			381,337		376,989		—	—			2,711,555
Operating income	189,016			40,863		45,976		—	(87	)		275,768
Allowance for equity funds used during construction	6,085			472		214		—	—			6,771
Equity in earnings of subsidiaries	40,964			—		—		—	(40,964	)	[2]	—
Interest expense and other charges, net	(44,041		)	(11,030	)	(9,773	)		87		[1]	(64,757		)
Allowance for borrowed funds used during construction	2,306			182		91		—	—			2,579
Income before income taxes	194,330			30,487		36,508		—	(40,964	)		220,361
Income taxes	55,609			11,264		13,852		—	—			80,725
Net income	138,721			19,223		22,656		—	(40,964	)		139,636
Preferred stock dividends of subsidiaries	—			534		381		—	—			915
Net income attributable to Hawaiian Electric	138,721			18,689		22,275		—	(40,964	)		138,721
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—	—			1,080
Net income for common stock	$	137,641		18,689		22,275		—	(40,964	)		$	137,641

Consolidating statement of comprehensive income (loss)

Year ended December 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Net income for common stock	$	137,641		18,689		22,275		—	(40,964	)		$	137,641
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net gains arising during the period, net of taxes	(218,608		)	(28,725	)	(29,352	)	—	58,077		[1]	(218,608		)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	10,212			1,270		1,090		—	(2,360	)	[1]	10,212
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	207,833			27,437		28,257		—	(55,694	)	[1]	207,833
Other comprehensive loss, net of tax benefits	(563		)	(18	)	(5	)	—	23			(563		)
Comprehensive income attributable to common shareholder	$	137,078		18,671		22,270		—	(40,941	)		$	137,078

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Consolidating statement of income

Year ended December 31, 2013



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	2,124,174		431,517		424,603		—		(122	)	[1]	$	2,980,172
Expenses
Fuel oil	851,365			125,516		208,671		—		—			1,185,552
Purchased power	527,839			128,368		54,474		—		—			710,681
Other operation and maintenance	283,768			61,418		58,081		3		—			403,270
Depreciation	99,738			34,188		20,099		—		—			154,025
Taxes, other than income taxes	200,962			40,092		40,077		—		—			281,131
Impairment of utility assets	—			—		—		—		—			—
Total expenses	1,963,672			389,582		381,402		3		—			2,734,659
Operating income (loss)	160,502			41,935		43,201		(3	)	(122	)		245,513
Allowance for equity funds used during construction	4,495			643		423		—		—			5,561
Equity in earnings of subsidiaries	41,410			—		—		—		(41,410	)	[2]	—
Interest expense and other charges, net	(39,107		)	(11,341	)	(8,953	)	—		122		[1]	(59,279		)
Allowance for borrowed funds used during construction	1,814			263		169		—		—			2,246
Income (loss) before income taxes	169,114			31,500		34,840		(3	)	(41,410	)		194,041
Income taxes	45,105			10,830		13,182		—		—			69,117
Net income (loss)	124,009			20,670		21,658		(3	)	(41,410	)		124,924
Preferred stock dividends of subsidiaries	—			534		381		—		—			915
Net income (loss) attributable to Hawaiian Electric	124,009			20,136		21,277		(3	)	(41,410	)		124,009
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—		—			1,080
Net income (loss) for common stock	$	122,929		20,136		21,277		(3	)	(41,410	)		$	122,929

Consolidating statement of comprehensive income (loss)

Year ended December 31, 2013



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Net income (loss) for common stock	$	122,929		20,136		21,277		(3	)	(41,410	)		$	122,929
Other comprehensive income, net of taxes:
Retirement benefit plans:
Net losses arising during the period, net of tax benefits	203,479			30,542		27,820		—		(58,362	)	[1]	203,479
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	20,694			2,880		2,557		—		(5,437	)	[1]	20,694
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	(222,595		)	(33,277	)	(30,254	)	—		63,531		[1]	(222,595		)
Other comprehensive income, net of taxes	1,578			145		123		—		(268	)		1,578
Comprehensive income (loss) attributable to common shareholder	$	124,507		20,281		21,400		(3	)	(41,678	)		$	124,507

131

Consolidating balance sheet

December 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating 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	)	[2]	0
Current assets
Cash and equivalents	16,281			2,682		5,385		101	—			24,449
Advances to affiliates	—			15,500		7,500		—	(23,000	)	[1]	—
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	)	[1]	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	)	[3]	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	5,742			1,494		1,105		—	—			8,341
Other	47,731			14,693		13,062		—	—			75,486
Total other long-term assets	662,430			130,749		115,148		—	—			908,327
Total assets	$	4,481,558		955,935		831,201		101	(588,741	)		$	5,680,054
Capitalization and liabilities
Capitalization
Common stock equity	$	1,728,325		292,702		263,725		101	(556,528	)	[2]	$	1,728,325
Cumulative preferred stock–not subject to mandatory redemption	22,293			7,000		5,000		—	—			34,293
Long-term debt, net	880,546			215,000		191,000		—	—			1,286,546
Total capitalization	2,631,164			514,702		459,725		101	(556,528	)		3,049,164
Current liabilities
Short-term borrowings-affiliate	23,000			—		—		—	(23,000	)	[1]	—
Accounts payable	84,631			17,702		12,513		—	—			114,846
Interest and preferred dividends payable	15,747			4,255		3,113		—	(4	)	[1]	23,111
Taxes accrued	131,668			30,342		29,325		—	(251	)	[3]	191,084
Regulatory liabilities	—			1,030		1,174		—	—			2,204
Other	41,083			8,760		13,194		—	(8,958	)	[1]	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		[1]	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	)	[1]	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	$	4,481,558		955,935		831,201		101	(588,741	)		$	5,680,054

132

Consolidating balance sheet

December 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	43,819		5,464		3,016		—	—			$	52,299
Plant and equipment	3,782,438			1,179,032		1,048,012		—	—			6,009,482
Less accumulated depreciation	(1,253,866		)	(473,933	)	(447,711	)	—	—			(2,175,510		)
Construction in progress	134,376			12,421		11,819		—	—			158,616
Utility property, plant and equipment, net	2,706,767			722,984		615,136		—	—			4,044,887
Nonutility property, plant and equipment, less accumulated depreciation	4,950			82		1,531		—	—			6,563
Total property, plant and equipment, net	2,711,717			723,066		616,667		—	—			4,051,450
Investment in wholly-owned subsidiaries, at equity	538,639			—		—		—	(538,639	)	[2]	—
Current assets
Cash and equivalents	12,416			612		633		101	—			13,762
Advances to affiliates	16,100			—		—		—	(16,100	)	[1]	—
Customer accounts receivable, net	111,462			24,222		22,800		—	—			158,484
Accrued unbilled revenues, net	103,072			15,926		18,376		—	—			137,374
Other accounts receivable, net	9,980			981		2,246		—	(8,924	)	[1]	4,283
Fuel oil stock, at average cost	74,515			13,800		17,731		—	—			106,046
Materials and supplies, at average cost	33,154			6,664		17,432		—	—			57,250
Prepayments and other	20,231			10,137		3,575		—	(475	)	[1], [3]	33,468
Regulatory assets	58,550			6,745		6,126		—	—			71,421
Total current assets	439,480			79,087		88,919		101	(25,499	)		582,088
Other long-term assets
Regulatory assets	623,784			107,454		102,788		—	(183	)	[1]	833,843
Unamortized debt expense	5,640			1,438		1,245		—	—			8,323
Other	53,106			15,366		13,366		—	—			81,838
Total other long-term assets	682,530			124,258		117,399		—	(183	)		924,004
Total assets	$	4,372,366		926,411		822,985		101	(564,321	)		$	5,557,542
Capitalization and liabilities
Capitalization
Common stock equity	$	1,682,144		281,846		256,692		101	(538,639	)	[2]	$	1,682,144
Cumulative preferred stock–not subject to mandatory redemption	22,293			7,000		5,000		—	—			34,293
Long-term debt, net	830,546			190,000		186,000		—	—			1,206,546
Total capitalization	2,534,983			478,846		447,692		101	(538,639	)		2,922,983
Current liabilities
Short-term borrowings-affiliate	—			10,500		5,600		—	(16,100	)	[1]	—
Accounts payable	122,433			23,728		17,773		—	—			163,934
Interest and preferred dividends payable	15,407			3,989		2,931		—	(11	)	[1]	22,316
Taxes accrued	176,339			37,548		36,807		—	(292	)	[3]	250,402
Regulatory liabilities	191			—		441		—	—			632
Other	45,369			9,587		15,804		—	(9,096	)	[1]	61,664
Total current liabilities	359,739			85,352		79,356		—	(25,499	)		498,948
Deferred credits and other liabilities
Deferred income taxes	407,979			91,924		73,536		—	—			573,439
Regulatory liabilities	236,727			77,707		29,966		—	(183	)	[1]	344,217
Unamortized tax credits	49,865			14,902		14,725		—	—			79,492
Defined benefit pension and other postretirement benefit plans liability	446,888			72,547		75,960		—	—			595,395
Other	52,446			10,658		13,532		—	—			76,636
Total deferred credits and other liabilities	1,193,905			267,738		207,719		—	(183	)		1,669,179
Contributions in aid of construction	283,739			94,475		88,218		—	—			466,432
Total capitalization and liabilities	$	4,372,366		926,411		822,985		101	(564,321	)		$	5,557,542

133

Consolidating statements of changes in common stock equity



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments		Hawaiian Electric Consolidated
Balance, December 31, 2012	$	1,472,136		268,908		228,927		104		(497,939	)	$	1,472,136
Net income (loss) for common stock	122,929			20,136		21,277		(3	)	(41,410	)	122,929
Other comprehensive income, net of tax benefits	1,578			145		123		—		(268	)	1,578
Issuance of common stock, net of expenses	78,499			—		12,461		—		(12,461	)	78,499
Common stock dividends	(81,578		)	(14,387	)	(14,017	)	—		28,404		(81,578		)
Balance, December 31, 2013	$	1,593,564		274,802		248,771		101		(523,674	)	$	1,593,564
Net income for common stock	137,641			18,689		22,275		—		(40,964	)	137,641
Other comprehensive loss, net of taxes	(563		)	(18	)	(5	)	—		23		(563		)
Issuance of common stock, net of expenses	39,994			—		—		—		—		39,994
Common stock dividends	(88,492		)	(11,627	)	(14,349	)	—		25,976		(88,492		)
Balance, December 31, 2014	$	1,682,144		281,846		256,692		101		(538,639	)	$	1,682,144
Net income for common stock	135,714			20,755		22,165		—		(42,920	)	135,714
Other comprehensive income, net of tax benefits	880			122		44		—		(166	)	880
Common stock issuance expenses	(8		)	—		(1	)	—		1		(8		)
Common stock dividends	(90,405		)	(10,021	)	(15,175	)	—		25,196		(90,405		)
Balance, December 31, 2015	$	1,728,325		292,702		263,725		101		(556,528	)	$	1,728,325

134

Consolidating statement of cash flows

Year ended December 31, 2015



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	136,794		21,289		22,546		—	(42,920	)	[2]	$	137,709
Adjustments to reconcile net income to net cash provided by operating activities
Equity in earnings	(43,020		)	—		—		—	42,920		[2]	(100		)
Common stock dividends received from subsidiaries	25,296			—		—		—	(25,196	)	[2]	100
Depreciation of property, plant and equipment	117,682			37,250		22,448		—	—			177,380
Other amortization	4,678			2,124		2,137		—	—			8,939
Impairment of utility assets	4,573			724		724		—	—			6,021
Other	4,403			(2,476	)	(255	)	—	—			1,672
Increase in deferred income taxes	53,338			8,295		13,707		—	286		[1]	75,626
Change in tax credits, net	4,284			527		33		—	—			4,844
Allowance for equity funds used during construction	(5,641		)	(604	)	(683	)	—	—			(6,928		)
Changes in assets and liabilities:
Decrease in accounts receivable	15,652			3,420		4,617		—	38		[1]	23,727
Decrease in accrued unbilled revenues	29,733			4,593		5,767		—	—			40,093
Decrease in fuel oil stock	25,060			5,490		4,280		—	—			34,830
Decrease (increase) in materials and supplies	2,233			(201	)	789		—	—			2,821
Decrease (increase) in regulatory assets	(20,356		)	(3,930	)	104		—	—			(24,182		)
Decrease in accounts payable	(42,751		)	(6,425	)	(5,379	)	—	—			(54,555		)
Change in prepaid and accrued income taxes and revenue taxes	(50,382		)	(6,166	)	(6,548	)	—	—			(63,096		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	870			(161	)	416		—	—			1,125
Change in other assets and liabilities	(24,197		)	(3,545	)	(4,554	)	—	(324	)	[1]	(32,620		)
Net cash provided by operating activities	238,249			60,204		60,149		—	(25,196	)		333,406
Cash flows from investing activities
Capital expenditures	(267,621		)	(48,645	)	(33,895	)	—	—			(350,161		)
Contributions in aid of construction	35,955			2,160		2,124		—	—			40,239
Advances from affiliates	16,100			(15,500	)	(7,500	)	—	6,900		[1]	—
Other	924			132		84		—	—			1,140
Net cash used in investing activities	(214,642		)	(61,853	)	(39,187	)	—	6,900			(308,782		)
Cash flows from financing activities
Common stock dividends	(90,405		)	(10,021	)	(15,175	)	—	25,196		[2]	(90,405		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—	—			(1,995		)
Proceeds from issuance of long-term debt	50,000			25,000		5,000		—	—			80,000
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	23,000			(10,500	)	(5,600	)	—	(6,900	)	[2]	—
Other	(1,257		)	(226	)	(54	)	—	—			(1,537		)
Net cash (used in) provided by financing activities	(19,742		)	3,719		(16,210	)	—	18,296			(13,937		)
Net increase in cash and cash equivalents	3,865			2,070		4,752		—	—			10,687
Cash and cash equivalents, January 1	12,416			612		633		101	—			13,762
Cash and cash equivalents, December 31	$	16,281		2,682		5,385		101	—			$	24,449

135

Consolidating statement of cash flows

Year ended December 31, 2014



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income	$	138,721		19,223		22,656		—	(40,964	)	[2]	$	139,636
Adjustments to reconcile net income to net cash provided by operating activities
Equity in earnings	(41,064		)	—		—		—	40,964		[2]	(100		)
Common stock dividends received from subsidiaries	26,076			—		—		—	(25,976	)	[2]	100
Depreciation of property, plant and equipment	109,204			35,904		21,279		—	—			166,387
Other amortization	4,535			2,926		2,436		—	—			9,897
Impairment of utility assets	1,866			—		—		—	—			1,866
Other	758			—		—		—	—			758
Increase in deferred income taxes	56,901			12,083		13,963		—	—			82,947
Change in tax credits, net	4,998			680		384		—	—			6,062
Allowance for equity funds used during construction	(6,085		)	(472	)	(214	)	—	—			(6,771		)
Change in cash overdraft	—			—		(1,038	)	—	—			(1,038		)
Changes in assets and liabilities:
Decrease in accounts receivable	16,213			7,150		3,483		—	(103	)	[1]	26,743
Decrease in accrued unbilled revenues	4,680			1,174		896		—	—			6,750
Decrease in fuel oil stock	25,098			378		2,565		—	—			28,041
Decrease (increase) in materials and supplies	2,357			219		(2,648	)	—	—			(72		)
Decrease (increase) in regulatory assets	(14,620		)	(3,357	)	977		—	—			(17,000		)
Decrease in accounts payable	(56,044		)	(6,645	)	(2,838	)	—	—			(65,527		)
Change in prepaid and accrued income taxes and revenue taxes	(4,166		)	(3,251	)	3,381		—	—			(4,036		)
Decrease in defined benefit pension and other postretirement benefit plans liability	(562		)	—		(399	)	—	—			(961		)
Change in other assets and liabilities	(50,180		)	(12,907	)	(3,703	)	—	103		[1]	(66,687		)
Net cash provided by operating activities	218,686			53,105		61,180		—	(25,976	)		306,995
Cash flows from investing activities
Capital expenditures	(237,970		)	(49,895	)	(48,814	)	—	—			(336,679		)
Contributions in aid of construction	30,021			7,695		4,090		—	—			41,806
Advances from affiliates	(9,261		)	1,000		—		—	8,261		[1]	—
Other	604			492		68		—	—			1,164
Investment in consolidated subsidiary	—			—		—		—	—			—
Net cash used in investing activities	(216,606		)	(40,708	)	(44,656	)	—	8,261			(293,709		)
Cash flows from financing activities
Common stock dividends	(88,492		)	(11,627	)	(14,349	)	—	25,976		[2]	(88,492		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—	—			(1,995		)
Proceeds from the issuance of common stock	40,000			—		—		—	—			40,000
Repayment of long-term debt	—			(11,400	)	—		—	—			(11,400		)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	(1,000		)	10,500		(1,239	)	—	(8,261	)	[1]	—
Other	(337		)	(50	)	(75	)	—	—			(462		)
Net cash used in financing activities	(50,909		)	(13,111	)	(16,044	)	—	17,715			(62,349		)
Net increase (decrease) in cash and cash equivalents	(48,829		)	(714	)	480		—	—			(49,063		)
Cash and cash equivalents, January 1	61,245			1,326		153		101	—			62,825
Cash and cash equivalents, December 31	$	12,416		612		633		101	—			$	13,762

136

Consolidating statement of cash flows

Year ended December 31, 2013



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income (loss)	$	124,009		20,670		21,658		(3	)	(41,410	)	[2]	$	124,924
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Equity in earnings	(41,510		)	—		—		—		41,410		[2]	(100		)
Common stock dividends received from subsidiaries	28,505			—		—		—		(28,405	)	[2]	100
Depreciation of property, plant and equipment	99,738			34,188		20,099		—		—			154,025
Other amortization	2,549			2,360		2,825		—		—			7,734
Increase in deferred income taxes	41,409			10,569		12,529		—		—			64,507
Change in tax credits, net	5,152			818		1,047		—		—			7,017
Allowance for equity funds used during construction	(4,495		)	(643	)	(423	)	—		—			(5,561		)
Change in cash overdraft	—			—		1,038		—		—			1,038
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	49,974			(1,459	)	1,178		—		(248	)	[1]	49,445
Decrease (increase) in accrued unbilled revenues	(7,152		)	(2,707	)	33		—		—			(9,826		)
Decrease in fuel oil stock	23,563			1,307		2,462		—		—			27,332
Increase in materials and supplies	(5,598		)	(1,547	)	(814	)	—		—			(7,959		)
Increase in regulatory assets	(46,047		)	(9,237	)	(10,177	)	—		—			(65,461		)
Increase (decrease) in accounts payable	18,527			1,525		(5,321	)	—		—			14,731
Change in prepaid and accrued income taxes and revenue taxes	4,632			(4,114	)	(2,546	)	—		—			(2,028		)
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	2,325			(1	)	(84	)	—		—			2,240
Change in other assets and liabilities	(20,613		)	(6,894	)	(8,034	)	—		248		[1]	(35,293		)
Net cash provided by (used in) operating activities	274,968			44,835		35,470		(3	)	(28,405	)		326,865
Cash flows from investing activities
Capital expenditures	(262,562		)	(58,416	)	(57,066	)	—		—			(378,044		)
Contributions in aid of construction	21,686			7,590		2,884		—		—			32,160
Advances from affiliates	2,561			17,050		—		—		(19,611	)	[1]	—
Other	677			21		209		—		—			907
Investment in consolidated subsidiary	(12,461		)	—		—		—		12,461		[2]	—
Net cash used in investing activities	(250,099		)	(33,755	)	(53,973	)	—		(7,150	)		(344,977		)
Cash flows from financing activities
Common stock dividends	(81,578		)	(14,388	)	(14,017	)	—		28,405		[2]	(81,578		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—		—			(1,995		)
Proceeds from the issuance of common stock	78,500			—		12,461		—		(12,461	)	[2]	78,500
Proceeds from the issuance of long-term debt	140,000			56,000		40,000		—		—			236,000
Repayment of long-term debt	(90,000		)	(56,000	)	(20,000	)	—		—			(166,000		)
Net decrease in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	(17,050		)	—		(2,561	)	—		19,611		[1]	—
Other	(681		)	(273	)	(195	)	—		—			(1,149		)
Net cash provided by (used in) financing activities	28,111			(15,195	)	15,307		—		35,555			63,778
Net increase (decrease) in cash and cash equivalents	52,980			(4,115	)	(3,196	)	(3	)	—			45,666
Cash and cash equivalents, January 1	8,265			5,441		3,349		104		—			17,159
Cash and cash equivalents, December 31	61,245			1,326		153		101		—			62,825

Explanation of consolidating adjustments on consolidating schedules:


[1]	Eliminations of intercompany receivables and payables and other intercompany transactions.


[2]	Elimination of investment in subsidiaries, carried at equity.


[3]	Reclassification of accrued income taxes for financial statement presentation.

137

5 · Bank segment (HEI only)

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data



Years ended December 31	2015		2014		2013
(in thousands)
Interest and dividend income
Interest and fees on loans	$	184,782	$	179,341	$	172,969
Interest and dividends on investment securities	15,120		11,945		13,095
Total interest and dividend income	199,902		191,286		186,064
Interest expense
Interest on deposit liabilities	5,348		5,077		5,092
Interest on other borrowings	5,978		5,731		4,985
Total interest expense	11,326		10,808		10,077
Net interest income	188,576		180,478		175,987
Provision for loan losses	6,275		6,126		1,507
Net interest income after provision for loan losses	182,301		174,352		174,480
Noninterest income
Fees from other financial services	22,211		21,747		27,099
Fee income on deposit liabilities	22,368		19,249		18,363
Fee income on other financial products	8,094		8,131		8,405
Bank-owned life insurance	4,078		3,949		3,928
Mortgage banking income	6,330		2,913		8,309
Gains on sale of investment securities	—		2,847		1,226
Other income, net	4,750		2,375		4,753
Total noninterest income	67,831		61,211		72,083
Noninterest expense
Compensation and employee benefits	90,518		79,885		82,910
Occupancy	16,365		17,197		16,747
Data processing	12,103		11,690		10,952
Services	10,204		10,269		9,015
Equipment	6,577		6,564		7,295
Office supplies, printing and postage	5,749		6,089		4,233
Marketing	3,463		3,999		3,373
FDIC insurance	3,274		3,261		3,253
Other expense	18,067		17,314		19,637
Total noninterest expense	166,320		156,268		157,415
Income before income taxes	83,812		79,295		89,148
Income taxes	29,082		27,994		31,421
Net income	$	54,730	$	51,301	$	57,727

138

Statements of Comprehensive Income



Years ended December 31	2015			2014			2013
(in thousands)
Net income	$	54,730		$	51,301		$	57,727
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 $1,541, ($3,856),and $9,037 for 2015, 2014 and 2013, respectively	(2,334		)	5,840			(13,686		)
Less: reclassification adjustment for net realized gains included in net income, net of taxes of nil, $1,132 and $488 for 2015, 2014 and 2013, respectively	—			(1,715		)	(738		)
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of ($59), $6,164 and ($10,450) for 2015, 2014 and 2013, respectively	90			(9,336		)	15,826
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $1,011, $561 and $1,187 for 2015, 2014 and 2013, respectively	1,531			850			1,797
Other comprehensive income (loss), net of taxes	(713		)	(4,361		)	3,199
Comprehensive income	$	54,017		$	46,940		$	60,926

Balance Sheets Data



December 31				2015						2014
(in thousands)
Assets
Cash and due from banks				$	127,201					$	107,233
Interest-bearing deposits				93,680						54,230
Available-for-sale investment securities, at fair value				820,648						550,394
Stock in Federal Home Loan Bank, at cost				10,678						69,302
Loans receivable held for investment				4,615,819						4,434,651
Allowance for loan losses				(50,038		)				(45,618		)
Net loans				4,565,781						4,389,033
Loans held for sale, at lower of cost or fair value				4,631						8,424
Other				309,946						305,416
Goodwill				82,190						82,190
Total assets				$	6,014,755					$	5,566,222
Liabilities and shareholder’s equity
Deposit liabilities–noninterest-bearing				$	1,520,374					$	1,342,794
Deposit liabilities–interest-bearing				3,504,880						3,280,621
Other borrowings				328,582						290,656
Other				101,029						118,363
Total liabilities				5,454,865						5,032,434
Commitments and contingencies
Common stock				1						1
Additional paid in capital				340,496						338,411
Retained earnings				236,664						211,934
Accumulated other comprehensive loss, net of tax benefits
Net unrealized gains (losses) on securities	$	(1,872	)				$	462
Retirement benefit plans	(15,399		)	(17,271		)	(17,020		)	(16,558		)
Total shareholder’s equity				559,890						533,788
Total liabilities and shareholder’s equity				$	6,014,755					$	5,566,222

139



December 31	2015		2014
(in thousands)
Other assets
Bank-owned life insurance	$	138,139	$	134,115
Premises and equipment, net	88,077		92,407
Prepaid expenses	3,550		3,196
Accrued interest receivable	15,192		13,632
Mortgage-servicing rights	8,884		11,540
Low-income housing equity investments	37,793		33,438
Real estate acquired in settlement of loans, net	1,030		891
Other	17,281		16,197
	$	309,946	$	305,416
Other liabilities
Accrued expenses	$	30,705	$	37,880
Federal and state income taxes payable	13,448		28,642
Cashier’s checks	21,768		20,509
Advance payments by borrowers	10,311		9,652
Other	24,797		21,680
	$	101,029	$	118,363

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

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



										Gross unrealized losses
			Gross		Gross			Estimated		Less than 12 months						12 months or longer
(dollars in thousands)	Amortized cost		unrealized gains		unrealized losses			fair value		Number of issues	Fair value		Amount			Number of issues	Fair value		Amount
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	)
December 31, 2014
Available-for-sale
U.S. Treasury and federal agency obligations	$	119,507	$	1,092	$	(1,039	)	$	119,560	6	$	41,970	$	(361	)	5	$	29,168	$	(678	)
Mortgage-related securities- FNMA, FHLMC and GNMA	430,120		5,653		(4,939		)	430,834		6	47,029		(164		)	29	172,623		(4,775		)
	$	549,627	$	6,745	$	(5,978	)	$	550,394	12	$	88,999	$	(525	)	34	$	201,791	$	(5,453	)

ASB does not believe that the investment securities that were in an unrealized loss position as of December 31, 2015, 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 2015, 2014 and 2013.

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.

140

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



	Amortized		Fair
December 31, 2015	Cost		value
(in thousands)
Due in one year or less	$	—	$	—
Due after one year through five years	86,379		86,935
Due after five years through ten years	71,972		71,812
Due after ten years	54,883		54,212
	213,234		212,959
Mortgage-related securities-FNMA,FHLMC and GNMA	610,522		607,689
Total available-for-sale securities	$	823,756	$	820,648

The proceeds, gross gains and losses from sales of available-for-sale investment securities were as follows:



Years ended December 31	2015		2014		2013
(in millions)
Proceeds	$	—	$	79.6	$	71.4
Gross gains	—		2.8		1
Gross losses	—		—		—

Interest income from taxable and non-taxable investment securities were as follows:



Years ended December 31	2015		2014		2013
(in thousands)
Taxable	$	15,120	$	11,666	$	11,474
Non-taxable	—		279		1,621
	$	15,120	$	11,945	$	13,095

ASB pledged securities with a market value of approximately $100.5 million and $88.6 million as of December 31, 2015 and 2014, respectively, as collateral for public funds deposits, automated clearinghouse transactions with Bank of Hawaii, to-be-announced mortgage-backed securities settlements with JP Morgan, and deposits in ASB’s bankruptcy account with the Federal Reserve Bank of San Francisco. As of December 31, 2015 and 2014, securities with a carrying value of $260.5 million and $230.2 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

Stock in FHLB. As of December 31, 2015 and 2014, ASB’s stock in FHLB was carried at cost ($10.7 million and $69.3 million, respectively) because it can only be redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and borrowing levels. In May 2015, the FHLB of Seattle and FHLB of Des Moines completed the merger of the two banks and began operating as the FHLB of Des Moines on June 1, 2015. At December 31, 2014, the Company had $55 million of FHLB stock in excess of the required investment. With the merger, all of the Company's excess FHLB stock was repurchased. The FHLB repurchased a total of $58.6 million and $23.2 million of FHLB stock from ASB in 2015 and 2014, respectively. There was no other significant impact on ASB as a result of the merger.

Periodically and as conditions warrant, ASB reviews its investment in the stock of the FHLB for impairment. ASB evaluated its investment in FHLB stock for OTTI as of December 31, 2015, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2015 based on its evaluation of the underlying investment, including:


•	the net income and growth in retained earnings recorded by the FHLB in the first nine months of 2015;


•	compliance by the FHLB with all of its regulatory capital requirements and being classified “adequately capitalized” by the Federal Housing Finance Agency (Finance Agency);


•	being authorized by the Finance Agency to repurchase excess stock;


•	the impact of legislative and regulatory changes on institutions and, accordingly, on the customer base of the FHLB;


•	the liquidity position of the FHLB; and


•	ASB’s intent and assessment of whether it will more likely than not be required to sell the FHLB stock before recovery of its par value.

141

Future deterioration in the FHLB's financial position and/or negative developments in any of the factors considered in ASB's impairment evaluation above may result in future impairment losses.

Loans receivable.

The components of loans receivable were summarized as follows:



December 31	2015			2014
(in thousands)
Real estate:
Residential 1-4 family	$	2,069,665		$	2,044,205
Commercial real estate	690,561			531,917
Home equity line of credit	846,294			818,815
Residential land	18,229			16,240
Commercial construction	100,796			96,438
Residential construction	14,089			18,961
Total real estate	3,739,634			3,526,576
Commercial	758,659			791,757
Consumer	123,775			122,656
Total loans	4,622,068			4,440,989
Less: Deferred fees and discounts	(6,249		)	(6,338		)
Allowance for loan losses	(50,038		)	(45,618		)
Total loans, net	$	4,565,781		$	4,389,033

ASB's policy is to require private mortgage insurance on all real estate loans when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For non-owner occupied residential properties, the loan-to-value ratio may not exceed 80% of the lower of the appraised value or purchase price at origination. ASB is subject to the risk that the insurance company cannot satisfy the bank's claim on policies.

ASB services real estate loans for investors (principal balance of $1.5 billion, $1.4 billion and $1.4 billion as of December 31, 2015, 2014 and 2013, respectively), which are not included in the accompanying consolidated balance sheets data. ASB reports fees earned for servicing such loans as income when the related mortgage loan payments are collected and charges loan servicing cost to expense as incurred.

As of December 31, 2015 and 2014, ASB had pledged loans with an amortized cost of approximately $2.3 billion and $1.9 billion, respectively, as collateral to secure advances from the FHLB.

As of December 31, 2015 and 2014, the aggregate amount of loans to directors and executive officers of ASB and its affiliates and any related interests (as defined in Federal Reserve Board (FRB) Regulation O) of such individuals, was $27.8 million and $49.6 million, respectively. The $21.8 million decrease in such loans in 2015 was attributed to closed lines of credits and repayments of $21.8 million. As of December 31, 2015 and 2014, $25.8 million and $46.2 million of the loan balances, respectively, were to related interests of individuals who are directors of ASB. All such loans were made at ASB’s normal credit terms. Management believes these loans do not represent more than a normal risk of collection.

Allowance for loan losses. As discussed in Note 1, ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio.

142

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			Consumer			Unallo- cated			Total
December 31, 2015
Allowance for loan losses:
Beginning balance	$	4,662		$	8,954	$	6,982		$	1,875		$	5,471		$	28		$	14,017		$	3,629		$	—		$	45,618
Charge-offs	(356		)	—		(205		)	—			—			—			(1,074		)	(4,791		)	—			(6,426		)
Recoveries	226			—		80			507			—			—			2,773			985			—			4,571
Provision	(346		)	2,388		403			(711		)	(1,010		)	(15		)	1,492			4,074						6,275
Ending balance	$	4,186		$	11,342	$	7,260		$	1,671		$	4,461		$	13		$	17,208		$	3,897		$	—		$	50,038
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
December 31, 2014
Allowance for loan losses:
Beginning balance	$	5,534		$	5,059	$	5,229		$	1,817		$	2,397		$	19		$	15,803		$	2,367		$	1,891		$	40,116
Charge-offs	(987		)	—		(196		)	(81		)	—			—			(1,872		)	(2,414		)	—			(5,550		)
Recoveries	1,180			—		752			469			—			—			1,636			889			—			4,926
Provision	(1,065		)	3,895		1,197			(330		)	3,074			9			(1,550		)	2,787			(1,891		)	6,126
Ending balance	$	4,662		$	8,954	$	6,982		$	1,875		$	5,471		$	28		$	14,017		$	3,629		$	—		$	45,618
Ending balance: individually evaluated for impairment	$	951		$	1,845	$	46		$	1,057		$	—		$	—		$	760		$	6					$	4,665
Ending balance: collectively evaluated for impairment	$	3,711		$	7,109	$	6,936		$	818		$	5,471		$	28		$	13,257		$	3,623		$	—		$	40,953
Financing Receivables:
Ending balance	$	2,044,205		$	531,917	$	818,815		$	16,240		$	96,438		$	18,961		$	791,757		$	122,656					$	4,440,989
Ending balance: individually evaluated for impairment	$	22,981		$	5,112	$	779		$	7,850		$	—		$	—		$	13,108		$	16					$	49,846
Ending balance: collectively evaluated for impairment	$	2,021,224		$	526,805	$	818,036		$	8,390		$	96,438		$	18,961		$	778,649		$	122,640					$	4,391,143

Changes in the allowance for loan losses were as follows:



(dollars in thousands)	2015			2014			2013
Allowance for loan losses, January 1	$	45,618		$	40,116		$	41,985
Provision for loan losses	6,275			6,126			1,507
Charge-offs, net of recoveries
Real estate loans	(252		)	(1,137		)	(678		)
Other loans	2,107			1,761			4,054
Net charge-offs	1,855			624			3,376
Allowance for loan losses, December 31	$	50,038		$	45,618		$	40,116
Ratio of net charge-offs to average total loans	0.04		%	0.01		%	0.09		%

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.

143

Each loan is assigned an Asset Quality Rating (AQR) reflecting the likelihood of repayment or orderly liquidation of that loan transaction pursuant to regulatory credit classifications: Pass, Special Mention, Substandard, Doubtful, and Loss. The AQR is a function of the PD Model rating, the LGD, and possible non-model factors which impact the ultimate collectability of the loan such as character of the business owner/guarantor, interim period performance, litigation, tax liens, and major changes in business and economic conditions. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral. Special Mention loans have potential weaknesses that, if left uncorrected, could jeopardize the liquidation of the debt. Substandard loans have well-defined weaknesses that jeopardize the liquidation of the debt and are characterized by the distinct possibility that the Bank may sustain some loss. An asset classified Doubtful has the weaknesses of those classified Substandard, with the added characteristic that the weaknesses make collection or liquidation in full, on the basis of currently existing facts, conditions, and values, highly questionable and improbable.

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



December 31	2015							2014
(in thousands)	Commercial real estate		Commercial construction		Commercial		Total	Commercial real estate		Commercial construction		Commercial		Total
Grade:
Pass	$	642,410	$	86,991	$	703,208	1,432,609	$	493,105	$	79,312	$	743,334	$	1,315,751
Special mention	7,710		13,805		7,029		28,544	5,209		—		16,095		21,304
Substandard	40,441		—		47,975		88,416	33,603		17,126		31,665		82,394
Doubtful	—		—		447		447	—		—		663		663
Loss	—		—		—		—	—		—		—		—
Total	$	690,561	$	100,796	$	758,659	1,550,016	$	531,917	$	96,438	$	791,757	$	1,420,112

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
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	$	—
December 31, 2014
Real estate:
Residential 1-4 family	$	6,124	$	1,732	$	12,632	$	20,488	$	2,023,717	$	2,044,205	$	—
Commercial real estate	—		—		—		—		531,917		531,917		—
Home equity line of credit	1,341		501		194		2,036		816,779		818,815		—
Residential land	—		—		—		—		16,240		16,240		—
Commercial construction	—		—		—		—		96,438		96,438		—
Residential construction	—		—		—		—		18,961		18,961		—
Commercial	699		145		569		1,413		790,344		791,757		—
Consumer	829		333		403		1,565		121,091		122,656		—
Total loans	$	8,993	$	2,711	$	13,798	$	25,502	$	4,415,487	$	4,440,989	$	—

144

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



December 31	2015		2014
(in thousands)
Real estate:
Residential 1-4 family	$	20,554	$	19,253
Commercial real estate	1,188		5,112
Home equity line of credit	2,254		1,087
Residential land	970		720
Commercial construction	—		—
Residential construction	—		—
Commercial	20,174		10,053
Consumer	895		661
Total nonaccrual loans	$	46,035	$	36,886
Real estate:
Residential 1-4 family	$	—	$	—
Commercial real estate	—		—
Home equity line of credit	—		—
Residential land	—		—
Commercial construction	—		—
Residential construction	—		—
Commercial	—		—
Consumer	—		—
Total accruing loans 90 days or more past due	$	—	$	—
Real estate:
Residential 1-4 family	$	13,962	$	13,525
Commercial real estate	—		—
Home equity line of credit	2,467		480
Residential land	4,713		7,130
Commercial construction	—		—
Residential construction	—		—
Commercial	1,104		2,972
Consumer	—		—
Total troubled debt restructured loans not included above	$	22,246	$	24,107

145

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



December 31	2015										2014
(in thousands)	Recorded investment		Unpaid principal balance		Related allow- ance		Average recorded investment		Interest income recognized*		Recorded investment		Unpaid principal balance		Related allow- ance		Average recorded investment		Interest income recognized*
With no related allowance recorded
Real estate:
Residential 1-4 family	$	10,596	$	11,805	$	—	$	11,215	$	332	$	11,654	$	12,987	$	—	$	9,056	$	227
Commercial real estate	1,188		1,436		—		370		74		571		626		—		194		—
Home equity line of credit	707		948		—		484		4		363		606		—		402		5
Residential land	1,644		2,412		—		2,397		137		2,344		3,200		—		2,728		172
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial	5,671		6,333		—		5,185		157		8,235		11,471		—		5,204		38
Consumer	—		—		—		—		—		—		—		—		8		—
	19,806		22,934		—		19,651		704		23,167		28,890		—		17,592		442
With an allowance recorded
Real estate:
Residential 1-4 family	11,861		11,914		1,453		11,578		562		11,327		11,347		951		8,822		419
Commercial real estate	—		—		—		1,699		—		4,541		4,541		1,845		3,415		478
Home equity line of credit	2,518		2,579		442		1,597		49		416		420		46		132		6
Residential land	4,039		4,117		891		4,337		318		5,506		5,584		1,057		6,415		484
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial	15,448		16,073		3,527		12,507		211		4,873		5,211		760		12,089		438
Consumer	13		13		7		14		—		16		16		6		9		—
	33,879		34,696		6,320		31,732		1,140		26,679		27,119		4,665		30,882		1,825
Total
Real estate:
Residential 1-4 family	22,457		23,719		1,453		22,793		894		22,981		24,334		951		17,878		646
Commercial real estate	1,188		1,436		—		2,069		74		5,112		5,167		1,845		3,609		478
Home equity line of credit	3,225		3,527		442		2,081		53		779		1,026		46		534		11
Residential land	5,683		6,529		891		6,734		455		7,850		8,784		1,057		9,143		656
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial	21,119		22,406		3,527		17,692		368		13,108		16,682		760		17,293		476
Consumer	13		13		7		14		—		16		16		6		17		—
	$	53,685	$	57,630	$	6,320	$	51,383	$	1,844	$	49,846	$	56,009	$	4,665	$	48,474	$	2,267

* Since loan was classified as impaired.

Troubled debt restructurings. A loan modification is deemed to be a 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

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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 during 2015 and 2014 were as follows:



Years ended December 31	2015							2014
	Number	Outstanding recorded investment				Net increase in ALLL		Number	Outstanding recorded investment				Net increase in ALLL
(dollars in thousands)	of contracts	Pre-modification		Post-modification		Net increase in ALLL		of contracts	Pre-modification		Post-modification		Net increase in ALLL
Troubled debt restructurings
Real estate:
Residential 1-4 family	19	$	3,594	$	3,668	$	87	38	$	10,680	$	10,737	$	163
Commercial real estate	1	1,500		1,500		—		—	—		—		—
Home equity line of credit	39	2,441		2,441		370		8	502		502		42
Residential land	1	218		218		—		18	4,304		4,304		242
Commercial construction	—	—		—		—		—	—		—		—
Residential construction	—	—		—		—		—	—		—		—
Commercial	8	2,267		2,267		486		7	3,827		3,827		13
Consumer	—	—		—		—		—	—		—		—
	68	$	10,020	$	10,094	$	943	71	$	19,313	$	19,370	$	460

Loans modified in TDRs that experienced a payment default of 90 days or more in 2015 and 2014, and for which the payment default occurred within one year of the modification, were as follows:



Years ended December 31	2015			2014
(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	$	390
Commercial real estate	—	—		—	—
Home equity line of credit	1	6		—	—
Residential land	—	—		—	—
Commercial construction	—	—		—	—
Residential construction	—	—		—	—
Commercial	1	1,056		1	14
Consumer	—	—		—	—
	2	$	1,062	2	$	404

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 impaired or modified in TDRs totaled $0.1 million at December 31, 2015.

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

ASB received $275.3 million, $155.0 million, and $273.8 million of proceeds from the sale of residential mortgages in 2015, 2014, and 2013, respectively, and recognized gains on such sales of $6.3 million, $2.9 million, and $8.3 million in 2015,

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2014, and 2013, respectively. Repurchased mortgage loans in 2015, 2014, and 2013, were nil, $0.5 million and $1.9 million, respectively.

Mortgage servicing fees, a component of other income, net, were $3.5 million, $3.5 million, and $3.3 million for the years ended December 31, 2015, 2014, and 2013, respectively.

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



(in thousands)	Gross carrying amount			Accumulated amortization				Valuation allowance			Net carrying amount
December 31, 2015	$	14,531	¹	$	(5,647	)	¹	$	—		$	8,884
December 31, 2014	$	27,185		$	(15,436	)		$	(209	)	$	11,540

¹ Reflects sale of mortgage servicing rights and impact of loans paid in full.

Changes related to mortgage servicing rights were as follows:



(in thousands)	2015			2014			2013
Mortgage servicing rights
Balance, January 1	$	11,749		$	11,938		$	11,316
Amount capitalized	3,123			1,637			2,611
Amortization	(2,682		)	(1,731		)	(1,802		)
Sale of mortgage servicing rights	(3,302		)	—			—
Other-than-temporary impairment	(4		)	(95		)	(187		)
Carrying amount before valuation allowance, December 31	8,884			11,749			11,938
Valuation allowance for mortgage servicing rights
Balance, January 1	209			251			498
Provision (recovery)	(205		)	53			(60		)
Other-than-temporary impairment	(4		)	(95		)	(187		)
Balance, December 31	—			209			251
Net carrying value of mortgage servicing rights	$	8,884		$	11,540		$	11,687

The estimated aggregate amortization expenses of mortgage servicing rights for 2016, 2017, 2018, 2019 and 2020 are $1.3 million, $1.2 million, $1.0 million, $0.9 million and $0.8 million, respectively.

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.

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



December 31	2015			2014
(dollars in thousands)
Unpaid principal balance	$	1,097,314		$	1,391,030
Weighted average note rate	4.05		%	4.07		%
Weighted average discount rate	9.6		%	9.6		%
Weighted average prepayment speed	9.3		%	9.5		%

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:



December 31	2015			2014
(in thousands)
Prepayment rate:
25 basis points adverse rate change	$	(561	)	$	(757	)
50 basis points adverse rate change	(1,104		)	(1,524		)
Discount rate:
25 basis points adverse rate change	(111		)	(140		)
50 basis points adverse rate change	(220		)	(278		)

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

Deposit liabilities. The summarized components of deposit liabilities were as follows:



December 31	2015				2014
(dollars in thousands)	Weighted-average stated rate		Amount		Weighted-average stated rate		Amount
Savings	0.07	%	$	2,030,644	0.06	%	$	1,923,062
Checking
Interest-bearing	0.02		831,143		0.02		768,787
Noninterest-bearing	—		746,875		—		665,005
Commercial checking	—		773,499		—		677,789
Money market	0.13		167,641		0.12		158,010
Term certificates	0.93		475,452		0.83		430,762
	0.12	%	$	5,025,254	0.11	%	$	4,623,415

As of December 31, 2015 and 2014, term certificates of $100,000 or more totaled $163.2 million and $119.9 million, respectively.

The approximate scheduled maturities of term certificates outstanding at December 31, 2015 were as follows:



(in thousands)
2016	$	197,095
2017	72,817
2018	63,876
2019	53,525
2020	84,749
Thereafter	3,390
	$	475,452

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Interest expense on deposit liabilities by type of deposit was as follows:



Years ended December 31	2015		2014		2013
(in thousands)
Term certificates	$	3,747	$	3,603	$	3,702
Savings	1,257		1,134		1,052
Money market	205		214		232
Interest-bearing checking	139		126		106
	$	5,348	$	5,077	$	5,092

Other borrowings.

Securities sold under agreements to repurchase. 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
December 31, 2015	$	229	$	—	$	229
December 31, 2014	191		—		191



	Gross amount not offset in the Balance Sheet
(in millions)	Net amount of liabilities presented in the Balance Sheet		Financial instruments		Cash collateral pledged
December 31, 2015
Financial institution	$	50	$	56	$	—
Government entities	56		61		—
Commercial account holders	123		144		—
Total	$	229	$	261	$	—
December 31, 2014
Financial institution	$	50	$	57	$	—
Government entities	56		59		—
Commercial account holders	85		115		—
Total	$	191	$	231	$	—

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. The counterparties or tri-parties may determine that additional collateral is required based on movements in the fair value of the collateral. Typically, a five percent discount is taken from the fair value of the investment securities to determine the value of the collateral pledged for the repurchase agreements.

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Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:



(dollars in millions)	2015			2014			2013
Amount outstanding as of December 31	$	229		$	191		$	145
Average amount outstanding during the year	$	219		$	155		$	147
Maximum amount outstanding as of any month-end	$	277		$	195		$	151
Weighted-average interest rate as of December 31	1.24		%	1.45		%	1.75		%
Weighted-average interest rate during the year	1.29		%	1.67		%	1.74		%
Weighted-average remaining days to maturity as of December 31	117			343			367

Securities sold under agreements to repurchase were summarized as follows:



December 31	2015							2014
Maturity	Repurchase liability			Weighted-average interest rate		Collateralized by mortgage-related securities and federal agency obligations at fair value plus accrued interest		Repurchase liability			Weighted-average interest rate		Collateralized by mortgage-related securities and federal agency obligations at fair value plus accrued interest
(dollars in thousands)
Overnight	$	122,684		0.15	%	$	144,146	$	84,758		0.15	%	$	114,883
1 to 29 days	—			—		—		—			—		—
30 to 90 days	18,535			0.29		20,364		—			—		—
Over 90 days	87,363		¹	2.96		96,553		105,898		¹	2.50		115,842
	$	228,582		1.24	%	$	261,063	$	190,656		1.45	%	$	230,725


¹	$50.3 million callable by the counterparties quarterly at par until maturity in 2016.

Advances from Federal Home Loan Bank. FHLB advances are fixed rate for a specific term and consist of the following:



December 31, 2015	Weighted-average stated rate		Amount
(dollars in thousands)
Due in
2016	—	%	$	—
2017	4.28		50,000		¹
2018	1.95		50,000
2019	—		—
2020	—		—
Thereafter	—		—
	3.12	%	$	100,000


¹	Callable quarterly at par until maturity in 2017.

ASB and the FHLB are parties to an Advances, Security and Deposit Agreement (Advances Agreement), which applies to currently outstanding and future advances, and governs the terms and conditions under which ASB borrows and the FHLB makes loans or advances from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB’s credit policies, and makes certain warranties and representations to the FHLB. Upon the occurrence of and during the continuation of an “Event of Default” (which term includes any event of nonpayment of interest or principal of any advance when due or failure to perform any promise or obligation under the Advances Agreement or other credit arrangements between the parties), the FHLB may, at its option, declare all indebtedness and accrued interest thereon, including any prepayment fees or charges, to be immediately due and payable. Advances from the FHLB are collateralized by loans and stock in the FHLB. As of December 31, 2015 and 2014, ASB’s available FHLB borrowing capacity was $1.7 billion and $1.2 billion, respectively. ASB is required to obtain and hold a specific number of shares of capital stock of the FHLB. ASB was in compliance with all Advances Agreement requirements as of December 31, 2015 and 2014.

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Common stock equity. In 1988, HEI agreed with the OTS predecessor regulatory agency at the time, to contribute additional capital to ASB up to a maximum aggregate amount of approximately $65.1 million (Capital Maintenance Agreement). As of December 31, 2015, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the Capital Maintenance Agreement has been reduced to approximately $28.3 million. As of December 31, 2015, ASB was in compliance with the minimum capital requirements under OCC regulations.

In 2015, ASB paid cash dividends of $30 million to HEI, compared to cash dividends of $36 million in 2014. The FRB and OCC approved the dividends.

Related-party transactions. HEI charged ASB $2.1 million, $2.3 million and $1.9 million for general management and administrative services in 2015, 2014 and 2013, respectively. The amounts charged by HEI for services performed by HEI employees to its subsidiaries are allocated primarily on the basis of time expended in providing such services.

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

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

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

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

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



December 31	2015					2014
(in thousands)	Notional amount		Fair value			Notional amount		Fair value
Interest rate lock commitments	$	22,241	$	384		$	29,330	$	390
Forward commitments	23,644		(29		)	32,833		(106		)

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



Derivative Financial Instruments Not Designated
as Hedging Instruments ¹
December 31	2015				2014
(in thousands)	Asset derivatives		Liability derivatives		Asset derivatives		Liability derivatives
Interest rate lock commitments	$	384	$	—	$	393	$	3
Forward commitments	1		30		5		111
	$	385	$	30	$	398	$	114

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

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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	Location of net gains
as Hedging Instruments	(losses) recognized in	Years ended December 31
(in thousands)	the Statements of Income	2015			2014			2013
Interest rate lock commitments	Mortgage banking income	$	(6	)	$	(74	)	$	464
Forward commitments	Mortgage banking income	77			(245		)	139
		$	71		$	(319	)	$	603

Commitments. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain of the commitments are expected to expire without being drawn upon, the total commitment amounts do not necessarily represent future cash requirements. The Company minimizes its exposure to loss under these commitments by requiring that customers meet certain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may include residential real estate, accounts receivable, inventory and property, plant and equipment.

Letters of credit are conditional commitments issued by the Company to guarantee payment and performance of a customer to a third party. The credit risk involved in issuing letters of credit is essentially the same as that involved in extending loan facilities to customers. The Company holds collateral supporting those commitments for which collateral is deemed necessary.

The following is a summary of outstanding off-balance sheet arrangements:



December 31	2015		2014
(in thousands)
Unfunded commitments to extend credit:
Home equity line of credit	$	1,096,532	$	1,089,633
Commercial and commercial real estate	631,780		526,133
Consumer	60,198		56,312
Residential 1-4 family	24,863		20,524
Commercial and financial standby letters of credit	18,709		20,082
Total	$	1,832,082	$	1,712,684

Guarantees. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a result of a restructuring of Visa U.S.A. Inc. in preparation for an initial public offering by Visa. As a part of the restructuring, ASB entered into a judgment and loss sharing agreement with Visa in order to apportion financial responsibilities arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. In November 2012, a federal judge granted preliminary approval to a proposed settlement between merchants and Visa over credit card fees and in December 2013, a federal judge granted final approval to the settlement. Some merchants and trade organizations filed a notice of appeal shortly after the approval was issued. As of December 31, 2015, ASB had accrued a reserve of $1.1 million related to the agreement. Because the extent of ASB’s obligations under this agreement depends entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is not determinable.

Contingencies. In March 2011, a purported class action lawsuit was filed in the First Circuit Court of the state of Hawaii by a customer who claimed that ASB had improperly charged overdraft fees on debit card transactions. ASB filed a motion to dismiss the lawsuit on the basis that ASB’s overdraft practices are governed by federal regulations established for federal savings banks which preempt the customer’s state law claims. In July 2011, the Circuit Court denied ASB's motion without prejudice and ASB appealed that decision to the Hawaii Supreme Court. However, in December 2014, through a voluntary mediation process, ASB reached a tentative settlement of the claims. The tentative settlement, which received final Circuit Court approval on May 21, 2015, provided for a payment of $2.0 million into a class settlement fund, the proceeds of which would be used to refund class members and pay attorneys’ fees and administrative and other costs, in exchange for a complete release of all claims asserted against ASB. The $2.0 million settlement amount was fully reserved by ASB in December 2014 and paid into the settlement fund in January 2015.

Federal Deposit Insurance Corporation assessment. In February 2011, the Federal Deposit Insurance Corporation (FDIC) finalized rules to change its assessment base from total domestic deposits to average total assets minus average tangible equity, as required in the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Assessment rates were reduced to a range of 2.5 to 9 basis points on the new assessment base for financial institutions in the lowest risk category.

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Financial institutions in the highest risk category have assessment rates of 30 to 45 basis points. The new rate schedule was effective April 1, 2011. For the years ended December 31, 2015 and 2014, ASB’s FDIC insurance assessments were $3.0 million and $3.0 million, respectively. The FDIC may impose special assessments in the future if it is deemed necessary to ensure the Deposit Insurance Fund ratio does not decline to a level that is close to zero or that could otherwise undermine public confidence in federal deposit insurance.

6 · Unconsolidated variable interest entities

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 sheet as of December 31, 2015 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for 2015 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to Hawaiian Electric. So 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 December 31, 2015, the Utilities had five PPAs for firm capacity and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kilowatts (kWs) or less who buy power from or sell power to the Utilities), none of which are currently required to be consolidated as VIEs. Approximately 90% of the firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and Hpower. Purchases from all IPPs were as follows:



Years ended December 31	2015		2014		2013
(in millions)
AES Hawaii	$	134	$	145	$	134
Kalaeloa	187		279		301
HEP	44		51		51
Hpower	66		66		61
Puna Geothermal Venture	29		45		49
Hawaiian Commercial & Sugar (HC&S)	8		15		13
Other IPPs	126		121		102
Total IPPs	$	594	$	722	$	711

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

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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.

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 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, Hawaiian Electric and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that Hawaiian Electric makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that Hawaiian Electric makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

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

Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in Kalaeloa by reason of the provisions of Hawaiian Electric’s PPA with Kalaeloa. However, management has concluded that Hawaiian Electric is not the primary beneficiary of Kalaeloa because Hawaiian Electric does not have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, Hawaiian Electric has not consolidated Kalaeloa in its consolidated financial statements. The energy payments paid by Hawaiian Electric will fluctuate as fuel prices change, however, the PPA does not currently expose Hawaiian Electric to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through Hawaiian Electric's ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of December 31, 2015, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $11 million.

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

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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 December 31, 2015, Hawaiian Electric’s accounts payable to AES Hawaii amounted to $12 million.

7 · Short-term borrowings

As of December 31, 2015 and 2014, HEI had $103 million and $119 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 1.1% and 0.7%, respectively, and Hawaiian Electric had no commercial paper outstanding.

As of December 31, 2015, HEI and Hawaiian Electric each maintained a syndicated credit facility of $150 million and $200 million, respectively. Both HEI and Hawaiian Electric had no borrowings under its facility during 2015 and 2014. None of the facilities are collateralized.

Credit agreements.

HEI. On April 2, 2014, HEI and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (HEI Facility). The HEI Facility increased HEI’s line of credit to $150 million from $125 million, extended the term of the facility to April 2, 2019, and provided improved pricing compared to HEI’s prior facility. Under the HEI Facility, draws would generally bear interest, based on HEI’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 137.5 basis points and annual fees on undrawn commitments of 20 basis points. The HEI Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the HEI Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. In addition, the HEI Consolidated Net Worth covenant, as defined in the original facility, was removed from the HEI Facility, leaving only one financial covenant (relating to HEI’s ratio of funded debt to total capitalization, each on a non-consolidated basis). Under the credit agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less (actual ratio of 17% as of December 31, 2015, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. HEI currently intends to terminate the HEI Facility if, and when, the proposed Merger closes. The HEI Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI).

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

Hawaiian Electric. On April 2, 2014, Hawaiian Electric and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (Hawaiian Electric Facility). The Hawaiian Electric Facility increased Hawaiian Electric’s line of credit to $200 million from $175 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. The Hawaiian Electric Facility provided improved pricing compared to its prior facility. Under the Hawaiian Electric Facility, draws would generally bear interest, based on Hawaiian Electric’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 125 basis points and annual fees on undrawn commitments of 17.5 basis points. The Hawaiian Electric Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the Hawaiian Electric Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. The Hawaiian Electric Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, Hawaiian Electric, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for Hawaii Electric Light and 42% for Maui Electric as of December 31, 2015, as calculated under the agreement)). In addition to customary defaults, Hawaiian Electric’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if Hawaiian Electric fails to maintain a “Consolidated

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Capitalization Ratio” (equity) of at least 35% (ratio of 57% as of December 31, 2015, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI. Under the proposed Merger Agreement, Hawaiian Electric will become a wholly-owned subsidiary of NEE. The terms of the Hawaiian Electric Facility are such that the proposed Merger would constitute a “Change in Control.” Hawaiian Electric has requested, and the financial institutions providing the Hawaiian Electric Facility have consented and agreed, that the proposed Merger shall not constitute a “Change in Control,” as defined in the credit agreement, provided that (i) the Merger is consummated and (ii) Hawaiian Electric becomes and remains a wholly-owned subsidiary of NEE.

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

8 · Long-term debt



December 31	2015		2014
(dollars in thousands)
Long-term debt of Utilities¹	$	1,286,546	$	1,206,546
HEI term loan LIBOR + .75%, due 2017	125,000		125,000
HEI senior note 4.41%, due 2016	75,000		75,000
HEI senior note 5.67%, due 2021	50,000		50,000
HEI senior note 3.99%, due 2023	50,000		50,000
	$	1,586,546	$	1,506,546


¹	See components of “Total long-term debt” and unamortized discount in Hawaiian Electric and subsidiaries’ Consolidated Statements of Capitalization.

As of December 31, 2015, the aggregate principal payments required on the Company’s long-term debt for 2016 through 2020 are $75 million in 2016, $125 million in 2017, $50 million in 2018, nil in 2019 and $96 million in 2020. As of December 31, 2015, the aggregate payments of principal required on the Utilities' long-term debt for 2016 through 2020 are nil in 2016 and 2017, $50 million in 2018, nil in 2019 and $96 million in 2020.

The HEI term loan and senior notes contain customary representation and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable). The HEI term loan and senior notes also contain provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement, expiring on April 2, 2019. Upon a change of control or certain dispositions of assets (as defined in the Master Note Purchase Agreement dated March 24, 2011), HEI is required to offer to prepay the senior notes.

The Utilities’ senior notes contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes of each and all of the utilities then outstanding becoming immediately due and payable) and provisions requiring the maintenance by Hawaiian Electric, and each of Hawaii Electric Light and Maui Electric, of certain financial ratios generally consistent with those in Hawaiian Electric’s existing amended revolving noncollateralized credit agreement, expiring on April 2, 2019 (See Note 7 of the Consolidated Financial Statements).

Changes in long-term debt.

HEI. On May 2, 2014, HEI entered into a loan agreement with The Bank of Tokyo-Mitsubishi UFJ, Ltd., Royal Bank of Canada and U.S. Bank, National Association (Loan Agreement), which agreement includes substantially the same financial covenant and customary conditions as the HEI credit agreement described above. On May 2, 2014, HEI drew a $125 million Eurodollar term loan for a term of two years and at a resetting interest rate ranging from 0.94% to 1.23% through December 31, 2015. The proceeds from the term loan were used to pay-off $100 million of 6.51% medium term notes at maturity on May 5, 2014, pay down maturing commercial paper and for general corporate purposes.

On October 8, 2015, (a) the Royal Bank of Canada assigned its loans under the Loan Agreement to The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank, National Association and (b) HEI, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and U.S. Bank, National Association entered into Amendment No. 1 to the Loan Agreement. Amendment No. 1, among other things, improved pricing on Eurodollar Borrowings under the Loan Agreement by 15 basis points and extended the maturity date of the

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Loan Agreement to October 6, 2017. It is currently contemplated that borrowings under the Loan Agreement will be repaid concurrently with the closing of the NEE Merger.

Hawaiian Electric. On October 15, 2015, Hawaiian Electric, Maui Electric and Hawaii Electric Light issued, through a private placement pursuant to separate note purchase agreements (the Note Purchase Agreements), $50 million, $5 million and $25 million, respectively, of Series 2015A taxable unsecured 5.23% senior notes due October 1, 2045 (collectively, the Notes). Hawaiian Electric is also a party as guarantor under the Note Purchase Agreements entered into by Maui Electric and Hawaii Electric Light.

All the proceeds of the Notes were used by the Utilities to finance their capital expenditures and for the reimbursement of funds used for the payment of capital expenditures.

The Note Purchase Agreements contain customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the Notes then outstanding becoming immediately due and payable). The Note Purchase Agreements also include provisions regarding the maintenance of financial ratios that are generally consistent with those in the Hawaiian Electric credit agreement described above.

The Notes may be prepaid in whole or in part at any time at the prepayment price of the principal amount plus a “Make-Whole Amount.” Each of the Note Purchase Agreements also (a) requires the Utilities to offer to prepay the Notes (without a Make-Whole Amount) in the event that there is a “change in control” as defined, and (b) permits the Utilities to offer to prepay Notes (without a Make-Whole Amount) in the event of certain sales of assets. Under the Note Purchase Agreements, the proposed merger of HEI and NEE will not be deemed a “change in control.”

On December 15, 2015, the Department issued, at par, Refunding Series 2015 SPRBs in the aggregate principal amount of $47 million with a maturity of January 1, 2025 and a fixed coupon interest rate of 3.25% and loaned the proceeds to Hawaiian Electric ($40 million), Hawaii Electric Light ($5 million) and Maui Electric ($2 million). Proceeds from the sale were applied, together with other funds provided by the Utilities, to redeem at par on December 30, 2015, the Refunding Series 2005A SPRBs (which had an original maturity of January 1, 2025 and a fixed coupon rate of 4.80%).

9 · Shareholders’ equity

Reserved shares. As of December 31, 2015, HEI had reserved a total of 13,296,268 shares of common stock for future issuance under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP), the HEI 2011 Nonemployee Director Stock Plan, the ASB 401(k) Plan and the 2010 Executive Incentive Plan.

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 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

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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.

For 2015, 2014 and 2013, the equity forward transactions did not have a material dilutive effect on HEI’s EPS.

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



	HEI Consolidated												Hawaiian Electric Consolidated
(in thousands)	Net unrealized gains (losses) on securities			Unrealized losses on derivatives			Retirement benefit plans			AOCI			AOCI -retirement benefit plans
Balance, December 31, 2012	$	10,761		$	(760	)	$	(36,424	)	$	(26,423	)	$	(970	)
Current period other comprehensive income (loss)	(14,424		)	235			23,862			9,673			1,578
Balance, December 31, 2013	(3,663		)	(525		)	(12,562		)	(16,750		)	608
Current period other comprehensive income (loss)	4,125			236			(14,989		)	(10,628		)	(563		)
Balance, December 31, 2014	462			(289		)	(27,551		)	(27,378		)	45
Current period other comprehensive income (loss)	(2,334		)	235			3,215			1,116			880
Balance, December 31, 2015	$	(1,872	)	$	(54	)	$	(24,336	)	$	(26,262	)	$	925

Reclassifications out of AOCI were as follows:



	Amount reclassified from AOCI
Years ended December 31	2015			2014			2013			Affected line item in the Statement of Income
(in thousands)
HEI consolidated
Net realized gains on securities	$	—		$	(1,715	)	$	(738	)	Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	235			236			235			Interest expense
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	22,465			11,344			23,280			See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(25,139		)	207,833			(222,595		)	See Note 10 for additional details
Total reclassifications	$	(2,439	)	$	217,698		$	(199,818	)
Hawaiian Electric consolidated
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	$	20,381		$	10,212		$	20,694		See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(25,139		)	207,833			(222,595		)	See Note 10 for additional details
Total reclassifications	$	(4,758	)	$	218,045		$	(201,901	)

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10 · Retirement benefits

Defined benefit plans. Substantially all of the employees of HEI and the Utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (HEI Pension Plan). Substantially all of the employees of ASB and its subsidiaries participated in the American Savings Bank Retirement Plan (ASB Pension Plan) until it was frozen on December 31, 2007. The HEI Pension Plan and the ASB Pension Plan (collectively, the Plans) are qualified, noncontributory defined benefit pension plans and include, in the case of the HEI Pension Plan, benefits for utility union employees determined in accordance with the terms of the collective bargaining agreements between the Utilities and the union. The Plans are subject to the provisions of ERISA. In addition, some current and former executives and directors of HEI and its subsidiaries participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.

The continuation of the Plans and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Supplemental Plan for directors has been frozen since 1996. The ASB Pension Plan was frozen as of December 31, 2007. The HEI Supplemental Executive Retirement Plan and ASB Supplemental Executive Retirement, Disability, and Death Benefit Plan (noncontributory, nonqualified, defined benefit plans) were frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the respective plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time, and HEI and ASB reserve the right to terminate their respective plans at any time. If a participating employer terminates its participation in the Plans, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plans, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plans are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

To determine pension costs for HEI and its subsidiaries under the Plans and the Supplemental Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified under “Defined benefit pension and other postretirement benefit plans information” below.

Postretirement benefits other than pensions. HEI and the Utilities provide eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (Hawaiian Electric Benefits Plan). Eligibility of employees and dependents is based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible to receive benefits from the HEI Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.

The executive death benefit plan was frozen on September 10, 2009 to participants and benefit levels as of that date. The electric discount was eliminated for management employees and retirees of Hawaiian Electric in August 2009, Hawaii Electric Light in November 2010, and Maui Electric in August 2010, and for bargaining unit employees and retirees on January 31, 2011 per the collective bargaining agreement.

The Company’s and Utilities' cost for OPEB has been adjusted to reflect the plan amendments, which reduced benefits and created prior service credits to be amortized over average future service of affected participants. The amortization of the prior service credit will reduce benefit costs over the next few years until the various credit bases are fully recognized. Each participating employer reserves the right to terminate its participation in the Hawaiian Electric Benefits Plan at any time.

Balance sheet recognition of the funded status of retirement plans. Employers must recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO), to calculate the funded status).

The PUC allowed the Utilities to adopt pension and OPEB tracking mechanisms in previous rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the Utilities’ tracking mechanisms, any actual costs determined in accordance with GAAP that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit

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expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.0 million and 1.2 million in 2015 and 2014, respectively) determined in accordance with GAAP will be recovered.

Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), which amounts include the prepaid pension asset, net of taxes, as well as other pension and OPEB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The Utilities have reclassified to a regulatory asset/(liability) charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge to AOCI of $(41) million pretax and $340 million pretax for 2015 and 2014, respectively).

Under the pension tracking mechanism, the Utilities’ are required to make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitations on deductible contributions imposed by the Internal Revenue Code.

The OPEB tracking mechanisms generally require the Utilities to make contributions to the OPEB trust in the amount of the actuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations.

Retirement benefits expense for the Utilities for 2015, 2014 and 2013 was $30 million, $32 million and $30 million, respectively.

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Defined benefit pension and other postretirement benefit plans information. The changes in the obligations and assets of the Company’s and Utilities' retirement benefit plans and the changes in AOCI (gross) for 2015 and 2014 and the funded status of these plans and amounts related to these plans reflected in the Company’s and Utilities' consolidated balance sheet as of December 31, 2015 and 2014 were as follows:



	2015						2014
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
HEI consolidated
Benefit obligation, January 1	$	1,847,228		$	219,209		$	1,446,291		$	176,099
Service cost	66,260			3,927			49,264			3,490
Interest cost	76,960			9,011			72,202			8,550
Actuarial losses (gains)	(124,239		)	(2,911		)	342,446			39,098
Benefits paid and expenses	(68,179		)	(7,696		)	(62,975		)	(8,028		)
Benefit obligation, December 31	1,798,030			221,540			1,847,228			219,209
Fair value of plan assets, January 1	1,266,060			180,332			1,186,669			179,330
Actual (loss) return on plan assets	(14,422		)	(2,866		)	81,123			9,149
Employer contributions	86,802			917			60,103			(257		)
Benefits paid and expenses	(66,966		)	(7,696		)	(61,835		)	(7,890		)
Fair value of plan assets, December 31	1,271,474			170,687			1,266,060			180,332
Accrued benefit asset (liability), December 31	$	(526,556	)	$	(50,853	)	$	(581,168	)	$	(38,877	)
Other assets	$	12,509		$	—		$	12,800		$	—
Defined benefit pension and other postretirement benefit plans liability	(539,065		)	(50,853		)	(593,968		)	(38,877		)
Accrued benefit asset (liability), December 31	$	(526,556	)	$	(50,853	)	$	(581,168	)	$	(38,877	)
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)	$	639,831		$	20,933		$	317,544		$	(21,722	)
Recognized during year – prior service credit (cost)	(4		)	1,793			(88		)	1,793
Recognized during year – net actuarial (losses) gains	(36,800		)	(1,796		)	(20,304		)	11
Occurring during year – net actuarial losses (gains)	(21,264		)	11,620			342,679			40,851
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	581,763			32,550			639,831			20,933
Cumulative impact of PUC D&Os	(538,784		)	(35,333		)	(592,291		)	(22,975		)
AOCI debit/(credit), December 31	$	42,979		$	(2,783	)	$	47,540		$	(2,042	)
Net actuarial loss (gain)	$	581,951		$	44,845		$	640,015		$	35,022
Prior service gain	(188		)	(12,295		)	(184		)	(14,089		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	581,763			32,550			639,831			20,933
Cumulative impact of PUC D&Os	(538,784		)	(35,333		)	(592,291		)	(22,975		)
AOCI debit/(credit), December 31	42,979			(2,783		)	47,540			(2,042		)
Income taxes (benefits)	(16,944		)	1,084			(18,742		)	795
AOCI debit/(credit), net of taxes (benefits), December 31	$	26,035		$	(1,699	)	$	28,798		$	(1,247	)

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	2015						2014
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Hawaiian Electric consolidated
Benefit obligation, January 1	$	1,690,777		$	211,760		$	1,320,810		$	169,579
Service cost	64,262			3,870			47,597			3,392
Interest cost	70,529			8,700			65,979			8,234
Actuarial losses (gains)	(114,286		)	(2,860		)	314,210			38,488
Benefits paid and expenses	(63,037		)	(7,598		)	(57,819		)	(7,933		)
Transfers	1,445			118			—			—
Benefit obligation, December 31	1,649,690			213,990			1,690,777			211,760
Fair value of plan assets, January 1	1,129,005			177,256			1,058,260			176,291
Actual (loss) return on plan assets	(10,646		)	(2,712		)	69,242			9,036
Employer contributions	85,139			864			58,948			(274		)
Benefits paid and expenses	(62,584		)	(7,598		)	(57,445		)	(7,797		)
Other	919			120			—			—
Fair value of plan assets, December 31	1,141,833			167,930			1,129,005			177,256
Accrued benefit asset (liability), December 31	$	(507,857	)	$	(46,060	)	$	(561,772	)	$	(34,504	)
Other liabilities (short-term)	(425		)	(518		)	(421		)	(460		)
Defined benefit pension and other postretirement benefit plans liability	(507,432		)	(45,542		)	(561,351		)	(34,044		)
Accrued benefit asset (liability), December 31	$	(507,857	)	$	(46,060	)	$	(561,772	)	$	(34,504	)
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)	$	595,103		$	20,090		$	295,973		$	(21,907	)
Recognized during year – prior service credit (cost)	(40		)	1,804			(62		)	1,804
Recognized during year – net actuarial losses	(33,371		)	(1,754		)	(18,459		)	—
Occurring during year – net actuarial losses (gains)	(20,574		)	11,345			317,651			40,193
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	541,118			31,485			595,103			20,090
Cumulative impact of PUC D&Os	(538,784		)	(35,333		)	(592,291		)	(22,975		)
AOCI debit/(credit), December 31	$	2,334		$	(3,848	)	$	2,812		$	(2,885	)
Net actuarial loss (gain)	$	541,071		$	43,784		$	595,017		$	34,192
Prior service cost (gain)	47			(12,299		)	86			(14,102		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	541,118			31,485			595,103			20,090
Cumulative impact of PUC D&Os	(538,784		)	(35,333		)	(592,291		)	(22,975		)
AOCI debit/(credit), December 31	2,334			(3,848		)	2,812			(2,885		)
Income taxes (benefits)	(908		)	1,497			(1,094		)	1,122
AOCI debit/(credit), net of taxes (benefits), December 31	$	1,426		$	(2,351	)	$	1,718		$	(1,763	)

The Company does not expect any plan assets to be returned to the Company during the calendar year 2016.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2015, 2014 and 2013.

The Pension Protection Act of 2006 (Pension Protection Act) signed into law on August 17, 2006, amended the Employee Retirement Income Security Act of 1974 (ERISA). Among other things, the Pension Protection Act changed the funding rules for qualified pension plans. On August 8, 2014, President Obama signed the latest change to the Pension Protection Act, the Highway and Transportation Funding Act of 2014 (HATFA). HATFA resulted in an increase of the Adjusted Funding Target Attainment Percentage (AFTAP) for benefit distribution purposes and eased funding requirements effective with the 2014 plan year (a plan sponsor could have elected to apply the provisions of HATFA to 2013, but the Company did not so elect). As a result, the minimum funding requirements for the HEI Retirement Plan under ERISA are less than the net periodic cost for 2014 and 2015. Nevertheless, to satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities contributed the net periodic cost in 2014 and 2015 and expect to contribute the net periodic cost in 2016.

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The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan. The HEI Retirement Plan met the threshold requirements in each of 2013, 2014 and 2015 so that the more conservative assumptions did not apply for either 2014 or 2015 and will not apply for 2016. Other factors could cause changes to the required contribution levels.

For purposes of calculating NPPC and NPBC, the Company and the Utilities have determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in the first year and 25% in each of years two through five – and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range restriction around the fair value of such assets (i.e., 85% to 115% of fair value).

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style.

The asset allocation of defined benefit retirement plans to equity and fixed income securities managers and related investment policy targets and ranges were as follows:



	Pension benefits¹							Other benefits²
					Investment policy							Investment policy
December 31	2015		2014		Target		Range	2015		2014		Target		Range
Assets held by category
Equity securities managers	70	%	73	%	70	%	65-75	70	%	72	%	70	%	65-75
Fixed income securities managers	30		27		30		25-35	30		28		30		25-35
	100	%	100	%	100	%		100	%	100	%	100	%


¹	Asset allocation for 2015 and 2014 is applicable to only HEI and the Utilities. In 2014, ASB revised its defined benefit pension plan asset allocation to a liability driven investment strategy and as of December 31, 2015 and 2014, nearly all of its pension assets were invested in fixed income securities.


²	Asset allocation for 2015 and 2014 is applicable to only HEI and the Utilities. ASB does not fund its other benefits.

See Note 16 for additional disclosures about the fair value of the retirement benefit plans’ assets.

The following weighted-average assumptions were used in the accounting for the plans:



	Pension benefits						Other benefits
December 31	2015		2014		2013		2015		2014		2013
Benefit obligation
Discount rate	4.60	%	4.22	%	5.09	%	4.57	%	4.17	%	5.03	%
Rate of compensation increase	3.5		3.5		3.5		NA		NA		NA
Net periodic pension/benefit cost (years ended)
Discount rate	4.22		5.09		4.13		4.17		5.03		4.07
Expected return on plan assets¹	7.75		7.75		7.75		7.75		7.75		7.75
Rate of compensation increase	3.5		3.5		3.5		NA		NA		NA

NA Not applicable

¹ For 2015, HEI's and utilities' plan assets only. For 2015, ASB's expected return on plan assets was 4.22%.

The Company and the Utilities based their selection of an assumed discount rate for 2016 NPPC, NPBC and December 31, 2015 disclosure on a cash flow matching analysis that utilized bond information provided by Bloomberg for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2015. In selecting the expected rate of return on plan assets for 2016 NPPC and NPBC: a) HEI and the Utilities considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations, industry and corporate surveys and the past performance of the plans’ assets in selecting 7.75% and b) ASB considered its revised asset allocation in 2014 to a liability

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driven investment strategy in selecting 4.8%, which is consistent with the assumed discount rate as of December 31, 2015 with a 20 basis point active manager premium.

The Company and the Utilities adopted mortality tables published in October 2014 by the Society of Actuaries as its mortality assumptions as of December 31, 2014. The use of the RP-2014 Tables and the Mortality Improvement Scale MP-2014 had a significant effect on the Company’s and the Utilities’ benefit obligations and increased their costs and required contributions for 2015. The Company and the Utilities adopted revised mortality tables for their mortality assumptions as of December 31, 2015 (based on information published by the Society of Actuaries in October 2015), the use of which lowered obligations of the Company and Utilities as of December 31, 2015 and will lower their costs and required contributions in 2016.

As of December 31, 2015, the assumed health care trend rates for 2016 and future years were as follows: medical, 8%, grading down to 5% for 2028 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2014, the assumed health care trend rates for 2015 and future years were as follows: medical, 7.25%, grading down to 5% for 2024 and thereafter; dental, 5%; and vision, 4%. Medicare Advantage reimbursements are expected to phase out by 2016. For post age 65, the medical trend is 3% higher than pre-65 for 2015 to reflect anticipated increases above the ordinary medical trend rates. Starting in 2016, pre-65 and post-65 health care trend rates are assumed to be the same .

The components of NPPC and NPBC were as follows:



	Pension benefits									Other benefits
(in thousands)	2015			2014			2013			2015			2014			2013
HEI consolidated
Service cost	$	66,260		$	49,264		$	56,405		$	3,927		$	3,490		$	4,306
Interest cost	76,960			72,202			64,788			9,011			8,550			7,569
Expected return on plan assets	(88,554		)	(81,355		)	(72,537		)	(11,664		)	(10,902		)	(10,147		)
Amortization of net prior service (gain) cost	4			88			(97		)	(1,793		)	(1,793		)	(1,793		)
Amortization of net actuarial losses (gains)	36,800			20,304			38,438			1,796			(11		)	1,602
Net periodic pension/benefit cost	91,470			60,503			86,997			1,277			(666		)	1,537
Impact of PUC D&Os	(40,011		)	(13,324		)	(38,104		)	(240		)	1,976			(1,458		)
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os)	51,459			47,179			48,893			1,037			1,310			79
Hawaiian Electric consolidated
Service cost	$	64,262		$	47,597		$	54,482		$	3,870		$	3,392		$	4,163
Interest cost	70,529			65,979			59,119			8,700			8,234			7,288
Expected return on plan assets	(82,541		)	(72,661		)	(64,551		)	(11,495		)	(10,739		)	(10,002		)
Amortization of net prior service (gain) cost	40			62			(464		)	(1,804		)	(1,804		)	(1,803		)
Amortization of net actuarial losses	33,371			18,459			34,597			1,754			—			1,544
Net periodic pension/benefit cost	85,661			59,436			83,183			1,025			(917		)	1,190
Impact of PUC D&Os	(40,011		)	(13,324		)	(38,104		)	(240		)	1,976			(1,458		)
Net periodic pension/benefit cost (adjusted for impact of PUC D&Os)	$	45,650		$	46,112		$	45,079		$	785		$	1,059		$	(268	)

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefit plans that will be amortized from AOCI or regulatory assets into NPPC and NPBC during 2016 is as follows:



	HEI consolidated						Hawaiian Electric consolidated
(in millions)	Pension benefits			Other benefits			Pension benefits		Other benefits
Estimated prior service cost (credit)	$	(0.1	)	$	(1.8	)	$	—	$	(1.8	)
Net actuarial loss	23.9			1.1			21.8		1.1

The Company recorded pension expense of $35 million, $32 million and $34 million and OPEB expense of $0.9 million, $1.2 million and $0.4 million in 2015, 2014 and 2013, respectively, and charged the remaining amounts primarily to electric utility plant. The Utilities recorded pension expense of $29 million, $31 million and $30 million and OPEB expense of $0.7 million, $1.0 million and nil in 2015, 2014 and 2013, respectively, and charged the remaining amounts primarily to electric utility plant.

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The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2015, for the Company, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.2 million and the accumulated postretirement benefit obligation (APBO) by $3.8 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the APBO by $4.4 million. As of December 31, 2015, for the Utilities, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.2 million and the APBO by $3.7 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the APBO by $4.3 million.

HEI consolidated. The defined benefit pension plans with accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), in excess of plan assets as of December 31, 2015 and 2014, had aggregate ABOs of $1.5 billion and $1.5 billion, respectively, and plan assets of $1.2 billion and $1.2 billion, respectively. The defined benefit pension plans with PBOs in excess of plan assets as of December 31, 2015, had aggregate PBOs of $1.7 billion and plan assets of $1.2 billion. The defined benefit pension plans with PBOs in excess of plan assets as of December 31, 2014, had aggregate PBOs of $1.7 billion and plan assets of $1.2 billion. As of December 31, 2015 and 2014, the other postretirement benefit plans shown in the table above had ABOs in excess of plan assets.

The Company estimates that the cash funding for the qualified defined benefit pension plans in 2016 will be $65 million, which should fully satisfy the minimum required contributions to those plans, including requirements of the Utilities’ pension tracking mechanisms and the Plan’s funding policy. The Company's current estimate of contributions to its other postretirement benefit plans in 2016 is $49,000.

As of December 31, 2015, the benefits expected to be paid under all retirement benefit plans in 2016, 2017, 2018, 2019, 2020 and 2021 through 2025 amount to $80 million, $84 million, $87 million, $91 million, $96 million and $547 million, respectively.

Hawaiian Electric consolidated. The defined benefit pension plans with ABOs in excess of plan assets as of December 31, 2015 and 2014, had aggregate ABOs of $1.4 billion and $1.5 billion, respectively, and plan assets of $1.1 billion and $1.1 billion, respectively. All the defined benefit pension plans shown in the table above had PBOs in excess of plan assets as of December 31, 2015 and 2014. As of December 31, 2015 and 2014, the other postretirement benefit plan shown in the table above had ABOs in excess of plan assets.

The Utilities estimate that the cash funding for the qualified defined benefit pension plan in 2016 will be $64 million, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanisms and the Plan’s funding policy. The Utilities' current estimate of contributions to its other postretirement benefit plans in 2016 is $23,000.

As of December 31, 2015, the benefits expected to be paid under all retirement benefit plans in 2016, 2017, 2018, 2019, 2020 and 2021 through 2025 amounted to $74 million, $77 million, $80 million, $84 million, $88 million and $501 million, respectively.

Defined contribution plans information. The ASB 401(k) Plan is a defined contribution plan, which includes a discretionary employer profit sharing contribution by ASB (AmeriShare) and a matching contribution by ASB on the first 4% of employee deferrals (AmeriMatch).

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

For 2015, 2014 and 2013, the Company’s expense for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was $6 million, $5 million and $5 million, respectively, and cash contributions were $5 million, $5 million and $4 million, respectively. The Utilities’ expense for its defined contribution pension plan under the HEIRSP Plan for 2015, 2014 and 2013 was $1.5 million, $0.9 million and $0.6 million, respectively.

11 · 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

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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 December 31, 2015, approximately 3.5 million shares remained available for future issuance under the terms of the EIP, assuming recycling of shares withheld to satisfy minimum statutory tax liabilities relating to EIP awards, including an estimated 0.5 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).

As of May 11, 2010 (when the 2010 Equity and Incentive Plan became effective), no new awards could be granted under the 1987 Stock Option and Incentive Plan, as amended (SOIP). Since by March 2015 all of the shares of common stock for the outstanding SOIP grants and awards were issued or such grants and awards had expired, the remaining shares registered under the SOIP were deregistered and delisted.

For the SARs that were outstanding under the SOIP, the exercise price of each SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. SARs and related dividend equivalents issued in the form of stock awards generally became exercisable in installments of 25% each year for four years, and expired if not exercised ten years from the date of the grant. SARs compensation expense was recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each SAR grant was calculated on the date of grant using a Binomial Option Pricing Model. There were no outstanding SARs as of December 31, 2015.

The restricted shares that had been issued under the 2010 Equity and Incentive Plan became unrestricted in four equal annual increments on the anniversaries of the grant date and were forfeited to the extent they had not become unrestricted for terminations of employment during the vesting period, except accelerated vesting was provided for terminations by reason of death, disability and termination without cause. Restricted shares compensation expense had been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted shares were paid quarterly in cash. There were no outstanding restricted shares as of December 31, 2015.

Restricted stock units awarded under the 2010 Equity and Incentive Plan in 2015, 2014, 2013 and 2012 will vest and be issued in unrestricted stock in four equal annual increments on the anniversaries of the grant date and are forfeited to the extent they have not become vested for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Restricted stock units expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividend equivalent rights are accrued quarterly and are paid at the end of the restriction period when the associated restricted stock units vest.

Stock performance awards granted under the 2013-2015 and 2014-2016 long-term incentive plans (LTIPs) entitle the grantee to shares of common stock with dividend equivalent rights once service conditions and performance conditions are satisfied at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the performance period, except that pro-rata participation is provided for terminations due to death, disability and retirement based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the stock performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.

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 December 31, 2015, there were 141,044 shares remaining available for future issuance under the 2011 Director Plan.

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



(in millions)	2015		2014		2013
HEI consolidated
Share-based compensation expense¹	$	6.5	$	9.3	$	7.8
Income tax benefit	2.3		3.4		2.8
Hawaiian Electric consolidated
Share-based compensation expense¹	1.9		3.1		2.3
Income tax benefit	0.7		1.2		0.9


¹	$0.15 million, $0.16 million and $0.11 million of this share-based compensation expense was capitalized in 2015, 2014 and 2013, respectively.

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Stock awards. HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:



(dollars in millions)	2015		2014		2013
Shares granted	28,246		33,170		33,184
Fair value	$	0.8	$	0.8	$	0.8
Income tax benefit	0.3		0.3		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 grant date.

Nonqualified stock options. Information about HEI’s NQSOs was as follows:



	2013
	Shares		(1)
Outstanding, January 1	14,000		$	20.49
Exercised	(14,000	)	20.49
Outstanding, December 31	—		$	—


(1)	Weighted-average exercise price

As of December 31, 2015, there were no NQSOs outstanding.

NQSO activity and statistics were as follows:



(in thousands)	2013
Cash received from exercise	$	287
Intrinsic value of shares exercised ¹	128
Tax benefit realized for the deduction of exercises	50


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

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



	2015				2014				2013
	Shares		(1)		Shares		(1)		Shares	(1)
Outstanding, January 1	80,000		$	26.18	164,000		$	26.12	164,000	$	26.12
Granted	—		—		—		—		—	—
Exercised	(80,000	)	26.18		(22,000	)	26.18		—	—
Forfeited	—		—		(62,000	)	26.02		—	—
Expired	—		—		—		—		—	—
Outstanding, December 31	—		$	—	80,000		$	26.18	164,000	$	26.12
Exercisable, December 31	—		$	—	80,000		$	26.18	164,000	$	26.12


(1)	Weighted-average exercise price

As of December 31, 2015, there were no SARs outstanding.

SARs activity and statistics were as follows:



(in thousands)	2015		2014		2013
Intrinsic value of shares exercised ¹	$	502	$	29	$	—
Tax benefit realized for the deduction of exercises	82		11		—


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

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



	2014				2013
	Shares		(1)		Shares		(1)
Outstanding, January 1	4,503		$	22.21	9,005		$	22.21
Granted	—		—		—		—
Vested	(4,503	)	22.21		(4,502	)	22.21
Forfeited	—		—		—		—
Outstanding, December 31	—		$	—	4,503		$	22.21


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

For 2014 and 2013, total restricted stock vested had a grant-date fair value of $0.1 million and $0.1 million, respectively, and the tax benefits realized for the tax deductions related to restricted stock awards were nil for 2014 and 2013.

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



	2015					2014					2013
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	261,235			$	25.77	288,151			$	25.17	315,094			$	22.82
Granted	85,772			33.69		117,786			25.17		111,231			26.88
Vested	(102,173		)	25.67		(144,702		)	24.09		(118,885		)	20.48
Forfeited	(34,200		)	27.09		—			—		(19,289		)	25.62
Outstanding, December 31	210,634			$	28.82	261,235			$	25.77	288,151			$	25.17
Total weighted-average grant-date fair value of shares granted ($ millions)	$	2.9				$	3.0				$	3.0


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

For 2015, 2014 and 2013, total restricted stock units and related dividends that vested had a fair value of $3.7 million, $4.1 million and $3.7 million, respectively, and the related tax benefits were $1.1 million, $1.2 million and $0.9 million, respectively.

As of December 31, 2015, there was $3.9 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.5 years.

Long-term incentive plan payable in stock. The 2013-2015 LTIP and 2014-2016 LTIP provide for performance awards under the original EIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2013-2015 LTIP and 2014-2016 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on average common equity (ROACE), Hawaiian Electric consolidated net income, Hawaiian Electric consolidated ROACE and ASB net income - all based on the applicable three-year averages, and ASB return on assets relative to performance peers. The 2015-2017 LTIP provides for performance awards payable in cash, and thus, is not included in the tables below.

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



	2015					2014					2013
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	257,956			$	28.45	232,127			$	32.88	239,256			$	29.12
Granted	—			—		97,524			22.95		91,038			32.69
Vested (settled or lapsed)	(75,915		)	30.71		(70,189		)	35.46		(87,753		)	22.45
Forfeited	(19,541		)	26.25		(1,506		)	28.32		(10,414		)	32.72
Outstanding, December 31	162,500			$	27.66	257,956			$	28.45	232,127			$	32.88
Total weighted-average grant-date fair value of shares granted ($ millions)	$	—				$	2.2				$	3.0


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

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

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



	2014			2013
Risk-free interest rate	0.66		%	0.38		%
Expected life in years	3			3
Expected volatility	17.8		%	19.4		%
Range of expected volatility for Peer Group	12.4% to 23.3%			12.4% to 25.3%
Grant date fair value (per share)	$	22.95		$	32.69

For 2015, 2014 and 2013, total vested LTIP awards linked to TRS and related dividends had a fair value of nil, nil and $2.2 million, respectively, and the related tax benefits were nil, nil and $0.9 million, respectively. For 2015 and 2014, all of the shares vested (which were granted at target level based on the satisfaction of TRS performance) for the 2012-2014 LTIP and 2011-2013 LTIP lapsed. Of the 87,753 shares vested and granted (at target level based on the satisfaction of TRS performance) for the 2010-2012 LTIP, the HEI Compensation Committee approved settlement of 70,205 shares of HEI common stock in February 2013 (17,548 of the vested shares lapsed).

As of December 31, 2015, there was $0.5 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1 year.

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



	2015					2014					2013
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	364,731			$	26.01	296,843			$	26.14	247,175			$	25.04
Granted	—			—		129,603			25.18		120,399			26.89
Vested and settled	(121,249		)	26.05		(65,089		)	24.95		(18,280		)	18.95
Increase above target (cancelled)	3,412			26.89		4,949			26.70		(41,599		)	24.97
Forfeited	(24,247		)	25.82		(1,575		)	26.07		(10,852		)	26.20
Outstanding, December 31	222,647			$	26.02	364,731			$	26.01	296,843			$	26.14
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)	$	—				$	3.3				$	3.2


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

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For 2015, 2014 and 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $4.7 million, $1.9 million and $0.6 million, respectively, and the related tax benefits were $1.8 million, $0.8 million and $0.2 million, respectively.

As of December 31, 2015, there was $1.0 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1 year.

12 · Income taxes

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



	HEI consolidated								Hawaiian Electric consolidated
Years ended December 31	2015		2014			2013			2015			2014			2013
(in thousands)
Federal
Current (1)	$	44,343	$	(8,959	)	$	(295	)	$	—		$	1,108		$	1,313
Deferred (1)	36,664		91,412			73,473			68,757			68,775			58,024
Deferred tax credits, net	318		—			224			318			—			224
	81,325		82,453			73,402			69,075			69,883			59,561
State
Current (1)	2,402		(5,793		)	(630		)	(1,048		)	(9,436		)	(3,720		)
Deferred (1)	4,768		12,813			6,672			6,869			14,172			6,483
Deferred tax credits, net	4,526		6,106			6,793			4,526			6,106			6,793
	11,696		13,126			12,835			10,347			10,842			9,556
Total	$	93,021	$	95,579		$	86,237		$	79,422		$	80,725		$	69,117


(1)	HEI Consolidated amounts for 2014 and 2013 have been updated to reflect the first quarter 2015 adoption of ASU No. 2014-01. See Note 1 for a discussion of the adoption of ASU No. 2014-01

A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the consolidated statements of income was as follows:



	HEI consolidated									Hawaiian Electric consolidated
Years ended December 31	2015			2014			2013			2015			2014			2013
(in thousands)
Amount at the federal statutory income tax rate (1)	$	89,176		$	92,959		$	87,442		$	75,996		$	77,126		$	67,914
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit (1)	8,097			9,073			8,667			6,726			7,047			6,211
Other, net (1)	(4,252		)	(6,453		)	(9,872		)	(3,300		)	(3,448		)	(5,008		)
Total	$	93,021		$	95,579		$	86,237		$	79,422		$	80,725		$	69,117
Effective income tax rate	36.5		%	36.0		%	34.5		%	36.6		%	36.6		%	35.6		%


(1)	HEI Consolidated amounts for 2014 and 2013 have been updated to reflect the first quarter 2015 adoption of ASU No. 2014-01. See Note 1 for a discussion of the adoption of ASU No. 2014-01.

The Company's effective tax rate increased in 2015 and 2014 compared to 2013 primarily due to the increase in nondeductible merger costs. The Company's effective tax rate increase in 2014 compared to 2013 was also due to the $2.7 million out-of-period income tax benefits recognized in 2013 (see “Out-of-period income tax benefit” below). The Utilities' effective tax rate increased in 2014 compared to 2013 primarily due to the out-of-period income tax benefits.

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



	HEI consolidated				Hawaiian Electric consolidated
December 31	2015		2014		2015		2014
(in thousands)
Deferred tax assets
Net operating loss	$	—	$	—	$	37,283	$	51,936
Other (1)	64,870		56,526		20,238		17,663
Total deferred tax assets	64,870		56,526		57,521		69,599
Deferred tax liabilities
Property, plant and equipment related	492,441		448,723		489,884		446,259
Repairs deduction	104,081		86,408		104,081		86,408
Regulatory assets, excluding amounts attributable to property, plant and equipment	34,261		33,795		34,261		33,795
Deferred RAM and RBA revenues	26,400		32,889		26,400		32,889
Retirement benefits	42,006		25,336		44,991		28,758
Other (1)	46,558		62,945		12,710		14,929
Total deferred tax liabilities	745,747		690,096		712,327		643,038
Net deferred income tax liability	$	680,877	$	633,570	$	654,806	$	573,439


(1)	HEI consolidated and Hawaiian Electric consolidated amounts as of December 31, 2014 have been updated to reflect the Company's adoption of ASU No. 2014-01 and the Utilities' adoption of ASU No. 2015-17, respectively. See Note 1 for a discussion of the Company's adoption of ASU No. 2014-01 and the Utilities’ adoption of ASU No. 2015-17.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company and the Utilities will realize substantially all of the benefits of the deferred tax assets. As of December 31, 2015, the valuation allowance for deferred tax benefits is not significant. In 2015, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation that was retroactively enacted in the Protecting Americans from Tax Hikes (PATH) Act of 2015. The Utilities are included in the consolidated federal and Hawaii income tax returns of HEI and are subject to the provisions of HEI’s tax sharing agreement, which determines each subsidiary’s (or subgroup's) income tax return liabilities and refunds on a standalone basis as if it filed a separate return (or subgroup consolidated return). Consequently, although HEI consolidated does not anticipate any unutilized net operating loss (NOL) as of December 31, 2015, standalone Hawaiian Electric consolidated expects an unutilized NOL for federal tax purposes in accordance with the HEI tax sharing agreement. The Hawaiian Electric deferred tax asset associated with this NOL as of December 31, 2015 has decreased from December 31, 2014 as shown above.

HEI consolidated. In 2014 and 2013, credit adjustments to interest expense on income taxes was reflected in “Interest expense – other than on deposit liabilities and other bank borrowings” in the amount of $1.7 million and $0.3 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the Internal Revenue Service (IRS). As of December 31, 2015 and 2014, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and dividends payable” was $0.1 million and nil, respectively. As of December 31, 2015, the total amount of liability for uncertain tax positions was $3.6 million.

Hawaiian Electric consolidated. In 2014 and 2013, credit adjustments to interest expense on income taxes was reflected in “Interest and other charges” in the amount of $0.7 million and $0.3 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 2015 and 2014, the total amount of accrued interest related to uncertain tax positions was $0.1 million. As of December 31, 2015, the total amount of liability for uncertain tax positions was $3.6 million.

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The changes in total unrecognized tax benefits were as follows:



	HEI consolidated								Hawaiian Electric consolidated
(in millions)	2015		2014			2013			2015		2014			2013
Unrecognized tax benefits, January 1	$	—	$	0.9		$	0.8		$	—	$	0.5		0.4
Additions based on tax positions taken during the year	—		—			—			—		—			—
Reductions based on tax positions taken during the year	—		—			—			—		—			—
Additions for tax positions of prior years	3.6		0.1			0.5			3.6		0.1			0.5
Reductions for tax positions of prior years	—		—			(0.4		)	—		—			(0.4		)
Settlements			(1.0		)	—			—		(0.6		)	—
Lapses of statute of limitations	—		—			—			—		—			—
Unrecognized tax benefits, December 31	$	3.6	$	—		$	0.9		$	3.6	$	—		$	0.5

As of December 31, 2015, the disclosures above present the Company’s and the Utilities' accruals for potential tax liabilities and related interest. Based on information currently available, the Company and the Utilities believe these accruals have adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

In 2014, the IRS completed its examination of the Company’s federal income tax returns for tax years 2010 and 2011. In October 2014, the Company and the IRS reached an agreement on all adjustments, primarily related to depreciation , resulting in no material impacts to the income statement. Tax years 2011 through 2014 remain subject to examination by the Department of Taxation of the State of Hawaii.

Out-of-period income tax benefit. During 2013, the Company recorded a $3.1 million (including $2.7 million related to the Utilities) out-of-period income tax benefit, resulting primarily from the reversal of deferred tax liabilities due to errors in the amount of book over tax basis differences in plant and equipment. Management concluded that this out-of-period adjustment was not material to either the current or any prior period financial statements.

Recent tax developments. The Utilities adopted the safe harbor guidelines with respect to network (transmission and distribution) assets in 2011 and, in June 2013, the IRS released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. Management has adopted a method believed to be consistent with this guidance in its 2014 tax return filed in September 2015.

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

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

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

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13 · Cash flows



Years ended December 31	2015		2014		2013
(in millions)
Supplemental disclosures of cash flow information
HEI consolidated
Interest paid to non-affiliates	$	83	$	84	$	85
Income taxes paid	75		47		18
Income taxes refunded	55		24		4
Hawaiian Electric consolidated
Interest paid to non-affiliates	61		61		59
Income taxes paid	13		6		6
Income taxes refunded	12		8		32
Supplemental disclosures of noncash activities
HEI consolidated
Property, plant and equipment-unpaid invoices and accruals (investing)	5		43		(12		)
Common stock dividends reinvested in HEI common stock (financing) ¹	—		—		24
Loans transferred from held for investment to held for sale (investing to operating)	—		—		25
Real estate acquired in settlement of loans (investing)	1		3		4
Real estate transferred from property, plant and equipment to other assets held-for-sale (investing)	5		—		—
Obligations to fund low income housing investments, net (operating)	4		14		1
Hawaiian Electric consolidated
Electric utility property, plant and equipment
AFUDC-equity (operating)	7		7		6
Estimated fair value of noncash contributions in aid of construction (investing)	3		3		5
Unpaid invoices and accruals (investing)	5		40		(12		)
Refinancing of long-term debt (financing)	47		—		—


¹	The amounts shown represents common stock dividends reinvested in HEI common stock under the HEI DRIP in noncash transactions.

14 · Regulatory restrictions on net assets

As of December 31, 2015, the Utilities could not transfer approximately $711 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.

ASB is required to notify the FRB and OCC prior to making any capital distribution (including dividends) to HEI (through ASB Hawaii). Generally, the FRB and OCC may disapprove or deny ASB’s request to make a capital distribution if the proposed distribution will cause ASB to become undercapitalized, or the proposed distribution raises safety and soundness concerns, or the proposed distribution violates a prohibition contained in any statute, regulation or agreement between ASB and the OCC. As of December 31, 2015, ASB could transfer approximately $141 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.

HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

15 · Significant group concentrations of credit risk

Most of the Company’s business activity is with customers located in the State of Hawaii.

The Utilities are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. The Utilities provide the only electric public utility service on the islands they serve. The Utilities grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

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Most of ASB’s financial instruments are based in the State of Hawaii, except for the investment securities it owns. Substantially all real estate loans receivable are collateralized by real estate in Hawaii. ASB’s policy is to require mortgage insurance on all real estate loans with a loan to appraisal ratio in excess of 80% at origination.

16 · 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:


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.

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

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

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

Investment securities. The fair value of ASB’s investment securities is determined quarterly through pricing obtained from independent third-party pricing services or from brokers not affiliated with the trade. Non-binding broker quotes are infrequent and generally occur for new securities that are settled close to the month-end pricing date. The third-party pricing vendors the Company uses for pricing its securities are reputable firms that provide pricing services on a global basis and have processes in place to ensure quality and control. The third-party pricing services use a variety of methods to determine the fair value of securities that fall under Level 2 of the Company’s fair value measurement hierarchy. Among the considerations are quoted

175

prices for similar securities in an active market, yield spreads for similar trades, adjustments for liquidity, size, collateral characteristics, historic and generic prepayment speeds, and other observable market factors.

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

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

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

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

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

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

Time deposits. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

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

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

176

Interest rate lock commitments (IRLCs). The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.

Forward sales commitments. To be announced (TBA) mortgage-backed securities forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined using quoted prices in the market place that are observable and are classified as Level 2 measurements.

The following table presents the carrying amount, fair value, and placement in the fair value hierarchy of the Company’s financial instruments. For stock in Federal Home Loan Bank, 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
(in thousands)	Carrying or notional amount		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total
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	8,444		—		—		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	1,586,546		—		1,669,087		—		1,669,087
The Utilities' long-term debt, net (included in amount above)	1,286,546		—		1,363,766		—		1,363,766
Derivative liabilities	23,269		15		15		—		30
December 31, 2014
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	550,394		—		550,394		—		550,394
Stock in Federal Home Loan Bank	69,302		—		69,302		—		69,302
Loans receivable, net	4,397,457		—		8,713		4,570,109		4,578,822
Mortgage servicing rights	11,540		—		—		14,504		14,504
Bank-owned life insurance	134,115		—		134,115		—		134,115
Derivative assets	30,120		—		398		—		398
Financial liabilities
Deposit liabilities	4,623,415		—		4,623,773		—		4,623,773
Short-term borrowings—other than bank	118,972		—		118,972		—		118,972
Other bank borrowings	290,656		—		298,837		—		298,837
Long-term debt, net—other than bank	1,506,546		—		1,622,736		—		1,622,736
The Utilities' long-term debt, net (included in amount above)	1,206,546		—		1,313,893		—		1,313,893
Derivative liabilities	32,043		71		43		—		114

177

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



December 31	2015						2014
	Fair value measurements using						Fair value measurements using
(in thousands)	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
Money market funds (“other” segment)	$	—	$	10	$	—	$	—	$	10	$	—
Available-for-sale investment securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	607,689	$	—	$	—	$	430,834	$	—
U.S. Treasury and federal agency obligations	—		212,959		—		—		119,560		—
	$	—	$	820,648	$	—	$	—	$	550,394	$	—
Derivative assets ¹
Interest rate lock commitments	$	—	$	384	$	—	$	—	$	393	$	—
Forward commitments	—		1		—		—		5		—
	$	—	$	385	$	—	$	—	$	398	$	—
Derivative liabilities ¹
Interest rate lock commitments	$	—	$	—	$	—	$	—	$	3	$	—
Forward commitments	15		15		—		71		40		—
	$	15	$	15	$	—	$	71	$	43	$	—


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

There were no transfers of financial assets and liabilities between Level 1 and Level 2 of the fair value hierarchy during the years ended December 31, 2015 and 2014.

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 using
(in thousands)	Balance		Level 1		Level 2		Level 3
December 31, 2015
Loans	$	178	$	—	$	—	$	178
Real estate acquired in settlement of loans	1,030		—		—		1,030
December 31, 2014
Loans	2,445		—		—		2,445
Real estate acquired in settlement of loans	288		—		—		288
Mortgage servicing rights	1,240		—		—		1,240

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

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



					Significant unobsetvable input value (1)
(dollars in thousands)	Fair value		Valuation technique	Significant unobservable input	Range	Weighted Average
December 31, 2015
Residential loans	$	50	Fair value of property or collateral	Appraised value less 7% selling cost		N/A (2)
Home equity lines of credit	128		Fair value of property or collateral	Appraised value less 7% selling cost		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%	100%
December 31, 2014
Residential loans	$	2,297	Fair value of property or collateral	Appraised value less 7% selling cost	39-99%	83%
Home equity lines of credit	3		Fair value of property or collateral	Appraised value less 7% selling cost		N/A (2)
Commercial loans	145		Fair value of property or collateral	Fair value of business assets		N/A (2)
Total loans	$	2,445

Real estate acquired in settlement of loans	$	288	Fair value of property or collateral	Appraised value less 7% selling cost	100%	100%

Mortgage servicing rights	$	1,240	Discounted cash flow	Prepayment speed	6.7-22.4%	12.2%
				Discount rate	9.6%	9.6%


(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.

179

Retirement benefit plans

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



	Pension benefits									Other benefits
				Fair value measurements using									Fair value measurements using
(in millions)	December 31			Level 1		Level 2		Level 3		December 31			Level 1		Level 2		Level 3
2015
Equity securities	$	640		$	640	$	—	$	—	$	92		$	92	$	—	$	—
Equity index funds	119			119		—		—		17			17		—		—
Fixed income securities and public mutual funds	425			85		340		—		48			41		7		—
Pooled and mutual funds and other	84			3		81		—		14			4		10		—
Total	$	1,268		$	847	$	421	$	—	$	171		$	154	$	17	$	—
Cash, receivables and payables, net	3									—
Fair value of plan assets	$	1,271								$	171
2014
Equity securities	$	649		$	649	$	—	$	—	$	99		$	99	$	—	$	—
Equity index funds	132			132		—		—		19			19		—		—
Fixed income securities and public mutual funds	428			121		307		—		49			43		6		—
Pooled and mutual funds and other	82			1		81		—		14			3		11		—
Total	1,291			$	903	$	388	$	—	181			$	164	$	17	$	—
Cash, receivables and payables, net	(25		)							(1		)
Fair value of plan assets	$	1,266								$	180

The fair values of the financial instruments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset or liability. Those judgments are developed by the Company based on the best information available in the circumstances.

In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of ASU No. 2009-12, “Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for which the investment does not have a readily determinable fair value, using net asset value per share or its equivalent as a practical expedient.

The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2015 and 2014.

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

Fixed income securities and pooled and mutual funds and other (Level 2). Fixed income securities, other than those issued by the U.S. Treasury, are valued based on yields currently available on comparable securities of issuers with similar credit ratings. Pooled and mutual funds include commingled equity funds and other closed funds (some of which are not open to public investment) and are valued at the net asset value per share. “Other” consists primarily of fixed income securities purchased as part of the retirement benefit plans’ cash management process.

180

17 · Other related-party transactions

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:



	HEI consolidated						Hawaiian Electric consolidated
(in millions)	2015		2014		2013		2015		2014		2013
HMSA costs	$	30	$	25	$	23	$	23	$	20	$	18
HMSA expense*	21		18		17		14		13		12
HDS costs	3		3		3		2		2		2
HDS expense*	2		2		2		1		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).

181

18 · Quarterly information (unaudited)

Selected quarterly information was as follows:



	Quarters ended								Years ended
(in thousands, except per share amounts)	March 31		June 30		Sept. 30		Dec. 31		December 31
HEI consolidated
2015
Revenues	$	637,862	$	623,912	$	717,176	$	624,032	$	2,602,982
Operating income	69,506		72,730		97,095		83,222		322,553
Net income	32,339		35,491		51,144		42,793		161,767
Net income for common stock	31,866		35,018		50,673		42,320		159,877
Basic earnings per common share ¹	0.31		0.33		0.47		0.39		1.50
Diluted earnings per common share ²	0.31		0.33		0.47		0.39		1.50
Dividends per common share	0.31		0.31		0.31		0.31		1.24
Market price per common share ³
High	34.86		32.58		31.28		30.29		34.86
Low	31.75		29.62		27.02		27.45		27.02
2014
Revenues	$	783,749	$	798,657	$	867,096	$	790,040	$	3,239,542
Operating income	89,214		83,183		92,036		68,167		332,600
Net income	46,260		41,754		48,279		33,726		170,019
Net income for common stock	45,787		41,281		47,808		33,253		168,129
Basic earnings per common share ¹	0.45		0.41		0.47		0.32		1.65
Diluted earnings per common share ²	0.45		0.41		0.46		0.32		1.63
Dividends per common share	0.31		0.31		0.31		0.31		1.24
Market price per common share ³
High	26.80		25.65		26.89		35.00		35.00
Low	24.39		23.04		22.71		26.04		22.71
Hawaiian Electric consolidated
2015
Revenues	$	573,442	$	558,163	$	648,127	$	555,434	$	2,335,166
Operating income	57,636		66,161		82,657		67,662		274,116
Net income	27,373		33,340		43,504		33,492		137,709
Net income for common stock	26,874		32,841		43,006		32,993		135,714
2014
Revenues	720,062		738,429		803,565		725,267		2,987,323
Operating income	70,666		70,068		76,156		58,878		275,768
Net income	35,919		34,729		39,377		29,611		139,636
Net income for common stock	35,420		34,230		38,879		29,112		137,641

Note: HEI owns all of Hawaiian Electric's common stock, therefore per share data for Hawaiian Electric is not meaningful.


¹	The quarterly basic earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.


²	The quarterly diluted earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter plus the dilutive incremental shares at quarter end.


³	Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape.

182



ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

HEI and Hawaiian Electric: None



ITEM 9A.	CONTROLS AND PROCEDURES

HEI:

Disclosure Controls and Procedures

Management of the Company, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of December 31, 2015.

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

Based on their evaluation, as of December 31, 2015, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were not effective because of the material weakness in the Company’s internal control over financial reporting described below.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer and effected by the Company’s Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015. In making its assessment of internal control over financial reporting, management used the criteria described in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

Based upon that assessment, management has identified the following deficiency as of December 31, 2015 in the Company’s internal control over financial reporting:

The Company did not maintain effective controls over the preparation and review of its consolidated statement of cash flows. Specifically, controls were not designed to ensure that non-cash transactions were properly identified, evaluated and presented in the statement of cash flows, and management’s review process was not effective. The control deficiency resulted in the restatement of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2013 and for the three months ended March 31, 2015 and 2014, and the six months ended June 30, 2015 and 2014. The control deficiency also resulted in the revision of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2014 and for the nine months ended September 30, 2014.

This control deficiency could result in a misstatement of the amounts of the foregoing items and disclosures that would result in a material misstatement of the annual or interim Consolidated Statements of Cash Flows that would not be prevented or detected. Accordingly, the Company’s management has determined that this control deficiency constitutes a material weakness.

183

Because of this material weakness, management concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2015, based on criteria in Internal Control-Integrated Framework (2013) issued by the COSO.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.

Changes in Internal Control Over Financial Reporting

As described below under “Remediation Plans and Other Information”, there were changes in internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Remediation Plans and Other Information

The Company’s management, with oversight from its Audit Committee of the Board of Directors of HEI, is actively engaged in remediation efforts to address the material weakness identified above. Management has taken and will take a number of actions to remediate this material weakness including, but not limited to, a roll forward reconciliation and review of the capital expenditures amount included in the Consolidated Statements of Cash Flows, and enhancing templates to facilitate the preparation and review of cash flows. New controls relating to the preparation and review of the Statement of Cash Flows (including improved spreadsheet templates, a reconciliation of cash capital expenditures, enhanced procedures to identify non-cash items, and an additional level of management review) have been implemented and will continue to be tested for operational effectiveness. Management is committed to maintaining a strong internal control environment and believes this remediation effort, when tested for a sufficient period of time, will remediate the material weakness. Management cannot provide assurance, however, that the steps taken will remediate such weakness, nor can management be certain of whether additional actions will be required or the costs of any such actions.

Hawaiian Electric:

Disclosure Controls and Procedures

Management of Hawaiian Electric, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of Hawaiian Electric’s disclosure controls and procedures as of December 31, 2015.

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

Based on their evaluation, as of December 31, 2015, Hawaiian Electric’s Chief Executive Officer and Chief Financial Officer have concluded that Hawaiian Electric’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were not effective because of the material weakness in Hawaiian Electric’s internal control over financial reporting described below.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, Hawaiian Electric’s Chief Executive Officer and Chief Financial Officer and effected by Hawaiian Electric’s Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of Hawaiian Electric’s internal control over financial reporting as of December 31, 2015. In making its assessment of internal control over financial reporting, management used the criteria described in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

184

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of Hawaiian Electric’s annual or interim financial statements will not be prevented or detected on a timely basis.

Based upon that assessment, management has identified the following deficiency as of December 31, 2015 in Hawaiian Electric’s internal control over financial reporting:

Hawaiian Electric did not maintain effective controls over the preparation and review of its consolidated statement of cash flows. Specifically, controls were not designed to ensure that non-cash transactions were properly identified, evaluated and presented in the statement of cash flows, and management’s review process was not effective. The control deficiency resulted in the restatement of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2013 and for the three months ended March 31, 2015 and 2014, and the six months ended June 30, 2015 and 2014. The control deficiency also resulted in the revision of the net cash provided by operating activities and the net cash used in investing activities for the year ended December 31, 2014 and for the nine months ended September 30, 2014.

This control deficiency could result in a misstatement of the amounts of the foregoing items and disclosures that would result in a material misstatement of the annual or interim Consolidated Statements of Cash Flows that would not be prevented or detected. Accordingly, Hawaiian Electric’s management has determined that this control deficiency constitutes a material weakness.

Because of this material weakness, management concluded that Hawaiian Electric did not maintain effective internal control over financial reporting as of December 31, 2015, based on criteria in Internal Control-Integrated Framework (2013) issued by the COSO.

Changes in Internal Control Over Financial Reporting

As described below under “Remediation Plans and Other Information”, there were changes in internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.

Remediation Plans and Other Information

Hawaiian Electric’s management, with oversight from its Audit Committee of the Board of Directors of Hawaiian Electric, is actively engaged in remediation efforts to address the material weakness identified above. Management has taken and will take a number of actions to remediate this material weakness including, but not limited to, a roll forward reconciliation and review of the capital expenditures amount included in the Consolidated Statements of Cash Flows, and enhancing templates to facilitate the preparation and review of cash flows. New controls relating to the preparation and review of the Statement of Cash Flows (including improved spreadsheet templates, a reconciliation of cash capital expenditures, enhanced procedures to identify non-cash items, and an additional level of management review) have been implemented and will continue to be tested for operational effectiveness. Management is committed to maintaining a strong internal control environment and believes this remediation effort, when tested for a sufficient period of time, will remediate the material weakness. Management cannot provide assurance, however, that the steps taken will remediate such weakness, nor can management be certain of whether additional actions will be required or the costs of any such actions.



ITEM 9B.	OTHER INFORMATION

HEI and Hawaiian Electric: None

PART III



ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

HEI:

EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)

The executive officers of HEI are listed below. Messrs. Oshima and Wacker are officers of HEI subsidiaries rather than of HEI, but are deemed to be executive officers of HEI under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HEI executive officers serve from the date of their initial appointment until the annual meeting of the HEI Board at which officers are appointed (or the next annual appointment of officers by the applicable HEI subsidiary board), and thereafter are appointed

185

for one-year terms or until their successors have been duly appointed and qualified or until their earlier resignation or removal. HEI executive officers may also hold offices with HEI subsidiaries and affiliates in addition to their current positions listed below.



Name	Age	Business experience for last 5 years and prior positions with the Company
Constance H. Lau	63	HEI President and Chief Executive Officer since 5/06 HEI Director, 6/01 to 12/04 and since 5/06 Hawaiian Electric Chairman of the Board since 5/06 ASB Hawaii Director since 5/06 ASB Chairman of the Board since 5/06 · ASB Chairman of the Board since 11/10 · ASB Chairman of the Board and Chief Executive Officer, 2/08 to 11/10 · ASB Chairman of the Board, President and Chief Executive Officer, 5/06 to 1/08 · ASB President and Chief Executive Officer and Director, 6/01 to 5/06 · ASB Senior Executive Vice President and Chief Operating Officer and Director, 12/99 to 5/01 · HEI Treasurer, 4/89 to 10/99 · HEI Power Corp. Financial Vice President and Treasurer, 5/97 to 8/99 · Hawaiian Electric Treasurer and HEI Assistant Treasurer, 12/87 to 4/89 · Hawaiian Electric Assistant Corporate Counsel, 9/84 to 12/87
James A. Ajello	62	HEI Executive Vice President and Chief Financial Officer since 8/13 ASB Hawaii Director since 8/09 · HEI Executive Vice President, Chief Financial Officer and Treasurer, 5/11 to 8/13 · HEI Senior Financial Vice President, Treasurer and Chief Financial Officer, 1/09 to 5/11
Chester A. Richardson	67	HEI Executive Vice President, General Counsel, Secretary and Chief Administrative Officer since 5/11 · HEI Senior Vice President, General Counsel, Secretary and Chief Administrative Officer, 9/09 to 5/11 · HEI Senior Vice President, General Counsel and Chief Administrative Officer, 12/08 to 9/09 · HEI Vice President, General Counsel, 8/07 to 12/08
Alan M. Oshima	68	Hawaiian Electric President and Chief Executive Officer since 10/14 Hawaiian Electric Director, 2008 to 10/11 and since 10/14 HEI Charitable Foundation President since 10/11 · Hawaiian Electric Senior Executive Officer on loan from HEI, 5/14 to 9/14 · HEI Executive Vice President, Corporate and Community Advancement, 10/11 to 5/14 · Prior to joining the Company: AMO Consulting, Owner and Principal, 2008-10/11; Hawaiian Telcom Communications, Inc. (Hawaiian Telcom), Senior Advisor, 2008-10
Richard F. Wacker	53	ASB President and Chief Executive Officer since 11/10 ASB Hawaii Director since 12/14 ASB Director since 11/10

The remaining information required by this Item 10 for HEI is incorporated herein by reference to the following sections in HEI's 2016 Proxy Statement:


•	“Nominees for Class II directors whose terms expire at the 2019 Annual Meeting”


•	“Continuing Class III directors whose terms expire at the 2017 Annual Meeting”


•	“Continuing Class I directors whose terms expire at the 2018 Annual Meeting”


•	“Committees of the Board” (portions regarding whether HEI has an audit committee and identifying its members; no other portion of the Committees of the Board section is incorporated herein by reference)


•	“Audit Committee Report” (portion identifying audit committee financial experts who serve on the HEI Audit Committee only; no other portion of the Audit Committee Report is incorporated herein by reference)

Family relationships; executive officer and director arrangements

There are no family relationships between any executive officer or director of HEI and any other executive officer or director of HEI. There are no arrangements or understandings between any executive officer or director of HEI and any other person pursuant to which such executive officer or director was selected.

Section 16(a) beneficial ownership reporting compliance

Information required to be reported under this caption is incorporated herein by reference to the “Stock Ownership Information-Section 16(a) Beneficial Ownership Reporting Compliance” section in HEI's 2016 Proxy Statement

Code of Conduct

The HEI Board has adopted a Corporate Code of Conduct that includes a code of ethics applicable to, among others, its principal executive officer, principal financial officer and principal accounting officer. The Corporate Code of Conduct is available on HEI’s website at www.hei.com. HEI elects to disclose the information required by Form 8-K, Item 5.05,

186

“Amendments to the Registrant’s Code of Ethics, or Waiver of a Provision of the Code of Ethics,” through this website and such information will remain available on this website for at least a 12-month period.

Hawaiian Electric:

The information required by this Item 10 for Hawaiian Electric is incorporated herein by reference to pages 1 to 7 of Hawaiian Electric Exhibit 99.1.



ITEM 11.	EXECUTIVE COMPENSATION

HEI:

The information required by this Item 11 for HEI is incorporated herein by reference to the information relating to executive and director compensation in HEI's 2016 Proxy Statement.

Hawaiian Electric:

The information required by this Item 11 for Hawaiian Electric is incorporated herein by reference to:


•	Pages 7 to 34 of Hawaiian Electric Exhibit 99.1 to this Form 10-K;


•	The discussion of “2014-2016 Long-Term Incentive Plan?” at pages 14-15 of Hawaiian Electric’s Exhibit 99.1 to Annual Report on Form 10-K for the year ended December 31, 2014; and


•	Information concerning compensation paid to directors of Hawaiian Electric who are also directors of HEI under the section of HEI's 2016 Proxy Statement entitled, “Director Compensation.”

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

HEI:

The information required to be reported under this caption for HEI is incorporated herein by reference to the “Compensation Committee Interlocks and Insider Participation” section in HEI's 2016 Proxy Statement.

Hawaiian Electric:

The information required to be reported under this caption for Hawaiian Electric is incorporated herein by reference to page 34 of Hawaiian Electric Exhibit 99.1.

187



ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

HEI:

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The information required by this Item 12 for HEI is incorporated herein by reference to the “Stock Ownership Information-Security Ownership of Certain Beneficial Owners” section in HEI's 2016 Proxy Statement.

Equity Compensation Plan Information

Information as of December 31, 2015 about HEI Common Stock that may be issued under all of the Company’s equity compensation plans was as follows:



Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (2)
Equity compensation plans approved by shareholders	520,601	$	—	3,160,813
Equity compensation plans not approved by shareholders	—	—		—
Total	520,601	$	—	3,160,813

(1)This column includes the number of shares of HEI Common Stock which may be issued under the Revised and Amended HEI 2010 Equity Incentive Plan (amended EIP) on account of awards outstanding as of December 31, 2015, including:



EIP
156,869		Restricted stock units plus estimated compounded dividend equivalents (if applicable) *
78,584		Shares issued in February 2016 under the 2013-2015 LTIP plus compounded dividend equivalents
285,148		Shares issuable at maximum payouts under the 2014-2016 LTIP, including estimated compounded dividend equivalents
520,601


*	Under the amended EIP as of December 31, 2015, RSUs count as one share against shares available for issuance less estimated shares withheld for taxes under net share settlement which again become available for the issuance of new shares on a one-to-one basis.


(2)	This represents the number of shares available as of December 31, 2015 for future awards, including 3,019,769 shares available for future awards under the amended EIP and 141,044 shares available for future awards under the 2011 Nonemployee Director Plan.

188

Hawaiian Electric:

The information required by this Item 12 for Hawaiian Electric is incorporated herein by reference to pages 35 to 36 of Hawaiian Electric Exhibit 99.1.



ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

HEI:

The information required by this Item 13 for HEI is incorporated herein by reference to the sections relating to related person transactions and director independence in HEI's 2016 Proxy Statement.

Hawaiian Electric:

The information required by this Item 13 for Hawaiian Electric is incorporated herein by reference to pages 36 to 37 of Hawaiian Electric Exhibit 99.1.



ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

HEI:

The information required by this Item 14 for HEI is incorporated herein by reference to the relevant information in the Audit Committee Report in HEI's 2016 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated herein by reference).

Hawaiian Electric:

The information required by this Item 14 for Hawaiian Electric is incorporated herein by reference to page 38 of Hawaiian Electric Exhibit 99.1.

PART IV



ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial statements

See Item 8 for the combined Consolidated Financial Statements of HEI and Hawaiian Electric.

(a)(2) and (c) Financial statement schedules

The following financial statement schedules for HEI and Hawaiian Electric are included in this report on the pages indicated below:



		Page/s in Form 10-K
		HEI	Hawaiian Electric
Schedule I	Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) at December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013	190-192	NA
Schedule II	Valuation and Qualifying Accounts, Hawaiian Electric Industries, Inc. and subsidiaries and Hawaiian Electric Company, Inc. and subsidiaries for the years ended December 31, 2015, 2014 and 2013	193	193
NA Not applicable.

Certain schedules, other than those listed, are omitted because they are not required, or are not applicable, or the required information is shown in the Consolidated Financial Statements.

189

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS



December 31	2015			2014
(dollars in thousands)
Assets
Cash and cash equivalents	$	55,116		$	276
Accounts receivable	5,459			1,991
Property, plant and equipment, net	4,514			4,917
Deferred income tax assets	16,715			15,922
Other assets	11,984			11,070
Investments in subsidiaries, at equity	2,293,679			2,223,597
	$	2,387,467		$	2,257,773
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	1,254		$	1,993
Interest payable	2,450			2,583
Notes payable to subsidiaries	5,946			7,857
Commercial paper	103,063			118,972
Long-term debt, net	300,000			300,000
Retirement benefits liability	31,704			32,030
Other	15,410			3,765
	459,827			467,200
Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none	—			—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 107,460,406 shares and 102,565,266 shares	1,629,136			1,521,297
Retained earnings	324,766			296,654
Accumulated other comprehensive loss	(26,262		)	(27,378		)
	1,927,640			1,790,573
	$	2,387,467		$	2,257,773
Note to Balance Sheets
HEI Term loan LIBOR + .75% (effective October 8, 2015), due 2017	$	125,000		$	125,000
HEI senior note 4.41%, due 2016	75,000			75,000
HEI senior note 5.67%, due 2021	50,000			50,000
HEI senior note 3.99%, due 2023	50,000			50,000
	$	300,000		$	300,000

See Note 1 for the impact to prior period financial information of the adoption of ASU No. 2014-01.

The aggregate payments of principal required subsequent to December 31, 2015 on long-term debt are $75 million in 2016, $125 million in 2017 and nil in 2018, 2019 and 2020.

As of December 31, 2015, HEI has a General Agreement of Indemnity in favor of both Liberty Mutual Insurance Company (Liberty) and Travelers Casualty and Surety Company of America (Travelers) for losses in connection with any and all bonds, undertakings or instruments of guarantee and any renewals or extensions thereof executed by Liberty or Travelers, including, but not limited to, a $0.2 million self-insured United States Longshore & Harbor bond and a $0.6 million self-insured automobile bond.

190

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME



Years ended December 31	2015		2014		2013
(in thousands)
Revenues	$	327	$	303	$	288
Equity in net income of subsidiaries	190,033		188,727		180,552
Expenses:
Operating, administrative and general	34,350		20,921		16,063
Depreciation of property, plant and equipment	576		575		596
Taxes, other than income taxes	440		469		497
Interest expense	10,788		11,599		16,207
Income before income tax benefits	144,206		155,466		147,477
Income tax benefits	15,671		13,047		14,232
Net income	$	159,877	$	168,513	$	161,709

See Note 1 for the impact to prior period financial information of the adoption of ASU No. 2014-01.

The Company’s financial reporting policy for income tax allocations is based upon a separate entity concept whereby each subsidiary provides income tax expense (or benefits) as if each were a separate taxable entity. The difference between the aggregate separate tax return income tax provisions and the consolidated financial reporting income tax provision is charged or credited to HEI’s separate tax provision.

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

STATEMENTS OF COMPREHENSIVE INCOME

STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

Incorporated by reference are HEI and Subsidiaries’ Statements of Consolidated Comprehensive Income and Consolidated Statements of Changes in Shareholders’ Equity in Part II, Item 8.

191

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (continued)

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS



Years ended December 31	2015			2014			2013
(in thousands)
Net cash provided by operating activities	$	97,141		$	100,794		$	82,274
Cash flows from investing activities
Capital expenditures	(173		)	(74		)	(201		)
Investments in subsidiaries	—			(40,000		)	(78,500		)
Net cash used in investing activities	(173		)	(40,074		)	(78,701		)
Cash flows from financing activities
Net increase (decrease) in notes payable to subsidiaries with original maturities of three months or less	87			(222		)	56
Net increase (decrease) in short-term borrowings with original maturities of three months or less	(15,909		)	13,490			21,788
Proceeds from issuance of long-term debt	—			125,000			50,000
Repayment of long-term debt	—			(100,000		)	(50,000		)
Excess tax benefits from share-based payment arrangements	978			277			430
Net proceeds from issuance of common stock	104,435			26,898			55,086
Common stock dividends	(131,765		)	(126,458		)	(98,383		)
Other	46			—			—
Net cash used in financing activities	(42,128		)	(61,015		)	(21,023		)
Net increase (decrease) in cash and equivalents	54,840			(295		)	(17,450		)
Cash and cash equivalents, January 1	276			571			18,021
Cash and cash equivalents, December 31	$	55,116		$	276		$	571

In 2015, 2014 and 2013, cash dividends received from subsidiaries were $121 million, $124 million and $122 million, respectively.

Supplemental disclosures of noncash activities:

In 2015, 2014 and 2013, $2.3 million, $2.4 million and $2.3 million, respectively, of HEI accounts receivable from ASB Hawaii were reduced with a corresponding reduction in HEI notes payable to ASB Hawaii in noncash transactions.

In 2015, 2014 and 2013, $0.3 million, $2.5 million and $2.5 million, respectively, were contributed as equity by HEI into ASB Hawaii with a corresponding increase in HEI notes payable to ASB Hawaii in noncash transactions.

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to nil, nil and $24 million in 2015, 2014 and 2013, respectively. HEI satisfied the requirements of the HEI DRIP, Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and ASB 401(k) Plan from March 6, 2014 through January 5, 2016 by acquiring for cash its common shares through open market purchases rather than by issuing additional shares.

Note:

The “Notes to Consolidated Financial Statements” in Part II, Item 8 should be read in conjunction with the above HEI (Parent Company) financial statements.

192

Hawaiian Electric Industries, Inc. and subsidiaries

and Hawaiian Electric Company, Inc. and subsidiaries

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2015, 2014 and 2013



Col. A	Col. B		Col. C						Col. D			Col. E
(in thousands)			Additions
Description	Balance at begin- ning of period		Charged to costs and expenses		Charged to other accounts				Deductions			Balance at end of period
2015
Allowance for uncollectible accounts – electric utility	$	1,959	$	3,653	$	977		(a)	$	4,890	(b),(c)	$	1,699
Allowance for uncollectible interest – bank	$	1,514	$	—	$	165			$	—		$	1,679
Allowance for losses for loans receivable – bank	$	45,618	$	6,275	$	4,571		(a)	$	6,426	(b)	$	50,038
Allowance for mortgage-servicing assets – bank	$	209	$	—	$	(205	)		$	4		$	—
Deferred tax valuation allowance – HEI	$	45	$	9	$	—			$	—		$	54
2014
Allowance for uncollectible accounts – electric utility	$	2,329	$	1,384	$	1,613		(a)	$	3,367	(b)	$	1,959
Allowance for uncollectible interest – bank	$	1,661	$	—	$	—			$	147		$	1,514
Allowance for losses for loans receivable – bank	$	40,116	$	6,126	$	4,926		(a)	$	5,550	(b)	$	45,618
Allowance for mortgage-servicing assets – bank	$	251	$	53	$	—			$	95		$	209
Deferred tax valuation allowance – HEI	$	278	$	17	$	—			$	250		$	45
2013
Allowance for uncollectible accounts – electric utility	$	2,148	$	3,812	$	1,943		(a)	$	5,574	(b)	$	2,329
Allowance for uncollectible interest – bank	$	3,166	$	—	$	—			$	1,505		$	1,661
Allowance for losses for loans receivable – bank	$	41,985	$	1,507	$	4,826		(a)	$	8,202	(b)	$	40,116
Allowance for mortgage-servicing assets – bank	$	498	$	—	$	(60	)		$	187		$	251
Deferred tax valuation allowance – HEI	$	278	$	—	$	—			$	—		$	278


(a)	Primarily recoveries.


(b)	Bad debts charged off.


(c)	Reclass of allowance for one customer account into other long term assets.

193

(a)(3) and (b) Exhibits

The Exhibit Index attached to this Form 10-K is incorporated herein by reference. The exhibits listed for HEI and Hawaiian Electric are listed in the index under the headings “HEI” and “Hawaiian Electric,” respectively, except that the exhibits listed under “Hawaiian Electric” are also exhibits for HEI.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 execution of this report by registrant Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.



HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
	(Registrant)		(Registrant)


By	/s/ James A. Ajello	By	/s/ Tayne S. Y. Sekimura
	James A. Ajello		Tayne S. Y. Sekimura
	Executive Vice President and Chief Financial Officer		Senior Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer of HEI)		(Principal Financial Officer of Hawaiian Electric)

Date:	February 23, 2016	Date:	February 23, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities indicated on February 23, 2016. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.



Signature		Title

/s/ Constance H. Lau		President of HEI and Director of HEI
Constance H. Lau		Chairman of the Board of Directors of Hawaiian Electric
		(Chief Executive Officer of HEI)

/s/ Alan M. Oshima		President and Director of Hawaiian Electric
Alan M. Oshima		(Chief Executive Officer of Hawaiian Electric)


/s/ James A. Ajello		Executive Vice President and Chief Financial Officer of HEI
James A. Ajello		(Principal Financial and Accounting Officer of HEI)


/s/ Tayne S. Y. Sekimura		Senior Vice President and
Tayne S. Y. Sekimura		Chief Financial Officer of Hawaiian Electric
		(Principal Financial Officer of Hawaiian Electric)

/s/ Patsy H. Nanbu		Controller of Hawaiian Electric
Patsy H. Nanbu		(Principal Accounting Officer of Hawaiian Electric)

194

SIGNATURES (continued)



Signature		Title

/s/ Don E. Carroll		Director of Hawaiian Electric
Don E. Carroll


/s/ Thomas B. Fargo		Director of HEI and Hawaiian Electric
Thomas B. Fargo


/s/ Peggy Y. Fowler		Director of HEI and Hawaiian Electric
Peggy Y. Fowler


/s/ Timothy E. Johns		Director of Hawaiian Electric
Timothy E. Johns


/s/ Micah A. Kane		Director of Hawaiian Electric
Micah A. Kane


/s/ Bert A. Kobayashi, Jr.		Director of Hawaiian Electric
Bert A. Kobayashi, Jr.


/s/ A. Maurice Myers		Director of HEI
A. Maurice Myers


/s/ Keith P. Russell		Director of HEI
Keith P. Russell


/s/ James K. Scott		Director of HEI
James K. Scott


/s/ Kelvin H. Taketa		Director of HEI and Hawaiian Electric
Kelvin H. Taketa


/s/ Barry K. Taniguchi		Director of HEI
Barry K. Taniguchi


/s/ Jeffrey N. Watanabe		Chairman of the Board of Directors of HEI
Jeffrey N. Watanabe

195

EXHIBIT INDEX

The exhibits designated by an asterisk (*) are filed herewith. The exhibits not so designated are incorporated by reference to the indicated filing. A copy of any exhibit may be obtained upon written request for a $0.20 per page charge from the HEI Shareholder Services Division, P.O. Box 730, Honolulu, Hawaii 96808-0730.



Exhibit no.		Description
HEI:
	2	Agreement and Plan of Merger, dated as of December 3, 2014, by and among NextEra Energy, Inc., NEE Acquisition Sub I, LLC, NEE Acquisition Sub II, Inc. and HEI (Exhibit 2.1 to HEI’s Current Report on Form 8-K December 3, 2014, File No. 1-8503).

	3(i)	HEI’s Amended and Restated Articles of Incorporation (Exhibit 3(i) to HEI’s Current Report on Form 8-K, dated May 5, 2009, File No. 1-8503).

	3(ii)	Amended and Restated Bylaws of HEI as last amended May 9, 2011 (Exhibit 3(ii) to HEI’s Current Report on Form 8-K May 9, 2011, File No. 1-8503).

	4.1	Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of HEI and its subsidiaries (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

	4.2	Master Note Purchase Agreement among HEI and the Purchasers thereto, dated March 24, 2011 (Exhibit 4(a) to HEI’s Current Report on Form 8-K dated March 24, 2011, File No. 1-8503).

	4.2(a)	First Supplement to Note Purchase Agreement among HEI and the Purchasers thereto, dated March 6, 2013 (Exhibit 4(a) to HEI’s Current Report on Form 8-K dated March 6, 2013, File No. 1-8503).

	4.3(a)	Loan Agreement dated as of May 2, 2014 among HEI, as Borrower, the Lenders Party Thereto and Royal Bank of Canada, as Syndication Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Administrative Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd. and RBC Capital Markets, as Joint Lead Arrangers and Joint Book Runners (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-8503).

	4.3(b)	Amendment No. 1 dated as of October 8, 2015 by and among HEI, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as lender and Administrative Agent, and U.S. Bank, National Association, as lender, to Loan Agreement dated as of May 2, 2014 (Exhibit 4 to HEI’s Current Report on Form 8-K dated October 8, 2015, File No. 1-8503).

	4.4	Hawaiian Electric Industries Retirement Savings Plan, restatement effective January 1, 2013 (Exhibit 4.5 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).

	4.5	Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company, as Trustee (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8503).

	4.5(a)	Letter Amendment effective November 28, 2012 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company (Exhibit 4.6(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).

	4.5(b)	Letter Amendment effective October 1, 2014 to Master Trust Agreement dated as of September 4, 2012 between HEI and ASB and Fidelity Management Trust Company (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-8503).

	4.5(c)	First Amendment to Master Trust Agreement (dated as of September 4, 2012) effective March 1, 2015 between HEI and ASB and Fidelity Management Trust Company (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, File No. 1-8503).

	4.5(d)	Letter Amendment effective August 3, 2015 to Master Trust Agreement (dated as of September 4, 2012) between HEI and ASB and Fidelity Management Trust Company (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-8503).

	4.6	Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan, as amended and restated effective October 6, 2014 (Exhibit 4(a) to Registration Statement on Form S-3, Registration No. 333-199183).

	4.7	American Savings Bank 401(k) Plan, restatement effective January 1, 2013 (Exhibit 4.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).



Exhibit no.		Description
	*4.7(a)	Amendment 2013-1 to the American Savings Bank 401(k) Plan, effective January 1, 2014.

	10.1	Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc. dated September 23, 1982. (Exhibit 10.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8503).

	10.2	Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home Loan Bank of Seattle) (Exhibit (28)-2 to HEI’s Current Report on Form 8-K dated May 26, 1988, File No. 1-8503).

	10.3	OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

HEI Exhibits 10.4 through 10.21 are management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 through 10.19 are also management contracts or compensatory plans or arrangements with Hawaiian Electric participants.

	10.4	HEI Executive Incentive Compensation Plan amended as of February 4, 2013 (Exhibit 10.4 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).

	10.5	HEI Executives’ Deferred Compensation Plan (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	10.6	Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated November 16, 2010 (Exhibit 10.6 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

	10.7	Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated February 14, 2014 (Exhibit D to HEI’s Proxy Statement for Annual Meeting of Shareholders filed on March 25, 2014, File No. 1-8503).

	10.7(a)	Form of Non-Qualified Stock Option Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.4 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

	10.7(b)	Form of Stock Appreciation Right Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.5 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

	10.7(c)	Form of Restricted Shares Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.6 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

	10.7(d)	Form of Performance Shares Agreement pursuant to 2010 Equity and Incentive Plan (Exhibit 4.7 to Registration Statement filed on May 11, 2010 on Form S-8 Registration No. 333-166737).

	10.7(e)	Form of Restricted Stock Unit Agreement, amended as of February 4, 2013, pursuant to 2010 Equity and Incentive Plan (Exhibit 10.6(e) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).

	10.8	HEI Long-Term Incentive Plan amended as of February 4, 2013 (Exhibit 10.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).

	10.9	HEI Supplemental Executive Retirement Plan amended and restated as of January 1, 2009 (Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	10.9(a)	Amendments to the HEI Supplemental Executive Retirement Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.9(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.10	HEI Excess Pay Plan amended and restated as of January 1, 2009 (Exhibit 10.10 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.10(a)	HEI Excess Pay Plan Addendum for Constance H. Lau (Exhibit 10.10(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.10(b)	Amendment No. 1 dated December 13, 2010 to January 1, 2009 Restatement of HEI Excess Pay Plan (Exhibit 10.10(c) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).



Exhibit no.		Description
	10.11	Form of Change in Control Agreement (Exhibit 10.11 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.12	Nonemployee Director Retirement Plan, effective as of October 1, 1989 (Exhibit 10.15 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-8503).

	10.13	HEI 2011 Nonemployee Director Stock Plan (Appendix A to HEI’s Proxy Statement for 2011 Annual Meeting of Shareholders filed on March 21, 2011, File No. 1-8503).

	*10.14	Nonemployee Director’s Compensation Schedule effective January 1, 2014.

	10.15	HEI Non-Employee Directors’ Deferred Compensation Plan (Exhibit 10.5 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	10.16	Executive Death Benefit Plan of HEI and Participating Subsidiaries restatement effective as of January 1, 2009 (Exhibit 10.6 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	10.16(a)	Resolution of the Compensation Committee of the Board of Directors of Hawaiian Electric Industries, Inc. Re: Adoption of Amendment No. 1 to January 1, 2009 Restatement of the Executive Death Benefit Plan (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8503).

	10.17	Severance Pay Plan for Merit Employees of HEI and affiliates, restatement effective as of January 1, 2009 (Exhibit 10.17 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.18	Hawaiian Electric Industries Deferred Compensation Plan adopted on December 13, 2010 (Exhibit 10.18 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

	10.19	Form of Indemnity Agreement (HEI, Hawaiian Electric and ASB with their respective directors and HEI with certain of its senior officers) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8503).

	10.20	American Savings Bank Select Deferred Compensation Plan (Restatement Effective January 1, 2009) (Exhibit 10.7 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	*10.20(a)	Amendment No. 1 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 30, 2009.

	*10.20(b)	Amendment No. 2 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 29, 2010.

	*10.20(c)	Amendment No. 3 to January 1, 2009 Restatement of American Savings Bank Select Deferred Compensation Plan dated December 3, 2014.

	10.21	American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan, effective January 1, 2009 (Exhibit 10.8 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	10.21(a)	Amendments to the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.19(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.22	Amended and Restated Credit Agreement, dated as of April 2, 2014, among HEI, as Borrower, the Lenders Party Thereto and Wells Fargo Bank, National Association, as Syndication Agent, and Bank of America, N.A., Bank of Hawaii, Royal Bank of Canada, Union Bank, N.A. and U.S. Bank National Association as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and Issuing Bank, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Runners (Exhibit 10.1 to HEI’s Current Report on Form 8-K dated April 2, 2014, File No. 1-8503).

	*11	HEI - Computation of Earnings per Share of Common Stock.

	*12.1	HEI - Computation of Ratio of Earnings to Fixed Charges.

	*21.1	HEI - Subsidiaries of the Registrant.



Exhibit no.		Description
	*23.1	Consent of Independent Registered Public Accounting Firm.

	*31.1	Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer).

	*31.2	Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer).

	*32.1	HEI Certification Pursuant to 18 U.S.C. Section 1350.

	*101.INS	XBRL Instance Document.

	*101.SCH	XBRL Taxonomy Extension Schema Document.

	*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

	*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

	*101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

	*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

Hawaiian Electric:
	*2.1	Asset Purchase Agreement by and among Hamakua Energy Partners, L.P. and Hamakua Land Partnership, L.L.P., as sellers, and Hawaii Electric Light Company, Inc., as buyer, dated as of December 21, 2015. (confidential treatment has been requested for portions of this exhibit).**

	3(i).1	Hawaiian Electric’s Certificate of Amendment of Articles of Incorporation (Exhibit 3.1 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

	3(i).2	Articles of Amendment to Hawaiian Electric’s Amended Articles of Incorporation (Exhibit 3.1(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

	3(i).3	Articles of Amendment to Hawaiian Electric’s Amended Articles of Incorporation (Exhibit 3(i).4 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

	3(i).4	Articles of Amendment amending Article V of Hawaiian Electric’s Amended Articles of Incorporation effective August 6, 2009 (Exhibit 3(i).4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-4955).

	3(ii)	Hawaiian Electric’s Amended and Restated Bylaws (as last amended August 6, 2010) (Exhibit 3(ii) to Hawaiian Electric’s Current Report on Form 8-K dated August 9, 2010, File No. 1-4955).

	4.1	Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of Hawaiian Electric, Hawaii Electric Light and Maui Electric (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-4955).

	4.2	Certificate of Trust of HECO Capital Trust III (incorporated by reference to Exhibit 4(a) to Registration No. 333-111073).

	4.3	Amended and Restated Trust Agreement of HECO Capital Trust III dated as of March 1, 2004 (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.4	Hawaiian Electric Junior Indenture with The Bank of New York, as Trustee, dated as of March 1, 2004 (Exhibit 4(f) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.5	6.500% Quarterly Income Trust Preferred Security issued by HECO Capital Trust III, dated March 18, 2004 (Exhibit 4(d) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.6	6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Hawaiian Electric, dated March 18, 2004 (Exhibit 4(g) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).
**Pursuant to Item 6.01 (b)(2) of Regulation S-K, exhibits and schedules are omitted. Hawaiian Electric agrees to furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon request.



Exhibit no.		Description
	4.7	Trust Guarantee Agreement between The Bank of New York, as Trust Guarantee Trustee, and Hawaiian Electric dated as of March 1, 2004 (Exhibit 4(l) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.8	Maui Electric Junior Indenture with The Bank of New York, as Trustee, including Hawaiian Electric Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(h) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.9	Hawaii Electric Light Junior Indenture with The Bank of New York, as Trustee, including Hawaiian Electric Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(j) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.10	6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Maui Electric, dated March 18, 2004 (Exhibit 4(i) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.11	6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Hawaii Electric Light, dated March 18, 2004 (Exhibit 4(k) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.12	Expense Agreement, dated March 1, 2004, among HECO Capital Trust III, Hawaiian Electric, Maui Electric and Hawaii Electric Light (Exhibit 4(m) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.13	Note Purchase Agreement among Hawaiian Electric and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(a) to Hawaiian Electric’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

	4.14	Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(b) to Hawaiian Electric’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

	4.15	Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

	4.16	Note Purchase Agreement among Hawaiian Electric and the Purchasers that are parties thereto, dated September 13, 2012 (Exhibit 4 to Hawaiian Electric’s Current Report on Form 8-K dated September 13, 2012, File No. 1-4955).

	4.17	Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of October 3, 2013. (Exhibit 4(a) to Hawaiian Electric’s Current Report on Form 8-K dated October 3, 2013, File No. 1-4955).

	4.18	Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric Company, Limited and the Purchasers that are parties thereto, dated as of October 3, 2013. (Exhibit 4(b) to Hawaiian Electric’s Current Report on Form 8-K dated October 3, 2013, File No. 1-4955).

	4.19	Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light Company, Inc. and the Purchasers that are parties thereto, dated as of October 3, 2013. (Exhibit 4 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, 2013, File No. 1-4955).

	4.20	Note Purchase Agreement among Hawaiian Electric Company, Inc. and the Purchasers that are parties thereto, dated as of October 15, 2015. (Exhibit 4(a) to Hawaiian Electric’s Current Report on Form 8-K dated October 15, 2015, File No. 1-4955).

	4.21	Note Purchase and Guaranty Agreement among Hawaiian Electric, Maui Electric Company, Limited and the Purchasers that are parties thereto, dated as of October 15, 2015. (Exhibit 4(b) to Hawaiian Electric’s Current Report on Form 8-K dated October 15, 2015, File No. 1-4955).

	4.22	Note Purchase and Guaranty Agreement among Hawaiian Electric, Hawaii Electric Light Company, Inc. and the Purchasers that are parties thereto, dated as of October 15, 2015. (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated October 15, 2015, File No. 1-4955).

	10.1(a)	Power Purchase Agreement between Kalaeloa Partners, L.P., and Hawaiian Electric dated October 14, 1988 (Exhibit 10(a) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1988, File No. 1-4955).



Exhibit no.		Description
	10.1(b)	Amendment No. 1 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated June 15, 1989 (Exhibit 10(c) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

	10.1(c)	Lease Agreement between Kalaeloa Partners, L.P., as Lessor, and Hawaiian Electric, as Lessee, dated February 27, 1989 (Exhibit 10(d) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

	10.1(d)	Restated and Amended Amendment No. 2 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated February 9, 1990 (Exhibit 10.2(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

	10.1(e)	Amendment No. 3 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated December 10, 1991 (Exhibit 10.2(e) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991, File No. 1-4955).

	10.1(f)	Amendment No. 4 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 1, 1999 (Exhibit 10.1 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

	10.1(g)	Confirmation Agreement Concerning Section 5.2B(2) of Power Purchase Agreement and Amendment No. 5 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.3 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).

	10.1(h)	Agreement for Increment Two Capacity and Amendment No. 6 to Power Purchase Agreement between Hawaiian Electric and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.4 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-4955).

	10.2(a)	Power Purchase Agreement between AES Barbers Point, Inc. and Hawaiian Electric, entered into on March 25, 1988 (Exhibit 10(a) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, File No. 1-4955).

	10.2(b)	Agreement between Hawaiian Electric and AES Barbers Point, Inc., pursuant to letters dated May 10, 1988 and April 20, 1988 (Exhibit 10.4 to Hawaiian Electric’s Annual Report on Form 10-K for fiscal year ended December 31, 1988, File No. 1-4955).

	10.2(c)	Amendment No. 1, entered into as of August 28, 1988, to Power Purchase Agreement between AES Barbers Point, Inc. and Hawaiian Electric (Exhibit 10 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, File No. 1-4955).

	10.2(d)	Hawaiian Electric’s Conditional Notice of Acceptance to AES Barbers Point, Inc. dated January 15, 1990 (Exhibit 10.3(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989, File No. 1-4955).

	10.2(e)	Amendment No. 2, entered into as of May 8, 2003, to Power Purchase Agreement between AES Hawaii, Inc. and Hawaiian Electric (Exhibit 10.2(e) to Hawaiian Electric’s Annual Report on Form 10-K for fiscal year ended December 31, 2003, File No. 1-4955).

	*10.2(f)	Amendment No. 3, entered into as of November 13, 2015 (corrected version (1/15/16)), to Power Purchase Agreement between AES Hawaii, Inc. and Hawaiian Electric Company, Inc. (subject to PUC approval).

	10.3(a)	Purchase Power Contract between Hawaii Electric Light and Thermal Power Company dated March 24, 1986 (Exhibit 10(a) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

	10.3(b)	Firm Capacity Amendment between Hawaii Electric Light and Puna Geothermal Venture (assignee of AMOR VIII, who is the assignee of Thermal Power Company) dated July 28, 1989 to Purchase Power Contract between Hawaii Electric Light and Thermal Power Company dated March 24, 1986 (Exhibit 10(b) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 1-4955).

	10.3(c)	Amendment made in October 1993 to Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).



Exhibit no.		Description
	10.3(d)	Third Amendment dated March 7, 1995 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

	10.3(e)	Performance Agreement and Fourth Amendment dated February 12, 1996 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-4955).

	10.3(f)	Fifth Amendment dated February 7, 2011 to the Purchase Power Contract between Hawaii Electric Light and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.4(f) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, File No. 1-4955).

	10.3(g)	Power Purchase Agreement between Puna Geothermal Venture and Hawaii Electric Light dated February 7, 2011 (Exhibit 10.4(g) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, File No. 1-4955).

	10.4(a)	Power Purchase Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (but with the following attachments omitted: Attachment C, “Selected portions of the North American Electric Reliability Council Generating Availability Data System Data Reporting Instructions dated October 1996” and Attachment E, “Form of the Interconnection Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light,” which is provided in final form as Exhibit 10.6(b)) (Exhibit 10.7 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

	10.4(b)	Interconnection Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (Exhibit 10.7(a) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

	10.4(c)	Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and Hawaii Electric Light dated October 22, 1997 (Exhibit 10.7(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

	10.4(d)	Power Purchase Agreement Novation dated November 8, 1999 by and among Encogen Hawaii, L.P., Hamakua Energy Partners and Hawaii Electric Light (Exhibit 10.7(c) to Hawaiian Electric’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).

	10.4(e)	Consent and Agreement Concerning Certain Assets of Black River Energy, LLC By and Among Great Point Power Hamakua Holdings, LLC, Hamakua Energy Partners, L.P. and Hawaii Electric Light dated April 19, 2010 (Exhibit 10.6(e) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).

	10.4(f)	Guarantee Agreement between Great Point Power Hamakua Holdings, LLC and Hawaii Electric Light dated June 4, 2010 (Exhibit 10.6(f) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).

	10.5	Low Sulfur Fuel Oil Supply Contract by and between Chevron and Hawaiian Electric dated as of August 24, 2012 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.2 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

	10.5(a)	First Amendment, dated August 27, 2014, to Low Sulfur Fuel Oil Supply Contract by and between Chevron Products Company and Hawaiian Electric, dated August 24, 2012 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.1 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-4955).

	10.6(a)	Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and Hawaiian Electric, Maui Electric, Hawaii Electric Light, HTB and YB dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.9 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

	10.6(b)	Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and Hawaiian Electric, Maui Electric and Hawaii Electric Light entered into as of April 12, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(d) to Hawaiian Electric’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).



Exhibit no.		Description
	10.6(c)	Second Amendment dated December 17, 2013 to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and Hawaiian Electric, Maui Electric and Hawaii Electric Light entered into as of November 14, 1997, as amended by Amendment dated April 12, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.7(c) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, File No. 1-4955).

	10.6(d)	Third Amendment, dated August 27, 2014, to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract, dated November 14, 1997, as amended, between Hawaiian Electric, Maui Electric and Hawaii Electric Light and Chevron Products Company (Exhibit 10.2 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-4955).

	10.7(a)	Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between BHP Petroleum Americas Refining Inc. and Hawaiian Electric, Maui Electric and Hawaii Electric Light dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.12 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

	10.7(b)	First Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc., and Hawaiian Electric, Maui Electric and Hawaii Electric Light dated March 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(b) to Hawaiian Electric’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

	10.7(c)	Second Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc., and Hawaiian Electric, Maui Electric and Hawaii Electric Light dated January 31, 2012 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.4 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

	10.7(d)	Letter agreement dated December 11, 2013 between Hawaiian Electric, Maui Electric and Hawaii Electric Light and Hawaiian Independent Energy LLC (formerly known as Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc.) Re: The Inter-Island Industrial Fuel Oil and Diesel Supply Contract dated November 14, 1997, as amended by First Amendment and Second Amendment (Exhibit 10.10(d) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, File No. 1-4955).

	10.7(e)	Third Amendment, dated February 11, 2015, to the Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Hawaii Independent Energy (formerly known as Tesoro, which was formerly known as BHP Petroleum Americas Refining Inc.), LLC and Hawaiian Electric, Maui Electric and Hawaii Electric Light, dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.4 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, File No. 1-4955).

	10.8(a)	Contract of private carriage by and between HITI and Hawaii Electric Light dated December 4, 2000 (Exhibit 10.13 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

	10.8(b)	Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and Hawaii Electric Light, dated July 1, 2011 (Exhibit 10.13(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-4955).

	10.9(a)	Contract of private carriage by and between HITI and Maui Electric dated December 4, 2000 (Exhibit 10.14 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

	10.9(b)	Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and Maui Electric, dated July 1, 2011 (Exhibit 10.14(b) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-4955).

	10.10	Stipulated Settlement Agreement between the Hawaiian Electric Companies and the Division of Consumer Advocacy regarding Certain Regulatory Matters (Exhibit 10 to Hawaiian Electric’s Current Report on Form 8-K, dated January 28, 2013, File No. 1-4955).

	10.11	Release, Transition and Consulting agreement between Richard M. Rosenblum and Hawaiian Electric dated October 8, 2014 (Exhibit 10.14 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-4955).



Exhibit no.		Description
	10.12	Amended and Restated Credit Agreement, dated as of April 2, 2014, among Hawaiian Electric, as Borrower, the Lenders Party Thereto and Wells Fargo Bank, National Association, as Syndication Agent, and Bank of America, N.A., Bank of Hawaii, Royal Bank of Canada, Union Bank, N.A. and U.S. Bank National Association as Co-Documentation Agents, and JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and Issuing Bank, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Runners (Exhibit 10.2 to Hawaiian Electric’s Current Report on Form 8-K dated April 2, 2014, File No. 1-4955).

	11	Computation of Earnings Per Share of Common Stock (See note on Hawaiian Electric’s Item 6. Selected Financial Data).

	*12.2	Hawaiian Electric - Computation of Ratio of Earnings to Fixed Charges.

	*21.2	Hawaiian Electric - Subsidiaries of the Registrant.

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

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

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

	*99.1	Hawaiian Electric’s Directors, Executive Officers and Corporate Governance; Hawaiian Electric’s Executive Compensation; Hawaiian Electric’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters; Hawaiian Electric’s Certain Relationships and Related Transactions, and Director Independence; and Hawaiian Electric’s Principal Accounting Fees and Services.