Edgar Filing: HAWAIIAN ELECTRIC INDUSTRIES INC

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

Amendment No. 1

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

[ ] 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, 2014	June 30, 2014	February 13, 2015
Hawaiian Electric Industries, Inc. (HEI)	$2,571,503,656	101,560,176 (Without par value)	102,710,867 (Without par value)
Hawaiian Electric Company, Inc. (Hawaiian Electric)	None	15,429,105 ($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

This combined Amendment No. 1 on Form 10-K/A 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.

EXPLANATORY NOTE

HEI and Hawaiian Electric are filing this Amendment No. 1 on Form 10-K/A (the Amended Filing) to amend certain parts of their Annual Report on 2014 Form 10-K, originally filed with the Securities and Exchange Commission (SEC) on February 26, 2015 (the Original Filing).

Background and Effects of the Restatement

The Audit Committees of the Boards of Directors of HEI and Hawaiian Electric, after consultation with management, concluded on November 4, 2015 that it is necessary to restate 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 to revise 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 for the correction of misstatements related to capital expenditures, changes in accounts payable, changes in deferred income taxes, changes in accrued income taxes, and changes in other assets and liabilities as described below and other immaterial items. This Amended Filing restates HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012 and revises HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows for the year ended December 31, 2014 and makes other conforming changes (see “Items Amended in This Filing” below). This restatement does not impact HEI’s and Hawaiian Electric’s previously reported overall net change in cash and cash equivalents in their Consolidated Statements of Cash Flows for any period presented. Additionally, this restatement does not impact HEI’s and Hawaiian Electric’s Consolidated Balance Sheets or Consolidated Statements of Income for any period presented.

Management discovered that the Utilities’ capital expenditures on HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows did not correctly account for the beginning of period unpaid invoices and accruals (that were paid in cash during the period) and is restating its previously filed Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012 and revising its previously filed Consolidated Statements of Cash Flows for the year ended December 31, 2014 to correct for such misstatement by adjusting cash used for “Capital expenditures” (investing activity) and the change in accounts payable (operating activity).

Management also discovered that the eliminating journal entry to offset the Hawaiian Electric consolidated net operating loss deferred tax asset did not properly reflect the adjustment on the components of income taxes (current and deferred federal income taxes) and is revising its previously filed Consolidated Statements of Cash Flows to correct for such misstatement by adjusting “Increase in deferred income taxes,” “Change in prepaid and accrued income taxes and utility revenue taxes” and “Change in other assets and liabilities” for the year ended December 31, 2014 (operating activities).

The impact of the revision and restatements on the consolidated financial statements for the years ended December 31, 2014, 2013 and 2012 is summarized in Note 1, "Summary of significant accounting policies - Revision and restatements of previously issued financial statements" to HEI’s and Hawaiian Electric’s consolidated financial statements included in Part II, Item 8.

Internal Control Over Financial Reporting

Management reassessed its evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2014, based on the framework established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As a result of that reassessment, management identified a material weakness and, accordingly, has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2014. Management has restated its report on internal control over financial reporting as of December 31, 2014. For a description of the material weakness in internal control over financial reporting and actions taken, and to be taken, to remediate the material weakness, see Part II, Item 9A. "Controls and Procedures" of this 2014 Annual Report on Form 10-K/A.

Items Amended in This Filing

This Amended Filing amends and restates the following items of the Company's Original Filing as of, and for the years ended December 31, 2014, 2013 and 2012.

Part I - Item 1A. Risk Factors

Part II - Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations

Part II - Item 8. Financial Statements and Supplementary Data

Part II - Item 9A. Controls and Procedures

Part IV - Item 15. Exhibits and Financial Statement Schedules

In accordance with applicable SEC rules, this Amended Filing includes certifications as required by Rule 12b-15 under the Securities Exchange Act of 1934, as amended (the Exchange Act) from HEI's and Hawaiian Electric’s Principal Executive Officers and Principal Financial Officers dated as of the date of this amended filing.

Except for the items noted above, no other information included in the Original Filing is being amended by this Amended Filing. The Amended Filing speaks as of the date of the Original Filing and HEI and Hawaiian Electric have not updated the Original Filing to reflect events occurring subsequent to the date of the Original Filing. Accordingly, this Amended Filing should be read in conjunction with HEI's and Hawaiian Electric’s filings made with the SEC subsequent to the date of the Original Filing.

TABLE OF CONTENTS



		Page

Glossary of Terms		ii
Forward-Looking Statements		vi


	PART I
Item 1A.	Risk Factors	1

	PART II
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 8.	Financial Statements and Supplementary Data	52
Item 9A.	Controls and Procedures	150


	PART IV
Item 15.	Exhibits and Financial Statement Schedules	153
Signatures		159

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.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). 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
EGU		Electrical generating unit
EIP		2010 Executive Incentive Plan, as amended
Energy Agreement		Agreement, dated October 20, 2008, signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and Hawaiian Electric, for itself and on behalf of its electric utility subsidiaries, committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI. In September 2014, the parties to the Energy Agreement concluded that the agreements and policy directives in the Energy Agreement had been advanced or superseded by subsequent events, as well as by decisions and orders issued by the PUC, and accordingly ended the Energy Agreement as of September 14, 2014.
EOTP		East Oahu Transmission Project
EPA		Environmental Protection Agency - federal
EPS		Earnings per share

GLOSSARY OF TERMS (continued)



Terms		Definitions

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
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
HCEI		Hawaii Clean Energy Initiative
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., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
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., 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)
LSFO		Low sulfur fuel oil
LTIP		Long-term incentive plan
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

iii

GLOSSARY OF TERMS (continued)



Terms		Definitions

Merger Agreement		Agreement and Plan of Merger by and among HEI, NEE, Merger Sub II and Merger Sub I, dated December 3, 2014
Merger Sub I		NEE Acquisition Sub II, Inc., a Delaware corporation and a wholly owned subsidiary of NEE
Merger Sub II		NEE Acquisition Sub I, LLC, a Delaware limited liability company and a wholly owned subsidiary of NEE
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.
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
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
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, the timing and terms and conditions of required governmental and regulatory approvals, the ability to obtain the required shareholder approval and the ability to maintain relationships with employees, customers or suppliers, as well as the ability to integrate the businesses;


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

•

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


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


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


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


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


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


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


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


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

•

the PUC’s potential delay in considering (and potential disapproval of actual or proposed) Hawaii Clean Energy Initiative (HCEI)-related costs; reliance by the Utilities on outside parties such as the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, proposed undersea cables, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

•

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


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


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


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


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


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


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


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


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


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


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


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

•

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


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


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


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


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

•

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


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


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


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


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


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


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


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


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


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


•	other risks or uncertainties described elsewhere in this report (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 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 and HEI will be subject to 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;

•

focusing HEI’s management on the Merger, which 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


•	focusing HEI’s management 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.

In addition to the above risks, HEI may be required, under certain circumstances, to pay to NEE a termination fee of $90 million, plus NEE’s expenses up to $5 million.

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 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;

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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, 2014) 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 electric utility KWH sales, 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 KWH sales, an increase in uncollected billings of the Utilities, higher delinquencies in ASB’s loan portfolio and other adverse effects on HEI’s businesses.

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, 2014, 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 $905 million as of December 31, 2014), net of regulatory liabilities (amounting to $345 million as of December 31, 2014), 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 will initiate remediation efforts of the material weakness in the internal control over financial reporting. The remediation includes, but is not limited to, Hawaiian Electric and its subsidiaries instituting a control that requires a roll forward reconciliation and review of the capital expenditures amount included in the Consolidated Statement of Cash Flows and enhancing templates to facilitate the preparation and review of cash flows.

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. As part of the review, the Energy Agreement had provided that the PUC may examine whether there are renewable energy projects from which the Utilities should have, but did not, purchase energy or whether alternative fuel purchase strategies were appropriately used or not used.

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 the partial pass through of fuel costs would not be proper regulatory policy since the Utilities have no control over world oil markets, that 42 of the 50 states provide dollar-for-dollar pass through of market-driven changes in fuel or purchase power costs, and that 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.

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 69% of the net energy generated or purchased by the Utilities in 2014 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 2009, Hawaii’s RPS law was amended to require electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, 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 2010 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 to climate change have led to action by the state of Hawaii and federal legislative and regulatory proposals to reduce GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 and the regulations went into effect on June 30, 2014. In general, the regulations require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 16% below 2010 emission levels by 2020. The regulations will also assess affected sources an annual fee based on tons per year of GHG emissions commencing on the effective date of the regulations, estimated to be approximately $0.5 million annually for the Utilities. The DOH GHG regulations also track the federal “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities.

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

In response to the 2007 U.S. Supreme Court decision in Massachusetts v. Environmental Protection Agency, which ruled that the EPA has the authority to regulate GHG emissions from motor vehicles under the CAA, the EPA has accelerated rulemaking addressing GHG emissions from both mobile and stationary sources. On September 22, 2009, the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule. The rule, which applies to the Utilities, requires that sources above certain threshold levels monitor and report GHG emissions.

On June 3, 2010, the EPA’s final GHG Tailoring Rule was published. It created a new emissions threshold for GHG emissions from new and existing facilities and requires 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 the Agency’s plan for addressing the U.S. Supreme Court’s decision. Hawaiian Electric, Hawaii Electric Light and Maui Electric are evaluating the potential impacts of the Agency’s plan on utility operations and permitting. The current status of the GHG Tailoring Rule, and any further regulatory action the EPA may take in light of this recent decision, are 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.

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

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 43% of ASB’s loan portfolio as of December 31, 2014 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. Interest rates declined in 2014 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 many disparate factors, some of which are beyond its control, that could result in lower net interest income or decreased demand for its products and services. ASB’s results of operations depend primarily on the level of interest income generated by ASB’s earning assets in excess of the interest expense on its costing liabilities and the supply of and demand for its products and services (i.e., loans and deposits). ASB’s net income may also be adversely affected by various other factors, such as:


•	local 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 affecting capital requirements and increasing oversight of, and reporting by, banks;


•	additional legislative changes regulating the assessment of overdraft, interchange and credit card fees, which will 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), 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, 2014 approximately 79% of ASB’s loan portfolio was comprised of loans primarily collateralized by real estate, most of which was concentrated in the State of Hawaii. ASB’s HELOC (home equity line of credit) portfolio grew by 11% during 2014 and now comprises 23% 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. 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.

PART II



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

Restatement

As described in Note 1, “Summary of significant accounting policies - Revision and restatements of previously issued financial statements,” to HEI’s and Hawaiian Electric’s consolidated financial statements included in Part II, Item 8 “Financial Statements and Supplementary Data,” and Part II, Item 9A “Controls and Procedures,” HEI and Hawaiian Electric have revised or restated certain financial statements and other information, including this 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, parent company of ASB (the Spin-Off). The closing of the Merger is subject to various conditions, including federal and state regulatory approvals and the approval of holders of 75% of the outstanding shares of HEI common stock. 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 2014, net income for HEI common stock was $168 million, up 4% from $162 million in 2013 primarily due to the Utilities’ 12% higher net income. ASB had 11% lower net income in 2014 compared to 2013 and the “other” segment had a $2 million higher net loss. Basic earnings per share were $1.65 per share in 2014, up 1% from $1.63 per share in 2013.

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 2014 of $138 million increased 12% from the prior year due primarily to the increase in revenues in 2014 for the recovery of costs for clean energy and reliability investments and reduction of earnings in 2013 due to the Maui Electric refund to customers, offset in part due to higher O&M expenses, depreciation expense, interest costs, and a favorable deferred tax adjustment in 2013.

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 the investments in people and technology necessary to adapt to a constantly changing banking industry and remain competitive. ASB’s earnings in 2014 of $51 million decreased $6 million compared to prior year net income due primarily to lower noninterest income and a higher provision for loan losses. In 2014, ASB earnings were impacted by lower debit card interchange fees as a result of being non-exempt from the Durbin Amendment from July 1, 2013, and the settlement of a lawsuit. ASB’s future financial results will continue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio. If the Spin-Off occurs as contemplated by the Merger Agreement, ASB expects to be exempt from the Durbin Amendment.

HEI’s “other” segment had a net loss in 2014 of $20.8 million, compared to a net loss of $18.9 million in 2013. In 2014, HEI incurred $5 million of expenses related to the proposed merger and $3 million lower interest expense (each 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, 2014 was 3.7%. The dividend payout ratios based on net income for common stock for 2014, 2013 and 2012 were 75%, 76% and 87%, 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, reached record highs in both visitor spending and arrivals for the third consecutive year in 2014. Visitor expenditures increased 2.3% and arrivals increased 1.3% compared to 2013. Looking ahead, the Hawaii Tourism Authority expects scheduled nonstop seats to Hawaii for the first quarter of 2015 to increase by 6.1% over the first quarter of 2014 driven primarily by a 9.2% increase in domestic seats.

Hawaii’s unemployment rate was relatively stable at 4.0% in December 2014, lower than the state’s 4.7% rate in December 2013 and the December 2014 national unemployment rate of 5.6%.

Hawaii real estate activity, as indicated by the home resale market, experienced growth in median sales prices in 2014. Median sales prices for single family residential homes and condominiums on Oahu increased 3.8% and 5.4%, respectively, over 2013. However, the number of closed sales was down slightly in 2014. Closed sales for single family residential homes were down 0.8% and condominiums were down 1.3% compared to 2013.

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

At its January 2015 meeting, the Federal Open Market Committee (FOMC) held the federal funds rate target at 0% to 0.25% and this rate is expected to remain at record lows for a considerable time following the end of the asset purchase program in October 2014.

Overall, Hawaii’s economy is expected to see positive growth in 2015. Tourism had another record year in 2014, but future gains will be restrained due to limited 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 2014. Risks to local economic growth include planned reductions in active duty military personnel and weak Japanese visitor arrivals and spending.

Recent tax developments. The Tax Increase Prevention Act of 2014 provided a one year extension of 50% bonus depreciation, increasing the Company's 2014 federal tax depreciation by an estimated $162 million, primarily attributable to the Utilities. Previously, the American Taxpayer Relief Act of 2012 provided 50% bonus depreciation through 2013, resulting in an increase in 2013 federal tax depreciation of $160 million, primarily attributable to the Utilities.

Also, 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)	2014			% change		2013			% change		2012
Revenues	$	3,240		—		$	3,238		(4	)	$	3,375
Operating income	329			4		315			11		284
Net income for common stock	168			4		162			16		139
Net income (loss) by segment:
Electric utility	$	138		12		$	123		24		$	99
Bank	51			(11	)	58			(2	)	59
Other	(21		)	NM		(19		)	NM		(19		)
Net income for common stock	$	168		4		$	162		16		$	139
Basic earnings per share	$	1.65		1		$	1.63		14		$	1.43
Diluted earnings per share	$	1.64		1		$	1.62		14		$	1.42
Dividends per share	$	1.24		—		$	1.24		—		$	1.24
Weighted-average number of common shares outstanding (millions)	102.0			3		99.0			2		96.9
Dividend payout ratio	75		%			76		%			87		%


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 2014, the Company’s retirement benefit plans’ assets generated a gain of 6.8%, net of investment management and trustee fees, resulting in net earnings and unrealized gains of $90 million, compared to net earnings and unrealized gains of

$223 million for 2013 and $134 million for 2012. The market value of the retirement benefit plans’ assets for December 31, 2014 and 2013 were $1.4 billion and $1.4 billion, respectively.

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 2015. 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 2015. Based on plan assets as of December 31, 2014 and various assumptions in Note 10 of the Consolidated Financial Statements, the Company estimates the net periodic pension cost contribution for 2015 will be $85 million ($2 million for HEI and $83 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)	2014		2013			(Estimated) 2015		2014		2013		2012		2014		2013		2012
Consolidated HEI	$	28	$	13		$	23	$	20	$	21	$	22	$	71	$	70	$	68
Consolidated Hawaiian Electric	—		(1		)	19		19		18		20		66		65		63

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, 2014, 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	$(139)/$157	$(128)/$145
Other benefits
Discount rate	'+/- 50	(14)/16	(14)/15
Health care cost trend rate	'+/- 100	4/(5)	4/(4)

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

Other segment.



(dollars in millions)	2014			% change	2013			% change	2012
Revenues ¹	$	—		NM	$	—		NM	$ –
Operating loss	(22		)	NM	(17		)	NM	(17	)
Net loss	(21		)	NM	(19		)	NM	(19	)


¹	Including writedowns of and net gains and losses from investments.


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 holding passive, venture capital investments (venture capital investments

with a carrying value of $0.1 million as of December 31, 2014); 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 $21 million in 2014 compared to $16 million in 2013 and $16 million in 2012. In 2014, HEI had approximately $5 million of expenses related to the proposed merger. In 2013, HEI had higher administrative and general expenses, including retirement benefits, partly offset by lower executive compensation.

The “other” segment’s interest expenses were $12 million in 2014, $16 million in 2013 and $16 million in 2012. In 2014, HEI had lower average interest rates, partly offset by the impact of higher average borrowings. 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. In 2013, $50 million of long-term debt was refinanced at a lower interest rate. The “other” segment’s income tax benefits were $13 million in 2014, $14 million in 2013 and $15 million in 2012.

Effects of inflation. U.S. inflation, as measured by the U.S. Consumer Price Index (CPI), averaged 1.6% in 2014, 1.5% in 2013 and 2.1% in 2012. Hawaii inflation, as measured by the Honolulu CPI, was 1.8% in 2013, 2.4% in 2012 and 3.7% in 2011. DBEDT estimates average Honolulu CPI to have been 1.5% in 2014 and forecasts it to be 2.2% for 2015.

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 in the foreseeable future.

The Company’s total assets were $11.2 billion as of December 31, 2014 and $10.3 billion as of December 31, 2013.

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



December 31	2014				2013
(dollars in millions)
Short-term borrowings—other than bank	$	119	3	%	$	105	3	%
Long-term debt, net—other than bank	1,507		44		1,493		45
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,791		52		1,727		51
	$	3,451	100	%	$	3,359	100	%

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



	Year ended December 31, 2014
(in millions)	Average balance		End-of-period balance		December 31, 2013
Short-term borrowings ¹
Commercial paper	$	71	$	119	$	105
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility			150		125

This table does not include Hawaiian Electric’s separate commercial paper issuances and line of credit facilities, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources.” At February 13, 2015, HEI’s outstanding commercial paper balance was $105 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2014 was $119 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, 2014. 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.

On May 2, 2014, HEI closed a two-year term loan from three banks for $125 million. See Note 8 of the Consolidated Financial Statements for a brief description of the loan agreement and the application of the proceeds of the loan.

In December 2014, HEI filed an omnibus shelf 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.

Following the announcement that HEI has agreed to merge with NextEra Energy, Inc., on December 4, 2014, Fitch Ratings (Fitch) placed the ‘BBB’ long-term issuer default rating of HEI on Rating Watch Positive and noted “Fitch will likely resolve the Rating Watch on the conclusion of the transaction and could upgrade HEI by one notch given its ownership by a higher rated company. In such a scenario, the ratings of HEI will be equalized with that of its wholly-owned subsidiary, Hawaiian Electric Company (HECO), given the transaction contemplates the spin-off of the bank.” The key ratings drivers cited were (1) modest improvement in business risk, (2) structural challenges in Hawaii, (3) regulatory approvals required, and (4) credit metrics trajectory unchanged. Fitch also noted that “[f]uture developments that may, individually or collectively, lead to negative rating action include:-- [a]n inability to earn an adequate and timely recovery on invested capital; -- [a]ccelerating competitive inroads by distributed generation and energy efficiency; and -- [f]ailure to consummate acquisition by Nextera [sic] and material deterioration in regulatory environment.”

On December 4, 2014, Moody’s affirmed the ratings of HEI (Baa2 stable). Moody’s views “NextEra’s acquisition as potentially beneficial to HECO which has been experiencing numerous operational challenges due to pressure from regulators and other stakeholders to reduce costs and expand the use of renewable generation.” Moody’s also noted that the “rating could be downgraded or placed on negative outlook should the company’s relationship with the regulators deteriorate to a point where it might affect the company’s credit metrics in a meaningful way, or if HECO’s cash flow to debt metric declined to 13% or below on a sustained basis.”

On December 4, 2014, S&P placed the ‘BBB-’ issuer credit rating for HEI on CreditWatch with positive implications. S&P indicated that “[i]n light of the level of NextEra’s investment in HEI, NextEra’s proposed method of funding the acquisition, opportunities for growth, and stated commitment from management, we assess HEI and HECO as “core” subsidiaries of NextEra. As a result, upon the close of the transaction, we expect to raise our issuer credit ratings on HEI and HECO to be aligned with that of the ultimate parent NextEra.” S&P issued a subsequent report on January 26, 2015, stating “[t]he ratings of HEI and its subsidiaries are on CreditWatch with positive implications because of the proposed merger with higher-rated NextEra Energy Inc.”

As of February 13, 2015, 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	Stable	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, $48 million (approximately 1.8 million shares) in 2013 and $47 million (approximately 1.8 million shares) in 2012. From March 6, 2014 to date and from August 18, 2011 to January 8, 2012, 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 $325 million in 2014, $362 million in 2013 and $279 million in 2012. Investing activities used net cash of $592 million in 2014, $598 million in 2013 and $471 million in 2012. In 2014, 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 and the proceeds from sales of investment securities, redemption of stock from Federal Home Loan Bank of Seattle and real estate acquired in settlement of ASB loans. Financing activities provided net cash of $223 million in 2014, $237 million in 2013 and $142 million in 2012. In 2014, net cash provided by financing activities included net increases in deposits, other bank borrowings, long-term debt and short-term borrowings and proceeds from the issuance of common stock, offset by the 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 2014, Hawaiian Electric and ASB (via ASB Hawaii) paid cash dividends to HEI of $88 million and $36 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 58% at December 31, 2014), 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 2015 through 2017 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 2015 through 2017 to repay HEI senior notes of $75 million maturing in March 2016 and and HEI’s $125 million two-year term loan maturing in May 2016, 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 2015 through 2017 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 the special dividend of $0.50 per share through some combination of the accumulation of dividends from subsidiaries and/or equity financing and for payment of additional transaction advisory fees and contingent payments (approximately $30 million) through additional debt and/or equity financing.

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 $60 million in 2014 ($59 million by the Utilities, $1 million by HEI and nil by ASB), $83 million in 2013 ($81 million by the Utilities, $2 million by HEI and nil by ASB) and $78 million in 2012 ($63 million by the Utilities, $2 million by HEI and $13 million by ASB) and are expected to total $86 million in 2015 ($84 million by the Utilities, $2 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 $2 million of benefits in 2014, $2 million in 2013 and $1 million in 2012 and expects to pay $2 million of benefits in 2015. 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, 2014
(in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Contractual obligations
Time certificates	$	256	$	100	$	72	$	3	$	431
Other bank borrowings	—		156		50		—		206
Long-term debt	—		200		50		1,257		1,507
Interest on certificates of deposit, other bank borrowings and long-term debt	79		143		131		760		1,113
Operating leases, service bureau contract and maintenance agreements	29		47		31		39		146
Open purchase order obligations¹	55		26		2		3		86
Fuel oil purchase obligations (estimate based on December 31, 2014 fuel oil prices)	427		349		—		—		776
Power purchase obligations–minimum fixed capacity charges	124		197		184		531		1,036
Total (estimated)	$	970	$	1,218	$	520	$	2,593	$	5,301


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 $30 million). As of December 31, 2014, 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 2015.

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 and the approval of holders of 75% of the outstanding shares of HEI common stock. 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 $6 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 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 plans for Hawaii’s energy future with the PUC, as required by PUC orders issued in April 2014. The plans filed were the Hawaiian Electric Power Supply Improvement Plan, Maui Electric Power Supply Improvement Plan, Hawaii Electric Light Power Supply Improvement Plan, Hawaiian Electric Companies Distributed Generation Interconnection Plan, and Hawaiian Electric Companies Integrated Interconnection Queue Plan. Under these plans, the Utilities will support sustainable growth of rooftop solar, expand use of energy storage systems, empower customers by developing smart grids, offer new products and services to customers (e.g., community solar, microgrids and voluntary “demand response” programs), and switch from high-priced oil to lower cost liquefied natural gas.

Transition to renewable energy. The Utilities are committed to assisting the State of Hawaii in achieving or exceeding its Renewable Portfolio Standard goal of 40% renewable energy by 2030 (see “Renewable energy strategy” below). In addition, while it will not take precedence over the Utilities’ work to increase their use of renewable energy, the Utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas (LNG) as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used for the remaining generation. In December 2013, the Utilities executed a non-binding memorandum of understanding with The Gas Company, LLC d/b/a HawaiiGAS, documenting the parties’ desire to work together to (a) develop and/or secure infrastructure for large scale importation of LNG into Hawaii and (b) establish a consortium to competitively procure the LNG and provide storage and regasification of it at an LNG terminal site. In March 2014, Hawaiian Electric issued a RFP for the supply of containerized LNG. Hawaiian Electric received 3 final bid submissions in May 2014 and is in the final stage of selecting an LNG supplier. Also, see "Liquefied natural gas" in Note 4 of the Consolidated Financial Statements for a description of Hawaiian Electric's agreement with Fortis BC Energy Inc.

After launching a smart grid customer engagement plan during the second quarter of 2014, Hawaiian Electric replaced approximately 5,200 residential and commercial meters with smart meters in selected areas across Oahu as part of the Smart Grid Initial Phase. The Initial Phase is expected to run through 2015 and includes the installation of direct load control water heating switches and the launch of a Pre Pay Application. Also under the Initial Phase, fault circuit indicators and key remote controlled switches have been installed, a grid efficiency measure called Volt/Var Optimization was turned on and customer energy portals were launched and are available for customer use. The smart grid provides benefits such as customer tools to manage their electric bills, potentially shortening outages and enabling the Utilities to integrate more low-cost renewable energy, like wind and solar, which will reduce Hawaii’s dependence on imported oil. The Utilities are planning to seek approval from the PUC in 2015 to commit funds for an expansion of the smart grid project, including at Hawaii Electric Light and Maui Electric.

Decoupling. In 2010, the PUC issued an order approving decoupling, which was implemented by the Utilities in 2011 and 2012. The decoupling model implemented delinks revenues from sales and includes annual rate adjustments for certain O&M expenses and rate base changes.

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

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

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

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

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling, 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 February 7, 2014, in the first part of this bifurcated proceeding, the PUC issued a D&O on select issues, which made certain modifications to the decoupling mechanism. Among other things, the D&O requires:


•	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 was previously approved.

The second part of this proceeding continued with panel hearings held in October 2014. The proceeding is currently pending a PUC order instructing the parties regarding the issues and scope for limited briefs and reply briefs. See "Decoupling" in Note 4 of the Consolidated Financial Statements.

Actual and PUC-allowed (as of December 31, 2014) returns were as follows:



%	Return on rate base (RORB)*					ROACE**						Rate-making ROACE***
Year ended December 31, 2014	Hawaiian Electric		Hawaii Electric Light		Maui Electric	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric
Utility returns	7.76		6.28		7.50	8.74		6.71		8.81		9.85		6.65		9.44
PUC-allowed returns	8.11		8.31		7.34	10.00		10.00		9.00		10.00		10.00		9.00
Difference	(0.35	)	(2.03	)	0.16	(1.26	)	(3.29	)	(0.19	)	(0.15	)	(3.35	)	0.44

* 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 executive incentive compensation and certain advertising.

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

•the timing of general rate case decisions,


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

•the 5-year historical average for baseline plant additions,


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

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

The structural gap in 2015 to 2017 is expected to be 100 to 120 basis points. Factors which impact the range of the structural gap include the actual sales impacting the size of the RBA regulatory asset, the actual level of baseline additions in any given year relative to the 5-year historical average, 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 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 in excess of indexed escalations. The specific magnitude of the impact will depend on various factors, including changes in the required annual pension contribution, the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.

As part of decoupling, the Utilities also track their rate-making ROACEs as calculated under the earnings sharing mechanism, which includes only items considered in establishing rates. At year-end, each utility's rate-making ROACE is

compared against its ROACE allowed by the PUC to determine whether earnings sharing has been triggered. Annual earnings of a utility over and above the ROACE allowed by the PUC are shared between the utility and its ratepayers on a tiered basis. For 2014 and 2013, the earnings sharing mechanism was triggered for Maui Electric, and Maui Electric will credit $0.5 million and credited $0.4 million, respectively, to its customers for their portion of the earnings sharing. For 2012, the earnings sharing mechanism was triggered for Hawaiian Electric, and Hawaiian Electric credited its customers $2.6 million for their portion of the earnings sharing. Hawaiian Electric’s 2012 rate-making ROACE of 10.70% included various adjustments to Hawaiian Electric’s actual ROACE of 7.57% such as the exclusion of the $40 million of CIS project costs pursuant to the 2013 Agreement, and other expenses not considered in establishing electric rates (e.g., executive incentive compensation and certain advertising). Earnings sharing credits are included in the annual decoupling filing for the following year.

Annual decoupling filings. On May 30, 2014, the PUC approved the revised annual decoupling filings for tariffed rates for the Utilities that will be effective from June 1, 2014 through May 31, 2015. The tariffed rates include: (1) RAM adjusted revenues (the components of the annual incremental changes are shown below) with the 2014 rate base RAM return on investment calculated as the PUC ordered in its recent investigative docket on the decoupling mechanism, (2) accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2014 (and associated revenue taxes) to be collected:



(in millions)	Hawaiian Electric		Hawaii Electric Light		Maui Electric
Annual incremental RAM adjusted revenues
Operations and maintenance	$	4.0	$	0.9	$	1.0
Invested capital	26.8		3.9		4.4
Total annual incremental RAM adjusted revenues	$	30.8	$	4.8	$	5.4
Accrued earnings sharing credits to be refunded	$	—	$	—	$	(0.4	)
Accrued RBA balance as of December 31, 2014 (and associated revenue taxes) to be collected	$	72.6	$	8.2	$	9.6

Results of operations.


•	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 ¹
8,976			9,070			(94		)				Kilowatthour sales (millions) ²
4,909			4,506			403						Cooling degree days (Oahu)
2,759			2,764			(5		)				Number of employees (at December 31)


•	2013 vs. 2012



2013			2012			Increase (decrease)						(dollars in millions, except per barrel amounts)
$	2,980		$	3,109		$	(129	)				Revenues. Decrease largely due to:
									$	(150	)	Lower fuel prices and lower KWH sales
									(12		)	Maui Electric test year 2012 final D&O
									35			Higher decoupling revenues
1,186			1,297			(111		)				Fuel oil expense. Decrease largely due to lower fuel costs and less KWHs generated
711			725			(14		)				Purchased power expense. Decrease due to lower purchased power energy costs offset by higher KWHs purchased
403			397			6						Operation and maintenance expense. Increase largely due to:
									11			Higher customer service expenses (CIS and customer service support) offset by
									(8		)	Lower costs in overhauls, substation maintenance costs at Maui Electric and overhead line maintenance costs at Maui Electric and Hawaii Electric Light
435			480			(45		)				Other expenses. Decrease largely due to:
									(40		)	Write down of CIS project costs in 2012
									(12		)	Lower revenues in 2013 (which resulted in lower taxes, other than income taxes)
									9			Increase in depreciation due to increase in plant investments
246			213			33						Operating income. Increase largely due to write down of CIS project costs in 2012 offset by higher customer service expenses
8			11			(3		)				Allowance for funds used during construction
123			99			24						Net income for common stock. Increase largely due to write down of CIS project costs recognized in 2012
8.0		%	6.9		%	1.1		%				Return on average common equity
131.10			138.09			(6.99		)				Average fuel oil cost per barrel ¹
9,070			9,206			(136		)				Kilowatthour sales (millions) ²
4,506			4,532			(26		)				Cooling degree days (Oahu)
2,764			2,658			106						Number of employees (at December 31)


¹	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.


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

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

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

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

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

(3)

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

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

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


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

Hawaiian Electric 2011 test year rate case. In the Hawaiian Electric 2011 test year rate case, the PUC had granted Hawaiian Electric’s request to defer 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. This resulted in additional revenues of $7 million and $5 million for the first and second quarters of 2014, respectively, for a year-to-date amount of $12 million. There were no additional revenues recorded in the third quarter of 2014 as a result of the 2013 Agreement. See “Commitments and contingencies—Utility projects” in Note 4 of the Consolidated Financial Statements for additional information on the 2013 Agreement and the 2013 D&O and their effects.

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

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

Hawaiian Electric further explained that the abbreviated filing satisfies the obligation to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O. If the PUC determines that additional materials are required, Hawaiian Electric stated it will work with the Consumer Advocate on a schedule to submit additional information as needed. Hawaiian Electric asked for an expedited decision on this filing and stated that if the PUC decides that such a ruling is not in order, Hawaiian Electric reserves the right to supplement the abbreviated filing with additional material to support the increase in revenue requirements forgone by this filing-calculated to be $56 million over revenues at current effective rates. Hawaiian Electric’s revenue at current effective rates includes: (1) the revenue from Hawaiian Electric’s base rates, including the revenue from the energy cost adjustment clause and the purchased power adjustment clause, (2) the revenue that would be included in the decoupling 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 October 17, 2014, Maui Electric filed its notice of intent to file a general rate case application by the end of 2014, utilizing a 2015 calendar test year. The rate case filing is required to satisfy the obligation to file a general rate case under the three-year cycle established by the PUC in the decoupling final D&O. On December 30, 2014, Maui Electric filed its abbreviated 2015 test year rate case filing. In recognition that its customers have been enduring a high bill environment, Maui Electric proposed no change to its base rates, thereby foregoing the opportunity to seek a general

rate increase. If Maui Electric were to seek an increase in base rates, its requested increase in revenue, based on its revenue requirement for a normalized 2015 test year, would have been $11.6 million, or 2.8%, over revenues at current effective rates with estimated 2015 rate adjustment mechanism (RAM) revenues. The normalized 2015 test year revenue requirement is based on an estimated cost of common equity of 10.75%. Management cannot predict any actions by the PUC as a result of this filing.

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

Renewable energy strategy. The Utilities’ policy is to support efforts to increase renewable energy in Hawaii. The Utilities believe their actions will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel. The Utilities’ renewable energy strategy will also allow them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. The Utilities met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including savings from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from DSM energy efficiency programs and solar water heating will not count toward the RPS after 2014. For 2014, the Utilities achieved an RPS without DSM energy savings of an estimated 21%, primarily through a comprehensive portfolio of renewable energy power purchase agreements (PPAs), net energy metering programs and biofuels. The Utilities have been successful in adding significant amounts of renewable energy resources to their electric systems. The Utilities are on track to exceed their 2015 RPS goal, and lead the nation in terms of the amount of photovoltaic (PV) systems installed by its customers. Additionally, the State continues to pursue reduction in energy use, as embodied in its energy efficiency portfolio standard goals.

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

Developments in the Utilities’ renewable energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 4 of the Consolidated Financial Statements):

•

In July 2011, the PUC directed Hawaiian Electric to submit a draft request for proposals (RFP) for the PUC’s consideration for a competitive bidding process for 200 MW or more of renewable energy to be delivered to, or to be sited on, the island of Oahu. In October 2011, Hawaiian Electric filed a draft RFP with the PUC. In July 2013, the PUC issued orders related to the 200 MW RFP. First, it issued an order that Hawaiian Electric shall amend its current draft of the Oahu 200 MW RFP to remove references to the Lanai Wind Project, eliminate solicitations for an undersea transmission cable, and amend the draft RFP to reflect other guidance provided in the order. Second, it initiated an investigative proceeding to review the progress of the Lanai Wind Project stating that there was an uncertainty whether the project developer retained an equivalent ability to develop the project as when it submitted its bid in 2008 and its term sheet in 2011. Third, the PUC initiated a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui. (see Note 4 of the Consolidated Financial Statements for additional information).


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


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


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


•	In May 2012, Hawaii Electric Light signed a PPA, which the PUC approved in December 2013, with Hu Honua Bioenergy for 21.5 MW of renewable, dispatchable firm capacity fueled by locally grown biomass from a facility on the island of Hawaii.


•	In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii. Bids were received in January 2015, and

in February 2015, Ormat Technologies, Inc. was selected to provide 25 MW of additional geothermal energy, subject to successful contract negotiations and PUC approval of the final agreement.


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


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


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


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


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


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

•

In February 2013, Hawaiian Electric issued an “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding,” which seeks to lower the cost of electricity for customers in the near term with qualified renewable energy projects on Oahu that can be quickly placed into service at a low cost per KWH. Proposals were received and Hawaiian Electric obtained waivers from the PUC Competitive Bidding Framework for certain projects, subject to certain conditions. In the fourth quarter of 2014, Hawaiian Electric filed applications requesting PUC approval of power purchase agreements for renewable as-available energy for seven projects that were granted waivers from the Competitive Bidding Framework.

•

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


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


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


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


•	In December 2013, the PUC denied approval of Hawaii Electric Light’s contract with Aina Koa Pono-Ka’u LLC (AKP) to supply 16 million gallons of biodiesel per year, citing the higher cost of the biofuel over the cost of petroleum diesel.

•

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


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


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


•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2014, there were 11 MW, 1 MW and 2 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, 2014, there were approximately 214 MW, 46 MW and 48 MW of installed net energy metering capacity from renewable energy technologies (mainly PV) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively. The amount of net energy metering capacity installed in 2014 was about 32% lower than the amount installed in 2013, principally due to higher circuit saturations (resulting in the need for further technical reviews and potential equipment modification and/or upgrades).

Other regulatory matters. In addition to the items below, also see “Hawaii Clean Energy Initiative” and “Utility projects” in Note 4 of the Consolidated Financial Statements.

Adequacy of supply.

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

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

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

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

Maui Electric. In January 2015, Maui Electric filed its 2015 AOS letter, which indicated that Maui Electric’s generation capacity through 2018 is sufficient to meet the forecasted demands on the islands of Maui, Lanai, and Molokai. Maui Electric anticipates needing additional firm capacity on Maui in the 2019 timeframe. In February 2014, Maui Electric deactivated two fossil fuel generating units at its Kahului Power Plant. In January 2015, the two deactivated units at Kahului Power Plant were reactivated for a 3-day period based on forecasts of insufficient total system capacity due to scheduled maintenance for other generating units. Maui Electric anticipates the retirement of all generating units at the Kahului Power Plant in the 2019 timeframe. Maui Electric plans to issue one or more RFPs for energy storage, demand response and firm generating capacity, and to make system improvements needed to ensure reliability and voltage support in this timeframe.

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

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

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 “Hawaii Clean Energy Initiative” and “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.

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 is monitoring utility property and equipment near the affected areas and protecting that property and equipment to the extent possible (e.g., building barriers around poles).

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	2014				2013
(dollars in millions)
Short-term borrowings	$	—	—	%	$	—	—	%
Long-term debt, net	1,207		41		1,218		43
Preferred stock	34		1		34		1
Common stock equity	1,682		58		1,594		56
	$	2,923	100	%	$	2,846	100	%

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



	Year ended December 31, 2014
(in millions)	Average balance		End-of-period balance		December 31, 2013
Short-term borrowings¹
Commercial paper	$	56	$	—	$	—
Line of credit draws			—		—
Borrowings from HEI			—		—
Undrawn capacity under line of credit facility			200		175

The maximum amount of external short-term borrowings in 2014 was $103 million. At December 31, 2014, Hawaii Electric Light and Maui Electric had short-term borrowings from Hawaiian Electric of $11 million and $6 million, respectively, which intercompany borrowings are eliminated in consolidation. At February 13, 2015, Hawaiian Electric had $52 million of outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had loans to Hawaii Electric Light and Maui Electric of $21 million and $9 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.

Following the announcement that HEI has agreed to merge with NextEra Energy, Inc., on December 4, 2014, Fitch affirmed the ‘BBB+’ long-term issuer default rating of Hawaiian Electric with a stable rating outlook. Fitch noted that “HECO will benefit significantly from Nextera’s [sic] ownership, in Fitch’s view, given access to Nextera’s [sic] expertise in developing renewable projects, superior operational performance and portfolio transformation to cleaner fuels in addition to access to capital. However, the structural weakness in its service territory due to rising penetration of roof top solar compounded by the uncertainty around the fleet modernization plan limits any positive rating actions at this time.” The key ratings drivers cited

were (1) modest improvement in business risk, (2) structural challenges in Hawaii, (3) regulatory approvals required, and (4) credit metrics trajectory unchanged. Fitch also noted that “[f]uture developments that may, individually or collectively, lead to negative rating action include:-- [a]n inability to earn an adequate and timely recovery on invested capital; -- [a]ccelerating competitive inroads by distributed generation and energy efficiency; and -- [f]ailure to consummate acquisition by Nextera [sic] and material deterioration in regulatory environment.”

On December 4, 2014, Moody’s affirmed the ratings of Hawaiian Electric (Baa1 stable). Moody’s views “NextEra’s acquisition as potentially beneficial to HECO which has been experiencing numerous operational challenges due to pressure from regulators and other stakeholders to reduce costs and expand the use of renewable generation.” Moody’s also noted that the “rating could be downgraded or placed on negative outlook should the company’s relationship with the regulators deteriorate to a point where it might affect the company’s credit metrics in a meaningful way, or if HECO’s cash flow to debt metric declined to 13% or below on a sustained basis.”

On December 4, 2014, S&P placed the ‘BBB-’ issuer credit rating for Hawaiian Electric on CreditWatch with positive implications. S&P indicated that “[i]n light of the level of NextEra’s investment in HEI, NextEra’s proposed method of funding the acquisition, opportunities for growth, and stated commitment from management, we assess HEI and HECO as “core” subsidiaries of NextEra. As a result, upon the close of the transaction, we expect to raise our issuer credit ratings on HEI and HECO to be aligned with that of the ultimate parent NextEra.” S&P issued a subsequent report on January 26, 2015, stating “the outlook on HECO mirrors the outlook on parent HEI. The ratings on HEI and its subsidiaries are on CreditWatch with positive implications because of the proposed merger with higher-rated NextEra Energy Inc.”

As of February 13, 2015, 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	*	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	Stable	Watch-Positive

* Not rated.

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 SPRBs currently outstanding and issued prior to 2009 are insured by Financial Guaranty Insurance Company (FGIC), which was placed in a rehabilitation proceeding in the State of New York in June 2012. On August 19, 2013 FGIC's plan of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings of FGIC, which at the time the insured obligations were issued were higher than the ratings of the Utilities, have been withdrawn. Management believes that if Hawaiian Electric’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be more difficult and/or expensive to sell bonds in the future.

In April 2014, Hawaiian Electric, Hawaii Electric Light and Maui Electric filed an application with the PUC for approval of the sale of each utility’s common stock over a period from the date of approval in 2014 to December 31, 2016 (Hawaiian Electric’s sale to HEI of up to $250 million and Hawaii Electric Light’s and Maui Electric’s sales to Hawaiian Electric of up to

$26 million and $47 million, respectively), and the purchase of the Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric over the same period. In July 2014, the Utilities modified their request to the PUC to approve the issuance and sale of common stock in 2014 only in the amounts stated in the application (Hawaiian Electric’s issuance and sale of its common stock to HEI of up to $60 million and Hawaii Electric Light’s and Maui Electric’s issuance and sale of their common stock to Hawaiian Electric of up to $5 million and $20 million, respectively), which the PUC approved in November 2014. In December 2014, Hawaiian Electric sold $40 million of its common stock to HEI pursuant to this approval. Hawaii Electric Light and Maui Electric did not issue common stock in 2014.

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

Cash flows from operating activities generally relate to the amount and timing of cash received from customers and payments made to third parties. Using the indirect method of determining cash flows from operating activities, noncash expense items such as depreciation and amortization, as well as changes in certain assets and liabilities, are added to (or deducted from) net income. In 2014 and 2013, net cash provided by operating activities decreased by $20 million and increased by $105 million, respectively, compared to the prior year. In 2014, noncash depreciation and amortization amounted to $173 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 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 2013, noncash depreciation and amortization amounted to $159 million due to an increase in plant and equipment and deferred income taxes increased $65 million. Further, net cash provided by operating activities included a net decrease of $40 million in accounts receivable and accrued unbilled revenues due to more cash receipts from customers as a result of improved collections, a $27 million decrease in fuel oil stock due to lower payments to fuel suppliers, and a $15 million increase in accounts payable due to timing of vendor payments.

In 2014 and 2013, net cash used in investing activities decreased by $51 million and increased by $36 million, respectively, compared to the prior year. In 2014 and 2013, cash used for capital expenditures amounted to $337 million and $378 million, respectively, offset by contributions in aid of construction of $42 million and $32 million, respectively.

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. In 2014 and 2013, cash flows from financing activities decreased by $126 million and increased by $9 million, respectively, compared to the prior year. In 2014, cash used 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. In 2013, cash provided by financing activities consisted primarily of net proceeds received from the issuance of $236 million of taxable unsecured senior notes and $79 million of common stock, partially offset by the redemption of $166 million of special purpose revenue bonds and the payment of $84 million of common and preferred stock dividends.

For the three-year period 2015 through 2017, the Utilities forecast $1.9 billion of net capital expenditures, which could change over time based upon external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation. Hawaiian Electric’s consolidated cash flows from operating activities (net income for common stock, adjusted for non-cash income and expense items such as depreciation, amortization and deferred taxes), after the payment of common stock and preferred stock dividends, are currently not expected to provide sufficient cash to cover the forecasted net capital expenditures. Debt and equity financing are expected to be required to fund this estimated shortfall and to fund any unanticipated expenditures not included in the 2015 through 2017 forecast, such as increases in the costs or acceleration of the construction of capital projects, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements.

Proceeds from the issuance of equity, cash flows from operating activities, temporary increases in short-term borrowings and existing cash and cash equivalents are expected to provide the forecasted $420 million needed for the net capital expenditures and deferred software costs in 2015. For 2015, net capital expenditures and deferred software costs include

approximately $255 million for transmission and distribution projects, approximately $80 million for generation projects and approximately $85 million for general plant and other projects.

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 $56 million for 2014, $61 million for 2013 and $53 million for 2012 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 2014, 2013 and 2012. Contributions by the electric utilities to the retirement benefit plans for 2014, 2013 and 2012 totaled $59 million, $81 million and $63 million, respectively, and are expected to total $84 million in 2015. In addition, the electric utilities paid directly $1 million of benefits in 2014, $1 million of benefits in 2013 and $1 million of benefits in 2012 and expect to pay $1 million of benefits in 2015. 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, 2014	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		$	1,157	$	1,207
Interest on long-term debt	61		121		119		750		1,051
Operating leases	8		11		7		14		40
Open purchase order obligations ¹	55		26		2		3		86
Fuel oil purchase obligations (estimate based on December 31, 2014 fuel oil prices)	427		349		—		—		776
Purchase power obligations-minimum fixed capacity charges	124		197		184		531		1,036
Total (estimated)	$	675	$	704	$	362	$	2,455	$	4,196

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, 2014, 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 2015 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 68% of the net energy the Utilities generate and purchase in 2015 will be from the burning of fossil fuel oil as compared to 69% in 2014. Purchased KWHs provided approximately 46%, 44%, and 42% of the total net energy generated and purchased in 2014, 2013 and 2012, 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 2% in 2014, 1% in 2013 and 4% in 2012 when compared to the prior year. The change in O&M expenses (excluding expenses covered by surcharges or by third parties) was 1%, 1% and 4% for 2014, 2013 and 2012, respectively, when compared to the prior year. O&M expenses (excluding expenses covered by surcharges or by third parties) for 2015 are projected to be approximately 2% higher than 2014.

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, 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 such as for the Hu Honua biomass facility.

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 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), under rules deemed applicable to the Utilities’ facilities (e.g., Regional Haze Rule), if currently proposed legislation, rules and standards are adopted (e.g., GHG emission reduction rules), or if new legislation, rules or standards are adopted in the future. Similarly, recently issued rules governing cooling water intake 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, 2014, the consolidated regulatory liabilities and regulatory assets of the Utilities amounted to $345 million and $905 million, respectively, compared to $349 million and $576 million as of December 31, 2013, 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, 2014 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, 2014, revenues applicable to energy consumed, but not yet billed to customers, amounted to $138 million and the RBA revenues recognized in 2014 amounted to $69 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.

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 2014 with assets of $5.6 billion and net income of $51 million, compared to assets of $5.2 billion as of December 31, 2013 and net income of $58 million in 2013.

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 improved in 2014 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 improved to 0.01% for 2014 compared to 0.09% for 2013. However, ASB’s provision for loan losses for 2014 was $6.1 million compared to $1.5 million for 2013 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 2014 and 2013, the estimated net income impact of the lower debit card interchange fees was $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.


•	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	160			160			—			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	177			171			6
Operating income	75			87			(12		)	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		)%


•	2013 vs. 2012



(in millions)	2013			2012			Increase (decrease)			Primary reason(s)
Interest income	$	186		$	190		$	(4	)	The impact of higher average earning asset balances was more than offset by lower yields on earning assets. ASB’s average loan portfolio balance for 2013 was $221 million higher than 2012 as the average HELOC, residential and commercial real estate loan balances increased by $95 million, $76 million and $39 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 $35 million as ASB sold $70 million of agency obligations. ASB used excess liquidity to fund the loan growth.
Noninterest income	72			76			(4		)	Lower gains on sales of loans as residential loan production has decreased in 2013 compared to 2012 with the upward movement of loan rates and a decrease in debit card fees as a result of being non-exempt from the Durbin Amendment, partly offset by higher fee income from other financial products and the gain on sale of the credit card portfolio.
Revenues	258			266			(8		)
Interest expense	10			11			(1		)	Lower funding costs as a result of the low interest rate environment. Average deposit balances for 2013 increased by $166 million compared to 2012 due to an increase in core deposits of $230 million, partly offset by a decrease in term certificates of $64 million. The other borrowings average balance decreased by $11 million due to lower retail repurchase agreements, partly offset by higher outstanding FHLB advances.
Provision for loan losses	1			13			(12		)	The provision for loan losses benefited from lower net charge-offs and improved credit quality associated with the continued improvement in Hawaii’s economy, partly offset by loan loss reserves established for the growth in the loan portfolio.
Noninterest expense	160			153			7			Higher compensation and benefits expenses related to increased business volume, sales and performance incentives and higher inflation-related employee benefit costs.
Expenses	171			177			(6		)
Operating income	87			89			(2		)	Lower net interest and noninterest income, and higher noninterest expenses, partly offset by a lower provision for loan losses.
Net income	58			59			(1		)	Lower operating income, partly offset by lower taxes.
Return on average common equity¹	11.4		%	11.7		%	(0.3		)%


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:



	2014						2013						2012
(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	$	171,142		$	310	0.18	$	170,695		$	239	0.14	$	203,751		$	269	0.13
Securities purchased under resale agreements	5,096			20		0.39	11,370			43		0.38	—			—		—
Available-for-sale investment securities
Taxable	525,949			11,336		2.16	519,220			11,192		2.16	560,102			12,040		2.15
Non-taxable	11,600			429		3.69	69,377			2,494		3.60	63,336			2,328		3.68
Total available-for-sale investment securities	537,549			11,765		2.19	588,597			13,686		2.33	623,438			14,368		2.30
Loans
Residential 1-4 family	2,023,816			90,591		4.48	1,970,918			93,293		4.73	1,894,603			99,056		5.23
Commercial real estate	557,924			23,904		4.28	441,734			19,547		4.42	402,410			18,387		4.57
Home equity line of credit	790,701			25,716		3.25	680,445			20,442		3.00	585,797			16,106		2.75
Residential land	16,276			1,106		6.79	20,985			1,308		6.23	34,744			2,097		6.04
Commercial	783,670			29,294		3.74	726,597			29,188		4.02	714,679			30,925		4.33
Consumer	110,440			8,730		7.90	114,871			9,191		8.00	101,933			9,486		9.31
Total loans ^3,4	4,282,827			179,341		4.19	3,955,550			172,969		4.37	3,734,166			176,057		4.71
Total interest-earning assets	4,996,614			191,436		3.83	4,726,212			186,937		3.96	4,561,355			190,694		4.18
Allowance for loan losses	(42,242		)				(42,114		)				(39,323		)
Non-interest-earning assets	460,923						426,608						433,521
Total Assets	$	5,415,295					$	5,110,706					$	4,955,553
Liabilities and Stockholder’s Equity:
Savings	$	1,879,373		1,134		0.06	$	1,805,363		1,052		0.06	$	1,727,754		1,128		0.07
Interest-bearing checking	738,651			126		0.02	665,941			106		0.02	612,629			111		0.02
Money market	171,889			214		0.12	182,343			232		0.13	202,539			319		0.16
Time certificates	434,934			3,603		0.83	454,021			3,702		0.82	517,752			4,865		0.94
Total interest-bearing deposits	3,224,847			5,077		0.16	3,107,668			5,092		0.16	3,060,674			6,423		0.21
Advances from Federal Home Loan Bank	100,389			3,146		3.13	64,630			2,432		3.76	50,014			2,176		4.35
Securities sold under agreements to repurchase	155,012			2,585		1.67	146,758			2,553		1.74	172,683			2,693		1.56
Total interest-bearing liabilities	3,480,248			10,808		0.31	3,319,056			10,077		0.30	3,283,371			11,292		0.34
Non-interest bearing liabilities:
Deposits	1,285,964						1,179,559						1,060,121
Other	112,314						104,906						108,692
Stockholder’s equity	536,769						507,185						503,369
Total Liabilities and Stockholder’s Equity	$	5,415,295					$	5,110,706					$	4,955,553
Net interest income				$	180,628					$	176,860					$	179,402
Net interest margin (%)⁵						3.62						3.74						3.93


¹	Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million, $0.9 million and $0.8 million for 2014, 2013 and 2012, respectively.


²	Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank of Seattle ($83 million, $95 million and $97 million as of December 31, 2014, 2013 and 2012, respectively).


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


⁴	Includes loan fees of $3.7 million, $5.2 million and $4.9 million for 2014, 2013 and 2012, 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 $4.1 billion at the end of 2013 to $4.4 billion at the end of 2014 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	2014			2013
Outstanding balance (in thousands)	$	818,815		$	739,331
Percent of portfolio in first lien position	40.9		%	38.2		%
Net charge-off ratio	(0.07		)%	0.06		%
Delinquency ratio	0.25		%	0.28		%



							End of draw period – interest only									Current
December 31, 2014	Total			Interest only			2014-2015			2016-2018			Thereafter			amortizing
Outstanding balance (in thousands)	$	818,815		$	607,064		$	885		$	100,269		$	505,910		$	211,751
% of total	100		%	74		%	—		%	12		%	62		%	26		%

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 94% 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, 2014, approximately 20% of the portfolio balances were amortizing loans under the Fixed Rate Loan Option. Nearly all originations prior to 2008 consisted of amortizing equity lines that have structured principal payments during the draw period. These older vintage equity lines represent 6% 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 2014, the allowance for loan losses increased by $5.5 million primarily due to loan loss reserves for the growth in the loan portfolio and higher loss rates for loan portfolios with higher risk such as commercial real estate and unsecured personal loans.

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



December 31	2014				2013
(dollars in thousands)	Balance		% of total		Balance		% of total
U.S. Treasury and federal agency obligations	$	119,560	22	%	$	80,973	15	%
Mortgage-related securities — FNMA, FHLMC and GNMA	430,834		78		369,444		70
Municipal bonds	—		—		78,590		15
Total available-for-sale investment securities	$	550,394	100	%	$	529,007	100	%

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S. The increase in investment securities was due to the purchase of federal agency obligations and mortgage-related securities to replace the municipal bond portfolio that was sold in 2014.

The net unrealized gains on ASB’s investment securities were primarily caused by lower interest rates. All contractual cash flows of those investments are guaranteed by an agency of the U.S. government. See “Investment securities” in Note 1 for a discussion of securities impairment assessment.

As of December 31, 2014, 2013 and 2012, 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 Seattle and securities sold under agreements to repurchase continue to be additional sources of funds. As of December 31, 2014, ASB’s costing liabilities consisted of 94% deposits and 6% other borrowings. As of December 31, 2013, ASB’s costing liabilities consisted of 95% deposits and 5% 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, 2014 and 2013, ASB had an unrealized gain, net of taxes, on available-for-sale investment securities (including securities pledged for repurchase agreements) in AOCI of $0.5 million compared to an unrealized loss, net of taxes, of $4 million as of December 31, 2013. 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 is effective August 1, 2015.

The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. Financial institutions and their affiliates that have less than $10 billion in assets are exempt from this Amendment; however, on July 1, 2013, ASB became non-exempt as the consolidated assets of HEI exceeded $10 billion. ASB’s debit card interchange fees were impacted as a result of the application of this Amendment, by approximately $6 million after tax in 2014.

Final Capital Rules. On July 2, 2013, the FRB finalized its rule implementing the Basel III regulatory capital framework. The final rule would apply to banking organizations of all sizes and types regulated by the FRB and the OCC, except bank holding companies subject to the FRB’s Small Bank Holding Company Policy Statement and Savings & Loan Holding Companies (SLHCs) substantially engaged in insurance underwriting or commercial activities. HEI currently meets the requirements of the exemption as a top-tier grandfathered unitary SLHC that derived, as of June 30 of the previous calendar year, either 50% or more of its total consolidated assets or 50% or more of its total revenues on an enterprise-wide basis (calculated under GAAP) from activities that are not financial in nature pursuant to Section 4(k) of the Bank Holding Company Act. The FRB is temporarily excluding these SLHCs from the final rule while it considers a proposal relating to capital and other requirements for SLHC intermediate holding companies (such as ASB Hawaii). The FRB indicated that it would release a proposal on intermediate holding companies that would specify the criteria for establishing and transferring activities to intermediate holding companies and propose to apply the FRB’s capital requirements to such intermediate holding companies. The FRB has not yet issued such a proposal, nor a proposal on how to apply the Basel III capital rules to SLHCs that are substantially engaged in commercial or insurance underwriting activities, such as grandfathered unitary SLHCs like HEI.

Pursuant to the final rule and consistent with the proposals, all banking organizations, including covered holding companies, would initially be subject to the following minimum regulatory capital requirements: a common equity tier 1 capital ratio of 4.5%, a tier 1 capital ratio of 6%, a total capital ratio of 8% of risk-weighted assets and a leverage ratio of 4%, and these requirements would increase in subsequent years. In order to avoid restrictions on capital distributions and discretionary bonus payments to executive officers, the final rule requires a banking organization to hold a buffer of common equity tier 1 capital above its minimum risk-based capital requirements in an amount greater than 2.5% of total risk-weighted assets (capital conservation buffer). In addition, a countercyclical capital buffer would expand the capital conservation buffer by up to 2.5% of a banking organization’s total risk-weighted assets for advanced approaches banking organizations. The final rule would establish qualification criteria for common equity, additional tier 1 and tier 2 capital instruments that help to ensure their ability to absorb losses. All banking organizations would be required to calculate risk-weighted assets under the standardized approach, which harmonizes the banking agencies’ calculation of risk-weighted assets and address shortcomings in risk-based capital requirements identified by the agencies. 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 ratio + conservation buffer	4.50	%	5.125	%	5.75	%	6.375	%	7.00	%
Tier 1 capital ratio + conservation buffer	6.00	%	6.625	%	7.25	%	7.875	%	8.50	%
Total capital ratio + conservation buffer	8.00	%	8.625	%	9.25	%	9.875	%	10.50	%
Tier 1 leverage ratio	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Countercyclical capital buffer — not applicable to ASB			0.625	%	1.25	%	1.875	%	2.50	%

The final rule is effective January 1, 2015 for ASB. Subject to the timing and final outcome of the FRB’s SLHC intermediate holding company proposal, HEI anticipates that the capital requirements in the final rule will 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 of Seattle. As of December 31, 2014, ASB’s stock in FHLB of Seattle of $69.3 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, and ASB’s investment is substantially in excess of that requirement. In 2014 and 2013, the FHLB of Seattle paid ASB cash dividends of $88,000 and $47,000, respectively. FHLB of Seattle did not pay any cash dividends in 2012.

In September 2012, the Federal Housing Finance Agency (Finance Agency) classified the FHLB of Seattle as “adequately capitalized.” After receiving approval from the Finance Agency, the FHLB of Seattle began repurchasing excess stock, repurchasing a total of $23.2 million and $3.5 million of excess stock from ASB in 2014 and 2013, respectively.

In September 2014, the FHLB of Seattle announced that it had entered into an agreement to merge with the FHLB of Des Moines and in December 2014, the Finance Agency approved the banks’ application to merge. The merger agreement is pending approval and the voting process is scheduled to begin in mid-January and conclude in late February. The impact of this merger on ASB is uncertain at this time.

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 December 31, 2014, 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. The impact to property values and borrowers’ ability to repay their loans as a result of the lava flow cannot be determined at this time, but ASB does not expect the impact on ASB's financial condition or results of operations to be material.

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

Liquidity and capital resources.



December 31	2014		% change	2013		% change
(dollars in millions)
Total assets	$	5,565	6	$	5,244	4
Available-for-sale investment and mortgage-related securities	550		4	529		(21	)
Loans receivable held for investment, net	4,389		7	4,110		10
Deposit liabilities	4,623		6	4,372		3
Other bank borrowings	291		19	245		25

As of December 31, 2014, ASB was one of Hawaii’s largest financial institutions based on assets of $5.6 billion and deposits of $4.6 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, 2014 were $251 million higher than December 31, 2013. 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, 2014, FHLB borrowings totaled $100 million, representing 1.8% 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, 2014, ASB’s unused FHLB borrowing capacity was approximately $1.2 billion. As of December 31, 2014, securities sold under agreements to repurchase totaled $191 million, representing 3.4% 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, 2014, ASB had commitments to borrowers for loans and unused lines and letters of credit of $1.7 billion, including commitments to lend $0.5 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, 2014 and 2013, ASB had $36.9 million and $48.5 million of loans on nonaccrual status, respectively, or 0.8% and 1.2% of net loans outstanding, respectively. As of December 31, 2014 and 2013, ASB had $0.9 million and $1.2 million, respectively, of real estate acquired in settlement of loans

In 2014, operating activities provided cash of $42 million. Net cash of $299 million was used by investing activities primarily due to a net increase in loans held for investment of $284 million, purchases of investment securities of $184 million and capital expenditures of $28 million, partly offset by repayments of investment securities of $91 million, proceeds from the sales of investment securities of $80 million, redemption of FHLB stock of $23 million and proceeds from the sale of real estate acquired in settlement of loans of $3 million. Financing activities provided net cash of $261 million primarily due to a net increase in deposits of $251 million and proceeds from securities sold under agreements to repurchase of $56 million, partly offset by the payment of common stock dividends of $36 million and a net decrease in retail repurchase agreements of $9 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, 2014, 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, 2014, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.6 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, 2014, 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, 2014 with a tangible capital ratio of 8.9% (1.5%), a core capital ratio of 8.9% (4.0%) and a total risk-based capital ratio of 12.3% (8.0%).


•	ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2014 with a leverage ratio of 8.9% (5.0%), a Tier-1 risk-based capital ratio of 11.3% (6.0%) and a total risk-based capital ratio of 12.3% (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, 2014, 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, 2014, 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.

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. 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.

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. The financial impact of the calculated 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.

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 loan impairments for certain loans and goodwill.

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 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI and Hawaiian Electric:



Index to Consolidated Financial Statements	Page
Report of Independent Registered Public Accounting Firm - HEI	53
Report of Independent Registered Public Accounting Firm - Hawaiian Electric	54
Consolidated Financial Statements	55
HEI
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012	55
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	56
Consolidated Balance Sheets at December 31, 2014 and 2013	57
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2014, 2013 and 2012	58
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	59
Hawaiian Electric
Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012	60
Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	60
Consolidated Balance Sheets at December 31, 2014 and 2013	61
Consolidated Statements of Capitalization at December 31, 2014 and 2013	62
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2014, 2013 and 2012	64
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	65
Notes to Consolidated Financial Statements	66

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Hawaiian Electric Industries, Inc.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and its subsidiaries at December 31, 2014 and December 31, 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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. Management and we previously concluded that the Company maintained effective internal control over financial reporting as of December 31, 2014. However, management has subsequently determined that 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. Accordingly, management’s report has been restated and our present opinion on internal control over financial reporting, as presented herein, is different from that expressed in our previous report. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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 December 31, 2014 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.

As discussed in Note 1 to the consolidated financial statements and as discussed in the financial statement schedule, Schedule I, the Company has restated its 2013 and 2012 financial statements and financial statement schedule to correct errors.

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 26, 2015, except for the effects of the restatement and revision as discussed in Note 1 to the consolidated financial statements, the effects of the restatement and revision as discussed in the financial statement schedule, Schedule I, and the matter described in the penultimate paragraph of Management’s Report on Internal Control Over Financial Reporting, as to which the date is November 16, 2015

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Hawaiian Electric Company, Inc.

In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of income, comprehensive income, changes in common stock equity and cash flows present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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 consolidated financial statements, the Company has restated its 2013 and 2012 financial statements to correct errors.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 26, 2015, except for the effects of the restatement and revision as discussed in Note 1 to the consolidated financial statements, as to which the date is November 16, 2015

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries



Years ended December 31	2014			2013			2012
(in thousands, except per share amounts)
Revenues
Electric utility	$	2,987,323		$	2,980,172		$	3,109,439
Bank	252,497			258,147			265,539
Other	(278		)	151			17
Total revenues	3,239,542			3,238,470			3,374,995
Expenses
Electric utility	2,711,555			2,734,659			2,896,427
Bank	176,878			171,090			177,106
Other	22,185			17,302			17,266
Total expenses	2,910,618			2,923,051			3,090,799
Operating income (loss)
Electric utility	275,768			245,513			213,012
Bank	75,619			87,057			88,433
Other	(22,463		)	(17,151		)	(17,249		)
Total operating income	328,924			315,419			284,196
Interest expense, net – other than on deposit liabilities and other bank borrowings	(76,352		)	(75,479		)	(78,151		)
Allowance for borrowed funds used during construction	2,579			2,246			4,355
Allowance for equity funds used during construction	6,771			5,561			7,007
Income before income taxes	261,922			247,747			217,407
Income taxes	91,712			84,341			76,859
Net income	170,210			163,406			140,548
Preferred stock dividends of subsidiaries	1,890			1,890			1,890
Net income for common stock	$	168,320		$	161,516		$	138,658
Basic earnings per common share	$	1.65		$	1.63		$	1.43
Diluted earnings per common share	$	1.64		$	1.62		$	1.42
Dividends per common share	$	1.24		$	1.24		$	1.24
Weighted-average number of common shares outstanding	101,968			98,968			96,908
Net effect of potentially dilutive shares	969			655			430
Adjusted weighted-average shares	102,937			99,623			97,338

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	2014			2013			2012
(in thousands)
Net income for common stock	$	168,320		$	161,516		$	138,658
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 $(3,856), $9,037 and ($631) for 2014, 2013 and 2012, respectively	5,840			(13,686		)	956
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $1,132, $488 and $53 for 2014, 2013 and 2012, respectively	(1,715		)	(738		)	(81		)
Derivatives qualified as cash flow hedges:
Less: reclassification adjustment to net income, net of tax benefits of $150, $150 and $150 for 2014, 2013 and 2012, respectively	236			235			236
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of $149,364, ($142,478) and $63,303 for 2014, 2013 and 2012, respectively	(234,166		)	223,177			(99,159		)
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 $7,245, $14,870 and $9,764 for 2014, 2013 and 2012, respectively	11,344			23,280			15,291
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of ($132,373), $141,777 and ($48,299) for 2014, 2013 and 2012, respectively	207,833			(222,595		)	75,471
Other comprehensive income (loss), net of taxes	(10,628		)	9,673			(7,286		)
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	157,692		$	171,189		$	131,372

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

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries



December 31				2014						2013
(dollars in thousands)
ASSETS
Cash and cash equivalents				$	175,542					$	220,036
Accounts receivable and unbilled revenues, net				313,696						346,785
Available-for-sale investment securities				550,394						529,007
Stock in Federal Home Loan Bank of Seattle, at cost				69,302						92,546
Loans receivable held for investment, net				4,389,033						4,110,113
Loans held for sale, at lower of cost or fair value				8,424						5,302
Property, plant and equipment, net
Land	$	94,093					$	74,272
Plant and equipment	6,137,417						5,836,922
Construction in progress	168,214						146,742
	6,399,724						6,057,936
Less – accumulated depreciation	(2,250,950		)	4,148,774			(2,192,422		)	3,865,514
Regulatory assets				905,264						575,924
Other				541,542						512,627
Goodwill				82,190						82,190
Total assets				$	11,184,161					$	10,340,044
LIABILITIES AND SHAREHOLDERS’ EQUITY
Liabilities
Accounts payable				$	186,425					$	212,331
Interest and dividends payable				25,336						26,716
Deposit liabilities				4,623,415						4,372,477
Short-term borrowings—other than bank				118,972						105,482
Other bank borrowings				290,656						244,514
Long-term debt, net—other than bank				1,506,546						1,492,945
Deferred income taxes				631,734						529,260
Regulatory liabilities				344,849						349,299
Contributions in aid of construction				466,432						432,894
Defined benefit pension and other postretirement benefit plans liability				632,845						288,539
Other				531,230						524,224
Total liabilities				9,358,440						8,578,681
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: 102,565,266 shares and 101,259,800 shares at December 31, 2014 and 2013, respectively				1,521,297						1,488,126
Retained earnings				297,509						255,694
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains (losses) on securities	$	462					$	(3,663	)
Unrealized losses on derivatives	(289		)				(525		)
Retirement benefit plans	(27,551		)	(27,378		)	(12,562		)	(16,750		)
Total shareholders’ equity				1,791,428						1,727,070
Total liabilities and shareholders’ equity				$	11,184,161					$	10,340,044

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, 2011	96,038	$	1,349,446		$	198,397		$	(19,137	)	$	1,528,706
Net income for common stock	—	—			138,658			—			138,658
Other comprehensive loss, net of tax benefits	—	—			—			(7,286		)	(7,286		)
Issuance of common stock:
Dividend reinvestment and stock purchase plan	1,560	41,295			—			—			41,295
Retirement savings and other plans	330	8,196			—			—			8,196
Expenses and other, net	—	4,547			—			—			4,547
Dividend equivalents paid on equity-classified awards	—	—			(101		)	—			(101		)
Common stock dividends ($1.24 per share)	—	—			(120,150		)	—			(120,150		)
Balance, December 31, 2012	97,928	1,403,484			216,804			(26,423		)	1,593,865
Net income for common stock	—	—			161,516			—			161,516
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		$	255,694		$	(16,750	)	$	1,727,070
Net income for common stock	—	—			168,320			—			168,320
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		$	297,509		$	(27,378	)	$	1,791,428

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	2014			2013			2012
				As restated (1)			As restated (1)
(in thousands)
Cash flows from operating activities
Net income	$	170,210		$	163,406		$	140,548
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	172,762			160,061			150,389
Other amortization	6,795			4,667			7,958
Provision for loan losses	6,126			1,507			12,883
Impairment of utility assets	—			—			40,000
Loans receivable originated and purchased, held for sale	(155,755		)	(249,022		)	(519,622		)
Proceeds from sale of loans receivable, held for sale	155,030			273,775			513,000
Gain on sale of credit card portfolio	—			(2,251		)	—
Increase in deferred income taxes	103,916			80,399			90,848
Share-based compensation expense	9,287			7,780			6,698
Excess tax benefits from share-based payment arrangements	(277		)	(430		)	(61		)
Allowance for equity funds used during construction	(6,771		)	(5,561		)	(7,007		)
Change in cash overdraft	(1,038		)	1,038			—
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net	33,089			16,038			(18,501		)
Decrease in fuel oil stock	28,041			27,332			10,129
Increase in regulatory assets	(17,000		)	(65,461		)	(72,401		)
Increase (decrease) in accounts, interest and dividends payable	(67,189		)	12,406			5,497
Change in prepaid and accrued income taxes and utility revenue taxes	(39,091		)	(19,406		)	21,079
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	22,251			(33,014		)	(228		)
Change in other assets and liabilities	(94,966		)	(11,696		)	(102,275		)
Net cash provided by operating activities	325,420			361,568			278,934
Cash flows from investing activities
Available-for-sale investment securities purchased	(183,778		)	(112,654		)	(243,633		)
Principal repayments on available-for-sale investment securities	91,013			158,558			191,253
Proceeds from sale of available-for-sale investment securities	79,564			71,367			3,548
Redemption of stock from Federal Home Loan Bank of Seattle	23,244			3,476			1,742
Net increase in loans held for investment	(283,810		)	(398,426		)	(112,730		)
Proceeds from sale of real estate acquired in settlement of loans	3,213			9,212			11,336
Capital expenditures	(364,826		)	(389,438		)	(370,715		)
Contributions in aid of construction	41,806			32,160			45,982
Proceeds from sale of credit card portfolio	—			26,386			—
Other	1,125			1,177			1,778
Net cash used in investing activities	(592,449		)	(598,182		)	(471,439		)
Cash flows from financing activities
Net increase in deposit liabilities	250,938			142,561			159,884
Net increase in short-term borrowings with original maturities of three months or less	13,490			21,789			14,872
Net decrease in retail repurchase agreements	(9,465		)	(1,418		)	(37,291		)
Proceeds from other bank borrowings	130,601			130,000			5,000
Repayments of other bank borrowings	(75,000		)	(80,000		)	(5,000		)
Proceeds from issuance of long-term debt	125,000			286,000			457,000
Repayment of long-term debt	(111,400		)	(216,000		)	(375,500		)
Excess tax benefits from share-based payment arrangements	277			430			61
Net proceeds from issuance of common stock	26,898			55,086			23,613
Common stock dividends	(126,458		)	(98,383		)	(96,202		)
Preferred stock dividends of subsidiaries	(1,890		)	(1,890		)	(1,890		)
Other	(456		)	(1,187		)	(2,645		)
Net cash provided by financing activities	222,535			236,988			141,902
Net increase (decrease) in cash and cash equivalents	(44,494		)	374			(50,603		)
Cash and cash equivalents, January 1	220,036			219,662			270,265
Cash and cash equivalents, December 31	$	175,542		$	220,036		$	219,662

(1) As restated - See Note 1, “Summary of significant accounting policies - Revision and restatements of previously issued financial statements.”

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	2014			2013			2012
(in thousands)
Revenues	$	2,987,323		$	2,980,172		$	3,109,439
Expenses
Fuel oil	1,131,685			1,185,552			1,297,419
Purchased power	722,008			710,681			724,240
Other operation and maintenance	410,612			403,270			397,429
Depreciation	166,387			154,025			144,498
Taxes, other than income taxes	280,863			281,131			292,841
Impairment of utility assets	—			—			40,000
Total expenses	2,711,555			2,734,659			2,896,427
Operating income	275,768			245,513			213,012
Allowance for equity funds used during construction	6,771			5,561			7,007
Interest expense and other charges, net	(64,757		)	(59,279		)	(62,055		)
Allowance for borrowed funds used during construction	2,579			2,246			4,355
Income before income taxes	220,361			194,041			162,319
Income taxes	80,725			69,117			61,048
Net income	139,636			124,924			101,271
Preferred stock dividends of subsidiaries	915			915			915
Net income attributable to Hawaiian Electric	138,721			124,009			100,356
Preferred stock dividends of Hawaiian Electric	1,080			1,080			1,080
Net income for common stock	$	137,641		$	122,929		$	99,276

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	2014			2013			2012
(in thousands)
Net income for common stock	$	137,641		$	122,929		$	99,276
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of $139,236, ($129,601) and $57,375 for 2014, 2013 and 2012, respectively	(218,608		)	203,479			(90,082		)
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 $6,504, $13,180 and $8,709 for 2014, 2013 and 2012, respectively	10,212			20,694			13,673
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of ($132,373), $141,777 and ($48,069) for 2014, 2013 and 2012, respectively	207,833			(222,595		)	75,471
Other comprehensive income (loss), net of taxes	(563		)	1,578			(938		)
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	137,078		$	124,507		$	98,338

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

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2014			2013
(in thousands)
Assets
Property, plant and equipment
Utility property, plant and equipment
Land	$	52,299		$	51,883
Plant and equipment	6,009,482			5,701,875
Less accumulated depreciation	(2,175,510		)	(2,111,229		)
Construction in progress	158,616			143,233
Utility property, plant and equipment, net	4,044,887			3,785,762
Nonutility property, plant and equipment, less accumulated depreciation of $1,227 and $1,223 at respective dates	6,563			6,567
Total property, plant and equipment, net	4,051,450			3,792,329
Current assets
Cash and equivalents	13,762			62,825
Customer accounts receivable, net	158,484			175,448
Accrued unbilled revenues, net	137,374			144,124
Other accounts receivable, net	4,283			14,062
Fuel oil stock, at average cost	106,046			134,087
Materials and supplies, at average cost	57,250			59,044
Prepayments and other	66,383			52,857
Regulatory assets	71,421			69,738
Total current assets	615,003			712,185
Other long-term assets
Regulatory assets	833,843			506,186
Unamortized debt expense	8,323			9,003
Other	81,838			67,426
Total other long-term assets	924,004			582,615
Total assets	$	5,590,457		$	5,087,129
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,682,144		$	1,593,564
Cumulative preferred stock – not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (Note 4)
Long-term debt, net	1,206,546			1,206,545
Total capitalization	2,922,983			2,834,402
Current liabilities
Current portion of long-term debt	—			11,400
Accounts payable	163,934			189,559
Interest and preferred dividends payable	22,316			21,652
Taxes accrued	250,402			249,445
Regulatory liabilities	632			1,916
Other	65,146			63,881
Total current liabilities	502,430			537,853
Deferred credits and other liabilities
Deferred income taxes	602,872			507,161
Regulatory liabilities	344,217			347,383
Unamortized tax credits	79,492			73,539
Defined benefit pension and other postretirement benefit plans liability	595,395			262,162
Other	76,636			91,735
Total deferred credits and other liabilities	1,698,612			1,281,980
Contributions in aid of construction	466,432			432,894
Total capitalization and liabilities	$	5,590,457		$	5,087,129

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

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2014		2013
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding:
2014, 15,805,327 shares and 2013, 15,429,105 shares	$	105,388	$	102,880
Premium on capital stock	578,938		541,452
Retained earnings	997,773		948,624
Accumulated other comprehensive income, net of taxes - retirement benefit plans	45		608
Common stock equity	1,682,144		1,593,564
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, 2014 and 2013	2014		2013
(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	2014		2013
(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, 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, due 2025	40,000		40,000
Hawaii Electric Light, 4.80%, refunding series 2005A, due 2025	5,000		5,000
Maui Electric, 4.80%, refunding series 2005A, due 2025	2,000		2,000
Hawaii Electric Light, 5.50%, refunding series 1999A, paid in 2014	—		11,400
Total obligations to the State of Hawaii	462,000		473,400
Other long-term debt – unsecured:
Taxable senior notes:
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	693,000		693,000
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034	51,546		51,546
Total other long-term debt – unsecured	744,546		744,546
Total long-term debt	1,206,546		1,217,946
Less unamortized discount	—		1
Less current portion long-term debt	—		11,400
Long-term debt, net	1,206,546		1,206,545
Total capitalization	$	2,922,983	$	2,834,402

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, 2011	14,234	$	94,911	$	426,921	$	881,041		$	(32	)	$	1,402,841
Net income for common stock	—	—		—		99,276			—			99,276
Other comprehensive loss, net of tax benefits	—	—		—		—			(938		)	(938		)
Issuance of common stock, net of expenses	431	2,877		41,124		—			—			44,001
Common stock dividends	—	—		—		(73,044		)	—			(73,044		)
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 taxes	—	—		—		—			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 tax benefits	—	—		—		—			(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

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	2014			2013			2012
				As restated (1)			As restated (1)
(in thousands)
Cash flows from operating activities
Net income	$	139,636		$	124,924		$	101,271
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	166,387			154,025			144,498
Other amortization	6,410			5,077			6,998
Impairment of utility assets	—			—			40,000
Increase in deferred income taxes	82,947			64,507			86,878
Change in tax credits, net	6,062			7,017			6,075
Allowance for equity funds used during construction	(6,771		)	(5,561		)	(7,007		)
Change in cash overdraft	(1,038		)	1,038			—
Changes in assets and liabilities
Decrease (increase) in accounts receivable	26,743			49,445			(47,004		)
Decrease (increase) in accrued unbilled revenues	6,750			(9,826		)	3,528
Decrease in fuel oil stock	28,041			27,332			10,129
Decrease (increase) in materials and supplies	1,794			(7,959		)	(7,897		)
Increase in regulatory assets	(17,000		)	(65,461		)	(72,401		)
Increase (decrease) in accounts payable	(65,527		)	14,731			6,322
Change in prepaid and accrued income taxes and revenue taxes	(4,036		)	(2,028		)	25,239
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	(961		)	2,240			(744		)
Change in other assets and liabilities	(62,442		)	(32,636		)	(74,262		)
Net cash provided by operating activities	306,995			326,865			221,623
Cash flows from investing activities
Capital expenditures	(336,679		)	(378,044		)	(355,326		)
Contributions in aid of construction	41,806			32,160			45,982
Other	1,164			907			843
Net cash used in investing activities	(293,709		)	(344,977		)	(308,501		)
Cash flows from financing activities
Common stock dividends	(88,492		)	(81,578		)	(73,044		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,995		)	(1,995		)	(1,995		)
Proceeds from issuance of common stock	40,000			78,500			44,000
Proceeds from issuance of long-term debt	—			236,000			457,000
Repayment of long-term debt	(11,400		)	(166,000		)	(368,500		)
Other	(462		)	(1,149		)	(2,230		)
Net cash provided by (used in) financing activities	(62,349		)	63,778			55,231
Net increase (decrease) in cash and cash equivalents	(49,063		)	45,666			(31,647		)
Cash and cash equivalents, January 1	62,825			17,159			48,806
Cash and cash equivalents, December 31	$	13,762		$	62,825		$	17,159

(1) As restated - See Note 1, “Summary of significant accounting policies - Revision and restatements of previously issued financial statements.”

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 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).

Revision and restatements of previously issued financial statements. Management discovered that the Utilities’ capital expenditures on HEI’s and Hawaiian Electric’s Consolidated Statements of Cash Flows did not correctly account for the beginning of period unpaid invoices and accruals (that were paid in cash during the period) and is restating its previously filed Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012 and revising its previously filed Consolidated Statements of Cash Flow for the year ended December 31, 2014 to correct for such misstatement by adjusting cash used for “Capital expenditures” (investing activity) and change in accounts payable (operating activity).

Management also discovered that the eliminating journal entry to offset the Hawaiian Electric consolidated net operating loss deferred tax asset did not properly reflect the adjustment on the components of income taxes (current and deferred federal income taxes) and is restating its previously filed Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012 and revising its previously filed Consolidated Statements of Cash Flow for the year ended December 31, 2014 to correct for such misstatement by adjusting “Increase in deferred income taxes,” “Change in prepaid and accrued income taxes and utility revenue taxes” and “Change in other assets and liabilities” (operating activities).

Management determined it needed to correct the presentation for share-based compensation expense on the Company’s Consolidated Statement of Cash Flows, resulting in a corresponding change in the “Change in other assets and liabilities” amount.

This revision and restatements to correct for such misstatements and other immaterial items do not impact HEI’s and Hawaiian Electric’s previously reported overall net change in cash and cash equivalents in their Consolidated Statements of Cash Flows for any period presented. Additionally, the revision and restatements do not impact HEI’s and Hawaiian Electric’s Consolidated Balance Sheets or Consolidated Statements of Income for any period presented.The Company and Hawaiian Electric have concluded that the impact of the misstatements is not material to the previously issued Consolidated Statements of Cash Flow for the year ended December 31, 2014.

The table below illustrates the effects of the revision or restatements on the previously filed financial statements:



	2014									2013
	As									As
	previously			As						previously			As
(in thousands)	filed			revised			Difference			filed			restated			Difference
Consolidated Statements of Cash Flows and Note 3
HEI consolidated
Cash flows from operating activities
Other amortization	$	8,476		$	6,795		$	(1,681	)	N/A			N/A			N/A
Increase in deferred income taxes	59,184			103,916			44,732			N/A			N/A			N/A
Share-based compensation expense	—			9,287			9,287			$	—		$	7,780		$	7,780
Increase/(decrease) in accounts, interest and dividends payable	(92,294		)	(67,189		)	25,105			(23,153		)	12,406			35,559
Change in prepaid and accrued income taxes and utility revenue taxes	12,845			(39,091		)	(51,936		)	N/A			N/A			N/A
Change in other assets and liabilities	(93,400		)	(94,966		)	(1,566		)	(2,779		)	(11,696		)	(8,917		)
Net cash provided by operating activities	301,479			325,420			23,941			327,146			361,568			34,422
Cash flows from investing activities
Capital expenditures	(339,721		)	(364,826		)	(25,105		)	(353,879		)	(389,438		)	(35,559		)
Cash flows from investing activities-Other	(39		)	1,125			1,164			40			1,177			1,137
Net cash used in investing activities	(568,508		)	(592,449		)	(23,941		)	(563,760		)	(598,182		)	(34,422		)
Hawaiian Electric consolidated
Cash flows from operating activities
Other amortization	8,091			6,410			(1,681		)	N/A			N/A			N/A
Increase/(decrease) in accounts payable	(90,632		)	(65,527		)	25,105			(20,828		)	14,731			35,559
Change in other assets and liabilities	(62,959		)	(62,442		)	517			(31,499		)	(32,636		)	(1,137		)
Net cash provided by operating activities	283,054			306,995			23,941			292,443			326,865			34,422
Cash flows from investing activities
Capital expenditures	(311,574		)	(336,679		)	(25,105		)	(342,485		)	(378,044		)	(35,559		)
Cash flows from investing activities-Other	—			1,164			1,164			(230		)	907			1,137
Net cash used in investing activities	(269,768		)	(293,709		)	(23,941		)	(310,555		)	(344,977		)	(34,422		)
Note 12
HEI consolidated
Federal current taxes	33,762			(10,970		)	(44,732		)	N/A			N/A			N/A
Federal deferred taxes	46,427			91,159			44,732			N/A			N/A			N/A
Note 13
HEI consolidated
Property, plant and equipment - unpaid invoices and accruals (in millions)	68			43			(25		)	24			(12		)	(36		)
Hawaiian Electric consolidated
Electric utility property, plant and equipment - unpaid invoices and accruals (in millions)	65			40			(25		)	24			(12		)	(36		)

N/A - Not applicable.



	2012
	As previously			As
(in thousands)	filed			restated			Difference
Consolidated Statements of Cash Flows and Note 3
HEI consolidated
Cash flows from operating activities
Share-based compensation expense	$	—		$	6,698		$	6,698
Increase/(decrease) in accounts, interest and dividends payable	(39,738		)	5,497			45,235
Change in other assets and liabilities	(94,734		)	(102,275		)	(7,541		)
Net cash provided by operating activities	234,542			278,934			44,392
Cash flows from investing activities
Capital expenditures	(325,480		)	(370,715		)	(45,235		)
Cash flows from investing activities-Other	935			1,778			843
Net cash used in investing activities	(427,047		)	(471,439		)	(44,392		)
Hawaiian Electric consolidated
Cash flows from operating activities
Increase/(decrease) in accounts payable	(38,913		)	6,322			45,235
Change in other assets and liabilities	(73,419		)	(74,262		)	(843		)
Net cash provided by operating activities	177,231			221,623			44,392
Cash flows from investing activities
Capital expenditures	(310,091		)	(355,326		)	(45,235		)
Cash flows from investing activities-Other	—			843			843
Net cash used in investing activities	(264,109		)	(308,501		)	(44,392		)
Note 13
HEI consolidated
Property, plant and equipment - unpaid invoices and accruals (in millions)	37			(8		)	(45		)
Hawaiian Electric consolidated
Electric utility property, plant and equipment - unpaid invoices and accruals (in millions)	37			(8		)	(45		)

Consolidation. The HEI consolidated financial statements include the accounts of HEI and its subsidiaries (collectively, 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. All material intercompany accounts and transactions have been eliminated in consolidation. 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 3.1% in 2014, 2013 and 2012.

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.

The Company's operating lease expense was $19 million in 2014, 2013 and 2012. The Utilities' operating lease expense was $9 million, $8 million and $8 million in 2014, 2013 and 2012, respectively. The Company's and the Utilities' future minimum lease payments are as follows:



(in millions)	HEI		Hawaiian Electric
2015	$	17	$	8
2016	15		6
2017	12		5
2018	9		4
2019	7		3
Thereafter	23		14
	$	83	$	40

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 management. 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 written down 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.

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. HEI uses the two-class method of computing EPS as restricted stock grants include non-forfeitable rights to dividends and are participating securities.

Under the two-class method, HEI's EPS was comprised as follows for both participating securities and unrestricted common stock:



	2014				2013				2012
	Basic		Diluted		Basic		Diluted		Basic		Diluted
Distributed earnings	$	1.24	$	1.24	$	1.24	$	1.24	$	1.24	$	1.24
Undistributed earnings	0.41		0.40		0.39		0.38		0.19		0.18
	$	1.65	$	1.64	$	1.63	$	1.62	$	1.43	$	1.42

As of December 31, 2014 there were no shares that were antidilutive. As of December 31, 2013 and December 31, 2012, 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.

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

The Company and the Utilities retrospectively adopted ASU No. 2013-04 in the first quarter of 2014 and it did not have a material impact on the Company’s or the Utilities' results of operations, financial condition or liquidity.

Unrecognized tax benefits (UTBs). In July 2013, the FASB issued ASU No. 2013-11, “Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which requires the netting of UTBs against a deferred tax asset for a loss or other tax carryforwards that would apply in settlement of the uncertain tax positions. UTBs should be netted against all available same-jurisdiction loss or other tax carryforwards that would be utilized, rather than only against carryforwards that are created by the UTBs.

The Company and the Utilities prospectively adopted ASU No. 2013-11 in the first quarter of 2014 and it did not have a material impact on the Company’s or the Utilities' results of operations, financial condition or liquidity.

Investments in Qualified Affordable Housing Projects. In January 2014, the FASB issued ASU No. 2014-01, Investments-Equity Method and Joint Ventures (Topic 323): Accounting for Investments in Qualified Affordable Housing Projects,” which permits entities to make an accounting policy election to account for their investments in qualified affordable housing projects using the proportional amortization method if certain conditions are met. The amendments also require additional disclosures.

The Company has not determined whether it will adopt ASU No. 2014-01 in the first quarter of 2015.

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 plans to prospectively adopt ASU No. 2014-04 in the first quarter of 2015 and does not expect the adoption to have a material impact on the Company’s results of operations, financial condition or liquidity.

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

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

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

The Company plans to adopt ASU No. 2014-11 in the first quarter of 2015 and does not expect the adoption to have a material impact on the Company's results of operations, financial condition or liquidity.

Reclassifications. Hawaiian Electric changed its consolidated statements of income for each quarter in 2013 from a utility presentation to a commercial company presentation, under which all operating revenues and expenses (including non-regulated revenues and expenses) are included in the determination of operating income. Additionally, income tax expense, which was previously included partially in operating expenses and partially in other income (deductions), is now entirely presented directly above net income in income taxes and includes income taxes related to non-regulated revenues and expenses. On HEI’s consolidated balance sheet as of December 31, 2013, non-utility plant, net, amounting to $7 million was reclassified from “Other” assets to “Plant and equipment” (including related amounts of accumulated depreciation). These and other reclassifications made to prior years’ financial statements to conform to the 2014 presentation did not affect previously reported results of operations.

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. On a monthly basis, the Utilities adjust their allowance, with a corresponding charge (credit) on the statement of income, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote. At both December 31, 2014 and 2013, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $2 million.

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. Prior to the implementation of decoupling, 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 in the period are based on the prior year’s billed revenues (in the case of public service company taxes and PUC fees) or on the current year’s cash collections from electric sales (in the case of franchise taxes). For 2014, 2013 and 2012, the Utilities included approximately $267 million, $266 million and $280 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.

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 7.7% in 2014, 7.6% in 2013 and 7.6% in 2012, 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 deemed other-than-temporary impairment (OTTI), not related to credit losses, 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 over the remaining lives of the securities, adjusted for actual portfolio prepayments for investment securities or based on changes in anticipated prepayments for mortgage-related securities, using the interest method. The specific identification method is used in determining realized gains and losses on the sales of securities. 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. Estimates of future prepayments are based on the underlying collateral characteristics and historic prepayment behavior of each security.

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, 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.

Stock in Federal Home Loan Bank (FHLB) of Seattle 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 the 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. 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.

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 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 suffered from a loss-causing event. In most cases, the loss emergence period was within a twelve month period; however, 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.

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. 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 exist.

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 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, 2014 and 2013, 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. We performed a Step 0 analysis and determined that it was not more likely than not that the fair value of the Company 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 the Company exceeded its carrying value by 60%. For the three years ended December 31, 2014, 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. 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 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 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 MSR in proportion to and over the period of estimated net servicing income and assess 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 fair value.

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.

Under the equity method of accounting, ASB recognized its share of the project's pre-tax operating losses in "Other expense" in the statements of income.

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.

At December 31, 2014 and 2013, the carrying amount of qualifying affordable housing investments was $32.5 million and $14.5 million, respectively, and included in other assets in the consolidated balance sheets.

ASB’s unfunded commitments to fund to its affordable housing investments were $14.8 million and $0.6 million as of December 31, 2014 and 2013, 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.

2 · Proposed Merger

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

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

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

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

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

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

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

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

commercial interests, have moved to intervene in the proceeding. A PUC decision on the intervention motions and establishing a procedural schedule for the docket is pending.

Other requests. On January 29, 2015, HEI submitted its application to the FERC requesting all necessary authorization to consummate the transactions contemplated by the Merger Agreement. On February 1, 2015, HEI submitted a letter to FRB requesting deregistration as a Savings & Loan Holding Company (SLHC).

Pending litigation and other matters.

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

Since the December 3, 2014 announcement of the merger agreement, eight purported class action complaints were filed in the Circuit Court of the First Circuit for the State of Hawaii by alleged stockholders of HEI against HEI, Hawaiian Electric (in one complaint), the individual directors of HEI, NEE and NEE's acquisition subsidiaries. The lawsuits are captioned as follows: Miller v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2531-12 KTN (December 15, 2014) (the Miller Action); Walsh v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2541-12 JHC (December 15, 2014) (the Walsh Action); Stein v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2555-12 KTN (December 17, 2014) (the Stein Action); Brown v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2643-12 RAN (December 30, 2014) (the Brown Action); Cohn v. Hawaiian Electric Industries, Inc., et al., Case No. 14-1-2642-12 KTN (December 30, 2014) (the Cohn State Action); Guenther v. Watanabe, et al., Case No. 15-1-003-01 ECN (January 2, 2015) (the Guenther Action); Hudson v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0013-01 JHC (January 5, 2015) (the Hudson Action); Grieco v. Hawaiian Electric Industries, Inc., et al., Case No. 15-1-0094-01 KKS (January 21, 2015) (the Grieco Action). On January 12, 2015, plaintiffs in the Miller Action, the Walsh Action, the Stein Action, the Brown Action, the Guenther Action, and the Hudson Action filed a motion to consolidate their actions and to appoint co-lead counsel. On February 13, 2015, the Court held a hearing on this motion. On January 23, 2015, the Cohn State Action was voluntarily dismissed. Thereafter, the same alleged stockholder plaintiff filed a purported class action complaint in the United States District Court for the District of Hawaii against HEI, the individual directors of HEI, NEE and NEE's acquisition subsidiaries. The lawsuit is captioned as Cohn v. Hawaiian Electric Industries, Inc. et al., 15-cv-00029-JMS-KSC (January 27, 2015) (the Cohn Federal Action).

All eight 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. In addition, the Cohn Federal Action alleges that the HEI board of directors violated its fiduciary duties and federal securities laws by omitting material facts from the Registration Statement on Form S-4.

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

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

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.

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
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, as revised (1)	172,797		5,399		1,361			179,557
Interest expense, net	64,757		10,808		11,595			87,160
Income (loss) before income taxes	220,361		75,619		(34,058		)	261,922
Income taxes (benefit)	80,725		24,127		(13,140		)	91,712
Net income (loss)	139,636		51,492		(20,918		)	170,210
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	137,641		51,492		(20,813		)	168,320
Capital expenditures, as revised (1)	336,679		28,073		74			364,826
Assets (at December 31, 2014)	5,590,457		5,565,241		28,463			11,184,161
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	159,102		4,230		1,396			164,728
Interest expense, net	59,279		10,077		16,200			85,556
Income (loss) before income taxes	194,041		87,059		(33,353		)	247,747
Income taxes (benefit)	69,117		29,525		(14,301		)	84,341
Net income (loss)	124,924		57,534		(19,052		)	163,406
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	122,929		57,534		(18,947		)	161,516
Capital expenditures, as restated (1)	378,044		11,193		201			389,438
Assets (at December 31, 2013)	5,087,129		5,243,824		9,091			10,340,044
2012
Revenues from external customers	$	3,109,353	$	265,539	$	103		$	3,374,995
Intersegment revenues (eliminations)	86		—		(86		)	—
Revenues	3,109,439		265,539		17			3,374,995
Depreciation and amortization	151,496		5,334		1,517			158,347
Interest expense, net	62,055		11,292		16,096			89,443
Income (loss) before income taxes	162,319		89,021		(33,933		)	217,407
Income taxes (benefit)	61,048		30,384		(14,573		)	76,859
Net income (loss)	101,271		58,637		(19,360		)	140,548
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	99,276		58,637		(19,255		)	138,658
Capital expenditures, as restated (1)	355,326		14,979		410			370,715
Assets (at December 31, 2012)	5,108,793		5,041,673		(1,334		)	10,149,132

(1) As revised or restated - See Note 1, “Summary of significant accounting policies - Revision and restatements of previously issued financial statements.”

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

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

4 · Electric utility segment

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, 2014 are noted.

Regulatory assets were as follows:



December 31	2014		2013
(in thousands)
Retirement benefit plans (balance primarily varies with plans’ funded statuses)	$	683,243	$	350,821
Income taxes, net (1 to 55 years)	86,836		85,430
Decoupling revenue balancing account (1 to 2 years)	80,183		90,386
Unamortized expense and premiums on retired debt and equity issuances (19 to 30 years; 6 to 18 years remaining)	15,569		17,342
Vacation earned, but not yet taken (1 year)	10,248		9,149
Postretirement benefits other than pensions (18 years; less than 1 year remaining)	18		62
Other (1 to 50 years; 1 to 46 years remaining)	29,167		22,734
	$	905,264	$	575,924
Included in:
Current assets	$	71,421	$	69,738
Long-term assets	833,843		506,186
	$	905,264	$	575,924

Regulatory liabilities were as follows:



December 31	2014		2013
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	331,000	$	315,164
Retirement benefit plans (5 years beginning with respective utility’s next rate case)	12,413		31,546
Other (5 years; 1 to 2 years remaining)	1,436		2,589
	$	344,849	$	349,299
Included in:
Current liabilities	$	632	$	1,916
Long-term liabilities	344,217		347,383
	$	344,849	$	349,299

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 12% ($350 million), 11% ($340 million) and 11% ($349 million) of their operating revenues from the sale of electricity to various federal government agencies in 2014, 2013 and 2012, 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, 2014	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 $7 million, $6.2 million and $6.1 million for general management and administrative services in 2014, 2013 and 2012, 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, 2014 and 2013. 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 2014 and 2013 and de minimis in 2012.

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, 2014, the estimated cost of minimum purchases under the fuel supply contracts is $0.4 billion in 2015, $0.3 billion in 2016 and $6.4 million in 2017. The actual cost of purchases in 2015 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. The Utilities purchased $1.1 billion, $1.1 billion and $1.3 billion of fuel under contractual agreements in 2014, 2013 and 2012, respectively.

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. The amendment is subject to approval of the PUC, and can be terminated if approval is not received by April 15, 2015.

Hawaiian Electric and Hawaii Independent Energy, LLC, (HIE) a wholly owned subsidiary of Par Petroleum Corporation of Houston Texas, were parties to an amended LSFO supply contract (assigned to HIE pursuant to its purchase of the Hawaii refinery and related assets of Tesoro Hawaii Corp), which ran through December 31, 2014, with a provision that it would automatically renew for annual terms thereafter unless earlier terminated by either party. On August 28, 2014, Hawaiian Electric provided notice to HIE that it would not renew the LSFO supply contract.

The Utilities are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and HIE, respectively, which end December 31, 2015. 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, 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.

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, 2014, the Utilities had seven firm capacity PPAs for a total of 575 megawatts (MW) of firm capacity. Purchases from these seven independent power producers (IPPs) and all other IPPs totaled $0.7 billion for each of 2014, 2013 and 2012. 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 2015 through 2019 and a total of $0.5 billion in the period from 2020 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 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.

Hawaii Clean Energy Initiative. In January 2008, the State of Hawaii (State) and the U.S. Department of Energy signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism (DBEDT), the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs and the Utilities (collectively, the parties), signed an agreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement required approval of the PUC.

The parties to the Energy Agreement concluded that the agreements and policy directives in the Energy Agreement had been advanced or superseded by subsequent events, as well as by decisions and orders issued by the PUC, and accordingly ended the Energy Agreement on September 14, 2014. 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.

Utility projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery

for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in Hawaiian Electric’s consolidated net income.

In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for Hawaiian Electric’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the EOTP Phase I project cost issues and, in March 2013, the PUC eliminated the requirement for an audit of the CIP CT-1 and CIS project costs as described below.

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

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

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

In March 2012, the PUC approved a settlement agreement reached among Hawaiian Electric, the Consumer Advocate and the Department of Defense, under which, in lieu of a regulatory audit, Hawaiian Electric would write off $9.5 million of EOTP Phase 1 gross plant in service and associated adjustments. This resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million and the elimination of the requirement for a Phase 1 regulatory audit. The PUC also provided for an additional increase of approximately $5 million in Hawaiian Electric’s 2011 test year rate case for the additional revenue requirements reflecting all remaining Phase 1 costs not previously included in rates or agreed to be written off.

Renewable energy projects. The Utilities are committed to achieving or exceeding the State’s Renewable Portfolio Standard (RPS) goal of 40% renewable energy by 2030 and to decreasing the State’s dependence on imported fossil fuels. The Utilities continue to evaluate and pursue opportunities with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others.

In 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 Intrastructure Program (REIP) surcharge. The application is currently pending before the PUC.

A revised draft Request for Proposals (RFP) for 200MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands was posted on Hawaiian Electric's website prior to the issuance of a proposed final RFP. 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. On July 11, 2013, the PUC issued orders related to the 200 MW RFP, including an order initiating a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, Hawaii Electric Light filed an application to defer 2012 costs related to the Geothermal RFP. 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 the fourth quarter of 2014, Hawaiian Electric filed applications requesting PUC approval of power purchase agreements for renewable as-available energy for seven projects that were granted waivers from the Competitive Bidding Framework.

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 (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

On August 14, 2014, the Environmental Protection Agency (EPA) published in the Federal Register the final regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The regulations were effective October 14, 2014 and apply to the cooling water systems for the steam generating units at Hawaiian Electric’s power plants on the island of Oahu. The regulations prescribe a process, including a number of required site-specific studies, for states to develop facility-specific entrainment and impingement controls to be incorporated in the facility’s National Pollutant Discharge Elimination System permit. In the case of Hawaiian Electric's power plants, there are a number of studies that have yet to be completed before Hawaiian Electric and the Department of Health of the State of Hawaii (DOH) can determine what entrainment or impingement controls, if any, might be appropriate.

On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at Hawaiian Electric’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, Hawaiian Electric has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date of April 16, 2016. Hawaiian Electric also has pending with the EPA a Petition for Reconsideration and Stay dated April 16, 2012, and a Request for Expedited Consideration dated August 14, 2013. The submittals ask the EPA to revise an emissions standard for non-continental oil-fired EGUs on the grounds that the promulgated standard was incorrectly derived. The Petition and Request submittals to the EPA included additional data to demonstrate that the existing standard is erroneous. Hawaiian Electric has been in contact with the EPA regarding the status of its Petition, but has not been given a time frame for an EPA decision or action. Due to the EPA’s delay in taking action on Hawaiian Electric’s Petition for Reconsideration submitted in April 2012, Hawaiian Electric submitted to the EPA, on February 20, 2015, a Notice of Intent to Sue as a prerequisite to bringing a civil action.

On February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour sulfur dioxide (SO2) National Ambient Air Quality Standard (NAAQS) implementation plans. In May 2014, the EPA published a proposed data requirements rule for states to characterize their air quality in relation to the one-hour SO2 NAAQS. Under the proposed rule, the EPA expects to designate areas as attaining, or not attaining, the one-hour SO2 NAAQS in December 2017 or December 2020, depending on whether the area was characterized through modeling or monitoring. Hawaiian Electric will work with the DOH in implementing the one-hour SO2 NAAQS and in developing cost-effective strategies for NAAQS compliance, if needed.

Depending upon the specific measures required for compliance with the CWA 316(b) regulations and MATS, and the rules and guidance developed for compliance with the more stringent NAAQS, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts and their timing are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire or deactivate certain generating units earlier than anticipated.

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

Potential Clean Air Act Enforcement. On July 1, 2013, Hawaii Electric Light and Maui Electric received a letter from the U.S. Department of Justice (DOJ) asserting potential violations of the Prevention of Significant Deterioration (PSD) and Title V requirements of the Clean Air Act involving the Hill and Kahului Power Plants. The EPA referred the matter to the DOJ for enforcement based on Hawaii Electric Light’s and Maui Electric’s responses to information requests in 2010 and 2012. The letter expresses an interest in resolving the matter without the issuance of a notice of violation. The parties had preliminary discussions in February 2014, and are continuing to negotiate toward a resolution of the DOJ’s claims. As part of the ongoing negotiations, the DOJ proposed in November 2014 entering into a consent decree pursuant to which the Utilities would install certain pollution controls and pay a penalty. The Utilities are currently reviewing the proposal, but are unable to estimate the amount or effect of a consent decree, if any, at this time.

Former Molokai Electric Company generation site. In 1989, Maui Electric acquired by merger Molokai Electric Company. Molokai Electric Company had sold its former generation site (Site) in 1983, but continued to operate at the Site under a lease until 1985. The EPA has since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although Maui Electric never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the DOH, Maui Electric agreed to undertake additional investigations at the Site and an adjacent parcel that Molokai Electric Company had used for equipment storage (the Adjacent Parcel) to determine the extent of impacts of subsurface contaminants. A 2011 assessment by a Maui Electric contractor of the Adjacent Parcel identified environmental impacts, including elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, Maui Electric is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, residual fuel oils, and other subsurface contaminants. In March 2012, Maui Electric accrued an additional $3.1 million (reserve balance of $3.6 million as of December 31, 2014) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation. Maui Electric received DOH and EPA comments on a draft site investigation plan for site characterization in the fourth quarter of 2013. Management concluded that these comments did not require a change to the reserve balance. The site investigation plan has been revised to address the EPA and DOH comments and the final site investigation plan was submitted to the DOH and EPA in December 2014.

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

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

Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of greenhouse gas (GHG) emissions (including carbon dioxide emissions from the combustion of fossil fuels) to climate change have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. On June 20, 2014, the Governor signed the final regulations required to implement Act 234 and the regulations went into effect on June 30, 2014. In general, the regulations will require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 16% below 2010 emission levels by 2020. The regulations will also assess affected sources an annual fee based on tons per year of GHG emissions commencing on the effective date of the regulations, estimated to be approximately $0.5 million annually for the Utilities. The DOH GHG regulations also track the federal “Prevention of Significant Deterioration and Title V Greenhouse

Gas Tailoring Rule” (GHG Tailoring Rule, see below) and would create new thresholds for GHG emissions from new and existing stationary source facilities.

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

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The Utilities have submitted the required reports for 2010 through 2013 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the Utilities’ EGUs.

In June 2010, the EPA issued its GHG Tailoring Rule covering the permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds set forth in the rule, under the Prevention of Significant Deterioration program. On June 23, 2014, the U.S. Supreme Court issued a decision that invalidated the GHG Tailoring Rule, to the extent it regulated sources based solely on their GHG emissions. It also invalidated the GHG emissions threshold for regulation. On December 19, 2014, the EPA released two memorandums outlining the Agency’s plan for addressing the U.S. Supreme Court’s decision. Hawaiian Electric, Hawaii Electric Light and Maui Electric are evaluating the potential impacts of the Agency’s plan on utility operations and permitting. On January 8, 2014, the EPA published in the Federal Register its new proposal for New Source Performance Standards for GHG from new generating units. The proposed rule on GHG from new EGUs does not apply to oil- fired combustion turbines or diesel engine generators, and is not otherwise expected to have significant impacts on the Utilities.

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’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the Utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.

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



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

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

The reduction in the pension and OPEB expense is due to applying a 3-year average in the calculation of pension costs for the purpose of the 2012 test year. This is not a PUC decision to change the pension and OPEB tracking mechanisms, although the PUC emphasizes the need to evaluate alternatives to decrease or limit the growth in employee benefits costs.

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

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

As required by the final D&O, Maui Electric filed in September 2013 a System Improvement and Curtailment Reduction Plan (SICRP), which identified actions that Maui Electric had already implemented to increase the use of wind energy and further actions that it is committed to implement to benefit customers.

Maui Electric 2015 test year rate case. On December 30, 2014, Maui Electric filed its 2015 test year rate case in accordance with the three-year general rate case cycle established by the PUC in its Final D&O, issued on August 31, 2010, in the decoupling proceeding. This was an abbreviated rate case filing in which Maui Electric intends to forego the opportunity to seek a general rate increase in base rates, in recognition that its customers have been enduring a high bill environment. If Maui Electric were to seek an increase in base rates, the 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 rate adjustment mechanism (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.

Asset retirement obligations. AROs represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The Utilities’ recognition of AROs have no impact on their earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by the Utilities relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials.

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

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



(in thousands)	2014			2013
Balance, January 1	$	43,106		$	48,431
Accretion expense	890			1,263
Liabilities incurred	—			—
Liabilities settled	(14,577		)	(5,672		)
Revisions in estimated cash flows	—			(916		)
Balance, December 31	$	29,419		$	43,106

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. The implementation of decoupling has resulted in an improvement in the Utilities’ under-earning situation that has existed over the last several years.

On May 31, 2013, as provided for in its original order issued in 2010 approving decoupling and citing three years of implementation experience for Hawaiian Electric, the PUC opened an investigative docket to review whether the decoupling mechanisms are functioning as intended, are fair to the Utilities and their ratepayers, and are in the public interest. The PUC affirmed its support for the continuation of the sales decoupling (RBA) mechanism and stated its interest in evaluating the RAM to ensure it provides the appropriate balance of risks, costs, incentives and performance requirements, as well as administrative efficiency, and whether the current interest rate applied to the outstanding RBA balance is reasonable. The Utilities and the Consumer Advocate were named as parties to this proceeding and filed a joint statement of position that any material changes to the current decoupling mechanism should be made prospectively after 2016, unless the Utilities and the Consumer Advocate mutually agree to the change in this proceeding. The PUC granted several parties’ motions to intervene. In October 2013, the PUC issued orders that bifurcated the proceeding (Schedule A and Schedule B) and identified issues and procedural schedules for both Schedules.

Schedule A issues include:


•	for the RBA, the reasonableness of the interest rate related to the carrying charge of the outstanding RBA balance and whether there should be a risk sharing adjustment to the RBA;


•	for the RAM, whether it is reasonable to true up all actual prior year baseline projects, which are those capital projects less than $2.5 million, at year end or implement alternative methods to calculate the RAM rate base;


•	whether a risk sharing mechanism should be incorporated into the RBA;


•	whether performance metrics should be determined and reported; and


•	whether other factors should be considered if potential changes to existing RBA and RAM provisions are required.

Schedule B issues include:


•	whether performance metrics and incentives (rewards or penalties) should be implemented to control costs and encourage the Utilities to make necessary or appropriate changes to strategic and action plans;


•	whether the allocation of risk as a result of the decoupling mechanism is fairly reflected in the cost of capital allowed in rates;


•	changes or alternatives to the existing RAM; and


•	changes to ratemaking procedures to improve efficiency and/or effectiveness.

Oral arguments on Schedule A issues were held in January 2014. On February 7, 2014, the PUC issued a D&O on the Schedule A issues, which made certain modifications to the decoupling mechanism. Specifically, the D&O requires:


•	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.

The D&O required the Utilities to immediately investigate the possibility of deferring the payment of income taxes on the accrued amounts of decoupling revenue, and to report the results with recommendations to the PUC. The PUC reserved the right to determine in the next decoupling and rate case filings whether each Utilities’ allowed income taxes should be adjusted for this change. The Utilities updated the PUC on their progress in investigating the tax treatment of the revenues included in the RBA balances and provided information to the PUC concerning the application to the IRS for an accounting methods change to recognize RBA revenues for tax purposes when amounts are billed. On April 28, 2014, the Utilities received approval for this change from the IRS, effective January 1, 2014. This change will reduce the amount of interest to be accrued on the RBA balance as proposed by the Consumer Advocate (see "Recent tax developments" above).

As required, the Utilities developed websites to present certain Schedule A performance metrics and proposed additional performance metrics. These metrics are all currently being reviewed by the PUC and, if approved, will be available to the public.

The Schedule A issues on whether it is reasonable to automatically include all actual prior year capital expenditures on baseline projects in the Rate Base RAM and whether a risk sharing mechanism should be incorporated into the RBA, particularly with respect to the PUC’s concerns regarding maintaining and enhancing the Utilities' incentives to control costs and appropriately allocating risk and compensation for risk, will be addressed in the Schedule B proceedings.

On May 20, 2014, the Utilities and other parties filed their respective initial statements of position for the Schedule B issues in this proceeding. Specifically, the Utilities concluded that (1) the existing RAM provision can be modified to address concerns stated by the PUC regarding the review of baseline capital projects and the growth in plant additions, and (2) targeted incentives can be crafted to incentivize the activities identified by the PUC.

On September 15, 2014, the Utilities and other parties filed their respective reply statements of position for the Schedule B issues in this proceeding. Specifically, the Utilities concluded that (1) the existing RAM provision can be modified to address PUC concerns regarding the review of baseline capital projects, and to provide more incentives for the Utilities to control capital expenditure costs while aggressively moving forward with their plans, (2) if the RAM is to be replaced, the Utilities can support transition to a new appropriately designed incentive-based regulatory (IBR) model, (3) developing an IBR mechanism and process consistent with the objectives in the Utilities’ approved plans will also take reasonable time; thus, it would be more reasonable to target 2017 to begin implementation of any new IBR mechanism and decoupling should be retained in the meantime and (4) the Utilities would support the development of performance metrics to be implemented as part of a new IBR mechanism.

The Utilities and other parties participated in panel hearings on Schedule B issues in late October 2014.

In early December 2014, the PUC issued an order that amended the procedural schedule and issued information requests. On December 22, 2014, the Utilities and other parties filed their respective responses to PUC information requests. The proceeding is currently pending a PUC order instructing the parties regarding the issues and scope for limited briefs and reply briefs.

Management cannot predict the outcome of the proceedings or the ultimate impact of the proceedings on the results of operation of the Utilities.

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

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

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


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


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


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


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


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

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

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

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

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

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

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

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

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

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

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

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

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

The Utilities have requested approval of their motion within 60 days of filing or by March 20, 2015. On January 27, 2015, the Consumer Advocate opposed the Utilities’ motion, contended that further analysis is required to determine whether the Utilities’ requests are reasonable and in the public interest, and requested that the PUC hold the motion in abeyance until such further review can be conducted.

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

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

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.

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
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

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 losses arising during the period, net of tax benefits	(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 taxes	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

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 gains arising during the period, net of taxes	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 tax benefits	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

Consolidating statement of income

Year ended December 31, 2012



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	2,228,233		441,013		440,270		—		(77	)	[1]	$	3,109,439
Expenses
Fuel oil	945,246			116,866		235,307		—		—			1,297,419
Purchased power	540,802			145,386		38,052		—		—			724,240
Other operation and maintenance	266,208			60,447		70,771		3		—			397,429
Depreciation	90,783			33,337		20,378		—		—			144,498
Taxes, other than income taxes	209,943			41,370		41,528		—		—			292,841
Impairment of utility assets	29,000			5,500		5,500		—		—			40,000
Total expenses	2,081,982			402,906		411,536		3		—			2,896,427
Operating income (loss)	146,251			38,107		28,734		(3	)	(77	)		213,012
Allowance for equity funds used during construction	5,735			585		687		—		—			7,007
Equity in earnings of subsidiaries	28,836			—		—		—		(28,836	)	[2]	—
Interest expense and other charges, net	(40,842		)	(12,066	)	(9,224	)	—		77		[1]	(62,055		)
Allowance for borrowed funds used during construction	3,642			235		478		—		—			4,355
Income (loss) before income taxes	143,622			26,861		20,675		(3	)	(28,836	)		162,319
Income taxes	43,266			10,115		7,667		—		—			61,048
Net income (loss)	100,356			16,746		13,008		(3	)	(28,836	)		101,271
Preferred stock dividends of subsidiaries	—			534		381		—		—			915
Net income (loss) attributable to Hawaiian Electric	100,356			16,212		12,627		(3	)	(28,836	)		100,356
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—		—			1,080
Net income (loss) for common stock	$	99,276		16,212		12,627		(3	)	(28,836	)		$	99,276

Consolidating statement of comprehensive income (loss)

Year ended December 31, 2012



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Net income (loss) for common stock	$	99,276		16,212		12,627		(3	)	(28,836	)		$	99,276
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Net losses arising during the period, net of tax benefits	(90,082		)	(13,577	)	(10,935	)	—		24,512		[1]	(90,082		)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	13,673			2,101		1,771		—		(3,872	)	[1]	13,673
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	75,471			11,442		9,093		—		(20,535	)	[1]	75,471
Other comprehensive loss, net of tax benefits	(938		)	(34	)	(71	)	—		105			(938		)
Comprehensive income (loss) attributable to common shareholder	$	98,338		16,178		12,556		(3	)	(28,731	)		$	98,338

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]	0
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	44,680			8,611		13,567		—	(475	)	[3]	66,383
Regulatory assets	58,550			6,745		6,126		—	—			71,421
Total current assets	463,929			77,561		98,911		101	(25,499	)		615,003
Other long-term assets
Regulatory assets	623,784			107,454		102,788		—	(183	)	[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	$	4,396,815		924,885		832,977		101	(564,321	)		$	5,590,457
Capitalization and liabilities
Capitalization
Common stock equity	$	1,682,144		281,846		256,692		101	(538,639	)	[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
Current portion of long-term debt	—			—		—		—	—			—
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	48,282			9,866		16,094		—	(9,096	)	[1]	65,146
Total current liabilities	362,652			85,631		79,646		—	(25,499	)		502,430
Deferred credits and other liabilities
Deferred income taxes	429,515			90,119		83,238		—	—			602,872
Regulatory liabilities	236,727			77,707		29,966		—	(183	)	[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	1,215,441			265,933		217,421		—	(183	)		1,698,612
Contributions in aid of construction	283,739			94,475		88,218		—	—			466,432
Total capitalization and liabilities	$	4,396,815		924,885		832,977		101	(564,321	)		$	5,590,457

Consolidating balance sheet

December 31, 2013



(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	$	43,407		5,460		3,016		—	—			$	51,883
Plant and equipment	3,558,569			1,136,923		1,006,383		—	—			5,701,875
Less accumulated depreciation	(1,222,129		)	(453,721	)	(435,379	)	—	—			(2,111,229		)
Construction in progress	124,494			7,709		11,030		—	—			143,233
Utility property, plant and equipment, net	2,504,341			696,371		585,050		—	—			3,785,762
Nonutility property, plant and equipment, less accumulated depreciation	4,953			82		1,532		—	—			6,567
Total property, plant and equipment, net	2,509,294			696,453		586,582		—	—			3,792,329
Investment in wholly-owned subsidiaries, at equity	523,674			—		—		—	(523,674	)	[2]	—
Current assets
Cash and equivalents	61,245			1,326		153		101	—			62,825
Advances to affiliates	6,839			1,000		—		—	(7,839	)	[1]	—
Customer accounts receivable, net	121,282			28,088		26,078		—	—			175,448
Accrued unbilled revenues, net	107,752			17,100		19,272		—	—			144,124
Other accounts receivable, net	16,373			4,265		2,451		—	(9,027	)	[1]	14,062
Fuel oil stock, at average cost	99,613			14,178		20,296		—	—			134,087
Materials and supplies, at average cost	37,377			6,883		14,784		—	—			59,044
Prepayments and other	29,798			8,334		16,140		—	(1,415	)	[3]	52,857
Regulatory assets	54,979			6,931		7,828		—	—			69,738
Total current assets	535,258			88,105		107,002		101	(18,281	)		712,185
Other long-term assets
Regulatory assets	381,346			64,552		60,288		—	—			506,186
Unamortized debt expense	6,051			1,580		1,372		—	—			9,003
Other	42,163			11,270		13,993		—	—			67,426
Total other long-term assets	429,560			77,402		75,653		—	—			582,615
Total assets	$	3,997,786		861,960		769,237		101	(541,955	)		$	5,087,129
Capitalization and liabilities
Capitalization
Common stock equity	$	1,593,564		274,802		248,771		101	(523,674	)	[2]	$	1,593,564
Cumulative preferred stock–not subject to mandatory redemption	22,293			7,000		5,000		—	—			34,293
Long-term debt, net	830,547			189,998		186,000		—	—			1,206,545
Total capitalization	2,446,404			471,800		439,771		101	(523,674	)		2,834,402
Current liabilities
Current portion of long-term debt	—			11,400		—		—	—			11,400
Short-term borrowings-affiliate	1,000			—		6,839		—	(7,839	)	[1]	—
Accounts payable	145,062			24,383		20,114		—	—			189,559
Interest and preferred dividends payable	15,190			3,885		2,585		—	(8	)	[1]	21,652
Taxes accrued	175,790			37,899		37,171		—	(1,415	)	[3]	249,445
Regulatory liabilities	1,705			—		211		—	—			1,916
Other	48,443			9,033		15,424		—	(9,019	)	[1]	63,881
Total current liabilities	387,190			86,600		82,344		—	(18,281	)		537,853
Deferred credits and other liabilities
Deferred income taxes	359,621			79,947		67,593		—	—			507,161
Regulatory liabilities	235,786			76,475		35,122		—	—			347,383
Unamortized tax credits	44,931			14,245		14,363		—	—			73,539
Defined benefit pension and other postretirement benefit plans liability	202,396			28,427		31,339		—	—			262,162
Other	63,374			14,703		13,658		—	—			91,735
Total deferred credits and other liabilities	906,108			213,797		162,075		—	—			1,281,980
Contributions in aid of construction	258,084			89,763		85,047		—	—			432,894
Total capitalization and liabilities	$	3,997,786		861,960		769,237		101	(541,955	)		$	5,087,129

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, 2011	$	1,402,841		280,468		235,568		107		(516,143	)	$	1,402,841
Net income (loss) for common stock	99,276			16,212		12,627		(3	)	(28,836	)	99,276
Other comprehensive loss, net of tax benefits	(938		)	(34	)	(71	)	—		105		(938		)
Issuance of common stock, net of expenses	44,001			—		—		—		—		44,001
Common stock dividends	(73,044		)	(27,738	)	(19,197	)	—		46,935		(73,044		)
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 taxes	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 tax benefits	(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

100

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 (1)	1,749			2,596		2,065		—	—			6,410
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	4,223			219		(2,648	)	—	—			1,794
Increase in regulatory assets	(14,620		)	(3,357	)	977		—	—			(17,000		)
Decrease in accounts payable (2)	(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 (3)	(46,636		)	(12,577	)	(3,332	)	—	103		[1]	(62,442		)
Net cash provided by operating activities	218,686			53,105		61,180		—	(25,976	)		306,995
Cash flows from investing activities
Capital expenditures (4)	(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 (5)	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 issuance of common stock	40,000			—		—		—	—			40,000
Proceeds from issuance of long-term debt	—			—		—		—	—			—
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	)	[2]	—
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

(1) Prior to revision, other amortization for Maui Electric and Hawaiian Electric Consolidated were $3,746 and $8,091, respectively.

(2) Prior to revision, decrease in accounts payable for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(74,276), $(8,490), $(7,866) and $(90,632), respectively.

(3) Prior to revision, changes in other assets and liabilities for Hawaiian Electric, Hawaii Electric Light, Maui Electric, Consolidating adjustments and Hawaiian Electric Consolidated were $(46,032), $(12,085), $(4,945), $103 and $(62,959), respectively.

(4) Prior to revision, capital expenditures for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(219,738), $(48,050), $(43,786) and $(311,574), respectively.

(5) Prior to revision, cash flows from investing activities-other for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were nil.

101

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
	As restated			As restated		As restated							As restated
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	554			1,979		2,544		—		—			5,077
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 (1)	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 (2)	(18,618		)	(6,513	)	(7,753	)	—		248		[1]	(32,636		)
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 (3)	(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 (4)	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

(1) Prior to restatement, decrease in accounts payable for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(6,136), $(4,756), $(9,936) and $(20,828), respectively.

(2) Prior to restatement,changes in other assets and liabilities for Hawaiian Electric, Hawaii Electric Light, Maui Electric, Consolidating adjustments and Hawaiian Electric Consolidated were $(17,941), $(6,262), $(7,544), $248 and $(31,499), respectively.

(3) Prior to restatement, capital expenditures for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(237,899), $(52,135), $(52,451) and $(342,485), respectively.

(4) Prior to restatement, cash flows from investing activities-other for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were nil, $(230), nil and $(230), respectively.

102

Consolidating statement of cash flows

Year ended December 31, 2012



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
	As restated			As restated		As restated							As restated
Cash flows from operating activities
Net income (loss)	$	100,356		16,746		13,008		(3	)	(28,836	)	[2]	$	101,271
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Equity in earnings	(28,936		)	—		—		—		28,836		[2]	(100		)
Common stock dividends received from subsidiaries	47,035			—		—		—		(46,935	)	[2]	100
Depreciation of property, plant and equipment	90,783			33,337		20,378		—		—			144,498
Other amortization	1,508			3,252		2,238		—		—			6,998
Impairment of utility assets	29,000			5,500		5,500		—		—			40,000
Increase in deferred income taxes	66,968			7,457		12,453		—		—			86,878
Change in tax credits, net	5,006			522		547		—		—			6,075
Allowance for equity funds used during construction	(5,735		)	(585	)	(687	)	—		—			(7,007		)
Changes in assets and liabilities:
Increase in accounts receivable	(48,451		)	(1,106	)	(2,164	)	—		4,717		[1]	(47,004		)
Decrease (increase) in accrued unbilled revenues	2,728			4,106		(3,306	)	—		—			3,528
Decrease in fuel oil stock	4,861			3,732		1,536		—		—			10,129
Increase in materials and supplies	(6,683		)	(636	)	(578	)	—		—			(7,897		)
Increase in regulatory assets	(55,605		)	(9,649	)	(7,147	)	—		—			(72,401		)
Increase (decrease) in accounts payable (1)	6,329			(5,774	)	5,767		—		—			6,322
Change in prepaid and accrued income taxes and revenue taxes	19,871			1,935		3,433		—		—			25,239
Decrease in defined benefit pension and other postretirement benefits plans liability	(434		)	(191	)	(119	)	—		—			(744		)
Change in other assets and liabilities (2)	(45,366		)	(11,335	)	(12,843	)	(1	)	(4,717	)	[1]	(74,262		)
Net cash provided by (used in) operating activities	183,235			47,311		38,016		(4	)	(46,935	)		221,623
Cash flows from investing activities
Capital expenditures (3)	(271,864		)	(43,396	)	(40,066	)	—		—			(355,326		)
Contributions in aid of construction	32,285			8,184		5,513		—		—			45,982
Other (4)	486			192		165		—		—			843
Advances from (to) affiliates	(9,400		)	28,100		18,500		—		(37,200	)	[1]	—
Net cash used in investing activities	(248,493		)	(6,920	)	(15,888	)	—		(37,200	)		(308,501		)
Cash flows from financing activities
Common stock dividends	(73,044		)	(27,738	)	(19,197	)	—		46,935		[2]	(73,044		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—		—			(1,995		)
Proceeds from the issuance of long-term debt	367,000			31,000		59,000		—		—			457,000
Proceeds from issuance of common stock	44,000			—		—		—		—			44,000
Repayment of long-term debt	(259,580		)	(41,200	)	(67,720	)	—		—			(368,500		)
Net increase (decrease) in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	(46,600		)	—		9,400		—		37,200		[1]	—
Other	(1,992		)	139		(377	)	—		—			(2,230		)
Net cash provided by (used in) financing activities	28,704			(38,333	)	(19,275	)	—		84,135			55,231
Net increase (decrease) in cash and cash equivalents	(36,554		)	2,058		2,853		(4	)	—			(31,647		)
Cash and cash equivalents, January 1	44,819			3,383		496		108		—			48,806
Cash and cash equivalents, December 31	$	8,265		5,441		3,349		104		—			$	17,159

(1) Prior to restatement, increase (decrease) in accounts payable for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(31,743), $(8,110), $940 and $(38,913), respectively.

(2) Prior to restatement,changes in other assets and liabilities for Hawaiian Electric, Hawaii Electric Light, Maui Electric, Other subsidiaries, Consolidating adjustments and Hawaiian Electric Consolidated were $(44,880), $(11,143), $(12,678), $(1),$(4,717) and $(73,419), respectively.

(3) Prior to restatement, capital expenditures for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were $(233,792), $(41,060), $(35,239) and $(310,091), respectively.

(4) Prior to restatement, cash flows from investing activities-other for Hawaiian Electric, Hawaii Electric Light, Maui Electric and Hawaiian Electric Consolidated, were nil.

103

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.

104

5 · Bank segment (HEI only)

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data



Years ended December 31	2014		2013		2012
(in thousands)
Interest and dividend income
Interest and fees on loans	$	179,341	$	172,969	$	176,057
Interest and dividends on investment securities	11,945		13,095		13,822
Total interest and dividend income	191,286		186,064		189,879
Interest expense
Interest on deposit liabilities	5,077		5,092		6,423
Interest on other borrowings	5,731		4,985		4,869
Total interest expense	10,808		10,077		11,292
Net interest income	180,478		175,987		178,587
Provision for loan losses	6,126		1,507		12,883
Net interest income after provision for loan losses	174,352		174,480		165,704
Noninterest income
Fees from other financial services	21,747		27,099		31,361
Fee income on deposit liabilities	19,249		18,363		17,775
Fee income on other financial products	8,131		8,405		6,577
Bank-owned life insurance	3,949		3,928		3,981
Mortgage banking income	2,913		8,309		14,628
Gains on sale of investment securities	2,847		1,226		134
Other income, net	2,375		4,753		1,204
Total noninterest income	61,211		72,083		75,660
Noninterest expense
Compensation and employee benefits	79,885		82,910		75,979
Occupancy	17,197		16,747		17,179
Data processing	11,690		10,952		10,098
Services	10,269		9,015		9,866
Equipment	6,564		7,295		7,105
Office supplies, printing and postage	6,089		4,233		3,870
Marketing	3,999		3,373		3,260
FDIC insurance	3,261		3,253		3,307
Other expense	20,990		21,726		21,679
Total noninterest expense	159,944		159,504		152,343
Income before income taxes	75,619		87,059		89,021
Income taxes	24,127		29,525		30,384
Net income	$	51,492	$	57,534	$	58,637

105

Statements of Comprehensive Income



Years ended December 31	2014			2013			2012
(in thousands)
Net income	$	51,492		$	57,534		$	58,637
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 $(3,856), $9,037 and ($631), for 2014, 2013 and 2012, respectively	5,840			(13,686		)	956
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $1,132, $488 and $53 for 2014, 2013 and 2012, respectively	(1,715		)	(738		)	(81		)
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of $6,164, ($10,450) and $5,240 for 2014, 2013 and 2012, respectively	(9,336		)	15,826			(7,936		)
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 $561, $1,187 and $684 for 2014, 2013 and 2012, respectively	850			1,797			1,036
Other comprehensive income (loss), net of taxes	(4,361		)	3,199			(6,025		)
Comprehensive income	$	47,131		$	60,733		$	52,612

Balance Sheets Data



December 31				2014						2013
(in thousands)
Assets
Cash and due from banks				$	107,233					$	108,998
Interest-bearing deposits				54,230						47,605
Available-for-sale investment securities, at fair value				550,394						529,007
Stock in Federal Home Loan Bank of Seattle, at cost				69,302						92,546
Loans receivable held for investment				4,434,651						4,150,229
Allowance for loan losses				(45,618		)				(40,116		)
Net loans				4,389,033						4,110,113
Loans held for sale, at lower of cost or fair value				8,424						5,302
Other				304,435						268,063
Goodwill				82,190						82,190
Total assets				$	5,565,241					$	5,243,824
Liabilities and shareholder’s equity
Deposit liabilities–noninterest-bearing				$	1,342,794					$	1,214,418
Deposit liabilities–interest-bearing				3,280,621						3,158,059
Other borrowings				290,656						244,514
Other				116,527						105,679
Total liabilities				5,030,598						4,722,670
Commitments and contingencies (see “Litigation” below)
Common stock				1						1
Additional paid in capital				338,411						336,053
Retained earnings				212,789						197,297
Accumulated other comprehensive loss, net of tax benefits
Net unrealized gains (losses) on securities	$	462					$	(3,663	)
Retirement benefit plans	(17,020		)	(16,558		)	(8,534		)	(12,197		)
Total shareholder’s equity				534,643						521,154
Total liabilities and shareholder’s equity				$	5,565,241					$	5,243,824

106



December 31	2014		2013
(in thousands)
Other assets
Bank-owned life insurance	$	134,115	$	129,963
Premises and equipment, net	92,407		67,766
Prepaid expenses	3,196		3,616
Accrued interest receivable	13,632		13,133
Mortgage-servicing rights	11,540		11,687
Low-income housing equity investments	32,457		14,543
Real estate acquired in settlement of loans, net	891		1,205
Other	16,197		26,150
	$	304,435	$	268,063
Other liabilities
Accrued expenses	$	37,880	$	19,989
Federal and state income taxes payable	26,806		37,807
Cashier’s checks	20,509		21,110
Advance payments by borrowers	9,652		9,647
Other	21,680		17,126
	$	116,527	$	105,679

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, 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	)
December 31, 2013
Available-for-sale
Federal agency obligations	$	83,193	$	174	$	(2,394	)	$	80,973	10	$	70,799	$	(2,394	)	—	$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	374,993		4,911		(10,460		)	369,444		36	228,543		(8,819		)	4	19,655		(1,641		)
Municipal bonds	76,904		1,826		(140		)	78,590		3	14,478		(140		)	—	—		—
	$	535,090	$	6,911	$	(12,994	)	$	529,007	49	$	313,820	$	(11,353	)	4	$	19,655	$	(1,641	)

During 2014, ASB sold all of the municipal bonds held in its investment securities portfolio.

ASB does not believe that the investment securities that were in an unrealized loss position as of December 31, 2014, 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 gross unrealized losses reported for mortgage-related 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. ASB did not recognize OTTI for 2014, 2013 and 2012.

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.

107

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



	Amortized		Fair
December 31, 2014	Cost		value
(in thousands)
Due in one year or less	$	—	$	—
Due after one year through five years	34,953		35,007
Due after five years through ten years	47,131		47,885
Due after ten years	37,423		36,668
	119,507		119,560
Mortgage-related securities-FNMA,FHLMC and GNMA	430,120		430,834
Total available-for-sale securities	$	549,627	$	550,394

The proceeds, gross gains and losses from sales of available-for-sale investment securities were as follows:



Years ended December 31	2014		2013		2012
(in millions)
Proceeds	$	79.6	$	71.4	$	3.5
Gross gains	2.8		1.2		—
Gross losses	—		—		—

Interest income from taxable and non-taxable investment securities were as follows:



Years ended December 31	2014		2013		2012
(in thousands)
Taxable	$	11,666	$	11,474	$	12,309
Non-taxable	279		1,621		1,513
	$	11,945	$	13,095	$	13,822

ASB pledged securities with a market value of approximately $88.6 million and $87.1 million as of December 31, 2014 and 2013, respectively, as collateral for public funds deposits, automated clearinghouse transactions with Bank of Hawaii, and deposits in ASB’s bankruptcy account with the Federal Reserve Bank of San Francisco. As of December 31, 2014 and 2013, securities with a carrying value of $230.2 million and $187.1 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

Stock in FHLB of Seattle. As of December 31, 2014 and 2013, ASB’s stock in FHLB of Seattle was carried at cost ($69.3 million and $92.5 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. Periodically and as conditions warrant, ASB reviews its investment in the stock of the FHLB of Seattle for impairment. ASB evaluated its investment in FHLB stock for OTTI as of December 31, 2014, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2014 based on its evaluation of the underlying investment, including:


•	the net income and growth in retained earnings recorded by the FHLB of Seattle in the first nine months of 2014;


•	compliance by the FHLB of Seattle with all of its regulatory capital requirements and being classified “adequately capitalized” by the Federal Housing Finance Agency (Finance Agency);


•	being allowed by the Finance Agency to repurchase excess stock;


•	commitments by the FHLB of Seattle to make payments required by law or regulation and the level of such payments in relation to the operating performance of the FHLB of Seattle;


•	the impact of legislative and regulatory changes on institutions and, accordingly, on the customer base of the FHLB of Seattle;


•	the liquidity position of the FHLB of Seattle; 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.

Deterioration in the FHLB of Seattle’s financial position may result in future impairment losses.

108

Loans receivable.

The components of loans receivable were summarized as follows:



December 31	2014			2013
(in thousands)
Real estate:
Residential 1-4 family	$	2,044,205		$	2,006,007
Commercial real estate	531,917			440,443
Home equity line of credit	818,815			739,331
Residential land	16,240			16,176
Commercial construction	96,438			52,112
Residential construction	18,961			12,774
Total real estate	3,526,576			3,266,843
Commercial	791,757			783,388
Consumer	122,656			108,722
Total loans	4,440,989			4,158,953
Less: Deferred fees and discounts	(6,338		)	(8,724		)
Allowance for loan losses	(45,618		)	(40,116		)
Total loans, net	$	4,389,033		$	4,110,113

The Company’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. The Company is subject to the risk that the insurance company cannot satisfy the Company’s claim on policies.

ASB services real estate loans for investors (principal balance of $1.4 billion, $1.4 billion and $1.3 billion as of December 31, 2014, 2013 and 2012, 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, 2014 and 2013, ASB had pledged loans with an amortized cost of approximately $1.9 billion and $1.7 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

As of December 31, 2014 and 2013, 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 $49.6 million and $45.8 million, respectively. The $3.8 million increase in such loans in 2014 was attributed to new commitments and loans of $6.4 million to new and existing directors and executive officers, offset by closed lines of credits and repayments of $2.6 million. As of December 31, 2014 and 2013, $46.2 million and $40.5 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.

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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, 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
December 31, 2013
Allowance for loan losses:
Beginning balance	$	6,068		$	2,965	$	4,493		$	4,275		$	2,023	$	9	$	15,931		$	4,019		$	2,202		$	41,985
Charge-offs	(1,162		)	—		(782		)	(485		)	—		—		(3,056		)	(2,717		)	—			(8,202		)
Recoveries	1,881			—		358			868			—		—		1,089			630			—			4,826
Provision	(1,253		)	2,094		1,160			(2,841		)	374		10		1,839			435			(311		)	1,507
Ending balance	$	5,534		$	5,059	$	5,229		$	1,817		$	2,397	$	19	$	15,803		$	2,367		$	1,891		$	40,116
Ending balance: individually evaluated for impairment	$	642		$	1,118	$	—		$	1,332		$	—	$	—	$	2,246		$	—					$	5,338
Ending balance: collectively evaluated for impairment	$	4,892		$	3,941	$	5,229		$	485		$	2,397	$	19	$	13,557		$	2,367		$	1,891		$	34,778
Financing Receivables:
Ending balance	$	2,006,007		$	440,443	$	739,331		$	16,176		$	52,112	$	12,774	$	783,388		$	108,722					$	4,158,953
Ending balance: individually evaluated for impairment	$	20,317		$	4,604	$	1,179		$	10,577		$	—	$	—	$	21,225		$	19					$	57,921
Ending balance: collectively evaluated for impairment	$	1,985,690		$	435,839	$	738,152		$	5,599		$	52,112	$	12,774	$	762,163		$	108,703					$	4,101,032

Changes in the allowance for loan losses were as follows:



(dollars in thousands)	2014			2013			2012
Allowance for loan losses, January 1	$	40,116		$	41,985		$	37,906
Provision for loan losses	6,126			1,507			12,883
Charge-offs, net of recoveries
Real estate loans	(1,137		)	(678		)	3,828
Other loans	1,761			4,054			4,976
Net charge-offs	624			3,376			8,804
Allowance for loan losses, December 31	$	45,618		$	40,116		$	41,985
Ratio of net charge-offs to average total loans	0.01		%	0.09		%	0.24		%

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.

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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	2014						2013
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	493,105	$	79,312	$	743,334	$	375,217	$	52,112	$	703,053
Special mention	5,209		—		16,095		33,436		—		17,634
Substandard	33,603		17,126		31,665		28,020		—		59,663
Doubtful	—		—		663		3,770		—		3,038
Loss	—		—		—		—		—		—
Total	$	531,917	$	96,438	$	791,757	$	440,443	$	52,112	$	783,388

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, 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	$	—
December 31, 2013
Real estate:
Residential 1-4 family	$	2,728	$	622	$	15,411	$	18,761	$	1,987,246	$	2,006,007	$	—
Commercial real estate	—		—		3,770		3,770		436,673		440,443		—
Home equity line of credit	765		312		960		2,037		737,294		739,331		—
Residential land	184		48		2,756		2,988		13,188		16,176		—
Commercial construction	—		—		—		—		52,112		52,112		—
Residential construction	—		—		—		—		12,774		12,774		—
Commercial	1,668		612		3,026		5,306		778,082		783,388		—
Consumer	436		158		304		898		107,824		108,722		—
Total loans	$	5,781	$	1,752	$	26,227	$	33,760	$	4,125,193	$	4,158,953	$	—

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



December 31	2014		2013
(in thousands)
Real estate:
Residential 1-4 family	$	19,253	$	19,679
Commercial real estate	5,112		4,439
Home equity line of credit	1,087		2,060
Residential land	720		3,161
Commercial construction	—		—
Residential construction	—		—
Commercial	10,053		18,781
Consumer	661		401
Total nonaccrual loans	$	36,886	$	48,521
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	$	13,525	$	9,744
Commercial real estate	—		—
Home equity line of credit	480		171
Residential land	7,130		7,476
Commercial construction	—		—
Residential construction	—		—
Commercial	2,972		1,649
Consumer	—		—
Total troubled debt restructured loans not included above	$	24,107	$	19,040

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



December 31	2014										2013
(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	$	11,654	$	12,987	$	—	$	9,056	$	227	$	9,708	$	12,144	$	—	$	11,674	$	386
Commercial real estate	571		626		—		194		—		—		—		—		802		—
Home equity line of credit	363		606		—		402		5		672		1,227		—		623		2
Residential land	2,344		3,200		—		2,728		172		2,622		3,612		—		6,675		482
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial	8,235		11,471		—		5,204		38		3,466		4,715		—		4,837		12
Consumer	—		—		—		8		—		19		19		—		20		—
	23,167		28,890		—		17,592		442		16,487		21,717		—		24,631		882
With an allowance recorded
Real estate:
Residential 1-4 family	11,327		11,347		951		8,822		419		6,216		6,236		642		6,455		372
Commercial real estate	4,541		4,541		1,845		3,415		478		4,604		4,686		1,118		5,745		152
Home equity line of credit	416		420		46		132		6		—		—		—		—		—
Residential land	5,506		5,584		1,057		6,415		484		7,452		7,623		1,332		6,844		409
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial	4,873		5,211		760		12,089		438		17,759		20,640		2,246		15,635		139
Consumer	16		16		6		9		—		—		—		—		—		—
	26,679		27,119		4,665		30,882		1,825		36,031		39,185		5,338		34,679		1,072
Total
Real estate:
Residential 1-4 family	22,981		24,334		951		17,878		646		15,924		18,380		642		18,129		758
Commercial real estate	5,112		5,167		1,845		3,609		478		4,604		4,686		1,118		6,547		152
Home equity line of credit	779		1,026		46		534		11		672		1,227		—		623		2
Residential land	7,850		8,784		1,057		9,143		656		10,074		11,235		1,332		13,519		891
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial	13,108		16,682		760		17,293		476		21,225		25,355		2,246		20,472		151
Consumer	16		16		6		17		—		19		19		—		20		—
	$	49,846	$	56,009	$	4,665	$	48,474	$	2,267	$	52,518	$	60,902	$	5,338	$	59,310	$	1,954

* 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 of

113

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 2014 and 2013 were as follows:



Years ended December 31	2014							2013
	Number	Outstanding recorded investment				Net increase in ALLL (as of period end)		Number	Outstanding recorded investment				Net increase in ALLL (as of period end)
(dollars in thousands)	of contracts	Pre-modification		Post-modification		Net increase in ALLL (as of period end)		of contracts	Pre-modification		Post-modification		Net increase in ALLL (as of period end)
Troubled debt restructurings
Real estate:
Residential 1-4 family	38	$	10,680	$	10,737	$	163	34	$	8,876	$	8,957	$	297
Commercial real estate	—	—		—		—		—	—		—		—
Home equity line of credit	8	502		502		42		5	637		390		—
Residential land	18	4,304		4,304		242		20	6,215		6,206		131
Commercial construction	—	—		—		—		—	—		—		—
Residential construction	—	—		—		—		—	—		—		—
Commercial	7	3,827		3,827		13		7	4,646		4,646		94
Consumer	—	—		—		—		—	—		—		—
	71	$	19,313	$	19,370	$	460	66	$	20,374	$	20,199	$	522

Loans modified in TDRs that experienced a payment default of 90 days or more in 2014 and 2013, and for which the payment default occurred within one year of the modification, were as follows:



Years ended December 31	2014			2013
(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	67
Residential land	—	—		—	—
Commercial construction	—	—		—	—
Residential construction	—	—		—	—
Commercial	1	14		2	660
Consumer	—	—		—	—
	2	$	404	3	$	727

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 $0.5 million at December 31, 2014.

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

ASB received $155.0 million, $273.8 million, and $513.0 million of proceeds from the sale of residential mortgages in 2014, 2013, and 2012, respectively, and recognized gains on such loans of $2.9 million, $8.3 million, and $14.6 million in

114

2014, 2013, and 2012, respectively. Repurchased mortgage loans in 2014, 2013, and 2012 were $0.5 million, $1.9 million and $0.4 million, respectively.

Mortgage servicing fees, a component of other income, net, were $3.5 million, $3.3 million, and $2.8 million for the years ended December 31, 2014, 2013 and 2012, 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, 2014	$	27,185	$	(15,436	)	$	(209	)	$	11,540
December 31, 2013	$	25,644	$	(13,706	)	$	(251	)	$	11,687

Changes related to mortgage servicing rights were as follows:



(in thousands)	2014			2013			2012
Mortgage servicing rights
Balance, January 1	$	11,938		$	11,316		$	8,402
Amount capitalized	1,637			2,611			4,845
Amortization	(1,731		)	(1,802		)	(1,750		)
Other-than-temporary impairment	(95		)	(187		)	(181		)
Carrying amount before valuation allowance, December 31	11,749			11,938			11,316
Valuation allowance for mortgage servicing rights
Balance, January 1	251			498			175
Provision (recovery)	53			(60		)	504
Other-than-temporary impairment	(95		)	(187		)	(181		)
Balance, December 31	209			251			498
Net carrying value of mortgage servicing rights	$	11,540		$	11,687		$	10,818

The estimated aggregate amortization expenses of mortgage servicing rights for 2015, 2016, 2017, 2018 and 2019 are $1.7 million, $1.5 million, $1.3 million, $1.1 million and $1.0 million, respectively.

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

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



December 31	2014			2013
(dollars in thousands)
Unpaid principal balance	$	1,391,030		$	1,357,003
Weighted average note rate	4.07		%	4.07		%
Weighted average discount rate	9.6		%	9.8		%
Weighted average prepayment speed	9.5		%	8.6		%

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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	2014			2013
(in thousands)
Prepayment rate:
25 basis points adverse rate change	$	(757	)	$	(732	)
50 basis points adverse change	(1,524		)	(1,492		)
Discount rate:
25 basis points adverse rate change	(140		)	(154		)
50 basis points adverse change	(278		)	(306		)

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	2014				2013
(dollars in thousands)	Weighted-average stated rate		Amount		Weighted-average stated rate		Amount
Savings	0.06	%	$	1,923,062	0.06	%	$	1,826,907
Checking
Interest-bearing	0.02		768,787		0.02		721,700
Noninterest-bearing	—		665,005		—		643,628
Commercial checking	—		677,789		—		570,790
Money market	0.12		158,010		0.13		182,546
Term certificates	0.83		430,762		0.80		426,906
	0.11	%	$	4,623,415	0.11	%	$	4,372,477

As of December 31, 2014 and 2013, term certificates of $100,000 or more totaled $120 million and $102 million, respectively.

The approximate scheduled maturities of term certificates outstanding at December 31, 2014 were as follows:



(in thousands)
2015	$	255,896
2016	55,614
2017	44,315
2018	16,949
2019	54,979
Thereafter	3,009
	$	430,762

Interest expense on deposit liabilities by type of deposit was as follows:



Years ended December 31	2014		2013		2012
(in thousands)
Term certificates	$	3,603	$	3,702	$	4,865
Savings	1,134		1,052		1,128
Money market	214		232		319
Interest-bearing checking	126		106		111
	$	5,077	$	5,092	$	6,423

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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. 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, 2014	$	191	$	—	$	191
December 31, 2013	145		—		145



	Gross amount not offset in the Balance Sheet
(in millions)	Net amount of liabilities presented in the Balance Sheet		Financial instruments		Cash collateral pledged		Net amount
December 31, 2014
Financial institution	$	50	$	50	$	—	$	—
Government entities	56		56		—		—
Commercial account holders	85		85		—		—
Total	$	191	$	191	$	—	$	—
December 31, 2013
Financial institution	$	51	$	51	$	—	$	—
Commercial account holders	94		94		—		—
Total	$	145	$	145	$	—	$	—

The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts and segregated safekeeping accounts at the FHLB of Seattle. 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.

Information concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities, was as follows:



(dollars in millions)	2014			2013			2012
Amount outstanding as of December 31	$	191		$	145		$	146
Average amount outstanding during the year	$	155		$	147		$	173
Maximum amount outstanding as of any month-end	$	195		$	151		$	189
Weighted-average interest rate as of December 31	1.45		%	1.75		%	1.74		%
Weighted-average interest rate during the year	1.67		%	1.74		%	1.56		%
Weighted-average remaining days to maturity as of December 31	343			367			489

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As of December 31, 2014, securities sold under agreements to repurchase were summarized as follows:



Maturity	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	$	84,758		0.15	%	$	114,883
1 to 29 days	—			—		—
30 to 90 days	—			—		—
Over 90 days	105,898		¹	2.50		115,842
	$	190,656		1.45	%	$	230,725


¹	$50.3 million callable 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, 2014	Weighted-average stated rate		Amount
(dollars in thousands)
Due in
2015	—	%	$	—
2016	—		—
2017	4.28		50,000		¹
2018	1.95		50,000
2019	—		—
Thereafter	—		—
	3.12	%	$	100,000


¹	Callable quarterly at par until maturity in 2017.

ASB and the FHLB of Seattle 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 of Seattle makes loans or advances from time to time. Under the Advances Agreement, ASB agrees to abide by the FHLB of Seattle’s credit policies, and makes certain warranties and representations to the FHLB of Seattle. 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 of Seattle 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 of Seattle are collateralized by loans and stock in the FHLB of Seattle. As of December 31, 2014 and 2013, ASB’s available FHLB of Seattle borrowing capacity was $1.2 billion and $1.1 billion, respectively. ASB is required to obtain and hold a specific number of shares of capital stock of the FHLB of Seattle. ASB was in compliance with all Advances Agreement requirements as of December 31, 2014 and 2013.

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, 2014, 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, 2014, ASB was in compliance with the minimum capital requirements under OCC regulations.

In 2014, ASB paid cash dividends of $36 million to HEI, compared to cash dividends of $40 million in 2013. The FRB and OCC approved the dividends.

Related-party transactions. HEI charged ASB $2.3 million, $2.3 million and $1.9 million for general management and administrative services in 2014, 2013 and 2012, 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.

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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	2014					2013
(in thousands)	Notional amount		Fair value			Notional amount		Fair value
Interest rate lock commitments	$	29,330	$	390		$	25,070	$	464
Forward commitments	32,833		(106		)	26,018		139

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	2014				2013
(in thousands)	Asset derivatives		Liability derivatives		Asset derivatives		Liability derivatives
Interest rate lock commitments	$	393	$	3	$	488	$	24
Forward commitments	5		111		141		2
	$	398	$	114	$	629	$	26

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

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



Derivative Financial Instruments Not Designated	Location of net gains
as Hedging Instruments	(losses) recognized in	Years ended December 31
(in thousands)	the Statements of Income	2014			2013		2012
Interest rate lock commitments	Mortgage banking income	$	(74	)	$	464	$	—
Forward commitments	Mortgage banking income	(245		)	139		—
		$	(319	)	$	603	$	—

There were no significant gains or losses on derivatives in 2012.

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

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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	2014		2013
(in thousands)
Unfunded commitments to extend credit:
Home equity line of credit	$	1,089,633	$	1,011,334
Commercial and commercial real estate	526,133		527,987
Consumer	56,312		58,080
Residential 1-4 family	20,524		14,241
Commercial and financial standby letters of credit	20,082		15,747
Total	$	1,712,684	$	1,627,389

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, 2014, 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. ASB's appeal is pending before the Hawaii Supreme Court. However, in December 2014, through a voluntary mediation process, ASB reached a tentative settlement of the claims. The tentative settlement, which remains subject to final court approval, provides for a payment of $2.0 million into a class settlement fund, the proceeds of which will be used to refund class members and pay attorneys’ fees and administrative and other costs, in exchange for a complete release of all claims asserted against ASB. As of December 2014, the $2.0 million tentative settlement amount was fully reserved by ASB.

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

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. 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, 2014 and 2013, ASB’s FDIC insurance assessments were $3.0 million and $2.9 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.

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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, 2014 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 2014 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, 2014, the Utilities had seven 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	2014		2013		2012
(in millions)
AES Hawaii	$	145	$	134	$	146
Kalaeloa	279		301		310
HEP	51		51		65
HPOWER	66		61		65
Other IPPs	181		164		138
Total IPPs	$	722	$	711	$	724

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

Since 2004, Hawaiian Electric has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2014, the Utilities sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as Hawaii Electric Light and Maui Electric do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

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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.

Pursuant to the current accounting standards for VIEs, Hawaiian Electric is deemed to have a variable interest in Kalaeloa by reason of the provisions of Hawaiian Electric’s PPA with Kalaeloa. However, management has concluded that Hawaiian Electric is not the primary beneficiary of Kalaeloa because Hawaiian Electric does not have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, Hawaiian Electric has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses Hawaiian Electric could potentially absorb is the fact that Hawaiian Electric’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although Hawaiian Electric absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose Hawaiian Electric to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through Hawaiian Electric’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of December 31, 2014, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $13 million.

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7 · Short-term borrowings

As of December 31, 2014 and 2013, HEI had $119 million and $105 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 0.7% and 0.7%, respectively, and Hawaiian Electric had no commercial paper outstanding.

As of December 31, 2014, 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 2014 and 2013. 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 19% as of December 31, 2014, as calculated under the agreement) or if HEI no longer owns Hawaiian Electric. The HEI Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI).

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

Hawaiian Electric. On April 2, 2014, Hawaiian Electric and a syndicate of nine financial institutions entered into an amended and restated revolving non-collateralized credit agreement (Hawaiian Electric Facility). The Hawaiian Electric Facility increased Hawaiian Electric’s line of credit to $200 million from $175 million. In January 2015, the PUC approved Hawaiian Electric’s request to extend the term of the credit facility to April 2, 2019. The Hawaiian Electric Facility provided improved pricing compared to its prior facility. Under the Hawaiian Electric Facility, draws would generally bear interest, based on Hawaiian Electric’s current long-term credit ratings, at the “Adjusted LIBO Rate,” as defined in the agreement, plus 125 basis points and annual fees on undrawn commitments of 17.5 basis points. The Hawaiian Electric Facility contains updated provisions for pricing adjustments in the event of a long-term ratings change based on the Hawaiian Electric Facility’s ratings-based pricing grid. Certain modifications were made to incorporate some updated terms and conditions customary for facilities of this type. The Hawaiian Electric Facility does not contain clauses that would affect access to the facility by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses, but it continues to contain customary conditions which must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, Hawaiian Electric, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 41% for Hawaii Electric Light and 42% for Maui Electric as of December 31, 2014, as calculated under the agreement)). In addition to customary defaults, Hawaiian Electric’s failure to maintain its financial ratios, as defined in its credit agreement, or meet other requirements may result in an event of default. For example, under the credit agreement, it is an event of default if Hawaiian Electric fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 58% as of December 31, 2014, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI. Under the proposed Merger Agreement, Hawaiian Electric will become a wholly-owned subsidiary of NextEra. The terms of the Hawaiian Electric Facility are such that the proposed Merger would constitute a “Change in Control.” Hawaiian Electric has requested, and the financial institutions providing the Hawaiian Electric Facility have consented and agreed, that the proposed Merger shall not constitute a “Change in Control,” as defined in the credit agreement, provided that (i) the Merger is consummated and (ii) Hawaiian Electric becomes and remains a wholly-owned subsidiary of NextEra.

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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	2014		2013
(dollars in thousands)
Long-term debt of Utilities¹	$	1,206,546	$	1,217,945
HEI term loan LIBOR + .90%, due 2016	125,000		—
HEI medium-term note 6.51%, paid 2014	—		100,000
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
	$	1,506,546	$	1,492,945


¹	See components of “Total long-term debt” and unamortized discount in Hawaiian Electric and subsidiaries’ Consolidated Statements of Capitalization.

As of December 31, 2014, the aggregate principal payments required on the Company’s long-term debt for 2015 through 2019 are nil in 2015, $200 million in 2016, nil in 2017, $50 million in 2018 and nil in 2019. As of December 31, 2014, the aggregate payments of principal required on the Utilities' long-term debt for 2015 through 2019 are nil in 2015, 2016, 2017, $50 million in 2018 and nil in 2019.

The HEI medium-term notes 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 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).

May 2014 loan. On May 2, 2014, HEI entered into a loan agreement with The Bank of Tokyo-Mitsubishi UFJ, Ltd., Royal Bank of Canada and U.S. Bank, National Association, which agreement includes substantially the same financial covenant and customary conditions as the HEI credit agreement described above. On May 2, 2014, HEI drew a $125 million Eurodollar term loan for a term of two years and at a resetting interest rate ranging from 1.12% to 1.14% through December 31, 2014. 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.

9 · Shareholders’ equity

Reserved shares. As of December 31, 2014, HEI had reserved (a) a total of 18,372,187 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 1987 Stock Option and Incentive Plan, the HEI 2011 Nonemployee Director Stock Plan, the ASB 401(k) Plan and the 2010 Executive Incentive Plan and (b) a total of 4.7 million shares of common stock for future issuance in connection with the equity forward transaction described below.

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.

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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, to the extent that the transactions are physically settled, HEI would be required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transactions. Initially, the equity forward transactions had to be settled fully by March 25, 2015, but an amendment extended this date to December 31, 2015. Except in specified circumstances or events that would require physical settlement, HEI is able to elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to December 31, 2015.

The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI receives proceeds from the sale of common stock when the equity forward transactions are settled and records the proceeds at that time in equity. 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, HEI settled 1.3 million shares under the equity forward for proceeds of $32.1 million (net of the underwriting discount of $1.3 million), which funds were ultimately used to purchase Hawaiian Electric shares. On July 14, 2014, HEI settled 1.0 million shares for proceeds of $23.9 million (net of underwriting discount of $1.0 million), which funds were ultimately used to purchase Hawaiian Electric shares.

At December 31, 2014, the equity forward transactions could have been settled with delivery to the forward counterparty of (a) 4.7 million shares in exchange for cash of $106 million, (b) cash of approximately $51 million (which amount includes $5 million of underwriting discount), or (c) approximately 1.5 million shares.

Prior to their settlement, the shares remaining under the equity forward transactions will be reflected in HEI’s diluted EPS calculations using the treasury stock method. Under this method, the number of shares of HEI’s common stock used in calculating diluted EPS for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transactions less the number of shares that could be purchased by HEI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transactions (based on the adjusted forward sale price of $22.63 as of December 31, 2014). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transactions are outstanding.

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

For 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:

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	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, 2011	$	9,886		$	(996	)	$	(28,027	)	$	(19,137	)	$	(32	)
Current period other comprehensive income (loss)	875			236			(8,397		)	(7,286		)	(938		)
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

Reclassifications out of AOCI were as follows:



	Amount reclassified from AOCI
Years ended December 31	2014			2013			2012			Affected line item in the Statement of Income
(in thousands)
HEI consolidated
Net realized gains on securities	$	(1,715	)	$	(738	)	$	(81	)	Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	236			235			236			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	11,344			23,280			15,291			See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	207,833			(222,595		)	75,471			See Note 10 for additional details
Total reclassifications	$	217,698		$	(199,818	)	$	90,917
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	$	10,212		$	20,694		$	13,673		See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	207,833			(222,595		)	75,471			See Note 10 for additional details
Total reclassifications	$	218,045		$	(201,901	)	$	89,144

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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 are 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), 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 $1.2 million in 2014 and 2013) 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 $340 million pretax and $(364) million pretax for 2014 and 2013, respectively).

In 2007, the PUC allowed Hawaii Electric Light to record a regulatory asset in the amount of $12.8 million (representing Hawaii Electric Light’s prepaid pension asset and reflecting the accumulated pension contributions to its pension fund in excess of accumulated NPPC), which is included in rate base, and allowed recovery of that asset over a period of five years. Hawaii Electric Light is required to make contributions to the pension trust in the amount of the actuarially calculated NPPC that would be allowed without penalty by the tax laws.

In 2007, the PUC declined to allow Hawaiian Electric and Maui Electric to include their pension assets (representing the accumulated contributions to their pension fund in excess of accumulated NPPC), in their rate bases. However, under the tracking mechanisms, Hawaiian Electric and Maui Electric are required to fund only the minimum level required under the law until their pension assets are reduced to zero, at which time Hawaiian Electric and Maui Electric will 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 PUC’s exclusion of Hawaiian Electric’s and Maui Electric’s pension assets from rate base does not allow Hawaiian Electric and Maui Electric to earn a return on the pension asset, but this exclusion does not result in the exclusion of any pension benefit costs from their rates. The pension asset is to be (and has been, in the case of Maui Electric) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2014, Hawaiian Electric’s pension asset had been reduced to nil.

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 2014, 2013 and 2012 was $32 million, $30 million and $32 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 2014 and 2013 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, 2014 and 2013 were as follows:



	2014						2013
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
HEI consolidated
Benefit obligation, January 1	$	1,446,291		$	176,099		$	1,590,304		$	194,135
Service cost	49,264			3,490			56,405			4,306
Interest cost	72,202			8,550			64,788			7,569
Actuarial losses (gains)	342,446			39,098			(203,302		)	(21,743		)
Benefits paid and expenses	(62,975		)	(8,028		)	(61,904		)	(8,168		)
Benefit obligation, December 31	1,847,228			219,209			1,446,291			176,099
Fair value of plan assets, January 1	1,186,669			179,330			971,314			156,731
Actual return on plan assets	81,123			9,149			194,130			29,164
Employer contributions	60,103			(257		)	82,083			954
Benefits paid and expenses	(61,835		)	(7,890		)	(60,858		)	(7,519		)
Fair value of plan assets, December 31	1,266,060			180,332			1,186,669			179,330
Accrued benefit asset (liability), December 31	$	(581,168	)	$	(38,877	)	$	(259,622	)	$	3,231
Other assets	$	12,800		$	—		$	24,948		$	7,200
Defined benefit pension and other postretirement benefit plans liability	(593,968		)	(38,877		)	(284,570		)	(3,969		)
Accrued benefit asset (liability), December 31	$	(581,168	)	$	(38,877	)	$	(259,622	)	$	3,231
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)	$	317,544		$	(21,722	)	$	680,781		$	18,846
Recognized during year – net recognized transition obligation	—			—			—			—
Recognized during year – prior service credit (cost)	(88		)	1,793			97			1,793
Recognized during year – net actuarial losses	(20,304		)	11			(38,438		)	(1,602		)
Occurring during year – net actuarial losses (gains)	342,679			40,851			(324,896		)	(40,759		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	639,831			20,933			317,544			(21,722		)
Cumulative impact of PUC D&Os	(592,291		)	(22,975		)	(294,266		)	19,206
AOCI debit/(credit), December 31	$	47,540		$	(2,042	)	$	23,278		$	(2,516	)
Net actuarial loss (gain)	$	640,015		$	35,022		$	317,639		$	(5,840	)
Prior service gain	(184		)	(14,089		)	(95		)	(15,882		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	639,831			20,933			317,544			(21,722		)
Cumulative impact of PUC D&Os	(592,291		)	(22,975		)	(294,266		)	19,206
AOCI debit/(credit), December 31	47,540			(2,042		)	23,278			(2,516		)
Income taxes (benefits)	(18,742		)	795			(9,180		)	980
AOCI debit/(credit), net of taxes (benefits), December 31	$	28,798		$	(1,247	)	$	14,098		$	(1,536	)

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	2014						2013
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Hawaiian Electric consolidated
Benefit obligation, January 1	$	1,320,810		$	169,579		$	1,449,445		$	187,110
Service cost	47,597			3,392			54,482			4,163
Interest cost	65,979			8,234			59,119			7,288
Actuarial losses (gains)	314,210			38,488			(185,185		)	(20,900		)
Benefits paid and expenses	(57,819		)	(7,933		)	(57,051		)	(8,082		)
Benefit obligation, December 31	1,690,777			211,760			1,320,810			169,579
Fair value of plan assets, January 1	1,058,260			176,291			861,778			154,186
Actual return on plan assets	69,242			9,036			172,822			28,700
Employer contributions	58,948			(274		)	80,325			839
Benefits paid and expenses	(57,445		)	(7,797		)	(56,665		)	(7,434		)
Fair value of plan assets, December 31	1,129,005			177,256			1,058,260			176,291
Accrued benefit asset (liability), December 31	$	(561,772	)	$	(34,504	)	$	(262,550	)	$	6,712
Other assets	$	—		$	—		$	—		$	7,200
Other liabilities (short-term)	(421		)	(460		)	(388		)	(488		)
Defined benefit pension and other postretirement benefit plans liability	(561,351		)	(34,044		)	(262,162		)	—
Accrued benefit asset (liability), December 31	$	(561,772	)	$	(34,504	)	$	(262,550	)	$	6,712
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)	$	295,973		$	(21,907	)	$	623,588		$	17,432
Recognized during year – net recognized transition asset	—			—			—			—
Recognized during year – prior service credit (cost)	(62		)	1,804			464			1,803
Recognized during year – net actuarial losses	(18,459		)	—			(34,597		)	(1,544		)
Occurring during year – net actuarial losses (gains)	317,651			40,193			(293,482		)	(39,598		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	595,103			20,090			295,973			(21,907		)
Cumulative impact of PUC D&Os	(592,291		)	(22,975		)	(294,266		)	19,206
AOCI debit/(credit), December 31	$	2,812		$	(2,885	)	$	1,707		$	(2,701	)
Net actuarial loss (gain)	$	595,017		$	34,192		$	295,825		$	(6,001	)
Prior service cost (gain)	86			(14,102		)	148			(15,906		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	595,103			20,090			295,973			(21,907		)
Cumulative impact of PUC D&Os	(592,291		)	(22,975		)	(294,266		)	19,206
AOCI debit/(credit), December 31	2,812			(2,885		)	1,707			(2,701		)
Income taxes (benefits)	(1,094		)	1,122			(664		)	1,050
AOCI debit/(credit), net of taxes (benefits), December 31	$	1,718		$	(1,763	)	$	1,043		$	(1,651	)

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2014, 2013 and 2012.

On August 8, 2014 and July 6, 2012, President Obama signed the Highway and Transportation Funding Act of 2014 (HATFA) and the Moving Ahead for Progress in the 21st Century Act (MAP-21), respectively, which included provisions related to the funding and administration of pension plans with no impact to the Company’s or the Utilities' accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to not apply HATFA to the 2013 plan year. The Company elected to apply MAP-21 for 2012, which improved the plans’ Adjusted Funding Target Attainment Percentage for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect from April 1, 2011 to September 30, 2012) for HEI and the Utilities. MAP-21 caused the minimum required funding under the Employee Retirement Income Security Act of 1974, as amended (ERISA) to be less than the net periodic cost for 2013 and 2014. Similarly, HATFA caused the minimum required funding under ERISA to be less than the net periodic cost for 2014; therefore, to satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities contributed the net periodic cost in 2014.

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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 2012 and 2013 so that the more conservative assumptions did not apply for either the 2013 or 2014 valuation of plan liabilities for purposes of calculating the minimum required contribution. Other factors could cause changes to the required contribution levels.

The 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 around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual NPBC.

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	2014		2013		Target		Range	2014		2013		Target		Range
Assets held by category
Equity securities managers	73	%	73	%	70	%	65-75	72	%	74	%	70	%	65-75
Fixed income securities managers	27		27		30		25-35	28		26		30		25-35
	100	%	100	%	100	%		100	%	100	%	100	%


¹	Asset allocation for 2014 is applicable to 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, 2014, all of its pension assets were invested in fixed income securities. In 2013, ASB’s assets were invested using an allocation consistent with that of HEI and the Utilities.


²	Asset allocation for 2014 and 2013 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	2014		2013		2012		2014		2013		2012
Benefit obligation
Discount rate	4.22	%	5.09	%	4.13	%	4.17	%	5.03	%	4.07	%
Rate of compensation increase	3.5		3.5		3.5		NA		NA		NA
Net periodic benefit cost (years ended)
Discount rate	5.09		4.13		5.19		5.03		4.07		4.90
Expected return on plan assets	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

The Company and the Utilities based their selection of an assumed discount rate for 2015 NPBC and December 31, 2014 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, 2014. In selecting the expected rate of return on plan assets for 2015 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 driven investment strategy in selecting 4.22%, which is consistent with the assumed discount rate for 2015.

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The Company and the Utilities adopted updated mortality tables published 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.

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%. As of December 31, 2013, the assumed health care trend rates for 2014 and future years were as follows: medical, 7.5%, grading down to 5% for 2024 and thereafter; dental, 5%; and vision, 4%. Medicare Advantage reimbursements are expected to phase out by 2016; therefore, post age 65 medical trends are adjusted to reflect anticipated increases above the ordinary medical trend rates. For post age 65, the medical trend is 4% higher than pre-65 for 2014 and 3% higher in 2015.

The components of NPBC were as follows:



	Pension benefits									Other benefits
(in thousands)	2014			2013			2012			2014			2013			2012
HEI consolidated
Service cost	$	49,264		$	56,405		$	43,221		$	3,490		$	4,306		$	4,211
Interest cost	72,202			64,788			67,480			8,550			7,569			9,009
Expected return on plan assets	(81,355		)	(72,537		)	(71,183		)	(10,902		)	(10,147		)	(10,336		)
Amortization of net transition obligation	—			—			1			—			—			—
Amortization of net prior service (gain) cost	88			(97		)	(325		)	(1,793		)	(1,793		)	(1,793		)
Amortization of net actuarial loss (gains)	20,304			38,438			25,675			(11		)	1,602			1,498
Net periodic benefit cost	60,503			86,997			64,869			(666		)	1,537			2,589
Impact of PUC D&Os	(13,324		)	(38,104		)	(15,754		)	1,976			(1,458		)	(2,227		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	47,179			48,893			49,115			1,310			79			362
Hawaiian Electric consolidated
Service cost	$	47,597		$	54,482		$	41,603		$	3,392		$	4,163		$	4,014
Interest cost	65,979			59,119			61,453			8,234			7,288			8,703
Expected return on plan assets	(72,661		)	(64,551		)	(64,004		)	(10,739		)	(10,002		)	(10,195		)
Amortization of net transition obligation	—			—			—			—			—			(9		)
Amortization of net prior service (gain) cost	62			(464		)	(689		)	(1,804		)	(1,803		)	(1,803		)
Amortization of net actuarial loss	18,459			34,597			23,428			—			1,544			1,455
Net periodic benefit cost	59,436			83,183			61,791			(917		)	1,190			2,165
Impact of PUC D&Os	(13,324		)	(38,104		)	(15,754		)	1,976			(1,458		)	(2,227		)
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	46,112		$	45,079		$	46,037		$	1,059		$	(268	)	$	(62	)

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 net periodic benefit cost during 2015 is as follows:



	HEI consolidated					Hawaiian Electric consolidated
(in millions)	Pension benefits		Other benefits			Pension benefits		Other benefits
Estimated prior service cost (credit)	$	—	$	(1.8	)	$	—	$	(1.8	)
Net actuarial loss	35.8		1.7			32.4		1.7
Net transition obligation	—		—			—		—

The Company recorded pension expense of $32 million, $34 million and $35 million and OPEB expense of $1.2 million, $0.4 million and $1.0 million in 2014, 2013 and 2012, respectively, and charged the remaining amounts primarily to electric utility plant. The Utilities recorded pension expense of $31 million, $30 million and $32 million and OPEB expense of $1.0 million, nil and $0.4 million in 2014, 2013 and 2012, respectively, and charged the remaining amounts primarily to electric utility plant.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2014, 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

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APBO by $4.6 million. As of December 31, 2014, 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 $0.3 million and the APBO by $4.5 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, 2014 and 2013, had aggregate ABOs of $1.5 billion and $1.2 billion, respectively, and plan assets of $1.2 billion and $1.1 billion, respectively. 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. The defined benefit pension plans with PBOs in excess of plan assets as of December 31, 2013, had aggregate PBOs of $1.4 billion and plan assets of $1.1 billion. As of December 31, 2014, the other postretirement benefit plans shown in the table above had ABOs in excess of plan assets. As of December 31, 2013, the other postretirement benefit plans with ABOs in excess of plan assets had aggregate ABOs of $0.4 million and plan assets of nil .

The Company estimates that the cash funding for the qualified defined benefit pension plans in 2015 will be $85 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 2015 is $0.5 million.

As of December 31, 2014, the benefits expected to be paid under all retirement benefit plans in 2015, 2016, 2017, 2018, 2019 and 2020 through 2024 amounted to $76 million, $79 million, $83 million, $87 million, $91 million and $520 million, respectively.

Hawaiian Electric consolidated. The defined benefit pension plans with ABOs in excess of plan assets as of December 31, 2014 and 2013, had aggregate ABOs of $1.5 billion and $1.2 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, 2014 and 2013. As of December 31, 2014, the other postretirement benefit plan shown in the table above had an ABO in excess of plan assets. As of December 31, 2013, the other postretirement benefit plan shown in the table above had plan assets in excess of ABO.

The Utilities estimate that the cash funding for the qualified defined benefit pension plan in 2015 will be $83 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 2015 is $0.5 million.

As of December 31, 2014, the benefits expected to be paid under all retirement benefit plans in 2015, 2016, 2017, 2018, 2019 and 2020 through 2024 amounted to $70 million, $73 million, $76 million, $79 million, $83 million and $476 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 2014, 2013 and 2012, the Company’s expense for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was $5 million, $5 million and $4 million, respectively, and cash contributions were $5 million, $4 million and $4 million, respectively. The Utilities’ expense for its defined contribution pension plan under the HEIRSP Plan for 2014 and 2013 was $0.9 million and $0.6 million, respectively, and 2012 was de minimis.

11 · Share-based compensation

Under the 2010 Equity and Incentive Plan, 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 was amended and restated (EIP) effective March 1, 2014 and an additional 1.5 million shares was added to the shares available for issuance under these programs.

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As of December 31, 2014, approximately 3.6 million shares were remaining 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 0.9 million shares that could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals for awards outstanding under long-term incentive plans (assuming that such performance goals are achieved at maximum levels).

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), there are possible future issuances of an estimated 17,000 shares upon the exercise of outstanding SARs based on the market price of shares on December 31, 2014. As of May 11, 2010 (when the 2010 Equity and Incentive Plan became effective), no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered under the SOIP will be deregistered and delisted.

For the SARs 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 expire if not exercised ten years from the date of the grant. SARs compensation expense has been 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.

The restricted shares that have been issued under the 2010 Equity and Incentive Plan become unrestricted in four equal annual increments on the anniversaries of the grant date and are forfeited to the extent they have not become unrestricted for terminations of employment during the vesting period, except accelerated vesting is provided for terminations by reason of death, disability and termination without cause. Restricted shares compensation expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted shares are paid quarterly in cash. There were no outstanding restricted shares as of December 31, 2014.

Restricted stock units awarded under the 2010 Equity and Incentive Plan in 2014, 2013, 2012 and 2011 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 awarded under the SOIP and 2010 Equity and Incentive Plan in 2010 and prior years generally vest and will be issued as unrestricted stock four years after the date of the grant and are forfeited 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 the2012-2014, 2013-2015 and 2014-2016 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, 2014, there were 169,290 shares remaining available for future issuance under the 2011 Director Plan.

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



(in millions)	2014		2013		2012
HEI consolidated
Share-based compensation expense¹	$	9.3	$	7.8	$	6.7
Income tax benefit	3.4		2.8		2.4
Hawaiian Electric consolidated
Share-based compensation expense¹	3.1		2.3		1.8
Income tax benefit	1.2		0.9		0.7


¹	$0.16 million, $0.11 million and $0.08 million of this share-based compensation expense was capitalized in 2014, 2013 and 2012, 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)	2014		2013		2012
Shares granted	33,170		33,184		29,448
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				2012
	Shares		(1)		Shares		(1)
Outstanding, January 1	14,000		$	20.49	55,500		$	20.92
Granted	—		—		—		—
Exercised	(14,000	)	20.49		(41,500	)	21.06
Forfeited	—		—		—		—
Expired	—		—		—		—
Outstanding, December 31	—		$	—	14,000		$	20.49
Exercisable, December 31	—		$	—	14,000		$	20.49


(1)	Weighted-average exercise price

As of December 31, 2014, there were no NQSOs outstanding.

NQSO activity and statistics were as follows:



(in thousands)	2013		2012
Cash received from exercise	$	287	$	874
Intrinsic value of shares exercised ¹	128		354
Tax benefit realized for the deduction of exercises	50		138


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:



	2014				2013			2012
	Shares		(1)		Shares	(1)		Shares		(1)
Outstanding, January 1	164,000		$	26.12	164,000	$	26.12	282,000		$	26.14
Granted	—		—		—	—		—		—
Exercised	(22,000	)	26.18		—	—		(114,000	)	26.17
Forfeited	(62,000	)	26.02		—	—		—		—
Expired	—		—		—	—		(4,000	)	26.18
Outstanding, December 31	80,000		$	26.18	164,000	$	26.12	164,000		$	26.12
Exercisable, December 31	80,000		$	26.18	164,000	$	26.12	164,000		$	26.12


(1)	Weighted-average exercise price



December 31, 2014	Outstanding & Exercisable (Vested)
Year of Grant	Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price
2005	80,000	0.3	$	26.18

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As of December 31, 2014, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.6 million.

SARs activity and statistics were as follows:



(in thousands)	2014		2013		2012
Intrinsic value of shares exercised ¹	$	29	$	—	$	197
Tax benefit realized for the deduction of exercises	11		—		77


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.

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



	2014				2013				2012
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	4,503		$	22.21	9,005		$	22.21	46,807		$	24.45
Granted	—		—		—		—		—		—
Vested	(4,503	)	22.21		(4,502	)	22.21		(37,802	)	24.99
Forfeited	—		—		—		—		—		—
Outstanding, December 31	—		$	—	4,503		$	22.21	9,005		$	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, 2013 and 2012, total restricted stock vested had a grant-date fair value of $0.1 million, $0.1 million and $0.9 million, respectively, and the tax benefits realized for the tax deductions related to restricted stock awards were nil for 2014, nil for 2013 and $0.2 million for 2012.

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



	2014					2013					2012
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	288,151			$	25.17	315,094			$	22.82	247,286			$	21.80
Granted	117,786			25.17		111,231			26.88		98,446			25.99
Vested	(144,702		)	24.09		(118,885		)	20.48		(25,728		)	24.68
Forfeited	—			—		(19,289		)	25.62		(4,910		)	24.92
Outstanding, December 31	261,235			$	25.77	288,151			$	25.17	315,094			$	22.82
Total weighted-average grant-date fair value of shares granted ($ millions)	$	3.0				$	3.0				$	2.6


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

For 2014, 2013 and 2012 total restricted stock units and related dividends that vested had a fair value of $4.1 million, $3.7 million and $0.7 million, respectively, and the related tax benefits were $1.2 million, $0.9 million and $0.2 million, respectively.

As of December 31, 2014, there was $4.4 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.5 years.

Long-term incentive plan payable in stock. The 2012-2014 long-term incentive plan (LTIP), 2013-2015 LTIP and 2014-2016 LTIP provide for performance awards under the 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 2012-2014 LTIP, 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

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consolidated ROACE, ASB net income and ASB return on assets – all based on the applicable three-year averages, and ASB return on assets relative to performance peers.

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



	2014					2013					2012
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	232,127			$	32.88	239,256			$	29.12	197,385			$	25.94
Granted	97,524			22.95		91,038			32.69		81,223			30.71
Vested (settled or lapsed)	(70,189		)	35.46		(87,753		)	22.45		(35,397		)	14.85
Forfeited	(1,506		)	28.32		(10,414		)	32.72		(3,955		)	30.82
Outstanding, December 31	257,956			$	28.45	232,127			$	32.88	239,256			$	29.12
Total weighted-average grant-date fair value of shares granted ($ millions)	$	2.2				$	3.0				$	2.5


(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			2012
Risk-free interest rate	0.66		%	0.38		%	0.33		%
Expected life in years	3			3			3
Expected volatility	17.8		%	19.4		%	25.3		%
Range of expected volatility for Peer Group	12.4% to 23.3%			12.4% to 25.3%			15.5% to 34.5%
Grant date fair value (per share)	$	22.95		$	32.69		$	30.71

For 2014, 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of nil, $2.2 million and $0.6 million, respectively, and the related tax benefits were nil, $0.9 million and $0.2 million, respectively. For 2014, all of the shares vested (which were granted at target level based on the satisfaction of TRS performance) for the 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, 2014, there was $2.2 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 1.5 years.

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



	2014					2013					2012
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	296,843			$	26.14	247,175			$	25.04	182,498			$	22.63
Granted	129,603			25.18		120,399			26.89		125,157			26.05
Vested and settled	(65,089		)	24.95		(18,280		)	18.95		—			—
Increase above target (cancelled)	4,949			26.70		(41,599		)	24.97		(50,786		)	18.95
Forfeited	(1,575		)	26.07		(10,852		)	26.20		(9,694		)	24.44
Outstanding, December 31	364,731			$	26.01	296,843			$	26.14	247,175			$	25.04
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)	$	3.3				$	3.2				$	3.3


(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 2014 and 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $1.9 million and $0.6 million, respectively, and the related tax benefits were $0.8 million and $0.2 million, respectively.

As of December 31, 2014, there was $3.4 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.5 years.

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	2014			2013			2012			2014			2013			2012
(in thousands)
Federal
Current, as revised (1)	$	(10,970	)	$	(1,520	)	$	(15,411	)	$	1,108		$	1,313		$	(26,965	)
Deferred, as revised (1)	91,159			73,680			82,138			68,775			58,024			79,437
Deferred tax credits, net	—			224			187			—			224			186
	80,189			72,384			66,914			69,883			59,561			52,658
State
Current	(7,339		)	(1,555		)	(4,654		)	(9,436		)	(3,720		)	(4,940		)
Deferred	12,756			6,719			8,710			14,172			6,483			7,441
Deferred tax credits, net	6,106			6,793			5,889			6,106			6,793			5,889
	11,523			11,957			9,945			10,842			9,556			8,390
Total	$	91,712		$	84,341		$	76,859		$	80,725		$	69,117		$	61,048

(1) As revised for HEI consolidated by $(44,732) for "Current" and $44,732 for "Deferred" for the year ended December 31, 2014 - See Note 1, “Summary of significant accounting policies - Revision and restatements of previously issued financial statements.”

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	2014			2013			2012			2014			2013			2012
(in thousands)
Amount at the federal statutory income tax rate	$	91,672		$	86,711		$	76,092		$	77,126		$	67,914		$	56,812
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	7,490			7,772			6,464			7,047			6,211			5,453
Other, net	(7,450		)	(10,142		)	(5,697		)	(3,448		)	(5,008		)	(1,217		)
Total	$	91,712		$	84,341		$	76,859		$	80,725		$	69,117		$	61,048
Effective income tax rate	35.0		%	34.0		%	35.4		%	36.6		%	35.6		%	37.6		%

The Company's effective tax rate increased in 2014 compared to 2013 primarily due to the nondeductibility of merger costs, partly offset by increased tax credits in 2014 and the $2.7 million out-of-period income tax benefits in 2013 (see “Out-of-period income tax benefit”). The Utilities' effective tax rate increased in 2014 compared to 2013 primarily due to the out-of-period income tax benefits.

The Company’s and the Utilities' effective tax rate decreased in 2013 compared to 2012 primarily due to $3.5 million lower deferred taxes related to the tax gross-up of AFUDC-equity and a $3.1 million (including $2.7 million related to the Utilities) out-of-period income tax benefit (see “Out-of-period income tax benefit”).

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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	2014		2013		2014		2013
(in thousands)
Deferred tax assets
Net operating loss	$	—	$	—	51,936		19,848
Other	58,352		57,239		17,663		17,295
Total deferred tax assets	58,352		57,239		69,599		37,143
Deferred tax liabilities
Property, plant and equipment related	448,723		378,280		446,259		375,771
Repairs deduction	86,408		75,127		86,408		75,127
Regulatory assets, excluding amounts attributable to property, plant and equipment	33,795		33,251		33,795		33,251
Deferred RAM and RBA revenues	32,889		—		32,889		—
Retirement benefits	25,336		29,280		28,758		23,851
Other	62,935		70,561		14,929		15,602
Total deferred tax liabilities	690,086		586,499		643,038		523,602
Net deferred income tax liability	$	631,734	$	529,260	$	573,439	$	486,459
Prepayments and other (Current assets-debit)	$	—	$	—	$	32,915	$	20,702
Other (Current liabilities-credit)	—		—		3,482		—
Deferred income taxes (credit)	631,734		529,260		602,872		507,161
Net deferred income tax liability	$	631,734	$	529,260	$	573,439	$	486,459

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, 2014, the valuation allowance for deferred tax benefits is not significant. In 2014, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation resulting from the Tax Increase Prevention Act of 2014 and the IRS approval of an accounting method that defers the recognition of Revenue Balance Account income. 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 expect any unutilized net operating loss (NOL) as of December 31, 2014, standalone Hawaiian Electric consolidated expects an unutilized NOL for federal tax purposes in accordance with the HEI tax sharing agreement. The deferred tax asset associated with this NOL is $52 million and is included in “Prepayments and other.”

HEI consolidated. In 2014, 2013 and 2012, 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, $0.3 million and $1.4 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, 2014 and 2013, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and dividends payable” was nil and $0.4 million, respectively.

As of December 31, 2014, the total amount of liability for uncertain tax positions was nil.

Hawaiian Electric consolidated. In 2014, 2013 and 2012, credit adjustments to interest expense on income taxes was reflected in “Interest and other charges” in the amount of $0.7 million, $0.3 million and $0.5 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 2014 and 2013, the total amount of accrued interest related to uncertain tax positions was nil.

As of December 31, 2014, the total amount of liability for uncertain tax positions was nil.

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The changes in total unrecognized tax benefits were as follows:



	HEI consolidated									Hawaiian Electric consolidated
(in millions)	2014			2013			2012			2014			2013			2012
Unrecognized tax benefits, January 1	$	0.9		$	0.8		$	5.7		$	0.5		$	0.4		3.7
Additions based on tax positions taken during the year	—			—			0.3			—			—			0.3
Reductions based on tax positions taken during the year	—			—			—			—			—			—
Additions for tax positions of prior years	0.1			0.5			—			0.1			0.5			—
Reductions for tax positions of prior years	—			(0.4		)	(4.1		)	—			(0.4		)	(3.6		)
Settlements	(1.0		)	—			—			(0.6		)	—			—
Lapses of statute of limitations	—			—			(1.1		)	—			—			—
Unrecognized tax benefits, December 31	$	—		$	0.9		$	0.8		$	—		$	0.5		$	0.4

The 2012 reduction in unrecognized tax benefits was primarily due to the IRS’s acceptance of the deductibility of costs of repairs to utility generation property for tax years 2007-2009.

In 2014, the IRS completed its examination of the Company’s federal income tax returns for tax years 2010 and 2011. The Company and the IRS reached an agreement on all adjustments, primarily related to depreciation, and the Congressional Joint Committee on Taxation approved the resulting tax adjustments in October 2014. The income statement impact of the agreement was not material. Tax years 2007, 2009, and 2010 to 2013 remain subject to examination by the Department of Taxation of the State of Hawaii.

As of December 31, 2014, 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.

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. In September 2013, the IRS issued final regulations addressing the acquisition, production and improvement of tangible property, which are effective January 1, 2014. Management evaluated the impact of these new regulations, and does not expect a material impact on the Utilities since specific guidance on network (i.e., transmission and distribution) assets and generation property has already been received and accounted for in its tax computations. The IRS also proposed regulations addressing the disposition of property.

The Utilities adopted the safe harbor guidelines with respect to network assets in 2011 and in June 2013, the IRS released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. Management intends to adopt a method consistent with this guidance in its 2014 tax return.

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13 · Cash flows



Years ended December 31	2014		2013			2012
(in millions)
Supplemental disclosures of cash flow information
HEI consolidated
Interest paid to non-affiliates	$	84	$	85		$	84
Income taxes paid	47		18			17
Income taxes refunded	24		4			31
Hawaiian Electric consolidated
Interest paid to non-affiliates	61		59			57
Income taxes paid	6		6			6
Income taxes refunded	8		32			9
Supplemental disclosures of noncash activities
HEI consolidated
Property, plant and equipment-unpaid invoices and accruals, as revised for 2014 and restated for 2013 and 2012 (1)	43		(12		)	(8		)
Common stock dividends reinvested in HEI common stock ¹	—		24			24
Loans transferred from held for investment to held for sale	—		25			—
Real estate acquired in settlement of loans	3		4			11
Obligations to fund low income housing investments, net	14		1			—
Hawaiian Electric consolidated
Electric utility property, plant and equipment
AFUDC-equity	7		6			7
Estimated fair value of noncash contributions in aid of construction	3		5			10
Unpaid invoices and accruals, as revised for 2014 and restated for 2013 and 2012 (1)	40		(12		)	(8		)

(1) As revised or restated - See Note 1, “Summary of significant accounting policies - Revision and restatements of previously issued financial statements.”


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, 2014, the Utilities could not transfer approximately $668 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, 2014, ASB could transfer approximately $103 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

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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.

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

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place to ensure quality and control. The third-party pricing services use a variety of methods to determine the fair value of securities that fall under Level 2 of the Company’s fair value measurement hierarchy. Among the considerations are quoted prices for similar securities in an active market, yield spreads for similar trades, adjustments for liquidity, size, collateral characteristics, historic and generic prepayment speeds, and other observable market factors.

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

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

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

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

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

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

Tax credit investments. The estimated fair value of tax credit investments was determined in relation to the yield an aquirer of these investments would expect in relation to yields experienced on current new issues or secondary market transactions.

Time deposits. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

Other borrowings. For fixed-rate advances and repurchase agreements, fair value is estimated using quantitative discounted cash flow models that require the use of interest rate inputs that are currently offered for fixed-rate advances and

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repurchase agreements of similar remaining maturities. The majority of market inputs are actively quoted and can be validated through external sources, including brokers, market transactions and third party pricing services. For hybrid advances, fair value is obtained from an FHLB proprietary model mathematical approximation of the market value of the underlying hedge. The terms of the hedge are similar to the advances and therefore classified as Level 2 within the valuation hierarchy.

Long-term debt. Fair value was obtained from third-party financial services providers based on the current rates offered for debt of the same or similar remaining maturities and from discounting the future cash flows using the current rates offered for debt of the same or similar remaining maturities.

Interest rate lock commitments (IRLCs). The estimated fair value of commitments to originate residential mortgage loans for sale is based on quoted prices for similar loans in active markets. IRLCs are classified as Level 2 measurements.

Forward sales commitments. To be announced (TBA) mortgage-backed securities forward commitments are classified as Level 1, and consist of publicly-traded debt securities for which identical fair values can be obtained through quoted market prices in active exchange markets. The fair values of ASB’s best efforts and mandatory delivery loan sale commitments are determined using quoted prices in the market place that are observable and are classified as Level 2 measurements.

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

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			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, 2014
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	550,394		—		550,394		—		550,394
Stock in Federal Home Loan Bank of Seattle	69,302		—		69,302		—		69,302
Loans receivable, net	4,397,457		—		—		4,578,822		4,578,822
Derivative assets	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
December 31, 2013
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment securities	529,007		—		529,007		—		529,007
Stock in Federal Home Loan Bank of Seattle	92,546		—		92,546		—		92,546
Loans receivable, net	4,115,415		—		—		4,211,290		4,211,290
Derivative assets	46,356		98		531		—		629
Financial liabilities
Deposit liabilities	4,372,477		—		4,374,377		—		4,374,377
Short-term borrowings—other than bank	105,482		—		105,482		—		105,482
Other bank borrowings	244,514		—		256,029		—		256,029
Long-term debt, net—other than bank	1,492,945		—		1,508,425		—		1,508,425
The Utilities' long-term debt, net (included in amount above)	1,217,945		—		1,228,966		—		1,228,966
Derivative liabilities	4,732		—		26		—		26

As of December 31, 2014 and 2013, loans serviced by ASB for others had notional amounts of $1.4 billion and $1.4 billion, respectively, and the estimated fair value of the mortgage servicing rights for such loans was $14.5 million and $15.7 million, respectively.

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



December 31	2014						2013
	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	$	—	$	430,834	$	—	$	—	$	369,444	$	—
U.S. Treasury and federal agency obligations	—		119,560		—		—		80,973		—
Municipal bonds	—		—		—		—		78,590		—
	$	—	$	550,394	$	—	$	—	$	529,007	$	—
Derivative assets ¹
Interest rate lock commitments	$	—	$	393	$	—	$	—	$	488	$	—
Forward commitments	—		5		—		98		43		—
	$	—	$	398	$	—	$	98	$	531	$	—
Derivative liabilities ¹
Interest rate lock commitments	$	—	$	3	$	—	$	—	$	24	$	—
Forward commitments	71		40		—		—		2		—
	$	71	$	43	$	—	$	—	$	26	$	—


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, 2014 and 2013.

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



			Fair value measurements using
(in millions)	Balance		Level 1		Level 2		Level 3
December 31, 2014
Loans	$	2	$	—	$	—	$	2
Tax credit investments	9		—		—		9
Real estate acquired in settlement of loans	—		—		—		—
December 31, 2013
Loans	4		—		—		4
Real estate acquired in settlement of loans	—		—		—		—

For 2014 and 2013, 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 unobservable input value ¹
(dollars in thousands)	Fair value		Valuation technique	Significant unobservable input	Range	Weighted Average
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		7%
Commercial loans	145		Fair value of property or collateral	Fair value of business assets		91%
Total loans	$	2,445
Tax credit investments	$	8,975	Discounted cash flow	Present value of expected future cash flows	5-93%	88%
				Discount rate		7%
Real estate acquired in settlement of loans	$	288	Fair value of property or collateral	Appraised value less 7% selling cost	100%	100%
December 31, 2013
Residential loans	$	2,361	Fair value of property or collateral	Appraised value less 7% selling cost	44-96%	87%
Home equity lines of credit	170		Fair value of property or collateral	Appraised value less 7% selling cost	45-50%	50%
Commercial loans	217		Fair value of property or collateral	Fair value of business assets		19%
Commercial loans	1,668		Discounted cash flow	Present value of expected future cash flows		58%
				Discount rate		4.5%
Total loans	$	4,416


¹	Represent percent of outstanding principal balance.

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

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:

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	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
2014
Equity securities	$	649		$	649	$	—	$	—	$	99		$	99	$	—	$	—
Equity index funds	132			132		—		—		19			19		—		—
Fixed income securities	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
2013
Equity securities	$	672		$	672	$	—	$	—	$	102		$	102	$	—	$	—
Equity index funds	127			127		—		—		19			19		—		—
Fixed income securities	350			122		228		—		46			40		6		—
Pooled and mutual funds and other	84			—		83		1		13			—		13		—
Total	1,233			$	921	$	311	$	1	180			$	161	$	19	$	—
Cash, receivables and payables, net	(46		)							(1		)
Fair value of plan assets	$	1,187								$	179

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, 2014 and 2013.

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, respectively, that are not open to public investment and are valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses, using observable inputs.

Other (Level 3). Venture capital interest is valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.

For 2014 and 2013, the changes in Level 3 assets were as follows:



	2014						2013
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Balance, January 1	$	580		$	18		$	581		$	18
Realized and unrealized losses	(203		)	(6		)	(1		)	—
Purchases and settlements, net	(282		)	(8		)	—			—
Balance, December 31	$	95		$	4		$	580		$	18

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17 · 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
2014
Revenues	$	783,749	$	798,657	$	867,096	$	790,040	$	3,239,542
Operating income	88,306		82,275		91,102		67,241		328,924
Net income	46,400		41,894		48,286		33,630		170,210
Net income for common stock	45,927		41,421		47,815		33,157		168,320
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		1.64
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
2013
Revenues	$	782,232	$	794,567	$	829,168	$	832,503	$	3,238,470
Operating income	68,825		80,207		88,038		78,349		315,419
Net income	34,152		41,061		48,707		39,486		163,406
Net income for common stock	33,679		40,588		48,236		39,013		161,516
Basic earnings per common share ¹	0.34		0.41		0.49		0.39		1.63
Diluted earnings per common share ²	0.34		0.41		0.48		0.39		1.62
Dividends per common share	0.31		0.31		0.31		0.31		1.24
Market price per common share ³
High	27.92		28.30		27.24		27.15		28.30
Low	25.50		23.84		24.12		24.51		23.84
Hawaiian Electric consolidated
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
2013
Revenues	717,441		728,525		764,054		770,152		2,980,172
Operating income	51,121		58,975		69,853		65,564		245,513
Net income	24,928		29,192		38,315		32,489		124,924
Net income for common stock	24,429		28,693		37,817		31,990		122,929

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.

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ITEM 9A.	CONTROLS AND PROCEDURES

HEI:

Disclosure Controls and Procedures

The Company maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including its Principal Executive Officer and Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosure. As of December 31, 2014, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended. At the time that the original Annual Report on Form 10-K for the year ended December 31, 2014 was filed, the Company’s Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014. Subsequent to that evaluation, management, including the Company’s Principal Executive Officer and Principal Financial Officer, concluded that the Company’s disclosure controls and procedures were not effective as of December 31, 2014 due to the material weakness in the Company’s internal control over financial reporting described below.

Management's Report on Internal Control Over Financial Reporting (Restated)

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) of the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is a process designed, under the supervision and with the participation of our Principal Executive Officer and Principal Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of its financial reporting and the preparation of the financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 based on criteria established 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 a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis.

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 years ended December 31, 2013 and 2012 and for the three months ended March 31, 2015 and 2014, and the six months ended June 30, 2015 and 2014. The control deficiency 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. Additionally, this control deficiency could result in misstatements of the aforementioned accounts that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness.

In Management’s Report on Internal Control Over Financial Reporting included in our original Annual Report on Form 10- K for the year ended December 31, 2014, the Company’s Principal Executive Officer and Principal Financial Officer concluded that the Company maintained effective internal control over financial reporting as of December 31, 2014. The Company has subsequently concluded that the material weakness described above existed as of December 31, 2014. As a result of the material weakness in internal control over financial reporting, the Company’s management has concluded that, as of December 31, 2014, the Company’s internal control over financial reporting was not effective based on the criteria in Internal Control -

150

Integrated Framework (2013) issued by the COSO. Accordingly, management has restated its report on internal control over financial reporting.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 53.

Changes in Internal Control Over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Remediation

In order to address this material weakness, the Company’s management, with oversight from its Audit Committee of the Board of Directors of HEI, has taken steps and plans to take additional measures to remediate the underlying causes of the material weakness. The Company’s remediation plans related to the review of the Consolidated Statements of Cash Flows include 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 will be implemented, and will be tested for operational effectiveness. Management is committed to maintaining a strong internal control environment and believes this remediation effort will represent an improvement in controls. Management anticipates that the new controls, as or when implemented and when tested for a sufficient period of time, will remediate the material weakness.

Hawaiian Electric:

Disclosure Controls and Procedures

Hawaiian Electric maintains a set of disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed by Hawaiian Electric in reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms, and that such information is accumulated and communicated to Hawaiian Electric’s management, including its Principal Executive Officer and Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosure. As of December 31, 2014, an evaluation was performed under the supervision and with the participation of Hawaiian Electric’s management, including the Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of Hawaiian Electric’s disclosure controls and procedures, as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended. At the time that the original Annual Report on Form 10-K for the year ended December 31, 2014 was filed, Hawaiian Electric’s Principal Executive Officer and Principal Financial Officer concluded that Hawaiian Electric’s disclosure controls and procedures were effective as of December 31, 2014. Subsequent to that evaluation, management, including Hawaiian Electric’s Principal Executive Officer and Principal Financial Officer, concluded that Hawaiian Electric’s disclosure controls and procedures were not effective as of December 31, 2014 due to the material weakness in Hawaiian Electric’s internal control over financial reporting described below.

Management's Report on Internal Control Over Financial Reporting (Restated)

Management of Hawaiian Electric is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) of the Securities Exchange Act of 1934, as amended. Hawaiian Electric’s internal control over financial reporting is a process designed, under the supervision and with the participation of our Principal Executive Officer and Principal Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of its financial reporting and the preparation of the financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Management conducted an evaluation of the effectiveness of Hawaiian Electric’s internal control over financial reporting as of December 31, 2014 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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Management did not maintain effective controls over the preparation and review of Hawaiian Electric’s 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 years ended December 31, 2013 and 2012 and for the three months ended March 31, 2015 and 2014, and the six months ended June 30, 2015 and 2014. The control deficiency 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. Additionally, this control deficiency could result in misstatements of the aforementioned accounts that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness.

In Management’s Report on Internal Control Over Financial Reporting included in our original Annual Report on Form 10- K for the year ended December 31, 2014, Hawaiian Electric’s Principal Executive Officer and Principal Financial Officer concluded that Hawaiian Electric maintained effective internal control over financial reporting as of December 31, 2014. Hawaiian Electric has subsequently concluded that the material weakness described above existed as of December 31, 2014. As a result of the material weakness in internal control over financial reporting, Hawaiian Electric’s management has concluded that, as of December 31, 2014, the Company’s internal control over financial reporting was not effective based on the criteria in Internal Control - Integrated Framework (2013) issued by the COSO. Accordingly, management has restated its report on internal control over financial reporting.

Changes in Internal Control Over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.

Remediation

In order to address this material weakness, Hawaiian Electric’s management, with oversight from its Audit Committee of the Board of Directors of Hawaiian Electric, has taken steps and plans to take additional measures to remediate the underlying causes of the material weakness. Hawaiian Electric’s remediation plans related to the review of the Consolidated Statements of Cash Flows include 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 will be implemented, and will be tested for operational effectiveness. Management is committed to maintaining a strong internal control environment and believes this remediation effort will represent an improvement in controls. Management anticipates that the new controls, as or when implemented and when tested for a sufficient period of time, will remediate the material weakness.

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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 Amendment No. 1 on Form 10-K/A
		HEI	Hawaiian Electric
Schedule I	Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) at December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012	154-156	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, 2014, 2013 and 2012	158	158
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.

153

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS



December 31	2014			2013
(dollars in thousands)
Assets
Cash and cash equivalents	$	276		$	571
Accounts receivable	1,991			1,661
Property, plant and equipment, net	4,917			5,419
Deferred income tax assets	15,922			10,057
Other assets	11,070			9,550
Investments in subsidiaries, at equity	2,224,452			2,122,841
	$	2,258,628		$	2,150,099
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	1,993		$	817
Interest payable	2,583			4,630
Notes payable to subsidiaries	7,857			7,936
Commercial paper	118,972			105,482
Long-term debt, net	300,000			275,000
Retirement benefits liability	32,030			21,559
Other	3,765			7,605
	467,200			423,029
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: 102,565,266 shares and 101,259,800 shares	1,521,297			1,488,126
Retained earnings	297,509			255,694
Accumulated other comprehensive loss	(27,378		)	(16,750		)
	1,791,428			1,727,070
	$	2,258,628		$	2,150,099
Note to Balance Sheets
HEI Term loan LIBOR + .90%, due 2016	$	125,000		$	—
HEI medium-term note 6.51%, due 2014	—			100,000
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		$	275,000

The aggregate payments of principal required subsequent to December 31, 2014 on long-term debt are nil in 2015, $200 million in 2016, nil in 2017, 2018 and 2019.

As of December 31, 2014, 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.

The Company has revised its previously issued "Schedule I - Condensed Financial Information of Registrant; Hawaiian Electric Industries, Inc. (Parent Company); Condensed Balance Sheets" to correct for an error in the presentation of deferred tax amounts related to Hawaiian Electric’s net operating loss carryforwards as of December 31, 2013. Amounts were reclassified among deferred income tax assets, other assets, deferred income taxes (liabilities) and other liabilities. These adjustments are

154

not considered material, individually or in the aggregate, to the previously issued Condensed Balance Sheet as of December 31, 2013 and had no impact on the Company's Consolidated Balance Sheet as of December 31, 2013. The table below illustrates the effects of these adjustments on the Condensed Balance Sheet for those line items affected:



	December 31, 2013
(in thousands)	As previously filed		As revised		Difference
Deferred income tax assets	$	1,594	$	10,057	$	8,463
Other assets	23,679		9,550		(14,129		)
Total assets	2,155,765		2,150,099		(5,666		)
Deferred income taxes	11,385		—		(11,385		)
Other liabilities	1,886		7,605		5,719
Total liabilities	428,695		423,029		(5,666		)
Total liabilities and shareholders' equity	2,155,765		2,150,099		(5,666		)

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	2014		2013		2012
(in thousands)
Revenues	$	303	$	288	$	221
Equity in net income of subsidiaries	188,534		180,359		157,883
Expenses:
Operating, administrative and general	20,921		16,063		16,191
Depreciation of property, plant and equipment	575		596		672
Taxes, other than income taxes	469		497		421
Interest expense	11,599		16,207		16,695
Income before income tax benefits	155,273		147,284		124,125
Income tax benefits	13,047		14,232		14,533
Net income	$	168,320	$	161,516	$	138,658

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.

155

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	2014			2013			2012
				(As restated)
(in thousands)
Net cash provided by operating activities	$	100,794		$	82,274		$	127,118
Cash flows from investing activities
Capital expenditures	(74		)	(201		)	(410		)
Investments in subsidiaries	(40,000		)	(78,500		)	(44,000		)
Net cash used in investing activities	(40,074		)	(78,701		)	(44,410		)
Cash flows from financing activities
Net increase (decrease) in notes payable to subsidiaries with original maturities of three months or less	(222		)	56			(1,797		)
Net increase in short-term borrowings with original maturities of three months or less	13,490			21,788			14,873
Proceeds from issuance of long-term debt	125,000			50,000			—
Repayment of long-term debt	(100,000		)	(50,000		)	(7,000		)
Excess tax benefits from share-based payment arrangements	277			430			61
Net proceeds from issuance of common stock	26,898			55,086			23,613
Common stock dividends	(126,458		)	(98,383		)	(96,202		)
Net cash used in financing activities	(61,015		)	(21,023		)	(66,452		)
Net increase (decrease) in cash and equivalents	(295		)	(17,450		)	16,256
Cash and cash equivalents, January 1	571			18,021			1,765
Cash and cash equivalents, December 31	$	276		$	571		$	18,021

Supplemental disclosures of noncash activities:

In 2014, 2013 and 2012, $2.4 million, $2.3 million and $1.8 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 2014, 2013 and 2012, $2.5 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, $24 million and $24 million in 2014, 2013 and 2012, 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 to date and from August 18, 2011 through January 8, 2012) 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.

The Company has revised its previously issued "Schedule I - Condensed Financial Information of Registrant; Hawaiian Electric Industries, Inc. (Parent Company); Condensed Statements of Cash Flows" for the year ended December 31, 2014 to correct for an error in the presentation of deferred tax expense related to Hawaiian Electric’s net operating loss carryforwards. The Company has restated its previously issued "Schedule I - Condensed Financial Information of Registrant; Hawaiian Electric Industries, Inc. (Parent Company); Condensed Statements of Cash Flows" for the year ended December 31, 2013 to correct for an error in the presentation of deferred tax expense related to Hawaiian Electric’s net operating loss carryforwards. Amounts were reclassified among “increase in deferred income taxes” and “change in prepaid and accrued income taxes”. These adjustments are not considered material, individually or in the aggregate, to the previously issued Condensed Statements of Cash Flows for the year ended December 31, 2014. The table below illustrates the effects of these adjustments on the Condensed Statement of Cash Flows for those line items affected. The Company has adjusted the presentation of the Condensed Statements of Cash Flows to reflect a condensed presentation and as such, no longer breaks out the components of operating activities. The below adjustments do not have an impact to total cash provided by operating activities:

156



(in thousands)	As previously filed			As corrected (1)			Difference
Year ended December 31, 2014
Decrease in deferred income taxes	$	(15,913	)	$	(3,269	)	$	12,644
Change in prepaid and accrued income taxes	15,867			3,223			(12,644		)
Year ended December 31, 2013 (restated)
Increase in deferred income taxes	15,228			1,086			(14,142		)
Change in prepaid and accrued income taxes	(15,604		)	(1,462		)	14,142

(1) The Company has adjusted the presentation of the Condensed Statements of Cash Flows to reflect a condensed presentation and as such, no longer breaks out the components of operating activities.

157

Hawaiian Electric Industries, Inc. and subsidiaries

and Hawaiian Electric Company, Inc. and subsidiaries

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2014, 2013 and 2012



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
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
2012
Allowance for uncollectible accounts – electric utility	$	2,221	$	3,230	$	1,180		(a)	$	4,483	(b)	$	2,148
Allowance for uncollectible interest – bank	$	4,825	$	—	$	—			$	1,659		$	3,166
Allowance for losses for loans receivable – bank	$	37,906	$	12,883	$	4,026		(a)	$	12,830	(b)	$	41,985
Allowance for mortgage-servicing assets – bank	$	175	$	504	$	—			$	181		$	498
Deferred tax valuation allowance – HEI	$	278	$	—	$	—			$	—		$	278


(a)	Primarily recoveries.


(b)	Bad debts charged off.

158

(a)(3) and (b) Exhibits

The Exhibit Index attached to this Form 10-K/A 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:	November 16, 2015	Date:	November 16, 2015

159

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	Underwriting Agreement, dated March 19, 2013, among HEI, J.P. Morgan Securities LLC and Morgan Stanley & Co. LLC, individually and acting as representatives of each of the other Underwriters listed in Schedule 1 thereto and J.P. Morgan Securities LLC acting as forward seller (Exhibit 1.1 to HEI’s Current Report on Form 8-K, dated March 19, 2013, File No. 1-8503).

	4.4	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).

	4.5	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).

	4.6	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).

	4.6(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).

	4.6(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).

	4.7	Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan, as amended and restated (Exhibit 4(a) to Registration Statement on Form S-3, Registration No. 333-180413).

	4.8	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).

	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).



Exhibit no.		Description
	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).

	10.6(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).

	10.6(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).

	10.6(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).

	10.6(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).

	10.6(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).

	10.7	1987 Stock Option and Incentive Plan of HEI (as amended and restated effective January 22, 2008) (Exhibit 10.3 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8503).

	10.7(a)	Form of Hawaiian Electric Industries, Inc. Stock Option Agreement with Dividend Equivalents (Exhibit 10.7(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-8503).

	10.7(b)	Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, File No. 1-8503).

	10.7(c)	Form of Hawaiian Electric Industries, Inc. Stock Appreciation Right Agreement with Dividend Equivalents (effective for April 7, 2005 stock appreciation rights grant) (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8503).

	10.7(d)	Form of Restricted Stock Unit Agreement Pursuant to the 1987 Stock Option and Incentive Plan of HEI (Exhibit 10.7(f) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, 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).



Exhibit no.		Description

	10.10(b)	HEI Excess Pay Plan Addendum for Richard M. Rosenblum (Exhibit 10.10(c) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-8503).

	10.10(c)	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).

	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, 2011 (Exhibit 10.14 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

	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).

	10.17(a)	Addendum A of Severance Pay Plan for Merit Employees of HEI and affiliates, restatement effective as of January 1, 2009 for James A. Ajello and Richard M. Rosenblum (Exhibit 10.17(a) 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).

	10.21	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).



Exhibit no.		Description
	10.23	Confirmation of Forward Sale Transaction dated March 19, 2013 between HEI and JPMorgan Chase Bank, National Association, London Branch (Exhibit 10.1 to HEI’s Current Report on Form 8-K dated March 19, 2013, File No. 1-8503).

	10.24	Confirmation of Additional Forward Sale Transaction dated March 20, 2013 between HEI and JPMorgan Chase Bank, National Association, London Branch (Exhibit 10.2 to HEI’s Current Report on Form 8-K dated March 19, 2013, File No. 1-8503).

	10.25	Amendments to Forward Confirmations dated November 3, 2014 between HEI and J.P. Morgan Securities LLC (as agent for JP Morgan Chase Bank, National Association) (Exhibit 10.25 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-8503).

	11	HEI - Computation of Earnings per Share of Common Stock (Exhibit 11 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-8503).

	12.1	HEI - Computation of Ratio of Earnings to Fixed Charges (Exhibit 12.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-8503).

	21.1	HEI - Subsidiaries of the Registrant (Exhibit 21.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-8503).

	*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:
	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).



Exhibit no.		Description

	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).

	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 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 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).



Exhibit no.		Description
	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).

	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).

	10.3(a)	Agreement between Maui Electric and Hawaiian Commercial & Sugar Company pursuant to letters dated November 29, 1988 and November 1, 1988 (Exhibit 10.8 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1988, File No. 1-4955).

	10.3(b)	Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and Maui Electric, dated November 30, 1989 (Exhibit 10(e) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

	10.3(c)	First Amendment to Amended and Restated Power Purchase Agreement by and between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and Maui Electric, dated November 1, 1990, amending the Amended and Restated Power Purchase Agreement dated November 30, 1989 (Exhibit 10(f) to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).



Exhibit no.		Description
	10.3(d)	Termination Notice dated December 27, 1999 for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and Maui Electric, dated November 30, 1989, as amended (Exhibit 10.2 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-4955).

	10.3(e)	Rescission dated January 23, 2001 of Termination Notice for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and Maui Electric, dated November 30, 1989, as amended (Exhibit 10.4(f) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

	10.3(f)	Letter agreement dated July 2, 2007 to not issue a notice of termination of Amended and Restated Power Purchase Agreement Between A&B-Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and Maui Electric dated November 30, 1989, as Amended on November 1, 1990 (Exhibit 10.3(f) to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).

	10.4(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).

	10.4(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).

	10.4(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).

	10.4(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).

	10.4(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).

	10.4(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).

	10.4(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).

	10.5(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).

	10.5(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).

	10.5(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).

	10.5(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).



Exhibit no.		Description
	10.5(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).

	10.5(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).

	10.6	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).

	10.6(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).

	10.7(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).

	10.7(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).

	10.7(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).

	10.7(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).

	10.8	Facilities and Operating Contract by and between Chevron and Hawaiian Electric dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.10 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

	10.9	Low Sulfur Fuel Oil Supply Contract by and between Tesoro and Hawaiian Electric dated as of August 28, 2012 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.3 to Hawaiian Electric’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

	10.10(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).

	10.10(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).



Exhibit no.		Description
	10.10(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).

	10.10(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).

	10.11(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).

	10.11(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).

	10.12(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).

	10.12(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).

	10.13	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).

	10.14	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).

	10.15	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 (Exhibit 12.2 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-4955).

	21.2	Hawaiian Electric - Subsidiaries of the Registrant (Exhibit 21.2 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-4955)

	*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 (Exhibit 99.1 to Hawaiian Electric’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014, File No. 1-4955).