HAWAIIAN ELECTRIC CO INC - Annual Report: 2013 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

[ ] 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. [ X ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Hawaiian Electric Industries Inc.	Large accelerated filer X 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, 2013	June 30, 2013	February 7, 2014
Hawaiian Electric Industries, Inc. (HEI)	$2,506,804,981	99,044,053 (Without par value)	101,415,268 (Without par value)
Hawaiian Electric Company, Inc. (Hawaiian Electric)	None	14,665,264 ($6 2/3 par value)	15,429,105 ($6 2/3 par value)

DOCUMENTS INCORPORATED BY REFERENCE

Hawaiian Electric’s Exhibit 99.1, consisting of:

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

Hawaiian Electric’s Executive Compensation—Part III

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

Part III

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

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

Selected sections of Proxy Statement of HEI for the 2014 Annual Meeting of Shareholders to be filed—Part III

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

TABLE OF CONTENTS



		Page

Glossary of Terms		ii
Forward-Looking Statements		v

	PART I

Item 1.	Business	1
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	33
Executive Officers of the Registrant (HEI)		33

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	74
Item 8.	Financial Statements and Supplementary Data	76
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	161
Item 9A.	Controls and Procedures	161
Item 9B.	Other Information	162

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	162
Item 11.	Executive Compensation	163
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	164
Item 13.	Certain Relationships and Related Transactions, and Director Independence	165
Item 14.	Principal Accounting Fees and Services	165

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	165
Signatures		170

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.
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
ASHI		American Savings Holdings, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
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); American Savings Holdings, 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
EOTP		East Oahu Transmission Project
EPA		Environmental Protection Agency - federal
EPS		Earnings per share
ERISA		Employee Retirement Income Security Act of 1974, as amended
ERL		Environmental Response Law of the State of Hawaii
Exchange Act		Securities Exchange Act of 1934

GLOSSARY OF TERMS (continued)



Terms		Definitions

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., American Savings Holdings, 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 2014 Proxy Statement		Selected sections of Hawaiian Electric Industries, Inc.’s 2014 Proxy Statement to be filed after the date of this Form 10-K, which are incorporated into this Form 10-K by reference
HEI’s MD&A		Hawaiian Electric Industries, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K
HEIPI		HEI Properties, Inc., 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
KWH		Kilowatthour
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
Moody’s		Moody’s Investors Service’s
MSFO		Medium sulfur fuel oil
MW		Megawatt/s (as applicable)
NA		Not applicable

iii

GLOSSARY OF TERMS (continued)



Terms		Definitions

NAAQS		National Ambient Air Quality Standard
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		Revenue adjustment mechanism
RBA		Revenue balancing account
REG		Renewable Energy Group Marketing & Logistics Group LLC
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.
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
SPRBs		Special Purpose Revenue Bonds
ST		Steam turbine
state		State of Hawaii
TDR		Troubled debt restructuring
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:

•

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 and potential conflict or crisis with North Korea or Iran);


•	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 and the potential effects of climate change, such as more severe storms and rising sea levels), including their impact on Company 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 to access credit markets to obtain commercial paper and other short-term and long-term debt financing (including lines of credit) and to access capital markets to issue HEI 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 implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement), setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), and the fulfillment by the electric utilities of their commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering (and potential disapproval of actual or proposed) HCEI-related costs; reliance by the Company 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);


•	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), revenue adjustment mechanisms (RAMs) and pension and postretirement benefits other than pensions (OPEB) tracking mechanisms, and the continued decoupling of revenues from 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, as contemplated under the Energy Agreement, 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 ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);


•	the ability of the electric 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, ASB and Hawaiian Electric and their subsidiaries or their competitors;

•

cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and Hawaiian Electric and their subsidiaries (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, Hawaiian Electric, ASB and their subsidiaries (including changes in taxation, increases in capital requirements, regulatory changes resulting from the HCEI, 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);


•	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, 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 electric utilities to recover increasing costs and earn a reasonable return on capital investments not covered by revenue adjustment mechanisms;


•	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, Hawaiian Electric, ASB and their subsidiaries, including the possible adoption of International Financial Reporting Standards or 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, Hawaiian Electric, ASB and their subsidiaries;


•	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.

PART I



ITEM 1.	BUSINESS

HEI Consolidated

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

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

Besides Hawaiian Electric and its subsidiaries, HEI also currently owns directly or indirectly the following subsidiaries: American Savings Holdings, Inc. (ASHI) (a holding company) and its subsidiary, American Savings Bank, F.S.B. (ASB); HEI Properties, Inc. (HEIPI); Hawaiian Electric Industries Capital Trusts II and III (both formed in 1997 to be available for trust securities financings); and The Old Oahu Tug Service, Inc. (TOOTS).

ASB, acquired by HEI in 1988, is one of the largest financial institutions in the State of Hawaii with assets of $5.2 billion as of December 31, 2013.

HEIPI, whose predecessor company was formed in February 1998, holds venture capital investments with a carrying value of $0.5 million as of December 31, 2013.

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

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

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

Commitments and contingencies. See “HEI Consolidated—Liquidity and capital resources –Selected contractual obligations and commitments” in HEI’s MD&A, Hawaiian Electric’s “Commitments and contingencies” below and Note 4 of the Consolidated Financial Statements.

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

HEI is subject to an agreement entered into with the PUC (the PUC Agreement) which, among other things, requires HEI to provide the PUC with periodic financial information and other reports concerning intercompany transactions and other

matters. It also prohibits the electric utilities from loaning funds to HEI or its nonutility subsidiaries and from redeeming common stock of the electric utility subsidiaries without PUC approval. Further, the PUC could limit the ability of the electric utility subsidiaries to pay dividends on their common stock. See “Restrictions on dividends and other distributions” and “Electric utility—Regulation” below.

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

Bank regulations generally prohibit savings and loan holding companies and their nonthrift subsidiaries from engaging in activities other than those which are specifically enumerated in the regulations. However, the unitary savings and loan holding company relationship among HEI, ASHI and ASB is “grandfathered” under the Gramm-Leach-Bliley Act of 1999 (Gramm Act) so that HEI and its subsidiaries are able to continue to engage in their current activities so long as ASB satisfies the qualified thrift lender (QTL) test discussed under “Bank—Regulation—Qualified thrift lender test.” ASB met the QTL test at all times during 2013; however, the failure of ASB to satisfy the QTL test in the future could result in a need for HEI to divest ASB. HEI is also affected by provisions of the Dodd-Frank Act relating to corporate governance and executive compensation, including provisions requiring shareholder “say on pay” and “say on pay frequency” votes, mandating additional disclosures concerning executive compensation and compensation consultants and advisors and further restricting proxy voting by brokers in the absence of instructions. See “Bank—Legislation and regulation” in HEI’s MD&A for a discussion of effects of the Dodd-Frank Act on HEI and ASB.

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

The abilities of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI are subject to contractual and regulatory restrictions. Under the PUC Agreement, in the event that the consolidated common stock equity of the electric utility subsidiaries falls below 35% of the total capitalization of the electric utilities (including the current maturities of long-term debt, but excluding short-term borrowings), the electric utility subsidiaries would, absent PUC approval, be restricted in their payment of cash dividends to 80% of the earnings available for the payment of dividends in the current fiscal year and preceding five years, less the amount of dividends paid during that period. The PUC Agreement also provides that the foregoing dividend restriction shall not be construed as relinquishing any right the PUC may have to review the dividend policies of the electric utility subsidiaries. As of December 31, 2013, the consolidated common stock equity of HEI’s electric utility subsidiaries was 56% of their total capitalization (as calculated for purposes of the PUC Agreement). As of December 31, 2013, Hawaiian Electric and its subsidiaries had common stock equity of $1.6 billion of which approximately $674 million was not available for transfer to HEI without regulatory approval.

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

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

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

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

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

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



December 31	2013	2012	2011	2010	2009
HEI	43	42	40	34	34
Hawaiian Electric and its subsidiaries	2,764	2,658	2,518	2,317	2,297
ASB and its subsidiaries	1,159	1,170	1,096	1,075	1,119
Other subsidiaries	—	—	—	—	3
	3,966	3,870	3,654	3,426	3,453

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

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

Electric utility

Hawaiian Electric and subsidiaries and service areas. Hawaiian Electric, Hawaii Electric Light and Maui Electric (Utilities) are regulated operating electric public utilities engaged in the production, purchase, transmission, distribution and sale of electricity on the islands of Oahu; Hawaii; and Maui, Lanai and Molokai, respectively. Hawaiian Electric acquired Maui Electric in 1968 and Hawaii Electric Light in 1970. In 2013, the electric utilities’ revenues and net income amounted to approximately 92% and 76%, respectively, of HEI’s consolidated revenues and net income, compared to approximately 92% and 72% in both 2012 and 2011.

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

Sales of electricity.



Years ended December 31	2013			2012			2011
(dollars in thousands)	Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues		Customer accounts*	Electric sales revenues
Hawaiian Electric	299,528	$	2,116,214	297,529	$	2,216,675	296,800	$	2,103,859
Hawaii Electric Light	82,637	430,272		81,792	439,249		81,199	443,189
Maui Electric	69,577	422,205		68,922	436,836		68,230	417,451
	451,742	$	2,968,691	448,243	$	3,092,760	446,229	$	2,964,499

* As of December 31.

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

Significant customers. The Utilities derived approximately 11% of their operating revenues in each of 2013, 2012 and 2011 from the sale of electricity to various federal government agencies.

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

Energy Agreement, energy efficiency and decoupling. On October 20, 2008, the Governor, the Hawaii Department of Business Economic Development and Tourism (DBEDT), the Consumer Advocate and the Utilities entered into an Energy Agreement pursuant to which they agreed to undertake a number of initiatives to help accomplish the objectives of the Hawaii Clean Energy Initiative (HCEI) established under a memorandum of understanding between the State of Hawaii and U.S. Department of Energy. The primary objective of the HCEI and Energy Agreement is to reduce Hawaii’s dependence on imported fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation. See Note 3 of the Consolidated Financial Statements. One of the initiatives under the Energy Agreement was advanced when, in 2009, the state legislature enacted Act 155, which gave the PUC the authority to establish an Energy Efficiency Portfolio Standard (EEPS) goal of 4,300 GWH of electricity use reductions by 2030. The PUC issued a decision and order (D&O) on January 3, 2012 approving a framework for EEPS that set 2008 as the initial base year for evaluation and linearly allocated the 2030 goal to interim incremental reduction goals of 1,375 GWH by 2015 and 975 GWH by each of the years 2020, 2025 and 2030.

These goals may be revised through goal evaluations scheduled every five years or as the result of recommendations by an EEPS technical working group (TWG) for consideration by the PUC. The interim and final reduction goals will be allocated among contributing entities by the EEPS TWG. The PUC may establish penalties in the future. Another of the initiatives was advanced when the PUC approved the implementation of revenue decoupling for the Utilities under which they are allowed to recover PUC-approved revenue requirements that are not based on the amount of electricity sold. Both the EEPS and the implementation of revenue decoupling could have an impact on sales. The statewide Energy Efficiency Potential Study issued in December 2013 indicated that Hawaii is on track to meet the 2015 interim EEPS target, and that available untapped energy efficiency resources in Hawaii exceed the EEPS goal of 4,300 GWH. The PUC plans to convene a meeting of the EEPS Technical Working Group in 2014 to review the results of the statewide Energy Efficiency Potential Study, and determine whether the PUC should adjust the overall EEPS goal, whether the PUC should establish targets, incentives or penalties for energy savings performance, and whether the PUC should adjust the amount of ratepayer funds that are collected and allocated to energy efficiency programs. Neither HEI nor Hawaiian Electric management can predict with certainty the impact of these or other governmental mandates, the HCEI or the Energy Agreement on HEI’s or Hawaiian Electric’s future results of operations, financial condition or liquidity.

Selected consolidated electric utility operating statistics.



Years ended December 31	2013		2012		2011		2010		2009
KWH sales (millions)
Residential	2,450.9		2,582.0		2,769.7		2,830.0		2,893.3
Commercial	3,105.9		3,074.4		3,203.8		3,185.0		3,221.7
Large light and power	3,462.7		3,499.8		3,503.4		3,512.8		3,524.5
Other	50.0		49.8		50.0		50.8		50.2
	9,069.5		9,206.0		9,526.9		9,578.6		9,689.7
KWH net generated and purchased (millions)
Net generated	5,352.0		5,601.7		6,022.2		6,053.6		6,117.6
Purchased	4,195.2		4,093.2		4,009.7		4,062.8		4,119.8
	9,547.2		9,694.9		10,031.9		10,116.4		10,237.4
Losses and system uses (%)	4.8		4.8		4.8		5.1		5.1
Energy supply (December 31)
Net generating capability—MW¹	1,787		1,787		1,787		1,785		1,815
Firm purchased capability—MW	567		545		540		540		532
	2,354		2,332		2,327		2,325		2,347
Net peak demand—MW²	1,535		1,535		1,530		1,562		1,618
Btu per net KWH generated	10,570		10,533		10,609		10,617		10,753
Average fuel oil cost per Mbtu (cents)	2,103.2		2,210.4		1,986.7		1,404.8		1,026.4
Customer accounts (December 31)
Residential	394,910		392,025		390,133		388,307		385,886
Commercial	54,616		54,005		53,904		54,374		54,527
Large light and power	556		577		567		548		558
Other	1,660		1,636		1,625		1,627		1,613
	451,742		448,243		446,229		444,856		442,584
Electric revenues (thousands)
Residential	$	892,438	$	952,159	$	946,653	$	781,467	$	690,656
Commercial	1,044,166		1,060,983		1,024,725		814,109		694,087
Large light and power	1,015,079		1,062,226		976,949		752,056		623,159
Other	17,008		17,392		16,172		13,004		10,721
	$	2,968,691	$	3,092,760	$	2,964,499	$	2,360,636	$	2,018,623
Average revenue per KWH sold (cents)	32.73		33.60		31.12		24.65		20.83
Residential	36.41		36.88		34.18		27.61		23.87
Commercial	33.62		34.51		31.99		25.56		21.54
Large light and power	29.31		30.35		27.89		21.41		17.68
Other	34.02		34.93		32.37		25.63		21.36
Residential statistics
Average annual use per customer account (KWH)	6,220		6,596		7,117		7,317		7,523
Average annual revenue per customer account	$	2,265	$	2,432	$	2,433	$	2,021	$	1,796
Average number of customer accounts	394,024		391,437		389,160		386,767		384,600


¹	The reduction in net generating capability in 2010 was attributable to the removal of distributed generation units at substations.


²	Sum of the net peak demands on all islands served, noncoincident and nonintegrated.

Generation statistics. The following table contains certain generation statistics as of and for the year ended December 31, 2013. The net generating and firm purchased capability available for operation at any given time may be more or less than shown because of capability restrictions or temporary outages for inspection, maintenance, repairs or unforeseen circumstances.



	Island of Oahu- Hawaiian Electric		Island of Hawaii- Hawaii Electric Light		Island of Maui- Maui Electric		Island of Lanai- Maui Electric		Island of Molokai- Maui Electric		Total
Net generating and firm purchased capability (MW) as of December 31, 2013¹
Conventional oil-fired steam units	1,106.8		63.8		35.9		—		—		1,206.5
Diesel	—		30.8		96.8		10.1		9.6		147.3
Combustion turbines (peaking units)	214.8		—		—		—		—		214.8
Other combustion turbines	—		46.3		—		—		2.2		48.5
Combined-cycle unit	—		56.2		113.6		—		—		169.8
Firm contract power²	456.5		94.6		16.0		—		—		567.1
	1,778.1		291.7		262.3		10.1		11.8		2,354.0

Net peak demand (MW)	1,144.0		190.2		190.3		5.0		5.4		1,534.9		³
Reserve margin	59.4	%	53.4	%	37.8	%	102.0	%	118.5	%	57.2	%
Annual load factor	71.7	%	69.6	%	68.5	%	62.4	%	67.9	%	71.0	%
KWH net generated and purchased (millions)	7,187.3		1,159.1		1,141.3		27.3		32.1		9,547.1


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


²	Nonutility generators— Hawaiian Electric: 208 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired) and 68.5 MW (HPower, refuse-fired); Hawaii Electric Light: 34.6 MW (Puna Geothermal Venture, geothermal) and 60 MW (Hamakua Energy Partners, L.P., oil-fired); Maui Electric: 16 MW (Hawaiian Commercial & Sugar Company, primarily bagasse-fired).


³	Noncoincident and nonintegrated.

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

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

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

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

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

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

Hawaiian Electric firm capacity PPAs. Hawaiian Electric currently has three major PPAs that provide a total of 456.5 MW of firm capacity, representing 26% of Hawaiian Electric’s total net generating and firm purchased capacity on Oahu as of December 31, 2013. In March 1988, Hawaiian Electric entered into a PPA with AES Barbers Point, Inc. (now known as AES

Hawaii, Inc. (AES Hawaii)), a Hawaii-based, indirect subsidiary of The AES Corporation. The agreement with AES Hawaii, as amended, provides that, for a period of 30 years beginning September 1992, Hawaiian Electric will purchase 180 megawatts (MW) of firm capacity. The AES Hawaii 180 MW coal-fired cogeneration plant utilizes a “clean coal” technology and is designed to sell sufficient steam to be a “Qualifying Facility” (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). In August 2012, Hawaiian Electric filed an application with the PUC seeking an exemption from the PUC’s Competitive Bidding Framework to negotiate an amendment to the PPA to purchase 186 MW of firm capacity, extend the PPA term until September 2032, and amend the energy pricing formula in the PPA. The PUC approved the exemption in April 2013, and Hawaiian Electric has been in negotiations with AES Hawaii.

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

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

Hawaii Electric Light and Maui Electric firm capacity PPAs. As of December 31, 2013, Hawaii Electric Light has PPAs for 119.5 MW (of which 94.6 MW are currently available) and Maui Electric has a PPA for 16 MW (including 4 MW of system protection) of firm capacity.

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

In October 1997, Hawaii Electric Light entered into an agreement with Encogen, which has been succeeded by Hamakua Energy Partners, L. P. (HEP). The agreement requires Hawaii Electric Light to purchase up to 60 MW (net) of firm capacity for a period of 30 years, expiring on December 31, 2030. The dual-train combined-cycle DTCC facility, which primarily burns naphtha, consists of two oil-fired combustion turbines and a steam turbine that utilizes waste heat from the combustion turbines.

In March 2012, Hawaii Electric Light entered into an agreement with Hu Honua Bioenergy LLC, which requires Hawaii Electric Light to purchase up to 21.5 MW (net) of renewable dispatchable firm capacity for a period of 20 years from its commercial operation date. Hu Honua will restore (i.e., refurbish and modernize) the Hilo Coast Power Company power plant to operate using biomass fuel from on-island sources. The PUC approved the PPA on December 20, 2013.

Maui Electric has a PPA with Hawaiian Commercial & Sugar Company (HC&S) for 16 MW of firm capacity. The HC&S generating units primarily burn bagasse (sugar cane waste) along with secondary fuels of diesel oil or coal. The PPA runs through December 31, 2014, and from year to year thereafter, subject to termination by either party on or after December 31, 2014, with two years’ prior written notice, except that the parties have agreed that notice to terminate on December 31, 2014 may be given on or before March 31, 2014. The parties are in discussions to extend the PPA and renegotiate more favorable terms and conditions so that Maui Electric can purchase, at its option, scheduled energy. In January 2014, Maui Electric filed with the PUC a request for an exemption or waiver from the Competitive Bidding Framework for the proposed extension.

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

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

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

See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 3 of the Consolidated Financial Statements.

The following table sets forth the average cost of fuel oil used by Hawaiian Electric, Hawaii Electric Light and Maui Electric to generate electricity in the years 2013, 2012 and 2011:



	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Consolidated
	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu	$/Barrel	¢/MBtu
2013	130.85	2,068.2	125.81	2,064.7	135.57	2,286.3	131.10	2,103.2
2012	139.14	2,195.5	129.27	2,112.5	138.60	2,327.4	138.09	2,210.4
2011	122.94	1,949.6	118.09	1,934.1	129.58	2,178.3	123.63	1,986.7

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



	Hawaiian Electric				Hawaii Electric Light				Maui Electric
	LSFO		Diesel/Biodiesel		MSFO		Diesel		MSFO		Diesel/Biodiesel
2013	98	%	2	%	53	%	47	%	18	%	82	%
2012	99		1		59		41		22		78
2011	99		1		56		44		22		78

In general, MSFO is the least costly fuel, biodiesel and diesel are the most expensive fuels and the price of LSFO falls in-between on a per-barrel basis. In 2013, prices of all petroleum fuels peaked during the year in early spring and then again in early fall having moved to lower levels in the summer months. Though LSFO prices ended 2013 slightly higher than at the end of the previous year, MSFO prices and diesel prices ended the year below where they began. On average, the prices of LSFO, MSFO and diesel were lower in 2013 as a whole, having decreased by approximately 5%, 8% and 3%, respectively. The per-unit price of biodiesel trended downward until late summer 2013, after which it increased gradually through the end of the year. Nevertheless, the average price of biodiesel for 2013 was approximately 30% lower than the prior year after the retroactive application of the $1 per gallon federal blenders credit enacted in early 2013.

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

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

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

to minimum floor rates specified in their approved PPAs. HEP energy prices vary primarily with Hawaii Electric Light’s diesel costs.

The Utilities estimate that 66% of the net energy they generate or purchase will come from fossil fuel oil in 2014. Hawaiian Electric generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. Hawaii Electric Light and Maui Electric generally maintain an average system fuel inventory level equivalent to approximately one month’s supply of both MSFO and diesel. The PPAs with AES Hawaii and HEP require that they maintain certain minimum fuel inventory levels.

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

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

See “Electric utility–Most recent rate proceedings, “Electric utility–Certain factors that may affect future results and financial condition–Regulation of electric utility rates” and “Electric utility–Material estimates and critical accounting policies–Revenues” in HEI’s MD&A and “Interim increases” and “Utility projects” under “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements.

Public Utilities Commission and Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii. Hermina M. Morita is the Chair of the PUC (for a term that will expire in June 2014) and was formerly a State Representative. The other commissioners are Michael E. Champley (for a term that will expire in June 2016), who previously was a senior energy consultant and a senior executive with DTE Energy, and Lorraine H. Akiba (for a term that will expire in June 2018), an attorney in private practice who previously served as the Director of the State Department of Labor and Industrial Relations.

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

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

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

Global climate change and greenhouse gas (GHG) emissions reduction. The Company shares the concerns of many regarding the potential effects of global climate changes and the human contributions to this phenomenon, including burning of fossil fuels for electricity production, transportation, manufacturing and agricultural activities, as well as deforestation. Recognizing that effectively addressing global climate changes requires commitment by the private sector, all levels of government, and the public, the Company is committed to taking direct action to mitigate GHG emissions from its operations. See “Environmental regulation–Global climate change and greenhouse gas emissions reduction” under “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements.

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

Commitments and contingencies. See “Selected contractual obligations and commitments” in Hawaiian Electric’s MD&A and “Electric utility–Certain factors that may affect future results and financial condition–Other regulatory and permitting contingencies” in HEI’s MD&A, Item 1A. Risk Factors, and Note 3 of the Consolidated Financial Statements for a discussion of important commitments and contingencies.

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

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

On October 20, 2008, Hawaiian Electric signed an Energy Agreement (see “Hawaii Clean Energy Initiative” under “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements) setting forth goals, objectives and actions with the purpose of decreasing Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation. As a result of the Energy Agreement, numerous PUC proceedings have been initiated, many of which have been completed, as described elsewhere in this report.

In 2009, the State Legislature amended Hawaii’s RPS law to require electric utilities (either individually or on a consolidated basis) 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 will not count toward the RPS after 2014 (only electrical generation using renewable energy as a source will count). The amended RPS law is consistent with the commitment in the Energy Agreement.

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

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

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

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

See also “HEI–Regulation” above.

Environmental regulation. Hawaiian Electric, Hawaii Electric Light and Maui Electric, like other utilities, are subject to periodic inspections by federal, state and, in some cases, local environmental regulatory agencies, including agencies responsible for the regulation of water quality, air quality, hazardous and other waste, and hazardous materials. These inspections may result in the identification of items needing corrective or other action. Except as otherwise disclosed in this report (see “Certain factors that may affect future results and financial condition–Environmental matters” for HEI Consolidated, the Electric utility and the Bank sections in HEI’s MD&A and Note 3 of the Consolidated Financial Statements, which are incorporated herein by reference), the Company believes that each subsidiary has appropriately responded to environmental

conditions requiring action and that, as a result of such actions, such environmental conditions will not have a material adverse effect on the Company or Hawaiian Electric.

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

In 2013 and 2014 to date, the Utilities did not experience any significant petroleum releases. The Company believes that each subsidiary’s costs of responding to petroleum releases to date will not have a material adverse effect on the respective subsidiary or the Company.

Air quality controls. The Clean Air Act (CAA) amendments of 1990, among other things, established a federal operating permits program (in Hawaii known as the Covered Source Permit program) and greatly expanded the hazardous air pollutant program. More stringent National Ambient Air Quality Standards (NAAQS) will affect new or modified generating units requiring a permit to construct under the Prevention of Significant Deterioration (PSD) program and the controls necessary to meet the NAAQS.

CAA operating permits (Title V permits) have been issued for all affected generating units.

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

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

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

The TSCA regulations specify procedures for the handling and disposal of polychlorinated biphenyls (PCB), a compound found in some transformer and capacitor dielectric fluids. The TSCA regulations also apply to responses to releases of PCB to the environment. The Utilities have instituted procedures to monitor compliance with these regulations and have implemented a program to identify and replace PCB transformers and capacitors in their systems. Management believes that all of the Utilities' facilities are currently in compliance with PCB regulations. In April 2010, the EPA issued an Advance Notice of Proposed Rule Making announcing its intent to reassess PCB regulations. The EPA projects that it will publish a notice of proposed rule making in November 2014.

Hawaii’s Environmental Response Law, as amended (ERL), governs releases of hazardous substances, including oil, to the environment in areas within the state’s jurisdiction. Responsible parties under the ERL are jointly, severally and strictly liable for a release of a hazardous substance. Responsible parties include owners or operators of a facility where a hazardous substance is located and any person who at the time of disposal of the hazardous substance owned or operated any facility at which such hazardous substance was disposed.

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

Research and development. The Utilities expensed approximately $3.0 million, $4.0 million, and $4.3 million in 2013, 2012 and 2011, respectively, for research and development (R&D). In 2013, 2012 and 2011, the electric utilities’ contributions to the Electric Power Research Institute accounted for approximately 64%, 55% and 48% of R&D expenses, respectively. There were also utility expenditures in 2013, 2012 and 2011 related to new technologies, biofuels, energy storage, demand response, seawater cooling traveling screens, electric and hybrid plug in vehicles and other renewables (e.g., wind and solar power integration and solar resource evaluation).

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

Properties. Hawaiian Electric owns and operates four generating plants on the island of Oahu at Honolulu, Waiau, Kahe and Campbell Industrial Park (CIP). These plants have an aggregate net generating capability of 1,322 MW as of December 31, 2013. The four plants are situated on Hawaiian Electric-owned land having a combined area of 535 acres and three parcels of land totaling 5.5 acres under leases expiring between June 30, 2016 and December 31, 2018, with options to extend to June 30, 2026. In addition, Hawaiian Electric owns a total of 132 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located.

Hawaiian Electric owns buildings and approximately 11.6 acres of land located in Honolulu which house its operating, engineering and information services departments and a warehousing center. It also leases an office building and certain office space in Honolulu. The lease for the office building expires in November 2021, with an option to extend through November 2024. Leases for certain office and warehouse spaces expire on various dates from July 31, 2014 through July 31, 2025, some with options to extend to various dates through December 31, 2034.

Hawaiian Electric's Barbers Point Tank Farm (BPTF) has three storage tanks with an aggregate of 1 million barrels of storage for LSFO. The BPTF is located in Campbell Industrial Park, on the same property as the CIP Generating Station, and is the central fuel storage facility where LSFO purchased by Hawaiian Electric is received and stored. From the BPTF, LSFO is transported via Hawaiian Electric owned underground pipelines to the Kahe and Waiau Power Plants. Hawaiian Electric also has fuel storage facilities at each of its plant sites with a nominal aggregate capacity of 732,000 barrels for LSFO storage, 44,000 barrels for diesel storage, and 88,000 barrels for biodiesel storage. Hawaiian Electric also owns a fuel storage facility at Iwilei that was used to provide fuel to the Honolulu Power Plant. As the Honolulu Power Plant was deactivated on January 31, 2014 and any future fuel supplies to the plant will be delivered by truck, the Iwilei fuel storage facility will no longer be needed to meet the plant’s fuel demands and will be taken out of service.

Hawaii Electric Light owns and operates five generating plants on the island of Hawaii, two at Hilo and one at each of Waimea, Keahole and Puna, along with distributed generators at substation sites. These plants have an aggregate net generating capability of 197.1 MW as of December 31, 2013 (excluding several small run-of-river hydro units). The plants are situated on Hawaii Electric Light-owned land having a combined area of approximately 44 acres. The distributed generators are located within Hawaii Electric Light-owned substation sites having a combined area of approximately 4 acres. Hawaii Electric Light also owns fuel storage facilities at these sites with a usable storage capacity of 51,500 barrels of bunker oil and 81,802 barrels of diesel. There are an additional 19,200 barrels of diesel and 22,770 barrels of bunker oil storage capacity for Hawaii Electric Light-owned fuel off-site at Chevron Products Company (Chevron)-owned terminalling facilities. Hawaii Electric Light pays a storage fee to Chevron and has no other interest in the property, tanks or other infrastructure situated on Chevron’s property. Hawaii Electric Light also owns 6 acres of land in Kona, which is used for a baseyard, and one acre of land in Hilo, which houses its accounting, customer services and administrative offices. Hawaii Electric Light also leases 3.7 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addition, Hawaii Electric Light owns a total of approximately 100 acres of land, and leases a total of approximately 8.5 acres of land, on which hydro facilities, substations and switching stations, microwave facilities, and transmission lines are located. The deeds to the sites located in Hilo contain certain restrictions, but the restrictions do not materially interfere with the use of the sites for public utility purposes.

Maui Electric owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 244.3 MW as of December 31, 2013. The plants are situated on Maui Electric-owned land having a combined area of 28.6 acres. Maui Electric also owns fuel oil storage facilities at these sites with a total maximum usable capacity of 81,272 barrels of bunker oil, and 94,586 barrels of diesel. There are an additional 56,358 barrels of diesel oil storage capacity for Maui Electric-owned fuel off-site at Aloha Petroleum, Ltd. (Aloha Petroleum)-owned terminalling facilities and 10,000 barrels of diesel oil storage capacity for Maui Electric-owned fuel off-site at Chevron Products Company (Chevron)-owned terminalling facilities. Maui Electric pays storage fees to Aloha Petroleum and Chevron. Maui Electric owns two 1 MW stand-by diesel generators and a 6,000 gallon fuel storage tank located in Hana. Maui Electric owns 65.7 acres of undeveloped land at Waena. Most of this Waena land is currently used for agricultural purposes by the former landowner.

Maui Electric’s administrative offices and engineering and distribution departments are located on 9.1 acres of Maui Electric-owned land in Kahului.

Maui Electric also owns and operates smaller distribution systems, generation systems (with an aggregate net capability of 21.9 MW as of December 31, 2013) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by Maui Electric.

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

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

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

Bank

General. ASB was granted a federal savings bank charter in January 1987. Prior to that time, ASB had operated since 1925 as the Hawaii division of American Savings & Loan Association of Salt Lake City, Utah. As of December 31, 2013, ASB was one of the largest financial institutions in the State of Hawaii based on total assets of $5.2 billion and deposits of $4.4 billion. In 2013, ASB’s revenues and net income amounted to approximately 8% and 36% of HEI’s consolidated revenues and net income, respectively, compared to approximately 8% and 42% in 2012 and approximately 8% and 43% in 2011, respectively.

At the time of HEI’s acquisition of ASB in 1988, HEI agreed with the OTS’ predecessor regulatory agency that ASB’s regulatory capital would be maintained at a level of at least 6% of ASB’s total liabilities, or at such greater amount as may be required from time to time by regulation. Under the agreement, HEI’s obligation to contribute additional capital to ensure that ASB would have the capital level required by the OTS was limited to a maximum aggregate amount of approximately $65.1 million. As of December 31, 2013, as a result of certain HEI contributions of capital to ASB, HEI’s maximum obligation under the agreement to contribute additional capital has been reduced to approximately $28.3 million. ASB is subject to OCC regulations on dividends and other distributions and ASB must receive a letter of non-objection from the OCC and FRB before it can declare and pay a dividend to HEI.

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



Years ended December 31	2013		2012		2011
Common equity to assets ratio
Average common equity divided by average total assets	9.90	%	10.14	%	10.24	%
Return on assets
Net income for common stock divided by average total assets	1.13		1.18		1.23
Return on common equity
Net income for common stock divided by average common equity	11.38		11.68		11.99

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

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

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



(in thousands)	2013 vs. 2012									2012 vs. 2011
Increase (decrease) due to	Rate			Volume			Total			Rate			Volume			Total
Income from earning assets
Other investments	$	47		$	(77	)	$	(30	)	$	—		$	(73	)	$	(73	)
Securities purchased under resale agreements	22			21			43			—			—			—
Available-for-sale investment and mortgage-related securities	59			(799		)	(740		)	(375		)	(298		)	(673		)
Loans
Residential 1-4 family	(9,670		)	3,907			(5,763		)	(4,351		)	(6,501		)	(10,852		)
Commercial real estate	(612		)	1,772			1,160			(1,941		)	2,417			476
Home equity line of credit	1,561			2,775			4,336			(947		)	3,118			2,171
Residential land	64			(853		)	(789		)	255			(1,137		)	(882		)
Commercial loans	(2,246		)	509			(1,737		)	(4,077		)	3,570			(507		)
Consumer loans	(1,422		)	1,127			(295		)	(390		)	1,556			1,166
Total loans	(12,325		)	9,237			(3,088		)	(11,451		)	3,023			(8,428		)
Total increase (decrease) in net interest income from earning assets	(12,197		)	8,382			(3,815		)	(11,826		)	2,652			(9,174		)
Expense from costing liabilities
Savings	139			(63		)	76			687			(59		)	628
Interest-bearing checking	—			5			5			77			(4		)	73
Money market	57			30			87			220			111			331
Time certificates	592			571			1,163			724			804			1,528
Advances from Federal Home Loan Bank	328			(584		)	(256		)	(241		)	618			377
Securities sold under agreements to repurchase	89			51			140			203			37			240
Total increase (decrease) in net interest income from costing liabilities	1,205			10			1,215			1,670			1,507			3,177
Total increase (decrease) in net interest income	$	(10,992	)	$	8,392		$	(2,600	)	$	(10,156	)	$	4,159		$	(5,997	)

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

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

Lending activities.

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



December 31	2013				2012				2011				2010				2009
(dollars in thousands)	Balance			% of total	Balance			% of total	Balance			% of total	Balance			% of total	Balance			% of total
Real estate loans: ¹
Residential 1-4 family	$	2,006,007		48.2	$	1,866,450		49.2	$	1,926,774		52.2	$	2,087,813		58.9	$	2,332,763		62.9
Commercial real estate	440,443			10.6	375,677			9.9	331,931			9.0	300,689			8.5	255,716			6.9
Home equity line of credit	739,331			17.8	630,175			16.6	535,481			14.5	416,453			11.7	326,896			8.8
Residential land	16,176			0.4	25,815			0.7	45,392			1.2	65,599			1.8	96,515			2.6
Commercial construction	52,112			1.3	43,988			1.2	41,950			1.1	38,079			1.1	68,174			1.9
Residential construction	12,774			0.3	6,171			0.2	3,327			0.1	5,602			0.2	16,705			0.5
Total real estate loans, net	3,266,843			78.6	2,948,276			77.8	2,884,855			78.1	2,914,235			82.2	3,096,769			83.6
Commercial loans	783,388			18.8	721,349			19.0	716,427			19.4	551,683			15.5	545,622			14.7
Consumer loans	108,722			2.6	121,231			3.2	93,253			2.5	80,138			2.3	64,360			1.7
	4,158,953			100.0	3,790,856			100.0	3,694,535			100.0	3,546,056			100.0	3,706,751			100.0
Less: Deferred fees and discounts	(8,724		)		(11,638		)		(13,811		)		(15,530		)		(19,494		)
Allowance for loan losses	(40,116		)		(41,985		)		(37,906		)		(40,646		)		(41,679		)
Total loans, net	$	4,110,113			$	3,737,233			$	3,642,818			$	3,489,880			$	3,645,578
Total loans as a % of assets	78.4		%		74.1		%		74.2		%		72.8		%		73.8		%


¹	Includes renegotiated loans.

The increase in the loans receivable balance in 2013 was primarily due to growth in the residential, home equity lines of credit, commercial and commercial real estate loan portfolios. The growth in these portfolios was consistent with ASB’s mix target and loan growth strategy. The increase in the loans receivable balance in 2012 and 2011 was primarily due to growth in commercial, commercial real estate, consumer and home equity lines of credit loans as ASB targeted these portfolios because of their shorter duration and/or variable rates. Offsetting these 2012 and 2011 loan portfolio increases was a decrease in the residential loan portfolio. Although ASB produced nearly $1.0 billion of new, long-term residential loans in 2012, nearly double the level for 2011, it sold more than half those loans to control interest rate risk and repayments were also higher than in 2011. The decrease in the loans receivable balance in 2010 and 2009 was primarily due to ASB’s decision to sell substantially all of its residential loan production in 2009 and the first nine months of 2010.

The following table summarizes ASB’s loans receivable held for investment based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:



December 31	2013								2012
Due	In 1 year or less		After 1 year through 5 years		After 5 years		Total		In 1 year or less		After 1 year through 5 years		After 5 years		Total
(in millions)
Residential loans - Fixed	$	377	$	848	$	652	$	1,877	$	488	$	912	$	393	$	1,793
Residential loans - Adjustable	41		70		18		129		36		33		4		73
Total residential loans	418		918		670		2,006		524		945		397		1,866
Commercial real estate loans-Fixed	24		58		48		130		19		64		39		122
Commercial real estate loans-Adjustable	55		175		133		363		56		100		142		298
Total commercial real estate loans	79		233		181		493		75		164		181		420
Consumer loans – Fixed	49		135		88		272		49		74		21		144
Consumer loans – Adjustable	37		32		544		613		48		68		529		645
Total consumer loans	86		167		632		885		97		142		550		789
Commercial loans – Fixed	54		133		32		219		62		107		36		205
Commercial loans – Adjustable	221		299		44		564		220		266		30		516
Total commercial loans	275		432		76		783		282		373		66		721
Total loans - Fixed	504		1,174		820		2,498		618		1,157		489		2,264
Total loans - Adjustable	354		576		739		1,669		360		467		705		1,532
Total loans	$	858	$	1,750	$	1,559	$	4,167	$	978	$	1,624	$	1,194	$	3,796

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

Residential mortgage lending. ASB’s general policy is to require private mortgage insurance when the loan-to-value ratio of the property exceeds 80% of the lower of the appraised value or purchase price at origination. For nonowner-occupied residential properties, the loan-to-value ratio may not exceed 80% of the lower of the appraised value or purchase price at origination.

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

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

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

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

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

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

Loan portfolio risk elements. When a borrower fails to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of real estate secured loans. In a foreclosure action, the property collateralizing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold. As of December 31, 2013, 2012 and 2011, ASB had $1.2 million, $6.1 million and $7.3 million, respectively, of real estate acquired in settlement of loans.

In addition to delinquent loans, other significant lending risk elements include: (1) loans which accrue interest and are 90 days or more past due as to principal or interest, (2) loans accounted for on a nonaccrual basis (nonaccrual loans), and (3) loans on which various concessions are made with respect to interest rate, maturity, or other terms due to the inability of the borrower to service the obligation under the original terms of the agreement (troubled debt restructured loans). ASB loans that were 90 days or more past due on which interest was being accrued as of December 31, 2013, 2012, 2011, 2010 and 2009 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and troubled debt restructured loans:



December 31	2013			2012			2011			2010			2009
(dollars in thousands)
Nonaccrual loans—
Real estate
Residential 1-4 family	$	19,679		$	26,721		$	28,298		$	36,420		$	31,848
Commercial real estate	4,439			6,750			3,436			—			344
Home equity line of credit	2,060			2,349			2,258			1,659			2,755
Residential land	3,161			8,561			14,535			15,479			25,164
Residential construction	—			—			—			—			326
Total real estate loans	29,339			44,381			48,527			53,558			60,437
Consumer loans	401			284			281			341			715
Commercial loans	18,781			20,222			17,946			4,956			4,171
Total nonaccrual loans	$	48,521		$	64,887		$	66,754		$	58,855		$	65,323
Nonaccrual loans to end of period loans	1.2		%	1.7		%	1.8		%	1.7		%	1.8		%
Troubled debt restructured loans not included above—
Real estate
Residential 1-4 family	$	9,744		$	6,759		$	5,029		$	5,150		$	1,986
Commercial real estate	—			—			—			1,963			513
Home equity line of credit	171			—			—			—			—
Residential land	7,476			11,090			24,828			27,689			15,665
Total real estate loans	17,391			17,849			29,857			34,802			18,164
Commercial loans	1,649			43			15,386			4,035			2,904
Total troubled debt restructured loans	$	19,040		$	17,892		$	45,243		$	38,837		$	21,068
Nonaccrual and troubled debt restructured loans to end of period loans	1.6		%	2.2		%	3.1		%	2.8		%	2.3		%

ASB realized $1.1 million, $3.0 million and $6.3 million of interest income on nonaccrual and troubled debt restructured (TDR) loans in 2013, 2012 and 2011, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $3.7 million, $6.7 million and $9.9 million in 2013, 2012 and 2011, respectively.

In 2013, nonaccrual loans decreased $16.4 million due to improved credit quality in the residential 1-4 family, commercial real estate and commercial loans, and repayments in the residential land portfolio. The improvement is attributed to the continued stabilization or increase of property values, more financial flexibility of borrowers, and overall general economic improvement in the State of Hawaii. TDR loans increased $1.1 million primarily due to increases of $3.0 million and $1.6 million of residential 1-4 and commercial loans, respectively, classified as TDR, partly offset by a $3.6 million decrease in residential land loans classified as TDR. ASB evaluates a restructured loan transaction to determine if the borrower is in financial difficulty and if the restructured terms are considered concessions—typically terms that are out of market, beyond normal or reasonable standards, or otherwise not available to a non-troubled borrower in the normal market place. A loan

classified as TDR must meet both criteria of financial difficulty and concession. In 2012, nonaccrual loans decreased by $1.9 million due to improved credit quality in the residential 1-4 family and consumer portfolios (residential 1-4 family lower by $1.6 million and residential land loans lower by $5.9 million), partially offset by higher nonaccrual commercial real estate and commercial loans of $5.6 million. The improvement was attributed to stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the State of Hawaii. TDR loans decreased by $27.4 million in 2012 due to decreases of $15.3 million and $13.7 million of commercial loans and residential land loans, respectively, classified as TDR. In 2011, nonaccrual loans increased by $7.9 million due to certain commercial loans that were current as to principal and interest payments but were classified and placed on nonaccrual status. The increase in troubled debt restructured loans was due to two commercial loans that were renegotiated. In 2010, nonaccrual loans decreased by $6.5 million due to a decrease in residential land loans that were more than 90 days delinquent and the renegotiation of certain residential land loans that had been on nonaccrual status.

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

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



(dollars in thousands)	2013			2012			2011			2010			2009
Allowance for loan losses, January 1	$	41,985		$	37,906		$	40,646		$	41,679		$	35,798
Provision for loan losses	1,507			12,883			15,009			20,894			32,000
Charge-offs
Residential 1-4 family	1,162			3,183			5,528			6,142			3,129
Home equity line of credit	782			716			1,439			2,517			2,331
Residential land	485			2,808			4,071			6,487			4,217
Total real estate loans	2,429			6,707			11,038			15,146			9,677
Commercial loans	3,056			3,606			5,335			6,261			14,853
Consumer loans	2,717			2,517			3,117			3,408			2,436
Total charge-offs	8,202			12,830			19,490			24,815			26,966
Recoveries
Residential 1-4 family	1,881			1,328			110			744			151
Home equity line of credit	358			108			25			63			—
Residential land	868			1,443			170			63			—
Total real estate loans	3,107			2,879			305			870			151
Commercial loans	1,089			649			869			1,537			404
Consumer loans	630			498			567			481			292
Total recoveries	4,826			4,026			1,741			2,888			847
Allowance for loan losses, December 31	$	40,116		$	41,985		$	37,906		$	40,646		$	41,679
Ratio of allowance for loan losses, December 31, to end of period loans	0.97		%	1.11		%	1.03		%	1.15		%	1.12		%
Ratio of provision for loan losses during the year to average loans outstanding	0.04		%	0.35		%	0.42		%	0.58		%	0.81		%
Ratio of net charge-offs during the year to average loans outstanding	0.09		%	0.24		%	0.49		%	0.61		%	0.66		%

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



December 31	2013				2012				2011
(dollars in thousands)	Allow-ance balance		Allowance to loan receivable %	Loan receivable % of total	Allow-ance balance		Allowance to loan receivable %	Loan receivable % of total	Allow-ance balance		Allowance to loan receivable %	Loan receivable % of total
Real estate
Residential 1-4 family	$	5,534	0.28	48.2	$	6,068	0.33	49.2	$	6,500	0.34	52.2
Commercial real estate	5,059		1.15	10.6	2,965		0.79	9.9	1,688		0.51	9.0
Home equity line of credit	5,229		0.71	17.8	4,493		0.71	16.6	4,354		0.81	14.5
Residential land	1,817		11.23	0.4	4,275		16.56	0.7	3,795		8.36	1.2
Commercial construction	2,397		4.60	1.3	2,023		4.60	1.2	1,888		4.50	1.1
Residential construction	19		0.15	0.3	9		0.15	0.2	4		0.12	0.1
Total real estate loans, net	20,055		0.61	78.6	19,833		0.67	77.8	18,229		0.63	78.1
Commercial loans	15,803		2.02	18.8	15,931		2.21	19.0	14,867		2.08	19.4
Consumer loans	2,367		2.18	2.6	4,019		3.32	3.2	3,806		4.08	2.5
	38,225		0.92	100.0	39,783		1.05	100.0	36,902		1.00	100.0
Unallocated	1,891				2,202				1,004
Total allowance for loan losses	$	40,116			$	41,985			$	37,906



December 31	2010				2009
(dollars in thousands)	Allowance balance		Allowance to loan receivable %	Loan receivable % of total	Allowance balance		Allowance to loan receivable %	Loan receivable % of total
Real estate
Residential 1-4 family	$	6,497	0.31	58.9	$	5,522	0.24	62.5
Commercial real estate	1,474		0.49	8.5	861		0.34	6.9
Home equity line of credit	4,269		1.03	11.7	4,679		1.43	8.8
Residential land	6,411		9.77	1.8	4,252		4.41	2.6
Commercial construction	1,714		4.50	1.1	3,068		4.50	1.8
Residential construction	7		0.12	0.2	19		0.11	0.5
Total real estate loans, net	20,372		0.70	82.2	18,401		0.59	83.1
Commercial loans	16,015		2.90	15.5	19,498		3.57	14.6
Consumer loans	3,325		4.15	2.3	2,590		4.02	2.3
	39,712		1.12	100.0	40,489		1.09	100.0
Unallocated	934				1,190
Total allowance for loan losses	$	40,646			$	41,679

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

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

reflecting the gradual improvement in the local economy including a recovery of the housing market. ASB’s provision for loan losses was $12.9 million in 2012, compared to $15.0 million in 2011.

In 2011, ASB’s allowance for loan losses decreased by $2.7 million from 2010 due to a lower historical loss ratio for the commercial markets portfolio and the decline of the residential land portfolio, which was a higher risk and had a higher historical loss ratio assigned to it. Partly offsetting these decreases was an increase in the allowance for loan losses for the commercial real estate portfolios due to a higher average loan balance. The levels of delinquencies and losses in 2011 declined from a year ago. ASB’s 2011 provision for loan losses was $15.0 million, or a decrease of $5.9 million from the prior year’s provision for loan losses. Although the economy had gradually recovered during the year and businesses stabilized, the housing market remained stagnant.

In 2010, ASB’s allowance for loan losses decreased by $1.0 million from 2009 due to lower residential, commercial and commercial construction average loan balances, partly offset by increases in the historical loss ratios for residential first mortgage and land loans. Although ASB’s loan quality improved in 2010, there were still signs of financial stress in the Hawaii and U.S. mainland markets. The slowdown in the economy, both nationally and locally, resulted in ASB experiencing higher levels of loan delinquencies and losses, which were concentrated in the vacant land portfolio and on the neighbor islands. ASB’s 2010 provision for loan losses was $20.9 million. While a mild recovery began in 2010 as the global economic recovery began to take hold, many challenges remained.

Investment activities. Currently, ASB’s investment portfolio consists of mortgage-related securities, stock of the FHLB of Seattle, federal agency obligations and municipal bonds. ASB owns mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) and federal agency obligations. The weighted-average yield on investments during 2013, 2012 and 2011 was 2.01%, 1.99% and 2.01%, respectively. ASB did not maintain a portfolio of securities held for trading during 2013, 2012 and 2011.

As of December 31, 2013, 2012 and 2011, ASB’s investment in stock of the FHLB of Seattle amounted to $93 million, $96 million and $98 million, respectively. The amount that ASB is required to invest in FHLB of Seattle stock is determined by FHLB requirements and ASB’s investment is in excess of that requirement. Since the third quarter of 2012, the FHLB of Seattle was granted authority to repurchase excess stock from its members. ASB’s pro-rata share of the repurchase amount in 2013 and 2012 was $3 million and $2 million, respectively. See “FHLB of Seattle stock” in HEI’s MD&A. Also, see “Regulation–Federal Home Loan Bank System” below.

ASB does not have any exposure to securities backed by subprime mortgages. See “Investment and mortgage-related securities” in Note 4 of the Consolidated Financial Statements for a discussion of other-than-temporarily impaired securities.

The following table summarizes the current face amount of ASB’s investment portfolio (excluding stock of the FHLB of Seattle, which has no contractual maturity), as of December 31, 2013, based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:



Due	In 1 year or less			After 1 year through 5 years			After 5 years through 10 years			After 10 years			Total
(dollars in millions)
Federal agency obligations	$	21		$	26		$	28		$	7		$	82
Mortgage-related securities - FNMA, FHLMC and GNMA	81			167			95			27			370
Municipal bonds	—			19			52			—			71
	$	102		$	212		$	175		$	34		$	523
Weighted average yield	2.06		%	2.20		%	2.33		%	2.16		%

Deposits and other sources of funds.

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

Deposits. ASB’s deposits are obtained primarily from residents of Hawaii. Net deposit inflow or outflow, measured as the year-over-year difference in year-end deposits, was an inflow of $143 million in 2013, compared to an inflow of $160 million in 2012 and $95 million in 2011.

The following table illustrates the distribution of ASB’s average deposits and average daily rates by type of deposit. Average balances have been calculated using the average daily balances.



Years ended December 31	2013						2012						2011
(dollars in thousands)	Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %		Average balance		% of total deposits		Weighted average rate %
Savings	$	1,805,363	42.1	%	0.06	%	$	1,727,754	41.9	%	0.07	%	$	1,672,033	41.5	%	0.11	%
Checking	1,845,500		43.0		0.01		1,672,750		40.6		0.01		1,510,848		37.5		0.01
Money market	182,343		4.3		0.13		202,539		4.9		0.16		250,682		6.2		0.26
Certificate	454,021		10.6		0.82		517,752		12.6		0.94		598,360		14.8		1.07
Total deposits	$	4,287,227	100.0	%	0.12	%	$	4,120,795	100.0	%	0.16	%	$	4,031,923	100.0	%	0.22	%

As of December 31, 2013, ASB had $102.1 million in certificate accounts of $100,000 or more, maturing as follows:



(in thousands)	Amount
Three months or less	$	22,012
Greater than three months through six months	9,253
Greater than six months through twelve months	23,726
Greater than twelve months	47,070
	$	102,061

This compares with $105.9 million in such certificate accounts at December 31, 2012.

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

Other borrowings. See “Other borrowings” in Note 4 of the Consolidated Financial Statements. ASB may obtain advances from the FHLB of Seattle provided that certain standards related to creditworthiness have been met. Advances are collateralized by a blanket pledge of certain notes held by ASB and the mortgages securing them. To the extent that advances exceed the amount of mortgage loan collateral pledged to the FHLB of Seattle, the excess must be covered by qualified marketable securities held under the control of and at the FHLB of Seattle or at an approved third-party custodian. FHLB advances generally are available to meet seasonal and other withdrawals of deposit accounts, to expand lending and to assist in the effort to improve asset and liability management. FHLB advances are made pursuant to several different credit programs offered from time to time by the FHLB of Seattle.

The increase in other borrowings in 2013 compared to 2012 was due to $50 million of additional FHLB advances taken out in 2013. The decrease in other borrowings in 2012 compared to 2011 was due to a decrease in retail repurchase agreements. The decrease in other borrowings in 2011 compared to 2010 was primarily due to the payoff of a maturing FHLB advance, partially offset by an increase in retail repurchase agreements.

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

Competition for deposits comes primarily from other savings institutions, commercial banks, credit unions, money market and mutual funds and other investment alternatives. As of December 31, 2013, there were 9 financial institutions insured by the FDIC in the State of Hawaii, of which 2 were thrifts and 7 were commercial banks. Additional competition for deposits comes from various types of corporate and government borrowers, including insurance companies. Competition for origination of first mortgage loans comes primarily from mortgage banking and brokerage firms, commercial banks, other savings institutions, insurance companies and real estate investment trusts.

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

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

See “Federal Deposit Insurance Corporation restoration plan” in Note 4 of the Consolidated Financial Statements for a discussion of FDIC deposit insurance assessment rates, the prepayment of estimated assessments for the fourth quarter of 2009 and for all of 2010, 2011 and 2012 and changes to the assessment rates and base. FICO will continue to impose an assessment on average total assets minus average tangible equity to service the interest on FICO bond obligations. As of December 31, 2013, ASB’s annual FICO assessment is 0.64 cents per $100 of average total assets minus average tangible equity.

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

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

Capital requirements. The OCC has set three capital standards for financial institutions. As of December 31, 2013, ASB was in compliance with all of the minimum standards with a core capital ratio of 9.1% (compared to a 4.0% requirement), a tangible capital ratio of 9.1% (compared to a 1.5% requirement) and total risk-based capital ratio of 12.1% (based on risk-based capital of $515.7 million, $175.6 million in excess of the 8.0% requirement).

The OCC requires that financial institutions with a composite rating of “1” under the Uniform Financial Institution Rating System (i.e., CAMELS rating system) must maintain core capital in an amount equal to at least 3% of adjusted total assets. All other institutions must maintain a minimum core capital of 4% of adjusted total assets, and higher capital ratios may be required if warranted by particular circumstances. As of December 31, 2013, ASB met the applicable minimum core capital requirement.

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

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

Financial Derivatives and Interest Rate Risk. ASB is subject to OCC rules relating to derivatives activities, such as interest rate swaps, interest rate lock commitments and forward commitments. See “Derivative financial instruments” in Note 4 of the Consolidated Financial Statements for a description of interest rate lock commitments and forward commitments used by ASB. Currently ASB does not use interest rate swaps to manage interest rate risk (IRR), but may do so in the future. Generally speaking, the OCC rules permit financial institutions to engage in transactions involving financial derivatives to the extent these transactions are otherwise authorized under applicable law and are safe and sound. The rules require ASB to have certain internal procedures for handling financial derivative transactions, including involvement of the ASB Board of Directors.

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

Liquidity. OCC regulations require ASB to maintain sufficient liquidity to ensure safe and sound operations. ASB’s principal sources of liquidity are customer deposits, borrowings, the maturity and repayment of portfolio loans and securities and the sale of loans into secondary market channels. ASB’s principal sources of borrowings are advances from the FHLB of Seattle and securities sold under agreements to repurchase from broker/dealers. ASB is approved by the FHLB of Seattle to borrow an amount of up to 35% of assets to the extent it provides qualifying collateral and holds sufficient FHLB of Seattle stock. As of December 31, 2013, ASB’s unused FHLB of Seattle borrowing capacity was approximately $1.1 billion. ASB utilizes growth in deposits, advances from the FHLB of Seattle and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and make investments. As of December 31, 2013, ASB had loan commitments, undisbursed loan funds and unused lines and letters of credit of $1.6 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

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

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

A financial institution that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OCC determines that any of the actions is necessary to resolve the problems of the association at the least possible long-term cost to the Deposit Insurance Fund. A financial institution that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless the OCC and the FDIC concur that other action would be more appropriate. As of December 31, 2013, ASB was “well-capitalized.”

Interest rates. FDIC regulations restrict the ability of financial institutions that are undercapitalized to offer interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of December 31, 2013, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

Qualified thrift lender test. In order to satisfy the QTL test, ASB must maintain 65% of its assets in “qualified thrift investments” on a monthly average basis in 9 out of the previous 12 months. Failure to satisfy the QTL test would subject ASB to various penalties, including limitations on its activities, and would also bring into operation restrictions on the activities that may be engaged in by HEI, ASHI and their other subsidiaries, which could effectively result in the required divestiture of ASB. At all times during 2013, ASB was in compliance with the QTL test. See “HEI Consolidated–Regulation.”

Federal Home Loan Bank System. ASB is a member of the FHLB System, which consists of 12 regional FHLBs, and ASB’s regional bank is the FHLB of Seattle. The FHLB System provides a central credit facility for member institutions. Historically, the FHLBs have served as the central liquidity facilities for savings associations and sources of long-term funds for financing housing. At such time as an advance is made to ASB or renewed, it must be collateralized by collateral from one of the following categories: (1) fully disbursed, whole first mortgages on improved residential property, or securities representing a whole interest in such mortgages; (2) securities issued, insured or guaranteed by the U.S. Government or any agency thereof; (3) FHLB deposits; and (4) other real estate-related collateral that has a readily ascertainable value and with respect to which a security interest can be perfected. The aggregate amount of outstanding advances collateralized by such other real estate-related collateral may not exceed 30% of ASB’s capital.

As mandated by the Gramm Act, the Federal Housing Finance Board (Board) regulations require each FHLB to maintain a minimum total capital leverage ratio of 5% of total assets and include risk-based capital standards requiring each FHLB to maintain permanent capital in an amount sufficient to meet credit risk and market risk. In June 2001, the FHLB of Seattle formulated a capital plan to meet these new minimum capital standards, which plan was approved by the Board. The capital plan requires ASB to own capital stock in the FHLB of Seattle in an amount equal to the total of 4% of the FHLB of Seattle’s advances to ASB plus the greater of (i) 5% of the outstanding balance of loans sold to the FHLB of Seattle by ASB or (ii) 0.5% of ASB’s mortgage loans and pass through securities. As of December 31, 2013, ASB was required under the capital plan to own capital stock in the FHLB of Seattle in the amount of $14 million and owned capital stock in the amount of $93 million, or $79 million in excess of the requirement. Under the capital plan, stock in the FHLB of Seattle can be required to be redeemed at the option of ASB, but the FHLB of Seattle may require up to a 5-year notice of redemption. This 5-year notice period has an adverse but immaterial effect on ASB’s liquidity. See “FHLB of Seattle stock” in HEI’s MD&A section for recent developments regarding the FHLB of Seattle.

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

Other laws. ASB is subject to federal and state consumer protection laws which affect deposit and lending activities, such as the Truth in Lending Act, the Truth in Savings Act, the Equal Credit Opportunity Act, the Real Estate Settlement Procedures Act, the Home Mortgage Disclosure Act and several federal and state financial privacy acts intended to protect consumers’ personal information and prevent identity theft, such as the Gramm Act and the Fair and Accurate Transactions Act. ASB is also subject to federal laws regulating certain of its lending practices, such as the Flood Disaster Protection Act, and laws requiring

reports to regulators of certain customer transactions, such as the Currency and Foreign Transactions Reporting Act and the International Money Laundering Abatement and Anti-Terrorist Financing Act. ASB’s relationship with LPL Financial LLP is also governed by regulations adopted by the FRB under the Gramm Act, which regulate “networking” relationships under which a financial institution refers customers to a broker-dealer for securities services and employees of the financial institution are permitted to receive a nominal fee for the referrals. These laws may provide for substantial penalties in the event of noncompliance. ASB believes that it currently is in compliance with these laws and regulations in all material respects.

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

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

Additional information. For additional information about ASB, see the sections under “Bank” in HEI’s MD&A, HEI’s “Quantitative and Qualitative Disclosures about Market Risk” and Note 4 of the Consolidated Financial Statements.

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

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



	Number of branches
December 31, 2013	Owned	Leased	Total
Oahu	7	32	39
Maui	3	4	7
Hawaii	3	3	6
Kauai	2	2	4
Molokai	—	1	1
	15	42	57

As of December 31, 2013, the net book value (NBV) of branches and office facilities is $52 million ($45 million NBV of the land and improvements for the branches and office facilities owned by ASB and $7 million represents the NBV of ASB’s leasehold improvements). The leases expire on various dates through February 2033, but many of the leases have extension provisions.

As of December 31, 2013, ASB owned 116 automated teller machines.



ITEM 1A.	RISK FACTORS

The businesses of HEI and its subsidiaries involve numerous risks which, if realized, could have a material and adverse effect on the Company’s financial statements. 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 Consolidated Financial Statements, Hawaiian Electric’s MD&A, Hawaiian Electric’s “Quantitative and Qualitative Disclosures About Market Risk.”

Holding Company and Company-Wide Risks.

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


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

•

the provisions of an HEI agreement entered into with federal bank regulators in connection with its acquisition of its bank subsidiary, ASB, which require HEI to contribute additional capital to ASB (up to a maximum amount of additional capital of $28.3 million as of December 31, 2013) 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 ASHI;


•	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 ASHI 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 turn led to declines in KWH sales (which continued through 2013), 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, 2013, 85% 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 and customer self-generation, with or without cogeneration. 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 the rate at which technological developments facilitating non-utility generation of electricity occur may adversely affect the Utilities and the results of their operations.


•	New technological developments, such as the commercial development of energy storage, 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 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 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 investment and mortgage-related securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses.

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 $576 million as of December 31, 2013), net of regulatory liabilities (amounting to $349 million as of December 31, 2013), would be charged to the statement of income in the period of discontinuance.

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.

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.

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, and more recently 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, Hawaiian Electric’s East Oahu Transmission Project encountered substantial opposition and consequent delay, increased costs and a subsequent partial write-off of costs in the fourth quarter of 2011. Also, 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.

The Energy Agreement confirms the intent of the parties that the existing ECACs will continue, but subject to periodic review by the PUC. The Energy Agreement also provides that as part of the review, 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 recent rate cases, the PUC has allowed the current ECAC to continue. However, 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 72% of the net energy generated or purchased by the Utilities in 2013 was generated from the burning of fossil fuel oil, and purchases of power by the Utilities provided about 44% 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 these contractual agreements end, the Utilities may not be able to purchase fuel and power on terms equivalent to the current contractual agreements. Further, 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 or 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 will 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.

In recent years, 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 “Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas (GHG) Tailoring Rule” (GHG Tailoring Rule) was published. It creates a new emissions threshold for GHG emissions from new and existing facilities and requires certain facilities to obtain PSD and Title V operating permits. The Utilities’ existing facilities have thus far not been subject to GHG emissions limits or controls, but the Utilities are required to conduct GHG analyses for modifications or new construction projects that are expected to result in GHG emissions above the specified threshold.

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 the HCEI Energy Agreement. On October 20, 2008, the Governor of the State of Hawaii, the DBEDT, the Division of Consumer Advocacy of the State of Hawaii Department of Commerce and Consumer Affairs and the Utilities (collectively, the parties), signed an Energy Agreement setting forth the goals and objectives of the HCEI and the related commitments of the parties. The Energy Agreement requires the parties to pursue a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and programs intended to secure greater energy efficiency and conservation.

The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, 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 under the Energy Agreement 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 HCEI programs may adversely impact the results of operations, financial condition and liquidity of the Utilities.

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 45% of ASB’s loan portfolio as of December 31, 2013 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. Although interest rates rose in 2013, new loan production rates are still historically low and below ASB's loan porfolio yields. This places additional pressure on ASB's asset yields and net interest margin. The degree to which compression of ASB's margin continues is uncertain as 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 ASHI. 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, 2013 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 17% during 2013 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. 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 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. Adverse changes in the economy may also have a negative effect on the ability of borrowers to make timely repayments of their loans. In addition, if poor economic conditions result in decreased demand for real estate loans, ASB’s profits may decrease if 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.



ITEM 1B.	UNRESOLVED STAFF COMMENTS

HEI: None.

Hawaiian Electric: Not applicable.



ITEM 2.	PROPERTIES

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



ITEM 3.	LEGAL PROCEEDINGS

HEI and Hawaiian Electric: HEI subsidiaries (including Hawaiian Electric and its subsidiaries and ASB) may be involved in ordinary routine PUC proceedings, environmental proceedings and/or litigation incidental to their respective businesses. See the descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in “Item 1. Business,” in HEI’s MD&A and in the Notes 3 and 4 of the Consolidated Financial Statements. Management believes that, other than these proceedings, the likelihood that HEI or its subsidiaries would incur material losses or write-offs in excess of insurance coverage and loss reserves recorded on HEI’s consolidated balance sheet from lawsuits or other proceedings currently pending or threatened is remote. Nevertheless, the outcomes of litigation and administrative proceedings are necessarily uncertain and there is a risk that the outcome of such matters could have a material

adverse effect on the financial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a particular period in the future.



ITEM 4.	MINE SAFETY DISCLOSURES

HEI and Hawaiian Electric: Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT (HEI)

The executive officers of HEI are listed below. Messrs. Rosenblum and Wacker are officers of HEI subsidiaries rather than of HEI, but are deemed to be executive officers of HEI under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HEI executive officers serve from the date of their initial appointment until the annual meeting of the HEI Board (or applicable HEI subsidiary board of directors) at which officers are appointed, and thereafter are appointed for one-year terms or until their successors have been duly appointed and qualified or until their earlier resignation or removal. HEI executive officers may also hold offices with HEI subsidiaries and affiliates in addition to their current positions listed below.



Name	Age	Business experience for last 5 years and prior positions with the Company
Constance H. Lau	61	HEI President and Chief Executive Officer since 5/06 HEI Director, 6/01 to 12/04 and since 5/06 Hawaiian Electric Chairman of the Board since 5/06 ASB Chairman of the Board since 5/06 · ASB Chairman of the Board, 11/10 to present · ASB Chairman of the Board and Chief Executive Officer, 2/08 to 11/10 · ASB Chairman of the Board, President and Chief Executive Officer, 5/06 to 1/08 · ASB President and Chief Executive Officer and Director, 6/01 to 5/06 · ASB Senior Executive Vice President and Chief Operating Officer and Director, 12/99 to 5/01 · HEI Treasurer, 4/89 to 10/99 · HEI Power Corp. Financial Vice President and Treasurer, 5/97 to 8/99 · Hawaiian Electric Treasurer and HEI Assistant Treasurer, 12/87 to 4/89 · Hawaiian Electric Assistant Corporate Counsel, 9/84 to 12/87
James A. Ajello	60	HEI Executive Vice President and Chief Financial Officer since 8/13 · HEI Executive Vice President, Chief Financial Officer and Treasurer, 5/11 to 8/13 · HEI Senior Financial Vice President, Treasurer and Chief Financial Officer, 1/09 to 5/11
Chester A. Richardson	65	HEI Executive Vice President, General Counsel, Secretary and Chief Administrative Officer since 5/11 · HEI Senior Vice President, General Counsel, Secretary and Chief Administrative Officer, 9/09 to 5/11 · HEI Senior Vice President, General Counsel and Chief Administrative Officer, 12/08 to 9/09 · HEI Vice President, General Counsel, 8/07 to 12/08
Richard M. Rosenblum	63	Hawaiian Electric President and Chief Executive Officer since 1/09 Hawaiian Electric Director since 2/09
Richard F. Wacker	51	ASB President and Chief Executive Officer since 11/10 ASB Director since 11/10 · Prior to joining the Company: Korea Exchange Bank, Chairman, 4/09 to 11/10, and Korea Exchange Bank, Chairman and Chief Executive Officer, 4/07 to 3/09

Family relationships; executive arrangements

There are no family relationships between any HEI executive officer and any other HEI executive officer or any HEI director or director nominee. There are no arrangements or understandings between any HEI executive officer and any other person pursuant to which such executive officer was selected.

PART II



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

HEI:

Certain of the information required by this item is incorporated herein by reference to Note 14, “Regulatory restrictions on net assets” and Note 17, “Quarterly information (unaudited)” of the Consolidated Financial Statements and "Item 6. Selected Financial Data” and “Equity compensation plan information” under "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" of this Form 10-K. Certain restrictions on dividends and other distributions of HEI are described in this report under “Item 1. Business—HEI—Regulation—Restrictions on dividends and other distributions” and that description is incorporated herein by reference. HEI’s common stock is traded on the New York Stock Exchange and the total number of holders of record of HEI common stock (i.e., registered shareholders) as of February 7, 2014, was 8,388.

Hawaiian Electric:

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

The dividends declared and paid on Hawaiian Electric’s common stock for the quarters of 2013 and 2012 were as follows:



Quarters ended	2013		2012
March 31	$	20,069,526	$	18,260,844
June 30	20,719,142		18,260,844
September 30	20,394,334		18,260,844
December 31	20,394,334		18,260,844

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

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



ITEM 6.	SELECTED FINANCIAL DATA

HEI:



Selected Financial Data
Hawaiian Electric Industries, Inc. and Subsidiaries
Years ended December 31	2013			2012			2011			2010			2009
(dollars in thousands, except per share amounts)
Results of operations
Revenues	$	3,238,470		$	3,374,995		$	3,242,335		$	2,664,982		$	2,309,590
Net income for common stock	$	161,516		$	138,658		$	138,230		$	113,535		$	83,011
Basic earnings per common share	$	1.63		$	1.43		$	1.45		$	1.22		$	0.91
Diluted earnings per common share	$	1.62		$	1.42		$	1.44		$	1.21		$	0.91
Return on average common equity	9.7		%	8.9		%	9.2		%	7.8		%	5.9		%
Financial position *
Total assets	$	10,340,044		$	10,149,132		$	9,594,477		$	9,087,409		$	8,925,002
Deposit liabilities	4,372,477			4,229,916			4,070,032			3,975,372			4,058,760
Other bank borrowings	244,514			195,926			233,229			237,319			297,628
Long-term debt, net	1,492,945			1,422,872			1,340,070			1,364,942			1,364,815
Preferred stock of subsidiaries – not subject to mandatory redemption	34,293			34,293			34,293			34,293			34,293
Common stock equity	1,727,070			1,593,865			1,528,706			1,480,394			1,438,405
Common stock
Book value per common share *	$	17.06		$	16.28		$	15.92		$	15.63		$	15.55
Market price per common share
High	28.30			29.24			26.79			24.99			22.73
Low	23.84			23.65			20.59			18.63			12.09
December 31	26.06			25.14			26.48			22.79			20.90
Dividends per common share	1.24			1.24			1.24			1.24			1.24
Dividend payout ratio	76		%	87		%	86		%	102		%	137		%
Market price to book value per common share *	153		%	154		%	166		%	146		%	134		%
Price earnings ratio **	16.0		x	17.6		x	18.3		x	18.7		x	23.0		x
Common shares outstanding (thousands) *	101,260			97,928			96,038			94,691			92,521
Weighted-average	98,968			96,908			95,510			93,421			91,396
Shareholders ***	30,653			31,349			32,004			32,624			33,302
Employees *	3,966			3,870			3,654			3,426			3,453


*	At December 31.


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


***	At December 31. Represents registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) who are not registered shareholders. As of February 7, 2014, HEI had 8,388 registered shareholders (i.e., holders of record of HEI common stock), 26,791 DRIP participants and total shareholders of 30,585.

See “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for discussions of certain contingencies that could adversely affect future results of operations and factors that affected reported results of operations.

For 2013, 2012, 2011, 2010 and 2009, under the two-class method of computing basic earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.39, $0.19, $0.21, $(0.02) and $(0.33) per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For 2013, 2012, 2011, 2010 and 2009, under the two-class method of computing diluted earnings per share, distributed earnings were $1.24 per share each year and undistributed earnings (loss) were $0.38, $0.18, $0.20, $(0.03) and $(0.33) per share, respectively, for both unvested restricted stock awards and unrestricted common stock.

Hawaiian Electric:

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries



Years ended December 31	2013			2012			2011			2010			2009
(in thousands)
Results of operations
Revenues	$	2,980,172		$	3,109,439		$	2,978,690		$	2,382.366		$	2,035,009
Net income for common stock	122,929			99,276			99,986			76,589			79,446

Financial position *
Utility plant	$	5,896,991		$	5,567,346		$	5,242,379		$	5,049,900		$	4,881,767
Accumulated depreciation	(2,111,229		)	(2,040,789		)	(1,966,894		)	(1,941,059		)	(1,848,416		)
Net utility plant	$	3,785,762		$	3,526,557		$	3,275,485		$	3,108,841		$	3,033,351
Total assets	$	5,087,129		$	5,108,793		$	4,674,007		$	4,287,745		$	3,980,457
Current portion of long-term debt	$	11,400		$	—		$	57,500		$	—		$	—
Long-term debt, net	1,206,545			1,147,872			1,000,570			1,057,942			1,057,815
Common stock equity	1,593,564			1,472,136			1,402,841			1,334,155			1,303,165
Cumulative preferred stock-not subject to mandatory redemption	34,293			34,293			34,293			34,293			34,293
Capital structure	$	2,845,802		$	2,654,301		$	2,495,204		$	2,426,390		$	2,395,273
Capital structure ratios (%)
Debt (short-term debt, which is nil, and long-term debt, net, including current portion)	42.8			43.2			42.4			43.6			44.2
Cumulative preferred stock	1.2			1.3			1.4			1.4			1.4
Common stock equity	56.0			55.5			56.2			55.0			54.4


*	At December 31.

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

See "Forward-Looking Statements" above, the “electric utility” sections and all information related to, or including, Hawaiian Electric and its subsidiaries in HEI’s MD&A in the Form 10-K and “Commitments and contingencies” in Note 3 of the Consolidated Financial Statements for discussions of certain contingencies that could adversely affect future results of operations, financial condition and cash flows.



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

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

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

HEI Consolidated

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 2013, net income for HEI common stock was $162 million, up $23 million from $139 million in 2012 primarily due to the Utilities’ writedown in 2012 of $24 million (net of taxes) of project costs in lieu of conducting regulatory audits. ASB had slightly lower net income in 2013 compared to 2012 and the “other” segment had slightly lower losses. Basic earnings per share were $1.63 per share in 2013, up 14% from $1.43 per share in 2012 due to the effects of the impact of the Utilities $24 million (net of taxes) writedown in 2012.

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 2013 of $123 million increased 24% from the prior year due primarily to the 2012 writedown of $24 million (net of taxes) of project costs in lieu of conducting regulatory audits. Key to results for 2014 will be the impacts of actions taken under the Hawaii Clean Energy Initiative (HCEI) and Energy Agreement, including the steps taken toward the integration of new generation from a variety of renewable energy sources into the utility systems, and managing operation and maintenance expenses to the levels included in rates.

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 2013 of $57.5 million decreased $1.1 million compared to prior year net income due primarily to lower net interest and noninterest income and higher noninterest expenses, partly offset by a lower provision for loan losses. In 2013, ASB earnings were also impacted by lower debit card interchange fees as a result of being non-exempt from the Durbin Amendment from July 1, 2013 and the sale of its credit card portfolio. ASB’s future financial results will continue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio.

HEI’s “other” segment had a net loss in 2013 of $18.9 million, comparable to the net loss of $19.3 million in 2012.

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, 2013 was 4.8%. The dividend payout ratios based on net income for common stock for 2013, 2012 and 2011 were 76%, 87% and 86%, 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. These strategies may include the formation of new subsidiaries or the acquisition or disposition of businesses. The Company may from time to time be engaged in preliminary discussions, either internally or with third parties,

regarding potential transactions. Management cannot predict whether any of these strategies or transactions will be carried out or, if so, whether they will be successfully implemented.

Economic conditions.

Note: The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization, U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS® Bureau of Economic Analysis and national and local newspapers).

Hawaii’s tourism industry, a significant driver of Hawaii’s economy, set a new record in 2013 with visitor arrivals growing by 2.6% over 2012 to 8.2 million arrivals. Visitor expenditures also grew 2.0% in 2013 compared to 2012 to over $14.5 billion. The good news was tempered, however, as strong growth in state visitor arrivals and expenditures in the first half of 2013 was partially offset by lower than 2012 arrivals and expenditures in the second half of the year. Hotel occupancies and average daily hotel room rates remained strong. The outlook for the visitor industry remains positive, but is expected to expand at a slower pace in 2014. The HTA expects scheduled nonstop seats to Hawaii for the first quarter of 2014 to increase by 2.4% over the first quarter of 2013, based on the expectation that airlift capacity declines in U.S. markets will be offset by increases in international flights.

For the first time since November 2008, the U.S. unemployment rate fell below 7% in December 2013. Hawaii’s unemployment rate was relatively stable at 4.5% in December 2013, lower than the state’s 5.1% rate in December 2012 and the December 2013 national unemployment rate of 6.7%.

Hawaii real estate activity, as indicated by the home resale market, was strong in 2013 as the median sales price for single family residential homes on Oahu increased 4.8% and the number of closed sales increased 4.6% over 2012. Oahu condominiums also maintained strong momentum as the median sales price rose 4.6% and closed sales increased 11.8% in 2013 over 2012. Strengthening interest in new housing was reflected in increased development activity. The announcements of several new planned condominium developments in Honolulu, at various price points from workforce housing to luxury projects, were met with immediate interest and generated strong pre-sale demand. In November 2013, Castle & Cooke’s Koa Ridge master plan for 3,500 single- and multi-family homes received Honolulu City Council and the Mayor’s approval for a zoning change from agricultural land after more than ten years of public debate.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011 increased regional demand for energy supplies, including petroleum, and the prices of the Utilities’ fuels have accordingly remained at the elevated 2011 level through 2013.

At its January 28-29, 2014 meeting, the Federal Open Market Committee (FOMC) saw quickening economic activity in recent quarters and improvement in labor market conditions as consistent with a strengthening in the broader economy. In light of the cumulative progress toward improved labor market conditions, the FOMC decided to continue to take measured steps to modestly reduce the pace of purchases of Treasury and agency mortgage-backed securities beyond the steps the FOMC had taken after its meeting in December 2013. The FOMC also indicated that if economic data continues to support the outlook of ongoing improvement, the pace of asset purchases would likely be further reduced. The FOMC emphasized that asset purchases are not on a preset course and are still contingent on FOMC evaluation.

On October 1, 2013, the U.S. government began a new fiscal year with no spending legislation enacted and as a result, a partial federal shutdown took effect. On October 16, 2013, the government shutdown ended when Congress passed legislation on a budget through January 15, 2014 and raised the government debt ceiling to provide the U.S. Treasury with borrowing authority through February 7, 2014. A final $1.1 trillion U.S. budget was approved with relative ease in January 2014.

Overall, Hawaii’s economy is expected to see continuing growth in 2014 and 2015. Local economic growth is expected to be supported by continued recovery in the construction industry and steady, but slower growth in the visitor industry. U.S. fiscal problems, continued uncertainty in global economies, heightened tensions in Asia and potential pandemics pose possible risks to local economic growth.

Recent tax developments. The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that impacted the Company through 2012, including the 50% and 100% bonus depreciation provisions for qualified property that resulted in an estimated net increase in federal tax depreciation of $131 million for 2012 over depreciation to which the Company would otherwise be entitled without the bonus provisions. The additional depreciation is attributable to the Utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and provided a one year extension of 50% bonus depreciation, which increased the Company’s federal tax depreciation for 2013 by an estimated

$131 million, primarily attributable to the Utilities. Congress has not extended the bonus depreciation provision and therefore no significant bonus depreciation will be taken on 2014 plant additions.

Also, see Note 12 of the Consolidated Financial Statements.

Health care reform. On June 28, 2012, the US Supreme Court upheld the Patient Protection and Affordable Care Act, the 2010 health care reform law. Currently, Hawaii’s Prepaid Health Care Act generally provides greater benefits to employees and dependents because of cost sharing limitations. The Company will continue to comply with its obligations under these laws and to monitor the interaction of the state and federal laws.

Results of operations.



(dollars in millions, except per share amounts)	2013			% change		2012			% change		2011
Revenues	$	3,238		(4	)	$	3,375		4		$	3,242
Operating income	315			11		284			(2	)	290
Net income for common stock	162			16		139			—		138
Net income (loss) by segment:
Electric utility	$	123		24		$	99		(1	)	$	100
Bank	58			(2	)	59			(2	)	60
Other	(19		)	NM		(19		)	NM		(22		)
Net income for common stock	$	162		16		$	139		—		$	138
Basic earnings per share	$	1.63		14		$	1.43		(1	)	$	1.45
Diluted earnings per share	$	1.62		14		$	1.42		(1	)	$	1.44
Dividends per share	$	1.24		—		$	1.24		—		$	1.24
Weighted-average number of common shares outstanding (millions)	99.0			2		96.9			1		95.5
Dividend payout ratio	76		%			87		%			86		%


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. During 2011, for example, the qualified retirement plan for employees of HEI and Hawaiian Electric was changed for employees hired on or after May 1, 2011. Those employees will receive lower benefit accruals, different early retirement reduction factors and no automatic cost of living increases. The change is expected to decrease ongoing costs through a reduction in service cost. (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 and the discount rate. 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 2013, the Company’s retirement benefit plans’ assets generated a gain of 20%, net of investment management and trustee fees, resulting in net earnings and unrealized gains of $223 million, compared to net earnings and unrealized gains of $134 million for 2012 and net losses and unrealized losses of $12 million for 2011. The market value of the retirement benefit plans’ assets for December 31, 2013 and 2012 were $1.4 billion and $1.1 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 2014. 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 2014. Based on plan assets as of December 31, 2013 and various assumptions in Note 10 of the Consolidated Financial Statements, the Company estimates that the cash contributions to the plans for 2014 will be $59 million ($1 million for HEI and $58 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)	2013			2012		(Estimated) 2014		2013		2012		2011		2013		2012		2011
Consolidated HEI	$	13		$	36	$	20	$	21	$	22	$	22	$	70	$	68	$	66
Consolidated Hawaiian Electric	(1		)	1		19		18		20		21		65		63		61

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, 2013, 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	$(95)/$106	$(87)/$97
Other benefits
Discount rate	'+/- 50	(11)/12	(10)/11
Health care cost trend rate	'+/- 100	5/(5)	5/(5)

The impact on 2014 net income for common stock for changes in actuarial assumptions should be immaterial based on the adoption by the electric utilities of pension and postretirement benefits other than pensions (OPEB) tracking mechanisms approved by the PUC. See Note 10 of the Consolidated Financial Statements for further retirement benefits information.

Other segment.



(dollars in millions)	2013			% change	2012		% change	2011
Revenues ¹	$	—		NM	$ –		NM	$	(1	)
Operating loss	(17		)	NM	(17	)	NM	(17		)
Net loss	(19		)	NM	(19	)	NM	(22		)


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 American Savings Holdings, Inc. (ASHI), both holding companies; HEI Properties, Inc., a company holding passive, venture capital investments (venture capital investments with a carrying value of $0.5 million as of December 31, 2013); The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; and Pacific Energy Conservation Services, Inc., a contract services company which provided windfarm operational and maintenance services to an affiliated electric utility until the windfarm was dismantled in the fourth quarter of 2010 and dissolved in the second quarter of 2011; as well as eliminations of intercompany transactions.

HEI corporate-level operating, general and administrative expenses were $16 million in 2013 compared to $16 million in 2012 and $15 million in 2011. In 2013, HEI had higher administrative and general expenses, including retirement benefits, partly offset by lower executive compensation. In 2012, HEI had higher executive compensation and employee benefits expenses, including retirement benefits.

The “other” segment’s interest expenses were $16 million in 2013, $16 million in 2012 and $22 million in 2011. In 2013, $50 million of long-term debt was refinanced at a lower interest rate. In 2012, HEI had lower average borrowings and interest rates. The “other” segment’s income tax benefits were $14 million in 2013, $15 million in 2012 and $17 million in 2011.

Effects of inflation. U.S. inflation, as measured by the U.S. Consumer Price Index (CPI), averaged 1.5% in 2013, 2.1% in 2012 and 3.2% in 2011. Hawaii inflation, as measured by the Honolulu CPI, was 2.4% in 2012, 3.7% in 2011 and 2.1% in 2010. DBEDT estimates average Honolulu CPI to have been 1.7% in 2013 and forecasts it to be 2.1% for 2014.

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 $10.3 billion as of December 31, 2013 and $10.1 billion as of December 31, 2012.

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



December 31	2013				2012
(dollars in millions)
Short-term borrowings—other than bank	$	105	3	%	$	84	3	%
Long-term debt, net—other than bank	1,493		45		1,423		45
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,727		51		1,594		51
	$	3,359	100	%	$	3,135	100	%

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



	Year ended December 31, 2013
(in millions)	Average balance		End-of-period balance		December 31, 2012
Short-term borrowings ¹
Commercial paper	$	68	$	105	$	84
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility (expiring December 5, 2016)			125		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 7, 2014, HEI’s outstanding commercial paper balance was $96 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 2013 was $105 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, 2013. 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. 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 common stock of Hawaiian Electric.

In November 2011, HEI filed an omnibus registration statement to register an indeterminate amount of debt and equity securities. Under Securities and Exchange Commission (SEC) regulations, this registration statement expires on November 4, 2014.

HEI has a line of credit facility of $125 million. See Note 7 of the Consolidated Financial Statements. The credit agreement, amended in December 2011, contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Issuer Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively) would result in a commitment fee increase of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 2.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts.

In addition to their impact on pricing under HEI’s credit agreement, 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.

On January 21, 2014, Fitch Ratings (Fitch) assigned initial ratings to HEI as noted in the table below. The key ratings drivers cited were (1) ownership of two investment grade subsidiaries, (2) subordination of cash flows and (3) moderate degree of parent level debt leverage.

As a result of updating it ratings methodology, Moody’s placed the ratings of most U.S. regulated utilities and utility holding companies on review for upgrade. HEI was included in the list of companies on review for upgrade. Subsequently, on January 30, 2014, Moody’s confirmed HEI’s ratings as noted in the table below and indicated that despite their view that Hawaiian Electric, like many other regulated utilities in the U.S., received more credit supportive regulatory treatment over the years, HEI's and Hawaiian Electric’s cash flow to debt ratios are too weak to support an upgrade. HEI's ratings reflect the relatively stable earnings and cash flow historically provided by both the vertically integrated utility businesses at Hawaiian Electric and the stable banking operations at ASB. The ratings also recognize the challenges at Hawaiian Electric, which have some of the highest retail electric rates in the country and the heavy pressure from regulators and stakeholders to reduce rates and dependence on fuel oil. Moody’s indicated the rating could be downgraded or placed on negative outlook if Maui Electric’s poor rate case outcome spills over to Hawaiian Electric and Hawaii Electric Light.

On February 10, 2014, S&P maintained its corporate credit ratings for HEI, as noted in the table below. S&P indicated that the "BBB-" issuer credit rating on HEI is derived from S&P's anchor of "bbb", based on a “strong” business risk and “significant” financial risk profile assessments for the company. The negative comparable rating analysis modifier resulted in a -1 notch adjustment to the anchor. S&P indicated that unfavorable comparable ratings analysis reflects the Utilities’ ongoing challenges to earn closer to the allowed returns and the need to continuously effectively manage regulatory risk; past challenges to complete major projects on budget and on schedule; and the potential threat from increasing roof-top solar penetration, relative to peers. The stable outlook reflects S&P’s understanding that “the decoupling mechanisms will remain largely unchanged and the company will successfully manage expenses, HECO will reach a constructive outcome in its next rate case filing, and HEI will maintain a balanced funding approach that continues to support the current credit profile.”

As of February 10, 2014, 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	Stable	Stable	Stable

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 $48 million (approximately 1.8 million shares) in 2013, $47 million (approximately 1.8 million shares) in 2012 and $24 million (approximately 1.0 million shares) in 2011. 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 $327 million in 2013, $235 million in 2012 and $250 million in 2011. Investing activities used net cash of $564 million in 2013, $427 million in 2012 and $327 million in 2011. In 2013, 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 purchases of investment and mortgage-related securities, partly offset by the repayments of investment and mortgage-related securities and the proceeds from sales of investment securities and real estate acquired in settlement of loans of ASB. Financing activities provided net cash of $237 million in 2013, $142 million in 2012 and $16 million in 2011. In 2013, 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 2013, Hawaiian Electric and ASB (via ASHI) paid cash dividends to HEI of $82 million and $40 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 56% at December 31, 2013), 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 2014 through 2016 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 $175 million will be required during 2014 through 2016 to repay maturing HEI medium-term notes, 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. Medium-term notes of $100 million maturing in May 2014 are expected to be replaced with new debt. In addition, Hawaiian Electric special purpose revenue bonds (SPRBs) totaling $11 million will be maturing during 2014 through 2016 and are expected to be repaid with proceeds from issuances of debt and/or equity financing. Additional debt and/or equity financing may be utilized to invest in the Utilities and bank, pay down commercial paper or other short-term borrowings or may be required to fund unanticipated expenditures not included in the 2014 through 2016 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 (potentially at more favorable rates) with additional debt or equity financing (or both).

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 $83 million in 2013 ($81 million by the Utilities, $2 million by HEI and nil by ASB), $78 million in 2012 ($63 million by the Utilities, $2 million by HEI and $13 million by ASB) and $75 million in 2011 ($73 million by the Utilities, $2 million by HEI and nil by ASB) and are expected to total $59 million in 2014 ($58 million by the Utilities, $1 million by HEI and nil by ASB). These

contributions satisfied the minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006, and the requirements of the electric utilities’ pension and OPEB tracking mechanisms. In addition, the Company paid directly $2 million of benefits in 2013, $1 million in 2012 and $2 million in 2011 and expects to pay $2 million of benefits in 2014. 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, 2013
(in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Contractual obligations
Deposit liabilities¹	$	4,190	$	139	$	38	$	5	$	4,372
Other bank borrowings	95		50		100		—		245
Long-term debt	111		75		50		1,257		1,493
Interest on certificates of deposit, other bank borrowings and long-term debt	80		148		135		824		1,187
Operating leases, service bureau contract and maintenance agreements	30		43		22		29		124
Open purchase order obligations ²	62		32		3		—		97
Fuel oil purchase obligations (estimate based on December 31, 2013 fuel oil prices)	941		1,133		—		—		2,074
Power purchase obligations–minimum fixed capacity charges	125		229		184		622		1,160
Liabilities for uncertain tax positions	1		—		—		—		1
Total (estimated)	$	5,635	$	1,849	$	532	$	2,737	$	10,753


¹	Deposits that have no maturity are included in the “Less than 1 year” column, however, they may have a duration longer than one year.


²	Includes contractual obligations and commitments for capital expenditures and expense amounts.



December 31, 2013	Total
(in millions)
Other credit commitments to ASB customers
Loan commitments (primarily expiring in 2014)	$	24
Loans in process	139
Unused lines and letters of credit	1,464
Total	$	1,627

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 and potential refunds of amounts collected from ratepayers (e.g., under the earnings sharing mechanism). As of December 31, 2013, 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 2014.

See Note 3 of the Consolidated Financial Statements for a discussion of fuel and power purchase 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.

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).

Declines in the Hawaii, U.S. and Asian economies in recent years led to declines in KWH sales, 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 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 and mortgage-related 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 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 including, but not limited to, mold and terrorism. 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 investment and mortgage-related securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses. 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 3 and 4 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 for 95% of Hawaii’s residents, operating 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. In 2012 and 2013, the Utilities continued 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 period, including a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below).

The Utilities are committed to achieving or exceeding the State’s 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 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.

Regulatory. In January 2013, the Utilities and Consumer Advocate signed a settlement agreement (2013 Agreement), which the PUC approved with clarifications in March 2013 (2013 D&O). See “Utility projects” in Note 3 of the Consolidated Financial Statements and the discussion under “Most recent rate proceedings” below.

In 2010, the PUC issued an order approving decoupling, which was implemented by the Utilities in 2011 or 2012. The decoupling model implemented delinks revenues from sales and includes annual revenue 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, instead of the 6% that has been previously approved.

The second part of this proceeding will continue this year with panel hearings scheduled for August 2014. See "Decoupling" in Note 3 of the Consolidated Financial Statements.

Actual and PUC-allowed (as of December 31, 2013) returns were as follows:



%	Return on rate base (RORB)*						ROACE**						Rate-making ROACE***
Year ended December 31, 2013	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric		Hawaii Electric Light		Maui Electric
Utility returns	7.24		6.77		7.25		7.98		7.41		8.91		8.91		7.46		9.33
PUC-allowed returns	8.11		8.31		7.34		10.00		10.00		9.00		10.00		10.00		9.00
Difference	(0.87	)	(1.54	)	(0.09	)	(2.02	)	(2.59	)	(0.09	)	(1.09	)	(2.54	)	0.33

* 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 bonuses and 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 the RAMs for Hawaii Electric Light and Maui Electric,

•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 3 of the Notes to Consolidated Financial Statements), and

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

The structural gap in 2014 to 2016 is expected to be 100 to 130 basis points. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the Utilities (primarily 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 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. 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 2013, Maui Electric’s rate-making ROACE was 9.33%, which was above the PUC allowed 9% ROACE and triggered the earnings sharing mechanism. As a result, Maui Electric will credit its customers $0.3 million for their portion of the earnings sharing. Maui Electric’s 2013 ratemaking ROACE of 9.33% included adjustments to Maui Electric’s actual ROACE of 8.91% such as expenses not considered in establishing electric rates (e.g., executive bonuses). For 2013, Hawaiian Electric’s rate-making ROACE was 8.91% and Hawaii Electric Light’s rate-making ROACE was 7.46%, which did not trigger the earnings sharing mechanism. For 2012, Hawaiian Electric’s rate-making ROACE was 10.70%, which was above the PUC-allowed 10% ROACE. As a result, 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 bonuses and advertising). For 2012, Hawaii Electric Light’s rate-making ROACE was 7.79% and Maui Electric’s rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.

Annual decoupling filings. On May 31, 2013, the PUC approved the revised annual decoupling filings for tariffed rates for the Utilities that will be effective from June 1, 2013 through May 31, 2014. The amounts approved as noted below reflect the Utilities’ agreements with the position of the Consumer Advocate. The revised tariffed rates include:



(in millions)	Hawaiian Electric			Hawaii Electric Light		Maui Electric
Annual incremental RAM adjusted revenues
Operations and maintenance	$	3.9		$	0.9	$	1.0
Invested capital	27.5			1.2		2.4
Total annual incremental RAM adjusted revenues	$	31.4		$	2.1	$	3.4
Accrued earnings sharing credits to be refunded	$	(2.6	)	$	—	$	—
Accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected	$	55.4		$	4.9	$	5.8

Results of operations.


•	2013 vs. 2012



2013			2012			Increase (decrease)						(dollar 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)

2012 vs. 2011



2012			2011			Increase (decrease)						(dollar in millions, except per barrel amounts)
$	3,109		$	2,979		$	130					Revenues. Increase largely due to:
									$	82		Higher fuel oil and purchased energy costs partially offset by lower KWH sales adjusted for decoupling mechanisms and revenue taxes thereon
									32			Rate increases granted to Hawaiian Electric for the 2011 test year, partly offset by the 2011 test year refund
									7			Interim rate increases granted to Maui Electric for the 2010 test year
1,297			1,265			32						Fuel oil expense. Increase largely due to higher fuel prices, partly offset by lower KWHs generated
725			690			35						Purchased power expense. Increase largely due to higher purchased energy costs and KWHs purchased
397			380			17						Operation and maintenance expense. Increase largely due to:
									11			Higher customer service expenses
									3			Increase in general liability reserve for an environmental matter
									(3		)	Regulatory decision allowing reversal of previously expensed interisland wind project support costs
									1			Increase largely due to higher overhaul costs at Hawaii Electric Light and Maui Electric
480			431			49						Other expenses. Increase largely due to:
									16			Higher taxes, other than income taxes, primarily resulting from higher revenues
									40			Partial write-off of the CIS project to reflect the settlement agreement with the Consumer Advocate, subject to PUC approval
									(9		)	Partial writedown of the East Oahu Transmission Project Phase 1 costs in December 2011
									2			Increase in depreciation and amortization expense resulting from changes in rates implemented in conjunction with the most recent D&Os
213			215			(2		)				Operating income. Decrease largely due to the partial write-off of the CIS project, partially offset by interim and final rate increases for Hawaiian Electric and Maui Electric.
11			8			3						Allowance for funds used during construction
99			100			(1		)				Net income for common stock. Decrease largely due to:
									22			Interim & final rate increases
									(24		)	Partial write-off of the CIS project costs
									6			Partial writedown of the East Oahu Transmission Project Phase 1 costs in 2011
									(9		)	Higher O&M expense, net of demand-side management
6.9		%	7.3		%	(0.4		)%				Return on average common equity
138.09			123.63			14.46						Average fuel oil cost per barrel ¹
9,206			9,527			(321		)				Kilowatthour sales (millions) ²
4,532			4,954			(422		)				Cooling degree days (Oahu)
2,658			2,518			140						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 for 2012 were lower than 2011 due largely to cooler, less humid weather, continued conservation efforts and increasing levels of customer-sited renewable generation. KWH sales for 2011 were lower than 2010 due largely to cooler, less humid weather and continued conservation efforts by customers.

Most recent rate proceedings. Unless otherwise agreed or ordered, each electric utility shall 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, the details of any granted interim and final PUC D&O increases, and whether an interim or final PUC D&O remains pending.



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
Hawaii Electric Light
2010 (2)
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 (3)
Request	8/16/12	$	19.8	4.2	10.25	8.30	$	455	57.05
Closed	3/27/13
Maui Electric
2012 (4)
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

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) 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.

(3) 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 D&O (described below), the rate case was withdrawn and the docket has been closed.

(4) 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 3 of the Consolidated Financial Statements.

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 of 2014, 2015 and 2016. On March 19, 2013, the PUC issued its 2013 D&O approving the 2013 Agreement, with clarifications. See “Utility projects” in Note 3 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.

Maui Electric 2012 test year rate case. See “Maui Electric 2012 test year rate case” in Note 3 of the Consolidated Financial Statements for information on the PUC’s final D&O.

Integrated Resource Planning. In June 2013, the Utilities filed their 2013 integrated resource planning (IRP) report and five-year action plans detailing plans to meet future electricity needs for the islands of Oahu, Maui, Molokai, Lanai and Hawaii. IRP aims to develop long-range 20-year resource plans for meeting energy needs under various scenarios and then to develop near-term actions for implementation over the next five years. The 2013 IRP process was the first IRP to employ scenario planning, as well as an independent entity that facilitated and provided oversight of the process, since the PUC revised the IRP Framework in March 2012. The IRP process included input from a community advisory group established by the PUC of almost 70 business, community, and government, environmental and other leaders. The Utilities also held two rounds of public meetings on the islands of Oahu, Maui, Molokai, Lanai and Hawaii to seek comments from the general public, in addition to 17 meetings with the advisory group.

The overarching goals of the action plans filed are lowering costs to customers, replacing expensive oil with cleaner sources of energy, modernizing the electric grid, and looking out for the interests of all customers. Significant action plan items include:


•	Lowering costs to customers by accelerating the development of low-cost, fast-track, utility-scale renewable energy projects, including solar and wind facilities.

•

Deactivating (i.e., removing from service with the possibility of reactivating in the future in a major emergency for example) older, less efficient oil-fired power plant units, to help lower costs and increase the use of renewable energy generation. This includes Honolulu Power Plant and two of four generating units at Maui’s Kahului Power Plant, which have shut down operations, as well as two generators at Oahu’s Waiau Power Plant, scheduled to be shutdown by the end of 2016. In addition, all units at Kahului Power Plant would be fully retired by 2019. Hawaii Island’s Shipman Plant is already deactivated and will be retired in 2014.


•	Converting or replacing power plants that are not deactivated to use cost-effective, cleaner fuels, including renewable biomass or biofuel and liquefied natural gas.


•	Supporting the state’s efforts to procure cheaper, cleaner, liquefied natural gas to replace the use of oil in making electricity.


•	Increasing the capability of utility grids to accept additional customer-sited renewable generation, especially roof-top photovoltaic systems, while protecting safety, reliability and fairness of electric service for all customers.


•	Developing “smart” grids for all three companies to improve customer service, integrate more renewable energy and enable customers to better control their electric bills. Major components of the smart grid include installing smart meters for all customers (with opt-out provisions) in the 2017-2018 timeframe, automating the grid and developing utility energy storage systems.

In July 2013, the Independent Entity, the person selected by the PUC to provide unbiased oversight of the IRP, filed a report to the PUC documenting his evaluation of the IRP process. The evaluation recognizes that the IRP report and action plans are compliant with many IRP Framework requirements and provides substantial analysis addressing the Principal Issues, which were issues and questions identified by the PUC to be addressed in the IRP process. However, the Independent Entity did

not certify that the IRP process was conducted consistent with all provisions of the IRP Framework or that it fully addressed the Principal Issues. Under the IRP Framework, the PUC should issue a decision (with approval, partial approval, rejection, modifications and/or other directives) on the action plans within six months after the Utilities’ IRP filing, unless the PUC determines that an evidentiary hearing is warranted. The PUC granted several parties' motions to intervene, and ordered that the parties submit simultaneous statements of position to aid the PUC in determining the completeness and compliance of the IRP report and action plans at this point in the review process, and how to move forward most productively in the proceeding. In September and October 2013, the parties submitted their statements of position.

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 2013, the Utilities achieved an RPS without DSM energy savings of 18%, primarily through a comprehensive portfolio of renewable energy power purchase agreements (PPAs), net energy metering programs and biofuels. The Utilities believe they are on track to meet the 2015 RPS.

Recent developments in the Utilities’ renewable energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 3 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 (see Note 3 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 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. In February 2013, Hawaii Electric Light issued the Final Geothermal RFP. Six bids were received in April 2013 and Hawaii Electric Light is developing further requests for information from the bidders based on its evaluation of the bids.


•	In August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire. After 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 photovoltaic 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.” The invitation for waiver projects 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, in June 2013 and November 2013, Hawaiian Electric

filed waiver requests from the PUC Competitive Bidding Framework for five projects (two of which have since been withdrawn) and six projects, respectively, which met these goals.


•	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.


•	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. If approved, the project is expected to be completed in 2015.


•	In October 2013, the Utilities signed a 3-year biodiesel supply contract, subject to PUC approval, with Pacific Biodiesel Technologies, LLC to spot purchase as available biodiesel at cost parity to petroleum diesel.


•	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 photovoltaic 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 Power Purchase Agreement 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.


•	The Utilities began accepting energy from feed-in tariff projects in 2011. As of December 31, 2013, there were 10 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, 2013, there were approximately 167 MW, 33 MW and 35 MW of installed net energy metering capacity from renewable energy technologies (mainly photovoltaic) at Hawaiian Electric, Hawaii Electric Light and Maui Electric, respectively. The amount of net energy metering capacity installed in 2013 was about 46% higher than the amount installed in 2012.

Other regulatory matters. In addition to the items below, also see “Hawaii Clean Energy Initiative” and “Utility projects” in Note 3 of the Consolidated Financial Statements.

Adequacy of supply.

Hawaiian Electric. In March 2013, Hawaiian Electric filed its 2013 Adequacy of Supply (AOS) letter, which indicated that based on its August 2012 sales and peak forecast, Hawaiian Electric’s generation capacity is sufficient to meet reasonably expected demands for service and provide reasonable reserves for emergencies through 2018. In January 2014 Hawaiian Electric deactivated two fossil fuel generating units from active service at its Honolulu Power Plant, 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, and also the U.S. Department of the Army for a utility owned and operated renewable, dispatchable, generation security project on federal lands. Hawaiian Electric is continuing negotiations with two firm capacity IPPs on Oahu with Power Purchase Agreements scheduled to expire in 2016 and 2022.

Hawaii Electric Light. In January 2014, Hawaii Electric Light filed its 2014 AOS letter, which indicated that Hawaii Electric Light’s generation capacity through 2016 is sufficiently large to meet all reasonably expected demands for service and provide for reasonable reserves for emergencies. In February 2013, Hawaii Electric Light filed with the PUC its Final RFP for Renewable Geothermal Dispatchable Energy and Firm Capacity Resources seeking up to 50 MW of firm, dispatchable geothermal capacity. Hawaii Electric Light is continuing the review process to meet the goals of the Geothermal RFP. In December 2013, the PUC approved Hawaii Electric Light's PPA with Hu Honua Bioenergy, LLC to provide firm renewable generating capacity. Should these additional firm renewable facilities come on line as anticipated, Hawaii Electric Light will not have a need for additional firm capacity in the foreseeable future. Included in the PUC’s D&O was a requirement for Hawaii Electric Light to file a Power Supply Improvement Plan (PSIP) within 120 days. The PSIP shall address, at a minimum, the following issues: (1) Fossil Generation Retirement Plan, which shall include an analysis of which existing fossil fuel plants can be retired, when it is feasible to retire each such plant, the effect on system operations of retiring each such plant, and the anticipated ratepayer savings that would result; (2) a Generation Flexibility Plan designed to enable Hawaii Electric Light to accommodate greater quantities of low cost energy resources; (3) a Must-Run Generation Reduction Plan to reduce or eliminate the must-run designation and operation of generating units on Hawaii Electric Light’s power supply system and enable Hawaii Electric light to accept additional lower-cost energy resources; and (4) a Generation Commitment and Economic Dispatch

Review to ensure that existing generation resource allocation policies and practices yield the most fuel-efficient and cost-effective outcome given Hawaii Electric Light’s rapidly changing portfolio of power supply resources.

Maui Electric. In January 2013, Maui Electric filed its 2013 AOS letter, which indicated that Maui Electric’s generation capacity through 2015 is sufficient to meet the forecasted demands on the islands of Maui, Lanai, and Molokai. Maui Electric expects to have adequate firm capacity on the island of Maui for the period through 2018 and anticipates needing additional firm capacity in the 2019 timeframe. In February 2014, Maui Electric deactivated two fossil fuel generating units at its Kahului Power Plant. Maui Electric anticipates the retirement of all generating units at the Kahului Power Plant in the 2019 timeframe because of their age. Maui Electric will seek to acquire additional firm generating capacity through a competitive bidding process, and make transmission system improvements needed to ensure reliability and voltage support, in this timeframe.

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 3 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 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 3 of the Consolidated Financial Statements.

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

Liquidity and capital resources. Management believes that Hawaiian Electric’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and 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	2013				2012
(dollars in millions)
Short-term borrowings	$	—	–%		$	—	–%
Long-term debt, net	1,218		43		1,148		43
Preferred stock	34		1		34		1
Common stock equity	1,594		56		1,472		56
	$	2,846	100	%	$	2,654	100	%

Information about 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, 2013
(in millions)	Average balance		End-of-period balance		December 31, 2012
Short-term borrowings¹
Commercial paper	$	32	$	—	$	—
Line of credit draws			—		—
Borrowings from HEI			—		—
Undrawn capacity under line of credit facility (expiring December 5, 2016)			175		175


¹	The maximum amount of external short-term borrowings in 2013 was $73 million. At December 31, 2013, Hawaiian Electric had $1 million of short-term borrowings from Hawaii Electric Light and Maui Electric had $7 million of short-term borrowings from

Hawaiian Electric, which borrowings are eliminated in consolidation. At February 7, 2014, Hawaiian Electric had $24 million of outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $8 million from Hawaii Electric Light and a loan of $14 million to Maui Electric.

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 SPRBs issued by the 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 of $175 million. See Note 7 of the Consolidated Financial Statements. The credit agreement, amended in December 2011, contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of Hawaiian Electric’s long-term rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 2.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts.

In addition to their impact on pricing under Hawaiian Electric’s credit agreement, 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.

On January 21, 2014, Fitch assigned initial ratings to Hawaiian Electric as noted in the table below. The key ratings drivers cited were (1) constructive regulatory environment, (2) solid credit profile, (3) elevated capital investment cycle, (4) atypical power/retail electricity market structure and (5) emerging competitive landscape.

As a result of updating it ratings methodology, Moody’s placed the ratings of most U.S. regulated utilities and utility holding companies on review for upgrade. Hawaiian Electric was included in the list of companies on review for upgrade. Subsequently, on January 30, 2014, Moody’s confirmed Hawaiian Electric’s ratings as noted in the table below and indicated that despite their view that Hawaiian Electric, like many other regulated utilities in the U.S., received more credit supportive regulatory treatment over the years, Hawaiian Electric’s cash flow to debt ratios are too weak to support an upgrade. The ratings also recognize the challenges of having some of the highest retail electric rates in the country and the heavy pressure from regulators and stakeholders to reduce rates and dependence on fuel oil. Moody’s indicated the rating could be downgraded or placed on negative outlook if Maui Electric’s poor rate case outcome spills over to Hawaiian Electric and Hawaii Electric Light.

On February 10, 2014, S&P maintained its corporate credit ratings for Hawaiian Electric, as noted in the table below. S&P indicated that the "BBB-" issuer credit rating on Hawaiian Electric is derived from S&P's anchor of "bbb", based on a “strong” business risk and “significant” financial risk profile assessments for the company. The negative comparable rating analysis modifier resulted in a -1 notch adjustment to the anchor. S&P indicated that unfavorable comparable ratings analysis reflects the Utilities' ongoing challenges to earn closer to the allowed returns and the need to continuously effectively manage regulatory risk; past challenges to complete major projects on budget and on schedule; and the potential threat from increasing roof-top solar penetration, relative to peers. The stable outlook reflects S&P’s understanding that “the decoupling mechanisms will remain largely unchanged and the company will successfully manage expenses, HECO will reach a constructive outcome in its next rate case filing, and HEI will maintain a balanced funding approach that continues to support the current credit profile.”

As of February 10, 2014, 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	Stable

* 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.

Revenue bonds are issued by the DBF to finance capital improvement projects of the Utilities, but the source of their repayment is the unsecured obligations of the Utilities 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 Ambac Assurance Corporation or Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012. On August 19, 2013 the plan of rehabilitation became effective and the rehabilitation proceeding terminated. The S&P and Moody’s ratings of these insurers, 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.

On November 15, 2010, the PUC approved the request of Hawaiian Electric, Hawaii Electric Light and Maui Electric for the sale of each utility’s common stock over a five-year period from 2010 through 2014 (Hawaiian Electric’s sale to HEI of up to $210 million and Hawaii Electric Light and Maui Electric’s sales to Hawaiian Electric of up to $43 million and $15 million, respectively), and the purchase of Hawaii Electric Light and Maui Electric common stock by Hawaiian Electric. In December 2010, Hawaii Electric Light and Maui Electric sold $23 million and $3 million, respectively, of their common stock to Hawaiian Electric, and Hawaiian Electric sold $4 million of its common stock to HEI. In December 2011 and December 2012, Hawaiian Electric sold $40 million and $44 million, respectively, of its common stock to HEI. In December 2013, Maui Electric sold $12.5 million of its common stock to Hawaiian Electric and Hawaiian Electric sold $78.5 million of its common stock to HEI.

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 unsecured senior notes with an aggregate principal amount of $236 million. See Note 8 of the Consolidated Financial Statements for a discussion of the use of these proceeds. PUC approval to issue an additional $80 million of long-term debt (Hawaiian Electric $50 million, Hawaii Electric Light $25 million and Maui Electric $5 million) and $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 2013 and 2012, net cash provided by operating activities increased by $115 million and $16 million, respectively, compared to the prior year. 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, and a $27 million decrease in fuel oil stock due to lower payments to fuel suppliers. In 2012, noncash depreciation and amortization amounted to $151 million due to an increase in plant and equipment and deferred income taxes increased $87 million. Further, net cash provided by operating activities included a $10 million decrease in fuel oil stock due to lower payments to fuel suppliers and lower fuel stock held, offset by a net increase of $43 million in accounts receivable and accrued unbilled revenues due to less cash receipts from customers and large customers' balances still outstanding at year end.

In 2013 and 2012, net cash used in investing activities increased by $46 million and $62 million, respectively, compared to the prior year. The increases resulted primarily from increased capital expenditures due to more capital projects.

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. In 2013 and 2012, cash flows from financing activities increased by $9 million and $88 million, respectively, compared to the prior year. 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. In 2012, cash provided by financing activities consisted of net proceeds received from the issuance of $457 million of taxable unsecured senior notes and $44 million of common stock, partially offset by the repayment of $369 million of long term debt and the payment of $75 million of common and preferred stock dividends. In 2011, no long-term debt was issued or redeemed.

For the three-year period 2014 through 2016, the Utilities forecast $1.1 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 2014 through 2016 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 $360 million needed for the net capital expenditures in 2014. For 2014, net capital expenditures include approximately $220 million for transmission and distribution projects, approximately $80 million for generation projects and approximately $60 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, commitments under the Energy Agreement, 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 Note 1 and Note 10 of the Consolidated Financial Statements and “Retirement benefits” above. The electric utilities were required to make contributions of $61 million for 2013, $53 million for 2012 and $71 million for 2011 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 2013, 2012 and 2011. Contributions by the electric utilities to the retirement benefit plans for 2013, 2012 and 2011 totaled $81 million, $63 million and $73 million, respectively, and are expected to total $58 million in 2014. In addition, the electric utilities paid directly $1 million of benefits in 2013, $1 million of benefits in 2012 and $1 million of benefits in 2011 and expect to pay $1 million of benefits in 2014. 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, 2013	Payments due by period
(in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total

Long-term debt	$	11	$	—	50		$	1,157	$	1,218
Interest on long-term debt	61		121		121		809		1,112
Operating leases	9		14		8		18		49
Open purchase order obligations ¹	62		32		3		—		97
Fuel oil purchase obligations (estimate based on December 31, 2013 fuel oil prices)	941		1,133		—		—		2,074
Purchase power obligations-minimum fixed capacity charges	125		229		184		622		1,160
Liabilities for uncertain tax positions	1		—		—		—		1
Total (estimated)	$	1,210	$	1,529	$	366	$	2,606	$	5,711

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, 2013, 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 2014 are discussed in the section “Retirement benefits” in Hawaiian Electric’s MD&A and Note 10 of the Consolidated Financial Statements.

See Note 3 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.

HCEI Energy Agreement. Hawaiian Electric, for itself and its subsidiaries, entered into the Energy Agreement on October 20, 2008. See “Hawaii Clean Energy Initiative” in Note 3 of the Consolidated Financial Statements.

The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, 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 independent power producers (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 under the Energy Agreement 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 DG interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outcome of the implementation of these or other HCEI programs on 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 3 of the Consolidated Financial Statements. The Company estimates that 66% of the net energy generated and purchased by the Utilities in 2014 will be generated from the burning of fossil fuel oil. Purchased KWHs provided approximately 40% of the total net energy generated and purchased in 2013, 2012 and 2011.

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

Other operation and maintenance expenses. O&M expenses increased by 1% in 2013 and 4% in 2012 and decreased by 1% in 2011 when compared to the prior year. The change in O&M expenses (excluding expenses covered by surcharges or by third parties) was 1%, 4% and de minimis for 2013, 2012 and 2011, respectively, when compared to the prior year. O&M expenses (excluding expenses covered by surcharges or by third parties) for 2014 are projected to be relatively flat when compared to 2013 as the electric utilities expect to manage expenses to near-2013 levels.

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 3 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 and Title V Tailoring 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, soon-to-be issued rules governing cooling water intake may significantly impact Hawaiian Electric’s steam generating facilities on Oahu.

Additional environmental compliance costs are expected to be incurred as a result of the initiatives called for in the Energy Agreement, including permitting and siting costs for new facilities and testing and permitting costs related to changing to the use of biofuels. 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 3 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 3 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, 2013, the consolidated regulatory liabilities and regulatory assets of the Utilities amounted to $349 million and $576 million, respectively, compared to $324 million and $865 million as of December 31, 2012, respectively. Regulatory liabilities and regulatory assets are itemized in Note 3 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, 2013 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, 2013, revenues applicable to energy consumed, but not yet billed to customers, amounted to $145 million and the RBA revenues recognized in 2013 amounted to $67 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 5 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 2013 with assets of $5.2 billion and net income of $58 million, compared to assets of $5.0 billion as of December 31, 2012 and net income of $59 million in 2012.

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 2013 as a result of stabilized or increasing property values, more financial flexibility of borrowers, and overall general economic improvement in the state of Hawaii. The slowdown in the economy, both nationally and locally, had resulted in ASB experiencing historically higher levels of loan delinquencies and losses in 2010 and 2011, which were concentrated in the residential land portfolio and on the neighbor islands. The residential land portfolio has declined, which enabled ASB to release some loan loss reserves on that portfolio. ASB’s provision for loan losses decreased in 2013 compared to 2012 due to continued improvement in credit quality, recoveries from previously charged off loans and the release of reserves related to the sale of the credit card portfolio.

Results of operations.


•	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 home equity lines of credit (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		)%


•	2012 vs. 2011



(in millions)	2012			2011			Increase (decrease)			Primary reason(s)
Interest income	$	190		$	199		$	(9	)	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 2012 was $116 million higher than 2011 as the average commercial markets, home equity lines of credit and commercial real estate loan balances increased by $77 million, $112 million and $51 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. Despite a $460 million increase in residential loan production, the average residential loan portfolio decreased by $122 million due to higher repayments and loan sales in connection with ASB’s long-term strategy to manage interest rate risk. The loan portfolio yield was impacted by the low 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 $14 million as ASB experienced higher prepayments on the portfolio, which were used to fund higher loan originations.
Noninterest income	76			65			11			Higher gain on sale of loans as more residential loans were sold in order to manage interest rate risk and increase in debit card fees due to an increase in transaction volume. The higher gain on sale revenue helped fund spending on ASB’s strategic priorities.
Revenues	266			264			2
Interest expense	11			14			(3		)	Lower funding costs as a result of the low interest rate environment. Average deposit balances for 2012 increased by $89 million compared to 2011 due to an increase in core deposits of $170 million, partly offset by a decrease in term certificates of $81 million. The other borrowings average balance decreased by $24 million due to the payoff of a maturing FHLB advance in 2011 and lower retail repurchase agreements.
Provision for loan losses	13			15			(2		)	The provision for loan losses benefited from lower net charge-offs and improved credit quality associated with the gradual improvement in Hawaii’s economy, partly offset by loan loss reserves established for the growth in the loan portfolio.
Noninterest expense	153			143			10			Higher transaction volumes and spending on ASB’s strategic projects and priorities, as well as increasing employee benefit expenses.
Expenses	177			172			5
Operating income	89			92			(3		)	Lower net interest income and higher noninterest expenses, partially offset by higher noninterest income.
Net income	59			60			(1		)	Lower operating income.
Return on average common equity¹	11.7		%	12.0		%	(0.3		)%


¹	Calculated using the average daily balances.

See Note 4 of the Consolidated Financial Statements for a discussion of guarantees and further information about ASB.

Average balance sheet and net interest margin. The following tables set forth average balances, together with interest and dividend income earned and accrued, and resulting yields and costs for 2013, 2012 and 2011.



	2013						2012							2011
(dollars in thousands)	Average balance			Interest		Yield/ rate (%)	Average balance			Interest		Yield/ rate (%)		Average balance			Interest		Yield/ rate (%)
Assets:
Other investments ¹	$	170,695		$	239	0.14	$	203,751		$	269	$	0.13	$	233,909		$	342	0.15
Securities purchased under resale agreements	11,370			43		0.38	—			—		—		—			—		—
Available-for-sale investment and mortgage-related securities	588,597			13,686		2.33	623,438			14,368		2.30		637,123			14,763		2.32
Loans
Residential 1-4 family	1,970,918			93,293		4.73	1,894,603			99,056		5.23		2,016,224			109,908		5.45
Commercial real estate	441,734			19,547		4.42	402,410			18,387		4.57		351,832			17,911		5.09
Home equity line of credit	680,445			20,442		3.00	585,797			16,106		2.75		474,029			13,935		2.94
Residential land	20,985			1,308		6.23	34,744			2,097		6.04		53,904			2,979		5.53
Commercial loans	726,597			29,188		4.02	714,679			30,925		4.33		637,182			31,432		4.93
Consumer loans	114,871			9,191		8.00	101,933			9,486		9.31		85,356			8,320		9.75
Total loans ^2,3	3,955,550			172,969		4.37	3,734,166			176,057		4.71		3,618,527			184,485		5.10
Total interest-earning assets ⁴	4,726,212			186,937		3.96	4,561,355			190,694		4.18		4,489,559			199,590		4.45
Allowance for loan losses	(42,114		)				(39,323		)					(39,263		)
Non-interest-earning assets	424,376						431,680							423,183
Total Assets	$	5,108,474					$	4,953,712						$	4,873,479
Liabilities and Shareholder’s Equity:
Savings	$	1,805,363		1,052		0.06	$	1,727,754		1,128		$	0.07	$	1,672,033		1,756		0.11
Interest-bearing checking	665,941			106		0.02	612,629			111		0.02		593,891			184		0.03
Money market	182,343			232		0.13	202,539			319		0.16		250,682			650		0.26
Time certificates	454,021			3,702		0.82	517,752			4,865		0.94		598,360			6,393		1.07
Total interest-bearing deposits	3,107,668			5,092		0.16	3,060,674			6,423		0.21		3,114,966			8,983		0.29
Advances from Federal Home Loan Bank	64,630			2,432		3.76	50,014			2,176		4.35		64,466			2,553		3.96
Securities sold under agreements to repurchase	146,758			2,553		1.74	172,683			2,693		1.56		182,655			2,933		1.61
Total interest-bearing liabilities	3,319,056			10,077		0.30	3,283,371			11,292		0.34		3,362,087			14,469		0.43
Non-interest bearing liabilities:
Deposits	1,179,559						1,060,121							916,957
Other	104,276						108,161							95,363
Shareholder’s equity	505,583						502,059							499,072
Total Liabilities and Shareholder’s Equity	$	5,108,474					$	4,953,712						$	4,873,479
Net interest income				$	176,860					$	179,402						$	185,121
Net interest margin (%) ⁵						3.74						3.93							4.12


¹	Includes federal funds sold, interest bearing deposits and stock in the Federal Home Loan Bank of Seattle ($95 million, $97 million and $98 million as of December 31, 2013, 2012 and 2011 respectively).


²	Includes loans held for sale.


³	Includes loan fees of $5.2 million, $4.9 million and $3.9 million for 2013, 2012 and 2011, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.


⁴	Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.9 million, $0.8 million and $0.5 million for 2013, 2012 and 2011, respectively.


⁵	Defined as net interest income as a percentage of average 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 4 of the Consolidated Financial Statements for the composition of ASB’s loans receivable.

The increase in the total loan portfolio from $3.7 billion at the end of 2012 to $4.1 billion at the end of 2013 was primarily due to growth in the residential 1-4, commercial real estate, home equity line of credit and commercial loan portfolios, which was consistent with ASB’s portfolio mix targets and loan growth strategy.

Home equity — key credit statistics.



December 31	2013			2012
Outstanding balance (in thousands)	$	739,331		$	630,175
Percent of portfolio in first lien position	38.2		%	29.9		%
Net charge-off ratio	0.06		%	0.10		%
Delinquency ratio	0.28		%	0.40		%



							End of draw period – interest only									Current
December 31, 2013	Total			Interest only			2013-2014			2015-2017			Thereafter			amortizing
Outstanding balance (in thousands)	$	739,331		$	544,072		$	136		$	11,459		$	532,477		$	195,259
% of total	100		%	74		%	—		%	2		%	72		%	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 91% 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, 2013, approximately 18% 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 9% 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 4 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 4 of the Consolidated Financial Statements for the tables which sets forth the allocation of ASB’s allowance for loan losses. For 2013, the allowance for loan losses decreased by $1.9 million, due to improved overall credit quality and higher recoveries in the residential 1-4 family and residential land loan portfolios.

Investment and mortgage-related securities. ASB’s investment portfolio was comprised as follows:



December 31	2013				2012
(dollars in thousands)	Balance		% of total		Balance		% of total
Federal agency obligations	$	80,973	15	%	$	171,491	26	%
Mortgage-related securities — FNMA, FHLMC and GNMA	369,444		70		417,383		62
Municipal bonds	78,590		15		82,484		12
	$	529,007	100	%	$	671,358	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 decrease in federal agency obligations was

primarily due to the sale of $70 million of agency obligations in the second quarter of 2013. The decrease in mortgage-related securities was due to paydowns in the portfolio.

The unrealized losses on ASB’s investment in federal agency mortgage-backed securities were primarily caused by higher interest rates. The higher interest rate environment coupled with tighter spreads on all mortgage collateralized securities caused the market value of the securities held to decrease below the carrying book value. All contractual cash flows of those investments are guaranteed by an agency of the U.S. government. See “Investment and mortgage-related securities” in Note 1 for a discussion of securities impairment assessment.

As of December 31, 2013, 2012 and 2011, 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, 2013, ASB’s costing liabilities consisted of 95% deposits and 5% other borrowings. As of December 31, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. See Note 4 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, 2013 and 2012, ASB had an unrealized loss, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $4 million compared to an unrealized gain, net of taxes, of $11 million as of December 31, 2012. 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 4 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, ASHI 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, ASHI 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 ASHI, as thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, OCC and the Bureau. In addition, HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.

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

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

On May 22, 2012, the Bureau issued the Final Remittance Rule (an amendment to Regulation E). It became effective on October 28, 2013. For consumer international wires, the rule now provides flexibility regarding the disclosure of foreign taxes,

as well as fees imposed by a designated recipient’s institution for receiving a remittance transfer in an account. Second, the rule limits a remittance transfer provider’s obligation to disclose foreign taxes to those imposed by a country’s central government. And third, the rule revises the error resolution provisions that apply when a remittance transfer is not delivered to a designated recipient because the sender provided incorrect or insufficient information, and, in particular, when a sender provides an incorrect account number and that incorrect account number results in the funds being deposited in the wrong account. This rule has not had a significant impact on ASB's results of operations.

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.

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. For the second half of 2013, ASB earned an average of 23 cents per electronic debit transaction, compared to an average of 49 cents per electronic debit transaction in the first half. ASB estimates debit card interchange fees to be lower, as a result of the application of this Amendment, by approximately $6 million after tax in 2014.

Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective.

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. The FRB anticipates that it will release a proposal on intermediate holding companies in the near term 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.

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 be effective for HEI or ASHI on January 1, 2015 as well. If the fully phased-in capital requirements were currently applicable to HEI and ASB, management believes HEI and ASB would satisfy the capital requirements, including the fully phased-in capital conservation buffer.

FHLB of Seattle stock. As of December 31, 2013, ASB’s investment in stock of the FHLB of Seattle of $92.5 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 2013, the FHLB of Seattle paid ASB cash dividends of $47,000. FHLB of Seattle did not pay any cash dividends in 2011 or 2012.

In September 2012, the Federal Housing Finance Agency (Finance Agency) classified the FHLB of Seattle as “adequately capitalized” and after receiving approval from the Finance Agency, began repurchasing excess stock. The FHLB of Seattle repurchased a total of $3.5 million and $1.7 million of excess stock from ASB in 2013 and 2012, respectively.

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

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

Liquidity and capital resources.



December 31	2013		% change		2012		% change
(dollars in millions)
Total assets	$	5,244	4		$	5,042	3
Available-for-sale investment and mortgage-related securities	529		(21	)	671		8
Loans receivable held for investment, net	4,110		10		3,737		3
Deposit liabilities	4,372		3		4,230		4
Other bank borrowings	245		25		196		(16	)

As of December 31, 2013, ASB was one of Hawaii’s largest financial institutions based on assets of $5.2 billion and deposits of $4.4 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, 2013 were $143 million higher than December 31, 2012. ASB’s principal sources of borrowings are advances from the FHLB and securities sold under agreements to repurchase from broker/dealers. As of December 31, 2013, FHLB borrowings totaled $100 million, representing 1.9% 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, 2013, ASB’s unused FHLB borrowing capacity was approximately $1.1 billion. As of December 31, 2013, securities sold under agreements to repurchase totaled $145 million, representing 2.8% of assets. ASB utilizes deposits, advances from the FHLB and securities sold under agreements to repurchase to fund maturing and withdrawable deposits, repay maturing borrowings, fund existing and future loans and purchase investment and mortgage-related securities. As of December 31, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion, including commitments to lend $0.3 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, 2013 and 2012, ASB had $48.5 million and $64.9 million of loans on nonaccrual status, respectively, or 1.2% and 1.7% of net loans outstanding, respectively. As of December 31, 2013 and 2012, ASB had $1.2 million and $6.1 million, respectively, of real estate acquired in settlement of loans.

In 2013, operating activities provided cash of $74 million. Net cash of $253 million was used by investing activities primarily due to purchases of investment and mortgage-related securities, a net increase in loans held for investment and capital expenditures, partly offset by repayments of investment and mortgage-related securities and proceeds from the sales of investment securities and real estate acquired in settlement of loans. Financing activities provided net cash of $151 million due to a net increase in deposits and a net increase in other borrowings, partly offset by the payment of common stock dividends.

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, 2013, 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 4 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 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, 2013, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.5 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, 2013, 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, 2013 with a tangible capital ratio of 9.1% (1.5%), a core capital ratio of 9.1% (4.0%) and a total risk-based capital ratio of 12.1% (8.0%).


•	ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 2013 with a leverage ratio of 9.1% (5.0%), a Tier-1 risk-based capital ratio of 11.2% (6.0%) and a total risk-based capital ratio of 12.1% (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 ASHI) 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, 2013, 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, ASHI 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, 2013, 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, ASHI 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.

Investment and mortgage-related securities. ASB owns federal agency obligations and mortgage-related securities issued by the FNMA, GNMA and FHLMC and municipal bonds, all of which are classified as available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported in AOCI.

ASB views the determination of whether an investment security is temporarily or other-than-temporarily impaired as a critical accounting policy since the estimate is susceptible to significant change from period to period because it requires management to make significant judgments, assumptions and estimates in the preparation of its consolidated financial statements.

See “Investment and mortgage-related securities” in Note 1 of the Consolidated Financial Statements for a discussion of securities impairment assessment and other-than-temporary impaired securities.

Prices for investments and mortgage-related securities are provided by an independent third party pricing service and are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The price of these securities is generally based on observable inputs, which include market liquidity, credit considerations of the underlying collateral, the levels of interest rates, expectations of prepayments and defaults, limited investor base, market sector concerns and overall market psychology. To validate the accuracy and completeness of security pricing, a separate third party pricing service is used on a quarterly basis to compare prices that were received from the initial third party pricing service. If the pricing differential between the two pricing sources exceeds an established threshold, the security price will be re-evaluated by sending a re-pricing request to both independent third party pricing services, to another third party vendor or to an independent broker to determine the most accurate price based on all observable inputs found in the market place. The third party price selected will be based on the value that best reflects the data and observable characteristics of the security. As of December 31, 2013, ASB had investment and mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $0.5 billion.

Allowance for loan losses. See Note 1 of the Consolidated Financial Statements and the discussion above under “Earning assets, costing liabilities and other factors.” As of December 31, 2013, ASB’s allowance for loan losses was $40.1 million and ASB had $48.5 million of loans on nonaccrual status, compared to $42.0 million and $64.9 million at December 31, 2012, respectively. In 2013, ASB recorded a provision for loan losses of $1.5 million, compared to a provision of $12.9 million in 2012.

The determination of the allowance for loan losses is sensitive to the credit risk ratings assigned to ASB’s loan portfolio and loss ratios inherent in the ASB loan portfolio at any given point in time. A sensitivity analysis provides insight regarding the impact that adverse changes in credit risk ratings may have on ASB’s allowance for loan losses. At December 31, 2013, in the event that 1% of the homogenous loans move down one delinquency classification (e.g., 1% of the loans in the 0-29 days delinquent category move to the 30-59 days delinquent category, 1% of the loans in the 30-59 days delinquent category move to the 60-89 days delinquent category and 1% of the loans in the 60-89 days delinquent category move to the 90+ days delinquent category) and 1% of non-homogenous loans were downgraded one credit risk rating category for each category (e.g., 1% of the loans in the “pass” category moved to the “special mention” category, 1% of the loans in the “special mention” category moved to the “substandard” category, 1% of the loans in the “substandard” category moved to the “doubtful” category and 1% of the loans in the “doubtful” category moved to the “loss” category), the allowance for loan losses would have

increased by approximately $0.4 million. The sensitivity analyses do not imply any expectation of future deterioration in ASB loans’ risk ratings and they do not necessarily reflect the nature and extent of future changes in the allowance for loan losses due to the numerous quantitative and qualitative factors considered in determining ASB’s allowance for loan losses. The example above is only one of a number of possible scenarios.

Although management believes ASB’s allowance for loan losses is adequate, the actual loan losses, provision for loan losses and allowance for loan losses may be materially different if conditions change (e.g., if there is a significant change in the Hawaii economy or real estate market), and material increases in those amounts could have a material adverse effect on the Company’s results of operations, financial condition and liquidity.



ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

The Company manages various market risks in the ordinary course of business, including credit risk and liquidity risk. The Company believes the electric utility and the “other” segment’s exposures to these two risks are not material as of December 31, 2013.

Credit risk for ASB is the risk that borrowers or issuers of securities will not be able to repay their obligations to the bank. Credit risk associated with ASB’s lending portfolios is controlled through its underwriting standards, loan rating of commercial and commercial real estate loans, on-going monitoring by loan officers, credit review and quality control functions in these lending areas and adequate allowance for loan losses. Credit risk associated with the securities portfolio is mitigated through investment portfolio limits, experienced staff working with analytical tools, monthly fair value analysis and on-going monitoring and reporting such as investment watch reports and loss sensitivity analysis. See “Allowance for loan losses” above and in Note 4 of the Consolidated Financial Statements.

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

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

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

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

Bank interest rate risk

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

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

See Note 4 of the Consolidated Financial Statements for a discussion of the use of rate lock commitments on loans held for sale and forward sale contracts to manage some interest rate risk associated with ASB’s residential loan sale program.

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

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

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

ASB’s interest-rate risk sensitivity measures as of December 31, 2013 and 2012 constitute “forward-looking statements” and were as follows:



	Change in NII (gradual change in interest rates)				Change in EVE (instantaneous change in interest rates)
Change in interest rates (basis points)	December 31, 2013		December 31, 2012		December 31, 2013		December 31, 2012
+300	1.3	%	1.6	%	(10.7	)%	(9.4	)%
+200	0.3		0.5		(6.9	)	(4.9	)
+100	—		0.1		(3.3	)	(1.9	)
-100	(0.5	)	(0.2	)	0.6		(1.7	)

Management believes that ASB’s interest rate risk position as of December 31, 2013 represents a reasonable level of risk. The NII profile under the rising interest rate scenarios was less asset sensitive for all rate increases as of December 31, 2013 compared to December 31, 2012 due to changes in the mix of assets and steepening of the yield curve which resulted in less cash flows maturing or repricing within the 12 month horizon.

ASB’s base EVE increased to $906 million as of December 31, 2013 compared to $767 million as of December 31, 2012 due to growth in capital, steepening of the yield curve and changes in assumptions about the behavior of core deposits.

The change in EVE was more sensitive in the rising scenarios as of December 31, 2013 compared to December 31, 2012 due to steepening of the yield curve which extended the duration of fixed-rate mortgage-related assets, the shift in the investment portfolio towards a longer duration mix, and changes in the mix of retail loans and core deposits.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and

other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pretax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

Other than bank interest rate risk

The Company’s general policy is to manage “other than bank” interest rate risk through use of a combination of short-term debt, long-term debt (currently fixed-rate debt) and preferred securities. As of December 31, 2013, management believes the Company is exposed to “other than bank” interest rate risk because of its periodic borrowing requirements, the impact of interest rates on the discount rate and the market value of plan assets used to determine retirement benefits expenses and obligations (see “Retirement benefits” in HEI’s MD&A and Note 10 of the Consolidated Financial Statements) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates”). Other than these exposures, management believes its exposure to “other than bank” interest rate risk is not material. The Company’s longer-term debt, in the form of borrowings of proceeds of revenue bonds, registered Medium-Term Notes and privately-placed Senior Notes, is at fixed rates (see Note 16 of the Consolidated Financial Statements for the fair value of long-term debt, net-other than bank).



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

HEI and Hawaiian Electric:



Index to Consolidated Financial Statements	Page
Report of Independent Registered Public Accounting Firm - HEI	77
Report of Independent Registered Public Accounting Firm - Hawaiian Electric	78
Consolidated Financial Statements	79
HEI
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011	79
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	80
Consolidated Balance Sheets at December 31, 2013 and 2012	81
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2013, 2012 and 2011	82
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	83
Hawaiian Electric
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011	84
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	84
Consolidated Balance Sheets at December 31, 2013 and 2012	85
Consolidated Statements of Capitalization at December 31, 2013 and 2012	86
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2013, 2012 and 2011	88
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	89
Notes to Consolidated Financial Statements	90

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 (the “Company”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 the Annual Report of Management on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 21, 2014

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 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 (the "Company") at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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 audits 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.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 21, 2014

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries



Years ended December 31	2013			2012			2011
(in thousands, except per share amounts)
Revenues
Electric utility	$	2,980,172		$	3,109,439		$	2,978,690
Bank	258,147			265,539			264,407
Other	151			17			(762		)
Total revenues	3,238,470			3,374,995			3,242,335
Expenses
Electric utility	2,734,659			2,896,427			2,763,556
Bank	171,090			177,106			172,806
Other	17,302			17,266			16,277
Total expenses	2,923,051			3,090,799			2,952,639
Operating income (loss)
Electric utility	245,513			213,012			215,134
Bank	87,057			88,433			91,601
Other	(17,151		)	(17,249		)	(17,039		)
Total operating income	315,419			284,196			289,696
Interest expense, net – other than on deposit liabilities and other bank borrowings	(75,479		)	(78,151		)	(82,106		)
Allowance for borrowed funds used during construction	2,246			4,355			2,498
Allowance for equity funds used during construction	5,561			7,007			5,964
Income before income taxes	247,747			217,407			216,052
Income taxes	84,341			76,859			75,932
Net income	163,406			140,548			140,120
Preferred stock dividends of subsidiaries	1,890			1,890			1,890
Net income for common stock	$	161,516		$	138,658		$	138,230
Basic earnings per common share	$	1.63		$	1.43		$	1.45
Diluted earnings per common share	$	1.62		$	1.42		$	1.44
Dividends per common share	$	1.24		$	1.24		$	1.24
Weighted-average number of common shares outstanding	98,968			96,908			95,510
Net effect of potentially dilutive shares	655			430			310
Adjusted weighted-average shares	99,623			97,338			95,820

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	2013			2012			2011
(in thousands)
Net income for common stock	$	161,516		$	138,658		$	138,230
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits of $9,037, ($631) and ($4,343) for 2013, 2012 and 2011, respectively	(13,686		)	956			6,578
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $488, $53 and $148 for 2013, 2012 and 2011, respectively	(738		)	(81		)	(224		)
Derivatives qualified as cash flow hedges:
Net unrealized holding losses arising during the period, net of tax benefits of $4 for 2011	—			—			(8		)
Less: reclassification adjustment to net income, net of tax benefits of $150, $150 and $115 for 2013, 2012 and 2011, respectively	235			236			181
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of $4,422 for 2011	—			—			6,943
Net gains (losses) arising during the period, net of (taxes) benefits of ($142,478), $63,303 and $83,147 for 2013, 2012 and 2011, respectively	223,177			(99,159		)	(130,191		)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $14,870, $9,764 and $5,976 for 2013, 2012 and 2011, respectively	23,280			15,291			9,364
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $141,777, ($48,299) and ($64,134) for 2013, 2012 and 2011, respectively	(222,595		)	75,471			100,692
Other comprehensive income (loss), net of taxes	9,673			(7,286		)	(6,665		)
Comprehensive income attributable to Hawaiian Electric Industries, Inc.	$	171,189		$	131,372		$	131,565

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

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries



December 31				2013						2012
(dollars in thousands)
ASSETS
Cash and cash equivalents				$	220,036					$	219,662
Accounts receivable and unbilled revenues, net				346,785						362,823
Available-for-sale investment and mortgage-related securities				529,007						671,358
Investment in stock of Federal Home Loan Bank of Seattle				92,546						96,022
Loans receivable held for investment, net				4,110,113						3,737,233
Loans held for sale, at lower of cost or fair value				5,302						26,005
Property, plant and equipment, net
Land	$	74,272					$	70,799
Plant and equipment	5,829,132						5,492,963
Construction in progress	146,742						156,353
	6,050,146						5,720,115
Less – accumulated depreciation	(2,191,199		)	3,858,947			(2,125,286		)	3,594,829
Regulatory assets				575,924						864,596
Other				519,194						494,414
Goodwill				82,190						82,190
Total assets				$	10,340,044					$	10,149,132
LIABILITIES AND SHAREHOLDERS’ EQUITY
Liabilities
Accounts payable				$	212,331					$	212,379
Interest and dividends payable				26,716						26,258
Deposit liabilities				4,372,477						4,229,916
Short-term borrowings—other than bank				105,482						83,693
Other bank borrowings				244,514						195,926
Long-term debt, net—other than bank				1,492,945						1,422,872
Deferred income taxes				529,260						439,329
Regulatory liabilities				349,299						324,152
Contributions in aid of construction				432,894						405,520
Defined benefit pension and other postretirement benefit plans liability				288,539						656,394
Other				524,224						524,535
Total liabilities				8,578,681						8,520,974
Preferred stock of subsidiaries - not subject to mandatory redemption				34,293						34,293
Commitments and contingencies (Notes 3 and 4)
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: 101,259,800 shares and 97,928,403 shares in 2013 and 2012, respectively				1,488,126						1,403,484
Retained earnings				255,694						216,804
Accumulated other comprehensive income (loss), net of taxes
Net unrealized gains (losses) on securities	$	(3,663	)				$	10,761
Unrealized losses on derivatives	(525		)				(760		)
Retirement benefit plans	(12,562		)	(16,750		)	(36,424		)	(26,423		)
Total shareholders’ equity				1,727,070						1,593,865
Total liabilities and shareholders’ equity				$	10,340,044					$	10,149,132

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, 2010	94,691	$	1,314,199	$	178,667		$	(12,472	)	$	1,480,394
Net income for common stock	—	—		138,230			—			138,230
Other comprehensive loss, net of tax benefits	—	—		—			(6,665		)	(6,665		)
Issuance of common stock:
Dividend reinvestment and stock purchase plan	879	21,217		—			—			21,217
Retirement savings and other plans	468	10,318		—			—			10,318
Expenses and other, net	—	3,712		—			—			3,712
Common stock dividends ($1.24 per share)	—	—		(118,500		)	—			(118,500		)
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

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	2013			2012			2011
(in thousands)
Cash flows from operating activities
Net income	$	163,406		$	140,548		$	140,120
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	160,061			150,389			148,152
Other amortization	4,667			7,958			19,318
Provision for loan losses	1,507			12,883			15,009
Impairment of utility assets	—			40,000			9,215
Loans receivable originated and purchased, held for sale	(249,022		)	(519,622		)	(267,656		)
Proceeds from sale of loans receivable, held for sale	273,775			513,000			273,932
Gain on sale of credit card portfolio	(2,251		)	—			—
Increase in deferred income taxes	80,399			90,848			79,444
Excess tax benefits from share-based payment arrangements	(430		)	(61		)	—
Allowance for equity funds used during construction	(5,561		)	(7,007		)	(5,964		)
Change in cash overdraft	1,038			—			(2,688		)
Changes in assets and liabilities
Decrease (increase) in accounts receivable and unbilled revenues, net	16,038			(18,501		)	(77,326		)
Decrease (increase) in fuel oil stock	27,332			10,129			(18,843		)
Increase in regulatory assets	(65,461		)	(72,401		)	(40,132		)
Decrease in accounts, interest and dividends payable	(23,153		)	(39,738		)	(34,480		)
Change in prepaid and accrued income taxes and utility revenue taxes	(19,406		)	21,079			73,153
Decrease in defined benefit pension and other postretirement benefit plans liability	(33,014		)	(228		)	(6,922		)
Change in other assets and liabilities	(2,779		)	(94,734		)	(53,966		)
Net cash provided by operating activities	327,146			234,542			250,366
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(112,654		)	(243,633		)	(361,876		)
Principal repayments on available-for-sale investment and mortgage-related securities	158,558			191,253			389,906
Proceeds from sale of available-for-sale investment and mortgage-related securities	71,367			3,548			32,799
Net increase in loans held for investment	(398,426		)	(112,730		)	(181,080		)
Proceeds from sale of real estate acquired in settlement of loans	9,212			11,336			8,020
Capital expenditures	(353,879		)	(325,480		)	(235,116		)
Contributions in aid of construction	32,160			45,982			23,534
Proceeds from sale of credit card portfolio	26,386			—			—
Other	3,516			2,677			(2,974		)
Net cash used in investing activities	(563,760		)	(427,047		)	(326,787		)
Cash flows from financing activities
Net increase in deposit liabilities	142,561			159,884			94,660
Net increase in short-term borrowings with original maturities of three months or less	21,789			14,872			43,898
Net increase (decrease) in retail repurchase agreements	(1,418		)	(37,291		)	10,910
Proceeds from other bank borrowings	130,000			5,000			—
Repayments of other bank borrowings	(80,000		)	(5,000		)	(15,000		)
Proceeds from issuance of long-term debt	286,000			457,000			125,000
Repayment of long-term debt	(216,000		)	(375,500		)	(150,000		)
Excess tax benefits from share-based payment arrangements	430			61			—
Net proceeds from issuance of common stock	55,086			23,613			15,979
Common stock dividends	(98,383		)	(96,202		)	(106,812		)
Preferred stock dividends of subsidiaries	(1,890		)	(1,890		)	(1,890		)
Other	(1,187		)	(2,645		)	(710		)
Net cash provided by financing activities	236,988			141,902			16,035
Net increase (decrease) in cash and cash equivalents	374			(50,603		)	(60,386		)
Cash and cash equivalents, January 1	219,662			270,265			330,651
Cash and cash equivalents, December 31	$	220,036		$	219,662		$	270,265

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	2013			2012			2011
(in thousands)
Revenues	$	2,980,172		$	3,109,439		$	2,978,690
Expenses
Fuel oil	1,185,552			1,297,419			1,265,126
Purchased power	710,681			724,240			689,652
Other operation and maintenance	403,270			397,429			380,084
Depreciation	154,025			144,498			142,975
Taxes, other than income taxes	281,131			292,841			276,504
Impairment of utility assets	—			40,000			9,215
Total expenses	2,734,659			2,896,427			2,763,556
Operating income	245,513			213,012			215,134
Allowance for equity funds used during construction	5,561			7,007			5,964
Interest expense and other charges, net	(59,279		)	(62,055		)	(60,031		)
Allowance for borrowed funds used during construction	2,246			4,355			2,498
Income before income taxes	194,041			162,319			163,565
Income taxes	69,117			61,048			61,584
Net income	124,924			101,271			101,981
Preferred stock dividends of subsidiaries	915			915			915
Net income attributable to Hawaiian Electric	124,009			100,356			101,066
Preferred stock dividends of Hawaiian Electric	1,080			1,080			1,080
Net income for common stock	$	122,929		$	99,276		$	99,986

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	2013			2012			2011
(in thousands)
Net income for common stock	$	122,929		$	99,276		$	99,986
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Prior service credit arising during the period, net of taxes of $4,408 for 2011	—			—			6,921
Net gains (losses) arising during the period, net of (taxes) benefits of ($129,601), $57,375 and $74,346 for 2013, 2012 and 2011, respectively	203,479			(90,082		)	(116,726		)
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 $13,180, $8,709 and $5,332 for 2013, 2012 and 2011, respectively	20,694			13,673			8,372
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of (taxes) benefits of $141,777, ($48,069) and ($64,134) for 2013, 2012 and 2011, respectively	(222,595		)	75,471			100,692
Other comprehensive income (loss), net of taxes	1,578			(938		)	(741		)
Comprehensive income attributable to Hawaiian Electric Company, Inc.	$	124,507		$	98,338		$	99,245

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

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2013			2012
(in thousands)
Assets
Utility plant, at cost
Land	$	51,883		$	51,568
Plant and equipment	5,701,875			5,364,400
Less accumulated depreciation	(2,111,229		)	(2,040,789		)
Construction in progress	143,233			151,378
Net utility plant	3,785,762			3,526,557
Current assets
Cash and equivalents	62,825			17,159
Customer accounts receivable, net	175,448			210,779
Accrued unbilled revenues, net	144,124			134,298
Other accounts receivable, net	14,062			28,176
Fuel oil stock, at average cost	134,087			161,419
Materials and supplies, at average cost	59,044			51,085
Prepayments and other	52,857			32,865
Regulatory assets	69,738			51,267
Total current assets	712,185			687,048
Other long-term assets
Regulatory assets	506,186			813,329
Unamortized debt expense	9,003			10,554
Other	73,993			71,305
Total other long-term assets	589,182			895,188
Total assets	$	5,087,129		$	5,108,793
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,593,564		$	1,472,136
Cumulative preferred stock – not subject to mandatory redemption	34,293			34,293
Commitments and contingencies (Note 3)
Long-term debt, net	1,206,545			1,147,872
Total capitalization	2,834,402			2,654,301
Current liabilities
Current portion of long-term debt	11,400			—
Accounts payable	189,559			186,824
Interest and preferred dividends payable	21,652			21,092
Taxes accrued	249,445			251,066
Regulatory liabilities	1,916			1,212
Other	63,881			60,801
Total current liabilities	537,853			520,995
Deferred credits and other liabilities
Deferred income taxes	507,161			417,611
Regulatory liabilities	347,383			322,940
Unamortized tax credits	73,539			66,584
Defined benefit pension and other postretirement benefit plans liability	262,162			620,205
Other	91,735			100,637
Total deferred credits and other liabilities	1,281,980			1,527,977
Contributions in aid of construction	432,894			405,520
Total capitalization and liabilities	$	5,087,129		$	5,108,793

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

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries



December 31	2013		2012
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value
Authorized: 50,000,000 shares. Outstanding:
2013, 15,429,105 shares and 2012, 14,665,264 shares	$	102,880	$	97,788
Premium on capital stock	541,452		468,045
Retained earnings	948,624		907,273
Accumulated other comprehensive income (loss), net of taxes - retirement benefit plans	608		(970		)
Common stock equity	1,593,564		1,472,136
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, 2013 and 2012	2013		2012
(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	2013		2012
(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
Hawaiian Electric, 5.00%, refunding series 2003B, due 2022	—		40,000
Hawaii Electric Light, 5.00%, refunding series 2003B, due 2022	—		12,000
Hawaii Electric Light, 4.75%, refunding series 2003A, due 2020	—		14,000
Hawaii Electric Light, 5.50%, refunding series 1999A, due 2014	11,400		11,400
Hawaiian Electric, 5.65%, series 1997A, due 2027	—		50,000
Hawaii Electric Light, 5.65%, series 1997A, due 2027	—		30,000
Maui Electric, 5.65%, series 1997A, due 2027	—		20,000
Total obligations to the State of Hawaii	473,400		639,400
Other long-term debt – unsecured:
Taxable senior notes:
Hawaii Electric Light, 3.83%, Series 2013A, due 2020	14,000		—
Hawaiian Electric, 4.45%, Series 2013A, due 2022	40,000		—
Hawaii Electric Light, 4.45%, Series 2013B, due 2022	12,000		—
Hawaiian Electric, 4.84%, Series 2013B, due 2027	50,000		—
Hawaii Electric Light, 4.84%, Series 2013C, due 2027	30,000		—
Maui Electric, 4.84%, Series 2013A, due 2027	20,000		—
Hawaiian Electric, 5.65%, Series 2013C, due 2043	50,000		—
Maui Electric, 5.65%, Series 2013B, due 2043	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		457,000
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034	51,546		51,546
Total other long-term debt – unsecured	744,546		508,546
Total long-term debt	1,217,946		1,147,946
Less unamortized discount	1		74
Less current portion long-term debt	11,400		—
Long-term debt, net	1,206,545		1,147,872
Total capitalization	$	2,834,402	$	2,654,301

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, 2010	13,831	$	92,224	$	389,609	$	851,613		$	709		$	1,334,155
Net income for common stock	—	—		—		99,986			—			99,986
Other comprehensive loss, net of tax benefits	—	—		—		—			(741		)	(741		)
Issuance of common stock, net of expenses	403	2,687		37,312		—			—			39,999
Common stock dividends	—	—		—		(70,558		)	—			(70,558		)
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

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	2013			2012			2011
(in thousands)
Cash flows from operating activities
Net income	$	124,924		$	101,271		$	101,981
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	154,025			144,498			142,975
Other amortization	5,077			6,998			17,378
Impairment of utility assets	—			40,000			9,215
Increase in deferred income taxes	64,507			86,878			69,091
Change in tax credits, net	7,017			6,075			2,087
Allowance for equity funds used during construction	(5,561		)	(7,007		)	(5,964		)
Change in cash overdraft	1,038			—			(2,688		)
Changes in assets and liabilities
Decrease (increase) in accounts receivable	49,445			(47,004		)	(44,404		)
Decrease (increase) in accrued unbilled revenues	(9,826		)	3,528			(33,442		)
Decrease (increase) in fuel oil stock	27,332			10,129			(18,843		)
Increase in materials and supplies	(7,959		)	(7,897		)	(6,471		)
Increase in regulatory assets	(65,461		)	(72,401		)	(40,132		)
Decrease in accounts payable	(20,828		)	(38,913		)	(35,815		)
Change in prepaid and accrued income taxes and revenue taxes	(2,028		)	25,239			69,736
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	2,240			(744		)	(27,004		)
Change in other assets and liabilities	(31,499		)	(73,419		)	(36,306		)
Net cash provided by operating activities	292,443			177,231			161,394
Cash flows from investing activities
Capital expenditures	(342,485		)	(310,091		)	(226,022		)
Contributions in aid of construction	32,160			45,982			23,534
Other	(230		)	—			77
Net cash used in investing activities	(310,555		)	(264,109		)	(202,411		)
Cash flows from financing activities
Common stock dividends	(81,578		)	(73,044		)	(70,558		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,995		)	(1,995		)	(1,995		)
Proceeds from issuance of common stock	78,500			44,000			40,000
Proceeds from issuance of long-term debt	236,000			457,000			—
Repayment of long-term debt	(166,000		)	(368,500		)	—
Other	(1,149		)	(2,230		)	(560		)
Net cash provided by (used in) financing activities	63,778			55,231			(33,113		)
Net increase (decrease) in cash and cash equivalents	45,666			(31,647		)	(74,130		)
Cash and cash equivalents, January 1	17,159			48,806			122,936
Cash and cash equivalents, December 31	$	62,825		$	17,159		$	48,806

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 2.

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.

HEI and Hawaiian Electric have combined their financial statements. Also, Hawaiian Electric changed its consolidated statements of income from a utility presentation to a commercial company presentation, resulting in more consistency between HEI’s and Hawaiian Electric’s consolidated financial statements. The combined notes to the consolidated financial statements apply to both HEI and Hawaiian Electric unless otherwise described.

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).

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 5 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.

Investment and mortgage-related securities. Debt securities that the Company intends to and has the ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Marketable equity securities and debt 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 equity securities and debt securities not classified as either held-to-maturity or trading securities are classified as available-for-sale securities and reported at fair value, with unrealized gains and losses and other-than-temporary impairment (OTTI) not related to credit losses excluded from earnings and reported on a net basis in accumulated other comprehensive income (loss) (AOCI).

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. An investment 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, the Company determines whether this impairment is temporary or other-than-temporary. If the Company does not expect to recover the entire amortized cost basis of the security, an OTTI exists. If the Company 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 the Company does not intend to sell the security and it is not more likely than not that the Company 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 other comprehensive income. Once an OTTI has been recognized on a security, the Company accounts for the security as if the security had been purchased on the measurement date of the OTTI at an amortized cost basis equal to the previous amortized cost basis less the OTTI recognized in earnings. The difference between the new amortized cost basis and the cash flows expected to be collected is accreted in accordance with existing applicable guidance as interest income. Any discount or reduced premium recorded for the security will be amortized over the remaining life of the security in a prospective manner based on the amount and timing of future estimated cash flows. If upon subsequent evaluation, there is a significant increase in cash flows expected to be collected or if actual cash flows are significantly greater than cash flows previously expected, such changes shall be accounted for as a prospective adjustment to the accretable yield.

The specific identification method is used in determining realized gains and losses on the sales of securities. Discounts and premiums on investment securities are accreted or amortized over the remaining lives of the securities, adjusted for actual portfolio prepayments, using the interest method. Discounts and premiums on mortgage-related securities are accreted or amortized over the remaining lives of the securities, adjusted based on changes in anticipated prepayments, using the interest method.

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 5 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 2013, 3.1% in 2012 and 3.2% in 2011.

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, $19 million and $14 million in 2013, 2012 and 2011, respectively, and future minimum lease payments are $18 million, $16 million, $13 million, $10 million, $7 million and $29 million for 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. The Utilities' operating lease expense was $8 million, $8 million and $6 million in 2013, 2012 and 2011, respectively, and future minimum lease payments are $9 million, $8 million, $6 million, $5 million, $3 million and $18 million for 2014, 2015, 2016, 2017, 2018 and thereafter, respectively.

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 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.

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:



	2013				2012				2011
	Basic		Diluted		Basic		Diluted		Basic		Diluted
Distributed earnings	$	1.24	$	1.24	$	1.24	$	1.24	$	1.24	$	1.24
Undistributed earnings	0.39		0.38		0.19		0.18		0.21		0.20
	$	1.63	$	1.62	$	1.43	$	1.42	$	1.45	$	1.44

As of December 31, 2013 and 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. As of December 31, 2011, there were no shares that were antidilutive.

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 and interpretations.

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 carryforward 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 plan to prospectively adopt ASU No. 2013-11 in the first quarter of 2014 and does not believe that such adoption will have a material impact on the Company’s or the Utilities' results of operations, financial condition or liquidity.

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 believe that such adoption will have a material impact on the Company’s results of operations, financial condition or liquidity.

Reclassifications. In the fourth quarter of 2013, Hawaiian Electric changed its consolidated statements of income for 2013 and prior comparative periods 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. These and other reclassifications made to prior years’ financial statements to conform to the 2013 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, 2013 and 2012, 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 revenue 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’ operating 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 2013, 2012 and 2011, the Utilities included approximately $266 million, $280 million and $264 million, respectively, of revenue taxes in “operating 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 5.

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 7.6% in 2013, 7.6% in 2012 and 8.0% in 2011, and reflected quarterly compounding.

Bank (HEI only)

Loans receivable. ASB states 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.

Loans held for sale, gain on sale of loans, and mortgage servicing assets and liabilities. Mortgage loans held for sale are stated at the lower of cost or estimated fair value on an aggregate basis. Generally, the determination of fair value is based on the fair value of the loans. 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 capitalizes mortgage servicing assets or liabilities when the related loans are sold with servicing rights retained. Accounting for the servicing of financial assets requires that mortgage servicing assets or liabilities resulting from the sale or securitization of loans be initially measured at fair value at the date of transfer, and permits a class-by-class election between fair value and the lower of amortized cost or fair value for subsequent measurements of mortgage servicing asset classes. Mortgage servicing assets or liabilities are included as a component of gain on sale of loans. Under ASC Topic 860, “Transfers and Servicing,” ASB elected to continue to amortize all mortgage servicing assets in proportion to and over the period of estimated net servicing income and assess servicing assets for impairment based on fair value at each reporting date. Such amortization is reflected as a component of revenues on the consolidated statements of income. The fair value of mortgage servicing assets, for the purposes of impairment, 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 speeds and income and expenses associated with servicing residential mortgage loans for others. ASB measures impairment of mortgage servicing assets on a disaggregated basis based on certain risk characteristics including loan type and note rate. Impairment losses are recognized through a valuation allowance for each impaired stratum, with any associated provision recorded as a component of loan servicing fees included in ASB’s noninterest income.

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). Adverse changes in any of these factors could result in higher charge-offs and provision for loan losses.

Commercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a ten-point 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. Ratings 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 (Risk Rating 1 to 6), Special Mention (Risk Rating 7), Substandard (Risk Rating 8), Doubtful (Risk Rating 9), and Loss (Risk Rating 10) based on credit quality. The allowance for loan loss allocations for

these loans are based on internal migration analyses with actual net losses. 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. 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 the allowance for loan loss allocations for these loan types uses historical loss ratio analyses based on actual net charge-offs. For residential loans, the loan portfolio is segmented by loan categories and geographic location within the State of Hawaii. The consumer loan portfolio is segmented into various secured and unsecured loan product types. The credit scored business loan portfolio is segmented by loans under lines of credit or term loans, and corporate credit cards. The look-back period of actual loss experience is reviewed annually and may vary depending on the credit environment.

In addition to actual loss experience, ASB 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.

For all loan segments, ASB generally ceases the accrual of interest on loans when they become contractually 90 days past due or when there is reasonable doubt as to collectability. Subsequent recognition of interest income for such loans is on the cash or cost recovery method. When, in management’s judgment, supported by underwriting, the borrower’s ability to make principal and interest payments has resumed and collectability is reasonably assured, a loan not accruing interest (nonaccrual loan) is returned to accrual status. ASB uses either the cash or cost-recovery method to record cash receipts on impaired loans that are not accruing interest. While the majority of consumer loans are subject to ASB’s policies regarding nonaccrual loans, all past due unsecured consumer loans may be charged off upon reaching a predetermined delinquency status varying from 120 to 180 days.

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.

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 and other intangibles. Goodwill is tested for impairment at least annually. Intangible assets with definite useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with ASC 350, “Intangibles—Goodwill and other” (ASC 350).

Goodwill. At December 31, 2013 and 2012, 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 in the fourth quarter using data as of September 30.

To determine if there was any impairment to the book value of goodwill pertaining to ASB, the fair value of ASB was estimated using a valuation method based on a market approach and discounted cash flow method with each method having an equal weighting in determining the fair value of ASB. The market approach considers publicly traded financial institutions with assets of $3.5 billion to $8 billion and measures the institutions’ market values as a multiple to (1) net income and (2) book equity. ASB used the median market value multiples for net income and book equity from its selection criteria and applied the multiples to its net income and book equity to calculate ASB’s fair value using the market approach. In order to reflect a premium that a buyer would pay for a controlling interest in ASB, a control premium of 18.3% was included in determining the market approach fair value. The control premium was based on control premiums paid in 18 acquisitions completed within the last two years where 100% interest was purchased and control premium information was available. The discounted cash flow method values a company on a going concern basis and is based on the concept that the future benefits derived from a particular company can be measured by its sustainable after-tax cash flows in the future. ASB’s discounted cash flow analysis was based on its income statement forecasts and a discount rate of 8.5% was applied to present value the cash flows. ASB used a Capital Asset Pricing Model analysis to determine its discount rate. As of September 30, 2013, the estimated fair value of ASB using this valuation methodology exceeded its book value by approximately 60%. For the three years ended December 31, 2013, there has been no impairment of goodwill.

Amortized intangible assets. The table below presents the gross carrying amount, accumulated amortization, valuation allowance and net carrying amount of ASB’s mortgage servicing assets as of December 31, 2013 and 2012:



December 31	2013								2012
(in thousands)	Gross carrying amount		Accumulated amortization		Valuation allowance		Net carrying amount		Gross carrying amount		Accumulated amortization		Valuation allowance		Net carrying amount
Mortgage servicing assets	$	25,644	(13,706	)	(251	)	$	11,687	$	25,835	(14,519	)	(498	)	$	10,818

Changes in the valuation allowance for mortgage servicing assets were as follows:



(in thousands)	2013			2012			2011
Valuation allowance, January 1	$	498		$	175		$	128
Provision (recovery)	(60		)	504			121
Other-than-temporary impairment	(187		)	(181		)	(74		)
Valuation allowance, December 31	$	251		$	498		$	175

The estimated aggregate amortization expenses for mortgage servicing assets for 2014, 2015, 2016, 2017 and 2018 are $1.6 million, $1.4 million, $1.3 million, $1.1 million and $1.0 million, respectively. ASB capitalizes mortgage servicing assets acquired through either the purchase or origination of mortgage loans for sale or the securitization of mortgage loans with servicing rights retained. Changes in mortgage interest rates impact the value of ASB’s mortgage servicing assets. Rising interest rates typically result in slower prepayment speeds in the loans being serviced for others which increases the value of mortgage servicing assets, whereas declining interest rates typically result in faster prepayment speeds which decrease the value of mortgage servicing assets and increase the amortization of the mortgage servicing assets. In 2013, 2012 and 2011, mortgage servicing assets acquired through the sale or securitization of loans held for sale were $2.6 million, $4.8 million and $2.8 million, respectively. Amortization expenses for ASB’s mortgage servicing assets amounted to $1.8 million, $1.7 million

and $1.1 million for 2013, 2012 and 2011, respectively, and are recorded as a reduction in revenues on the consolidated statements of income.

2 · 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 and (6) have similar economic characteristics. 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 American Savings Holdings, Inc.), other subsidiaries not qualifying as reportable segments and intercompany eliminations.

Segment financial information was as follows:



(in thousands)	Electric utility		Bank		Other			Total
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	342,485		11,193		201			353,879
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	310,091		14,979		410			325,480
Assets (at December 31, 2012)	5,108,793		5,041,673		(1,334		)	10,149,132
2011
Revenues from external customers	$	2,978,547	$	264,407	$	(619	)	$	3,242,335
Intersegment revenues (eliminations)	143		—		(143		)	—
Revenues	2,978,690		264,407		(762		)	3,242,335
Depreciation and amortization	160,353		5,909		1,208			167,470
Interest expense, net	60,031		14,469		22,075			96,575
Income (loss) before income taxes	163,565		91,536		(39,049		)	216,052
Income taxes (benefit)	61,584		31,693		(17,345		)	75,932
Net income (loss)	101,981		59,843		(21,704		)	140,120
Preferred stock dividends of subsidiaries	1,995		—		(105		)	1,890
Net income (loss) for common stock	99,986		59,843		(21,599		)	138,230
Capital expenditures	226,022		8,984		110			235,116
Assets (at December 31, 2011)	4,674,007		4,909,974		10,496			9,594,477

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.

3 · 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, 2013 are noted.

Regulatory assets were as follows:



December 31	2013		2012
(in thousands)
Retirement benefit plans (balance primarily varies with plans’ funded statuses)	$	350,821	$	660,835
Income taxes, net (1 to 55 years)	85,430		84,931
Decoupling revenue balancing account (1 to 2 years)	90,386		66,076
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 2 to 20 years remaining)	17,342		17,130
Vacation earned, but not yet taken (1 year)	9,149		8,493
Postretirement benefits other than pensions (18 years; 1 year remaining)	62		249
Other (1 to 50 years; 1 to 47 years remaining)	22,734		26,882
	$	575,924	$	864,596
Included in:
Current assets	$	69,738	$	51,267
Long-term assets	506,186		813,329
	$	575,924	$	864,596

Regulatory liabilities were as follows:



December 31	2013		2012
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	315,164	$	305,978
Retirement benefit plans (5 years beginning with respective utility’s next rate case; primarily 5 years remaining)	31,546		15,563
Other (5 years; 1 to 2 years remaining)	2,589		2,611
	$	349,299	$	324,152
Included in:
Current liabilities	$	1,916	$	1,212
Long-term liabilities	347,383		322,940
	$	349,299	$	324,152

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).

100

Major customers. The Utilities received 11% ($340 million), 11% ($349 million) and 11% ($316 million) of their operating revenues from the sale of electricity to various federal government agencies in 2013, 2012 and 2011, 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, 2013	Voluntary liquidation price		Redemption price
Series
C, D, E, H, J and K (Hawaiian Electric)	$	20	$	21
I (Hawaiian Electric)	20		20
G (Hawaii Electric Light)	100		100
H (Maui Electric)	100		100

Hawaiian Electric is obligated to make dividend, redemption and liquidation payments on the preferred stock of each of its subsidiaries if the respective subsidiary is unable to make such payments, but this obligation is subordinated to Hawaiian Electric's obligation to make payments on its own preferred stock.

Related-party transactions. HEI charged the Utilities $6.2 million, $6.1 million and $4.9 million for general management and administrative services in 2013, 2012 and 2011, 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 from HEI fluctuate during the year, and totaled nil at December 31, 2013 and 2012. 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 2013, nil in 2012 and de minimis in 2011.

Commitments and contingencies.

Fuel contracts. The Utilities have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2016. 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, 2013, the estimated cost of minimum purchases under the fuel supply contracts is $0.9 billion in 2014, $0.7 billion in 2015 and $0.4 billion in 2016. The actual cost of purchases in 2014 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, $1.3 billion and $1.3 billion of fuel under contractual agreements in 2013, 2012 and 2011, respectively.

Hawaiian Electric and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to an amended 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.

Hawaiian Electric and Tesoro Hawaii Corp. (Tesoro) are parties to an amended LSFO supply contract (LSFO contract), which runs through December 31, 2014 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 September 25, 2013, Tesoro sold its Hawaii refinery and related distribution and marketing assets to Hawaii Independent Energy, LLC, a wholly owned subsidiary of Par Petroleum Corporation of Houston Texas.

The Utilities are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Tesoro, 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.

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 Tesoro for LSFO under a Facility Fuel Supply Contract (fuel contract) between them. The fuel contract between Kalaeloa and Tesoro term ends May 31, 2016 and may be extended for terms thereafter unless terminated by one of the parties.

101

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, 2013, the Utilities had six firm capacity PPAs for a total of 567 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion for each of 2013, 2012 and 2011. 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 2014 through 2018 and a total of $0.6 billion in the period from 2019 through 2033.

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 will 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 require approval of the PUC.

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 Revenue 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.

102

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 meeting their commitments relating to decreasing the State’s dependence on imported fossil fuels under their 2008 Energy Agreement with the Governor, the DBEDT and the Consumer Advocate (Energy Agreement). 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 December 2009, the PUC allowed Hawaiian Electric to defer the costs of studies for a large wind project for later review of prudence and reasonableness. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.

In November 2011, Hawaiian Electric and Maui Electric filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between Hawaiian Electric and Maui Electric) also through the REIP surcharge for additional studies to determine the value proposition of interconnecting the islands of Oahu and of Maui County (Maui, Lanai, and Molokai) and if doing so would be operationally beneficial and cost-effective. In August 2012, the PUC allowed Hawaiian Electric and Maui Electric to defer the outside service costs for the additional studies for later review of prudence and reasonableness. The specific amount to be recovered, as well as the recovery mechanism and the terms of the recovery mechanism, were to be determined at a later date.

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. 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. The PUC also stated that it will review the PPA (if one is completed) and, as part of that process, determine whether the Lanai Wind Project should be developed taking into account potential as-available renewable energy projects and grid infrastructure options. The PUC stated it intends to evaluate the project as a combined resources proposal (i.e., wind project and generation tie transmission cable between the islands of Oahu and Lanai). Third, the PUC initiated a proceeding to solicit information and evaluate whether an interisland grid interconnection transmission system between the islands of Oahu and Maui is in the public interest, given the potential for large-scale wind and solar projects on Maui.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50MW 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 in April 2013 and are being evaluated.

In June 2013, Hawaiian Electric filed an application requesting PUC approval of Waivers from the Framework for Competitive Bidding for 5 projects (4 photovoltaic and 1 wind) selected as part of Hawaiian Electric’s “Invitation for Low Cost

103

Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.” Subsequently, two of the projects were withdrawn and in February 2014, three of the projects were granted waivers from the Competitive Bidding Framework. In November 2013, Hawaiian Electric filed a second waiver application requesting PUC approval for two additional projects (6 photovoltaic) selected as part of Hawaiian Electric's pricing refresh opportunity provided to developers that originally submitted proposals in response to the “Invitation for Low Cost Renewable Energy Projects on Oahu through Request for Waiver from Competitive Bidding.”

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 April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed 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 proposed regulations would apply to the cooling water systems for the steam generating units at Hawaiian Electric’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual O&M expenditures. On June 11, 2012, the EPA published additional information on the section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule.

On February 16, 2012, the Federal Register published the EPA’s final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at Hawaiian Electric’s power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. Based on a review of the final rule and the benefits and costs of alternative compliance strategies, Hawaiian Electric has selected a MATS compliance strategy based on switching to lower emission fuels. The use of lower emission fuels will provide for MATS compliance at lower overall costs and avoid the reduction in operational flexibility imposed by emissions control equipment. Hawaiian Electric requested and received a one-year extension, resulting in a MATS compliance date of April 16, 2016. Hawaiian Electric 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 and does not expect a decision before mid-2014.

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 NAAQS implementation plans. Hawaiian Electric will work with the DOH and the EPA in the rulemaking process for these implementation plans to ensure development of cost-effective strategies for NAAQS compliance. Based on the February 6, 2013 EPA guidance document, current estimates of the compliance date for the one-hour sulfur dioxide NAAQS is in the 2022 or later timeframe. Pending litigation may result in an accelerated timeframe, but the impact of the litigation cannot be predicted at this time.

Depending upon the final outcome of the CWA 316(b) regulations,the specific measures required for MATS compliance, and the rules and guidance developed for implementation of more stringent National Ambient Air Quality Standards, the Utilities may be required to incur material capital expenditures and other compliance costs, but such amounts 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 experience petroleum or other chemical releases into the environment associated with current 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 are scheduled to meet in February 2014 to engage in settlement discussions. Hawaii Electric Light and Maui Electric cannot currently estimate

104

the amount or effect of a settlement, if any. Hawaii Electric Light and Maui Electric continue to investigate the potential bases for the DOJ’s claims.

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, 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, 2013) 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 revised draft site investigation plan for site characterization in October and November 2013, respectively, both of which did not result in a change to the reserve balance. Maui Electric is currently revising the draft site investigation plan to address the DOH and EPA comments.

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. The Utilities participated in a Task Force established under Act 234, which was charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks 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. Hawaiian Electric submitted comments on the proposed regulations in January 2013. In October 2013, the DOH announced that it intends to issue a final rule that would change the required emission reduction from 25% to 16% and delay the accrual of GHG emissions fees until after the rule is promulgated, among other changes, but the final rule has not yet been formally approved or released. Hawaiian Electric continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.

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, 2011 and 2012 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. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. 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. This 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. President Obama also directed the EPA Administrator to issue proposed standards, regulations, or guidelines for GHG emissions from existing, modified and reconstructed power plants by no later than June 1, 2014, and final standards no later than June 1, 2015. Hawaiian Electric will participate in the federal GHG rulemaking process. 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.

105

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’ 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 relate 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% allocation 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 PUC found that the record did not sufficiently support the normalization of 2013 and 2014 Customer Information System costs into the 2012 test year and ordered a downward adjustment to remove these costs from the test year.

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 removed integrated resource planning (IRP) expenses from the test year as it could not determine whether these expenses have been reasonably incurred for the 2012 test year as required by the PUC’s IRP Framework and stated that it will determine the appropriate level and method of cost recovery for Maui Electric’s IRP expenses in the pending IRP proceeding.

The PUC reduced operational and renewable energy integration study costs because of the uncertainty regarding the scope of work and actual costs of these studies.

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.

On July 2, 2013, the PUC issued an order denying Maui Electric’s requests for an evidentiary hearing and for partial reconsideration of the final D&O, and dismissed Maui Electric’s motion for partial stay. The order allowed Maui Electric to defer IRP costs incurred since June 2012, which through December 31, 2013 totaled approximately $0.9 million, until the level of costs are determined and a method of recovery is decided in the IRP proceeding.

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

106

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 directed by the PUC, in June 2013 Maui Electric made its curtailment information available to the public on its website and in July 2013 filed documentation regarding the re-setting of its target heat rates to take into account the operation of the Auwahi wind farm.

In addition, as required by the final D&O, Maui Electric filed in September 2013 a System Improvement and Curtailment Reduction Plan, 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. In separate filings in October 2013, Maui Electric submitted additional information on the re-setting of its target heat rates and metrics to measure the success of its efforts to reduce or limit curtailment and execute on key actions. In December 2013, Maui Electric filed documentation regarding the re-setting of its target heat rates based on certain operational changes identified in the System Improvement and Curtailment Reduction Plan to be effective in May 2014. Management cannot predict any actions by the PUC as a result of these filings.

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

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



(in thousands)	2013			2012
Balance, January 1	$	48,431		$	50,871
Accretion expense	1,263			1,563
Liabilities incurred	—			—
Liabilities settled	(5,672		)	(4,003		)
Revisions in estimated cash flows	(916		)	—
Balance, December 31	$	43,106		$	48,431

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 revenue 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 revenue 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. Prior to and during the transition to decoupling, however, the Utilities’ returns have been below PUC-allowed returns.

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 are 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, consistent with the 2013 Agreement, 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. The schedule B part of the proceeding is intended to take place over a longer period, with panel hearings scheduled for August 2014.

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;

107


•	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 has been previously approved.

The D&O requires 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 within 120 days. The PUC reserves 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 are required to develop websites to present certain performance metrics first for review by the PUC and the parties and then to the public following PUC approval.

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.

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

Consolidating financial information (unaudited). 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 and (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 5). 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.

108

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
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

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 (loss), net of taxes:
Retirement benefit plans:
Net gains arising during the period, net of taxes	203,479			30,542		27,919		—		(58,461	)	[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 taxes	(222,595		)	(33,277	)	(30,377	)	—		63,654		[1]	(222,595		)
Other comprehensive income, net of taxes	1,578			145		99		—		(244	)		1,578
Comprehensive income (loss) attributable to common shareholder	$	124,507		20,281		21,376		(3	)	(41,654	)		$	124,507

109

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

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

110

Consolidating statement of income

Year ended December 31, 2011



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Revenues	$	2,114,066		444,891		419,760		—		(27	)	[1]	$	2,978,690
Expenses
Fuel oil	909,172			121,839		234,115		—		—			1,265,126
Purchased power	522,503			137,453		29,696		—		—			689,652
Other operation and maintenance	266,807			56,066		57,202		9		—			380,084
Depreciation	89,324			32,767		20,884		—		—			142,975
Taxes, other than income taxes	196,170			41,028		39,306		—		—			276,504
Impairment of utility assets	9,215			—		—		—		—			9,215
Total expenses	1,993,191			389,153		381,203		9		—			2,763,556
Operating income (loss)	120,875			55,738		38,557		(9	)	(27	)		215,134
Allowance for equity funds used during construction	4,572			592		800		—		—			5,964
Equity in earnings of subsidiaries	44,616			—		—		—		(44,616	)	[2]	—
Interest expense and other charges, net	(37,624		)	(12,554	)	(9,880	)	—		27		[1]	(60,031		)
Allowance for borrowed funds used during construction	1,941			248		309		—		—			2,498
Income (loss) before income taxes	134,380			44,024		29,786		(9	)	(44,616	)		163,565
Income taxes	33,314			16,839		11,431		—		—			61,584
Net income (loss)	101,066			27,185		18,355		(9	)	(44,616	)		101,981
Preferred stock dividends of subsidiaries	—			534		381		—		—			915
Net income (loss) attributable to Hawaiian Electric	101,066			26,651		17,974		(9	)	(44,616	)		101,066
Preferred stock dividends of Hawaiian Electric	1,080			—		—		—		—			1,080
Net income (loss) for common stock	$	99,986		26,651		17,974		(9	)	(44,616	)		$	99,986

Consolidating statement of comprehensive income

Year ended December 31, 2011



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Net income (loss) for common stock	$	99,986		26,651		17,974		(9	)	(44,616	)		$	99,986
Other comprehensive income (loss), net of taxes:
Retirement benefit plans:
Prior service credit arising during the period, net of taxes	6,921			1,419		1,239		—		(2,658	)	[1]	6,921
Net losses arising during the period, net of tax benefits	(116,726		)	(18,224	)	(16,816	)	—		35,040		[1]	(116,726		)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits	8,372			1,324		1,158		—		(2,482	)	[1]	8,372
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits	100,692			15,436		14,366		—		(29,802	)	[1]	100,692
Other comprehensive loss, net of tax benefits	(741		)	(45	)	(53	)	—		98			(741		)
Comprehensive income (loss) attributable to common shareholder	$	99,245		26,606		17,921		(9	)	(44,518	)		$	99,245

111

Consolidating balance sheet

December 31, 2013



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Assets
Utility plant, at cost
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
Net utility plant	2,504,341			696,371		585,050		—	—			3,785,762
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	47,116			11,352		15,525		—	—			73,993
Total other long-term assets	434,513			77,484		77,185		—	—			589,182
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

112

Consolidating balance sheet

December 31, 2012



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries	Consolidating adjustments			Hawaiian Electric Consolidated
Assets
Utility plant, at cost
Land	$	43,370		5,182		3,016		—	—			$	51,568
Plant and equipment	3,325,862			1,086,048		952,490		—	—			5,364,400
Less accumulated depreciation	(1,185,899		)	(433,531	)	(421,359	)	—	—			(2,040,789		)
Construction in progress	130,143			12,126		9,109		—	—			151,378
Net utility plant	2,313,476			669,825		543,256		—	—			3,526,557
Investment in wholly-owned subsidiaries, at equity	497,939			—		—		—	(497,939	)	[2]	—
Current assets
Cash and equivalents	8,265			5,441		3,349		104	—			17,159
Advances to affiliates	9,400			18,050		—		—	(27,450	)	[1]	—
Customer accounts receivable, net	154,316			29,772		26,691		—	—			210,779
Accrued unbilled revenues, net	100,600			14,393		19,305		—	—			134,298
Other accounts receivable, net	33,313			1,122		3,016		—	(9,275	)	[1]	28,176
Fuel oil stock, at average cost	123,176			15,485		22,758		—	—			161,419
Materials and supplies, at average cost	31,779			5,336		13,970		—	—			51,085
Prepayments and other	21,708			5,146		6,011		—	—			32,865
Regulatory assets	42,675			4,056		4,536		—	—			51,267
Total current assets	525,232			98,801		99,636		104	(36,725	)		687,048
Other long-term assets
Regulatory assets	601,451			109,815		102,063		—	—			813,329
Unamortized debt expense	7,042			2,066		1,446		—	—			10,554
Other	46,586			9,871		14,848		—	—			71,305
Total other long-term assets	655,079			121,752		118,357		—	—			895,188
Total assets	$	3,991,726		890,378		761,249		104	(534,664	)		$	5,108,793
Capitalization and liabilities
Capitalization
Common stock equity	$	1,472,136		268,908		228,927		104	(497,939	)	[2]	$	1,472,136
Cumulative preferred stock–not subject to mandatory redemption	22,293			7,000		5,000		—	—			34,293
Long-term debt, net	780,546			201,326		166,000		—	—			1,147,872
Total capitalization	2,274,975			477,234		399,927		104	(497,939	)		2,654,301
Current liabilities
Short-term borrowings-affiliate	18,050			—		9,400		—	(27,450	)	[1]	—
Accounts payable	134,651			27,457		24,716		—	—			186,824
Interest and preferred dividends payable	14,479			4,027		2,593		—	(7	)	[1]	21,092
Taxes accrued	174,477			38,778		37,811		—	—			251,066
Regulatory liabilities	1,212			—		—		—	—			1,212
Other	45,125			10,310		14,634		—	(9,268	)	[1]	60,801
Total current liabilities	387,994			80,572		89,154		—	(36,725	)		520,995
Deferred credits and other liabilities
Deferred income taxes	302,569			68,479		46,563		—	—			417,611
Regulatory liabilities	219,303			67,359		36,278		—	—			322,940
Unamortized tax credits	39,827			13,450		13,307		—	—			66,584
Defined benefit pension and other postretirement benefit plans liability	459,765			80,686		79,754		—	—			620,205
Other	68,783			17,799		14,055		—	—			100,637
Total deferred credits and other liabilities	1,090,247			247,773		189,957		—	—			1,527,977
Contributions in aid of construction	238,510			84,799		82,211		—	—			405,520
Total capitalization and liabilities	$	3,991,726		890,378		761,249		104	(534,664	)		$	5,108,793

113

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, 2010	$	1,334,155		269,986		229,651		91		(499,728	)	$	1,334,155
Net income (loss) for common stock	99,986			26,651		17,974		(9	)	(44,616	)	99,986
Other comprehensive loss, net of tax benefit	(741		)	(45	)	(53	)	—		98		(741		)
Issuance of common stock, net of expenses	39,999			—		—		25		(25	)	39,999
Common stock dividends	(70,558		)	(16,124	)	(12,004	)	—		28,128		(70,558		)
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 benefit	(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		99		—		(244	)	1,578
Issuance of common stock, net of expenses	78,499			—		—		—		—		78,499
Common stock dividends	(81,578		)	(14,387	)	(1,532	)	—		15,919		(81,578		)
Balance, December 31, 2013	$	1,593,564		274,802		248,771		101		(523,674	)	$	1,593,564

114

Consolidating statement of cash flows

Year ended December 31, 2013



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income (loss)	$	124,009		20,670		21,658		(3	)	(41,410	)	[2]	$	124,924
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Equity in earnings	(41,510		)	—		—		—		41,410		[2]	(100		)
Common stock dividends received from subsidiaries	28,505			—		—		—		(28,405	)	[2]	100
Depreciation of property, plant and equipment	99,738			34,188		20,099		—		—			154,025
Other amortization	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		)
Decrease in accounts payable	(6,136		)	(4,756	)	(9,936	)	—		—			(20,828		)
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	(17,941		)	(6,262	)	(7,544	)	—		248		[1]	(31,499		)
Net cash provided by (used in) operating activities	250,982			38,805		31,064		(3	)	(28,405	)		292,443
Cash flows from investing activities
Capital expenditures	(237,899		)	(52,135	)	(52,451	)	—		—			(342,485		)
Contributions in aid of construction	21,686			7,590		2,884		—		—			32,160
Advances from affiliates	2,561			17,050		—		—		(19,611	)	[1]	—
Other	—			(230	)	—		—		—			(230		)
Investment in consolidated subsidiary	(12,461		)	—		—		—		12,461		[2]	—
Net cash used in investing activities	(226,113		)	(27,725	)	(49,567	)	—		(7,150	)		(310,555		)
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 issuance of common stock	78,500					12,461		—		(12,461	)	[2]	78,500
Proceeds from 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		[2]	—
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

115

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
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	(31,743		)	(8,110	)	940		—		—			(38,913		)
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 benefit plans liability	(434		)	(191	)	(119	)	—		—			(744		)
Change in other assets and liabilities	(44,880		)	(11,143	)	(12,678	)	(1	)	(4,717	)	[1]	(73,419		)
Net cash provided by (used in) operating activities	145,649			45,167		33,354		(4	)	(46,935	)		177,231
Cash flows from investing activities
Capital expenditures	(233,792		)	(41,060	)	(35,239	)	—		—			(310,091		)
Contributions in aid of construction	32,285			8,184		5,513		—		—			45,982
Advances from (to) affiliates	(9,400		)	28,100		18,500		—		(37,200	)	[1]	—
Net cash used in investing activities	(210,907		)	(4,776	)	(11,226	)	—		(37,200	)		(264,109		)
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 common stock	44,000			—		—		—		—			44,000
Proceeds from the issuance of long-term debt	367,000			31,000		59,000		—		—			457,000
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

116

Consolidating statement of cash flows

Year ended December 31, 2011



(in thousands)	Hawaiian Electric			Hawaii Electric Light		Maui Electric		Other subsidiaries		Consolidating adjustments			Hawaiian Electric Consolidated
Cash flows from operating activities
Net income (loss)	$	101,066		27,185		18,355		(9	)	(44,616	)	[2]	$	101,981
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Equity in earnings	(44,716		)	—		—		—		44,616		[2]	(100		)
Common stock dividends received from subsidiaries	28,228			—		—		—		(28,128	)	[2]	100
Depreciation of property, plant and equipment	89,324			32,767		20,884		—		—			142,975
Other amortization	9,890			2,528		4,960		—		—			17,378
Impairment of utility assets	9,215			—		—		—		—			9,215
Increase in deferred income taxes	38,548			16,101		14,442		—		—			69,091
Change in tax credits, net	1,464			117		506		—		—			2,087
Allowance for equity funds used during construction	(4,572		)	(592	)	(800	)	—		—			(5,964		)
Change in cash overdraft	—			(2,527	)	(161	)	—		—			(2,688		)
Changes in assets and liabilities:
Increase in accounts receivable	(34,167		)	(2,985	)	(5,663	)	—		(1,589	)	[1]	(44,404		)
Decrease (increase) in accrued unbilled revenues	(31,616		)	(2,481	)	655		—		—			(33,442		)
Increase in fuel oil stock	(6,757		)	(3,466	)	(8,620	)	—		—			(18,843		)
Increase in materials and supplies	(6,206		)	(202	)	(63	)	—		—			(6,471		)
Increase in regulatory assets	(31,774		)	(2,025	)	(6,333	)	—		—			(40,132		)
Increase (decrease) in accounts payable	(34,515		)	4,391		(5,691	)	—		—			(35,815		)
Change in prepaid and accrued income taxes and revenue taxes	51,593			9,641		8,502		—		—			69,736
Decrease in defined benefit pension and other postretirement benefits plans liability	(20,439		)	(3,241	)	(3,324	)	—		—			(27,004		)
Change in other assets and liabilities	(17,432		)	(13,124	)	(7,337	)	(2	)	1,589		[1]	(36,306		)
Net cash provided by (used in) operating activities	97,134			62,087		30,312		(11	)	(28,128	)		161,394
Cash flows from investing activities
Capital expenditures	(160,528		)	(34,230	)	(31,264	)	—		—			(226,022		)
Contributions in aid of construction	15,003			6,271		2,260		—		—			23,534
Advances from (to) affiliates	—			(15,200	)	11,000		—		4,200		[1]	—
Other	77			—		—		—		—			77
Investment in consolidated subsidiary	(25		)	—		—		—		25		[2]	—
Net cash used in investing activities	(145,473		)	(43,159	)	(18,004	)	—		4,225			(202,411		)
Cash flows from financing activities
Common stock dividends	(70,558		)	(16,124	)	(12,004	)	—		28,128		[2]	(70,558		)
Preferred stock dividends of Hawaiian Electric and subsidiaries	(1,080		)	(534	)	(381	)	—		—			(1,995		)
Proceeds from issuance of common stock	40,000			—		—		25		(25	)	[2]	40,000
Net increase in short-term borrowings from non-affiliates and affiliate with original maturities of three months or less	4,200			—		—		—		(4,200	)	[1]	—
Other	(423		)	(116	)	(21	)	—		—			(560		)
Net cash provided by (used in) financing activities	(27,861		)	(16,774	)	(12,406	)	25		23,903			(33,113		)
Net increase (decrease) in cash and cash equivalents	(76,200		)	2,154		(98	)	14		—			(74,130		)
Cash and cash equivalents, January 1	121,019			1,229		594		94		—			122,936
Cash and cash equivalents, December 31	$	44,819		3,383		496		108		—			$	48,806

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.

117

4 · Bank subsidiary (HEI only)

Selected financial information

American Savings Bank, F.S.B.

Statements of Income Data



Years ended December 31	2013		2012		2011
(in thousands)
Interest and dividend income
Interest and fees on loans	$	172,969	$	176,057	$	184,485
Interest and dividends on investment and mortgage-related securities	13,095		13,822		14,568
Total interest and dividend income	186,064		189,879		199,053
Interest expense
Interest on deposit liabilities	5,092		6,423		8,983
Interest on other borrowings	4,985		4,869		5,486
Total interest expense	10,077		11,292		14,469
Net interest income	175,987		178,587		184,584
Provision for loan losses	1,507		12,883		15,009
Net interest income after provision for loan losses	174,480		165,704		169,575
Noninterest income
Fees from other financial services	27,099		31,361		28,881
Fee income on deposit liabilities	18,363		17,775		18,026
Fee income on other financial products	8,405		6,577		6,704
Mortgage banking income	8,309		14,628		5,028
Gains on sale of securities	1,226		134		371
Other income, net	8,681		5,185		6,344
Total noninterest income	72,083		75,660		65,354
Noninterest expense
Compensation and employee benefits	82,910		75,979		71,137
Occupancy	16,747		17,179		17,154
Data processing	10,952		10,098		8,155
Services	9,015		9,866		7,396
Equipment	7,295		7,105		6,903
Office supplies, printing and postage	4,233		3,870		3,934
Marketing	3,373		3,260		3,001
Communication	1,864		1,809		1,764
Other expense	23,115		23,177		23,949
Total noninterest expense	159,504		152,343		143,393
Income before income taxes	87,059		89,021		91,536
Income taxes	29,525		30,384		31,693
Net income	$	57,534	$	58,637	$	59,843

Statements of Comprehensive Income



Years ended December 31	2013			2012			2011
(in thousands)
Net income	$	57,534		$	58,637		$	59,843
Other comprehensive income (loss), net of taxes:
Net unrealized gains (losses) on securities:
Net unrealized gains (losses) on securities arising during the period, net of (taxes) benefits of $9,037, ($631) and ($4,343), for 2013, 2012 and 2011, respectively	(13,686		)	956			6,578
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $488, $53 and $148 for 2013, 2012 and 2011, respectively	(738		)	(81		)	(224		)
Retirement benefit plans:
Net gains (losses) arising during the period, net of (taxes) benefits of ($10,450), $5,240 and $6,577 for 2013, 2012 and 2011, respectively	15,826			(7,936		)	(9,960		)
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $1,187, $684 and $346 for 2013, 2012 and 2011, respectively	1,797			1,036			523
Other comprehensive income (loss), net of taxes	3,199			(6,025		)	(3,083		)
Comprehensive income	$	60,733		$	52,612		$	56,760

118

Balance Sheet Data



December 31				2013						2012
(in thousands)
Assets
Cash and cash equivalents				$	156,603					$	184,430
Available-for-sale investment and mortgage-related securities				529,007						671,358
Investment in stock of Federal Home Loan Bank of Seattle				92,546						96,022
Loans receivable held for investment				4,150,229						3,779,218
Allowance for loan losses				(40,116		)				(41,985		)
Loans receivable held for investment, net				4,110,113						3,737,233
Loans held for sale, at lower of cost or fair value				5,302						26,005
Other				268,063						244,435
Goodwill				82,190						82,190
Total assets				$	5,243,824					$	5,041,673
Liabilities and shareholder’s equity
Deposit liabilities–noninterest-bearing				$	1,214,418					$	1,164,308
Deposit liabilities–interest-bearing				3,158,059						3,065,608
Other borrowings				244,514						195,926
Other				105,679						117,752
Total liabilities				4,722,670						4,543,594
Commitments and contingencies (see “Litigation” below)
Common stock				336,054						333,712
Retained earnings				197,297						179,763
Accumulated other comprehensive loss, net of tax benefits
Net unrealized gains (losses) on securities	$	(3,663	)				$	10,761
Retirement benefit plans	(8,534		)	(12,197		)	(26,157		)	(15,396		)
Total shareholder’s equity				521,154						498,079
Total liabilities and shareholder’s equity				$	5,243,824					$	5,041,673
Other assets
Bank-owned life insurance				$	129,963					$	125,726
Premises and equipment, net				67,766						62,458
Prepaid expenses				3,616						13,199
Accrued interest receivable				13,133						13,228
Mortgage-servicing rights				11,687						10,818
Real estate acquired in settlement of loans, net				1,205						6,050
Other				40,693						12,956
				$	268,063					$	244,435
Other liabilities
Accrued expenses				$	19,989					$	17,103
Federal and state income taxes payable				37,807						35,408
Cashier’s checks				21,110						23,478
Advance payments by borrowers				9,647						9,685
Other				17,126						32,078
				$	105,679					$	117,752

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.

Investment and mortgage-related securities. ASB owns investment securities (federal agency obligations) and mortgage-related securities issued by the Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC), Government National Mortgage Association (GNMA) and municipal bonds.

As of December 31, 2013, ASB’s investment portfolio distribution was 70% mortgage-related securities issued by FNMA, FHLMC or GNMA, 15% federal agency obligations and 15% municipal bonds. These investment and mortgage-related securities are widely traded in the market and have observable transactions that allow them to be readily priced.

119

which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its findings on an on-going basis by monitoring market activity and events.

Third party pricing services provide security prices in good faith using rigorous methodologies; however, they do not warrant or guarantee the adequacy or accuracy of their information. Therefore, ASB utilizes a separate third party pricing vendor to corroborate security pricing of the first pricing vendor. If the pricing differential between the two pricing sources exceeds an established threshold, a pricing inquiry will be sent to both vendors or to an independent broker to determine a price that can be supported based on observable inputs found in the market. Such challenges to pricing are required infrequently and are generally resolved using additional security-specific information that was not available to a specific vendor.



			Gross		Gross			Estimated		Gross unrealized losses
	Amortized		unrealized		unrealized			fair		Less than 12 months					12 months or longer
(dollars in thousands)	cost		gains		losses			value		Fair value		Amount			Fair value		Amount
December 31, 2013
Available-for-sale
Federal agency obligations	$	83,193	$	174	$	(2,394	)	$	80,973	$	70,799	$	(2.394	)	$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	374,993		4,911		(10,460		)	369,444		228,543		(8,819		)	19,655		(1,641		)
Municipal bonds	76,904		1,826		(140		)	78,590		14,478		(140		)	—		—
	$	535,090	$	6,911	$	(12,994	)	$	529,007	$	313,820	$	(11,353	)	$	19,655	$	(1,641	)
December 31, 2012
Available-for-sale
Federal agency obligations	$	168,324	$	3,167	$	—		$	171,491	$	—	$	—		$	—	$	—
Mortgage-related securities- FNMA, FHLMC and GNMA	407,175		10,412		(204		)	417,383		32,269		(204		)	—		—
Municipal bonds	77,993		4,491		—			82,484		—		—			—		—
	$	653,492	$	18,070	$	(204	)	$	671,358	$	32,269	$	(204	)	$	—	$	—

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 (see contractual maturities table below).

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



	Amortized		Fair
(in thousands)	Cost		value
Due in one year or less	$	—	$	—
Due after one year through five years	42,920		43,137
Due after five years through ten years	95,860		96,751
Due after ten years	21,317		19,675
	160,097		159,563
Mortgage-related securities-FNMA,FHLMC and GNMA	374,993		369,444
Total available-for-sale securities	$	535,090	$	529,007

All positions with variable maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual maturities will likely differ from these contractual maturities because borrowers have the right to prepay obligations with or without prepayment penalties.

In 2013, 2012 and 2011, proceeds from sales of available-for-sale mortgage-related securities were nil, $3.5 million and $30.7 million, resulting in gross realized gains of nil, $0.1 million and $0.4 million, respectively, and there were no gross realized losses. In 2013, proceeds from the sale of federal agency obligations were $71.4 million resulting in gross realized gains of $1.2 million and no gross realized losses. There were no federal agency obligation sales in 2012 and 2011. In 2011, proceeds from the sale of municipal bonds were $2.1 million resulting in gross realized gains of $5,000 and no gross realized losses. There were no sales of municipal bonds in 2013 and 2012.

120

ASB pledged mortgage-related securities and federal agency obligations with a market value of approximately $87.1 million and $98.0 million as of December 31, 2013 and 2012, 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, 2013 and 2012, mortgage-related securities and federal agency obligations with a carrying value of $187.1 million and $189.3 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

FHLB of Seattle stock. As of December 31, 2013 and 2012, ASB’s investment in stock of the FHLB of Seattle was carried at cost because it can only be redeemed at par and it is a required investment based on measurements of ASB’s capital, assets and/or 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, 2013, consistent with its accounting policy. ASB did not recognize an OTTI loss for 2013 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 2013;


•	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.

Other-than-temporary impaired securities. All securities are reviewed for impairment in accordance with accounting standards for OTTI recognition. Under these standards ASB’s intent to sell the security, the probability of more-likely-than-not being forced to sell the position prior to recovery of its cost basis and the probability of more-likely-than-not recovering the amortized cost of the position was determined. If ASB’s intent is to hold positions determined to be other-than-temporarily impaired, credit losses, which are recognized in earnings, are quantified using the position’s pre-impairment discount rate and the net present value of cash flows expected to be collected from the security. Non-credit related impairments are reflected in other comprehensive income. ASB did not recognize OTTI for 2013, 2012 or 2011.

Loans receivable.



December 31	2013			2012
(in thousands)
Real estate loans:
Residential 1-4 family	$	2,006,007		$	1,866,450
Commercial real estate	440,443			375,677
Home equity line of credit	739,331			630,175
Residential land	16,176			25,815
Commercial construction	52,112			43,988
Residential construction	12,774			6,171
Total real estate loans	3,266,843			2,948,276
Commercial loans	783,388			721,349
Consumer loans	108,722			121,231
Total loans	4,158,953			3,790,856
Deferred loan fees, net and unamortized discounts	(8,724		)	(11,638		)
Allowance for loan losses	(40,116		)	(41,985		)
Total loans, net	$	4,110,113		$	3,737,233

As of December 31, 2013 and 2012, ASB’s commitments to originate loans approximated $163.7 million and $97.9 million, respectively. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any

121

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. ASB minimizes its exposure to loss under these commitments by requiring that customers meet certain conditions prior to disbursing funds. The amount of collateral, if any, is based on a credit evaluation of the borrower and may include residential real estate, accounts receivable, inventory and property, plant and equipment.

As of December 31, 2013 and 2012, standby, commercial and banker’s acceptance letters of credit totaled $15.7 million and $10.5 million, respectively. Letters of credit are conditional commitments issued by ASB 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. ASB holds collateral supporting those commitments for which collateral is deemed necessary. As of December 31, 2013 and 2012, undrawn consumer lines of credit, including credit cards, totaled $1.1 billion and $1.0 billion, respectively, and undrawn commercial loans including lines of credit totaled $396.4 million and $376.2 million, respectively.

ASB services real estate loans for investors ($1.4 billion, $1.3 billion and $1.0 billion as of December 31, 2013, 2012 and 2011, respectively), which are not included in the accompanying consolidated balance sheet data. ASB reports fees earned for servicing such loans as income when the related mortgage loan payments are collected and charges loan servicing costs to expense as incurred.

As of December 31, 2013 and 2012, ASB had pledged loans with an amortized cost of approximately $1.7 billion and $1.0 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

As of December 31, 2013 and 2012, 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 $45.8 million and $70.9 million, respectively. The $25.1 million decrease in such loans in 2013 was attributed to new commitments and loans of $0.5 million to new and existing directors and executive officers, offset by closed lines of credits and repayments of $25.6 million. As of December 31, 2013 and 2012, $40.5 million and $65.9 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 except that residential real estate loans and consumer loans to directors and executive officers of ASB were made at preferred employee interest rates. 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. The allowance for loan losses consists of an allocated portion, which estimates credit losses for specifically identified loans and pools of loans, and an unallocated portion.

Segmentation. ASB segments its loan portfolio by three levels. In the first level, the loan portfolio is separated into homogeneous and non-homogeneous loan portfolios. Residential, consumer and credit scored business loans are considered homogeneous loans. These are loans that are typically underwritten based on common, uniform standards, and are generally classified as to the level of loss exposure based on delinquency status. Commercial loans and commercial real estate (CRE) loans are defined as non-homogeneous loans and ASB utilitizes a uniform ten–point risk rating system for evaluating the credit quality of the loans. These are loans where the underwriting criteria are not uniform and the risk rating classification is based upon considerations broader than just delinquency performance.

In the second level of segmentation, the loan portfolios are further stratified into individual products with common risk characteristics. For residential loans, the loan portfolio is segmented by loan categories and geographic location first within the State of Hawaii (Oahu vs. the neighbor islands) and second collectively outside of the state. The consumer loan portfolio is segmented into various secured and unsecured loan product types. The credit scored business loan portfolio is segmented by loans under lines of credit or term loans. For commercial loans, the portfolio is differentiated by separating Commercial & Industrial (C&I) loans, C&I National Lending loans and C&I loans guaranteed by Small Business Administration programs while CRE loans are grouped by owner-occupied loans, investor loans, construction loans, and vacant land loans.

For the third and last level of segmentation, loans are categorized into the regulatory asset quality classifications – Pass, Substandard, and Loss for homogeneous loans based primarily on delinquency status, and Pass (Risk Rating 1 to 6), Special Mention (Risk Rating 7), Substandard (Risk Rating 8), Doubtful (Risk Rating 9), and Loss (Risk Rating 10) for non-homogeneous loans based on credit quality.

Specific allocation.

Residential real estate. All residential real estate loans that are 180 days delinquent, or where ASB has initiated foreclosure action or have been modified in a TDR are reviewed for impairment based on the fair value of the collateral, net of costs to sell. Generally, impairment amounts derived under this method are immediately charged off.

122

Consumer. The consumer loan portfolio specific allocation is determined based on delinquency; unsecured consumer loans are generally charged-off based on delinquency status varying from 120 to 180 days.

Commercial and CRE. A specific allocation is determined for impaired commercial and CRE loans. See further discussion in Note 1.

Pooled allocation.

Residential real estate and consumer. Pooled allocation for non-impaired residential real estate and consumer loans are determined using a historical loss rate analysis and qualitative factor considerations.

Commercial and CRE. Pooled allocation for pass, special mention, substandard, and doubtful grade commercial and CRE loans that share common risk characteristics and properties are determined using a historical loss rate analysis and qualitative factor considerations.

Qualitative adjustments. Qualitative adjustments to historical loss rates or other static sources may be necessary since these rates may not fully consider all losses inherent in the current portfolio (for example, risks in growing and/or unseasoned portfolios). To estimate the level of adjustments, management considers factors, including levels and trends in problem loans, the nature, volume and term of the loan portfolios, changes in lending policies and practices, changes in management and staffing, economic conditions, industry trends, and credit concentrations.

Unallocated allowance. ASB’s allowance incorporates an unallocated portion to cover risk factors and events that may have occurred as of the evaluation date that have not been reflected in the risk measures due to inherent limitations to the precision of the estimation process. These risk factors, in addition to micro- and macro- economic factors, past, current and anticipated events based on facts at the balance sheet date, and realistic courses of action that management expects to take, are assessed in determining the level of unallocated allowance.

123

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		Commer- cial loans			Consumer loans			Unallo- cated			Total
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
December 31, 2012
Allowance for loan losses:
Beginning balance	$	6,500		$	1,688	$	4,354		$	3,795		$	1,888	$	4	$	14,867		$	3,806		$	1,004		$	37,906
Charge-offs	(3,183		)	—		(716		)	(2,808		)	—		—		(3,606		)	(2,517		)	—			(12,830		)
Recoveries	1,328			—		108			1,443			—		—		649			498			—			4,026
Provision	1,423			1,277		747			1,845			135		5		4,021			2,232			1,198			12,883
Ending balance	$	6,068		$	2,965	$	4,493		$	4,275		$	2,023	$	9	$	15,931		$	4,019		$	2,202		$	41,985
Ending balance: individually evaluated for impairment	$	384		$	535	$	—		$	3,221		$	—	$	—	$	2,659		$	—		$	—		$	6,799
Ending balance: collectively evaluated for impairment	$	5,684		$	2,430	$	4,493		$	1,054		$	2,023	$	9	$	13,272		$	4,019		$	2,202		$	35,186
Financing Receivables:
Ending balance	$	1,866,450		$	375,677	$	630,175		$	25,815		$	43,988	$	6,171	$	721,349		$	121,231		$	—		$	3,790,856
Ending balance: individually evaluated for impairment	$	25,279		$	6,751	$	1,560		$	18,563		$	—	$	—	$	20,298		$	22		$	—		$	72,473
Ending balance: collectively evaluated for impairment	$	1,841,171		$	368,926	$	628,615		$	7,252		$	43,988	$	6,171	$	701,051		$	121,209		$	—		$	3,718,383

Changes in the allowance for loan losses were as follows:



(dollars in thousands)	2013			2012			2011
Allowance for loan losses, January 1	$	41,985		$	37,906		$	40,646
Provision for loan losses	1,507			12,883			15,009
Charge-offs, net of recoveries
Real estate loans	(678		)	3,828			10,733
Other loans	4,054			4,976			7,016
Net charge-offs	3,376			8,804			17,749
Allowance for loan losses, December 31	$	40,116		$	41,985		$	37,906
Ratio of net charge-offs to average loans outstanding	0.09		%	0.24		%	0.49		%

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 and industrial, commercial real estate and commercial construction loans.

124

A dual ten-point risk rating system is used to reflect the probability of default (borrower risk rating) and loss given default (transaction risk rating). The borrower risk rating addresses risk presented by the individual borrower and is based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting quality and industry/economic factors. Separately, the transaction risk rating addresses risk in the transaction and is a function of the type of collateral control exercised over the collateral, loan structure, guarantees, and other structural support or enhancements to the loan.

The numerical representation of the risk categories are:



1- Substantially risk free	6- Acceptable risk
2- Minimal risk	7- Special mention
3- Modest risk	8- Substandard
4- Better than average risk	9- Doubtful
5- Average risk	10- Loss

Grades 1 through 6 are considered pass grades. 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.

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



December 31	2013						2012
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	375,217	$	52,112	$	703,053	$	314,182	$	39,063	$	638,854
Special mention	33,436		—		17,634		25,437		4,925		24,511
Substandard	28,020		—		59,663		29,308		—		53,538
Doubtful	3,770		—		3,038		6,750		—		4,446
Loss	—		—		—		—		—		—
Total	$	440,443	$	52,112	$	783,388	$	375,677	$	43,988	$	721,349

The increase in commercial real estate and commercial construction loans graded special mention, substandard or doubtful was due to the downgrade of a small number of specific large commercial credits that are being closely monitored and managed. This risk migration reflects both adverse financial trends affecting those borrowers and improved risk rating accuracy of loans across all portfolios.

125

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, 2013
Real estate loans:
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 loans	1,668		612		3,026		5,306		778,082		783,388		—
Consumer loans	436		158		304		898		107,824		108,722		—
Total loans	$	5,781	$	1,752	$	26,227	$	33,760	$	4,125,193	$	4,158,953	$	—
December 31, 2012
Real estate loans:
Residential 1-4 family	$	6,353	$	1,741	$	24,054	$	32,148	$	1,834,302	$	1,866,450	$	—
Commercial real estate	85		—		6,750		6,835		368,842		375,677		—
Home equity line of credit	1,077		142		1,319		2,538		627,637		630,175		—
Residential land	2,851		75		7,788		10,714		15,101		25,815		—
Commercial construction	—		—		—		—		43,988		43,988		—
Residential construction	—		—		—		—		6,171		6,171		—
Commercial loans	3,052		2,814		1,098		6,964		714,385		721,349		131
Consumer loans	598		348		424		1,370		119,861		121,231		242
Total loans	$	14,016	$	5,120	$	41,433	$	60,569	$	3,730,287	$	3,790,856	$	373

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



December 31	2013				2012
	Nonaccrual loans		Accruing loans 90 days or more past due		Nonaccrual loans		Accruing loans 90 days or more past due
(in thousands)
Real estate loans:
Residential 1–4 family	$	19,679	$	—	$	26,721	$	—
Commercial real estate	4,439		—		6,750		—
Home equity line of credit	2,060		—		2,349		—
Residential land	3,161		—		8,561		—
Commercial construction	—		—		—		—
Residential construction	—		—		—		—
Commercial loans	18,781		—		20,222		131
Consumer loans	401		—		284		242
Total	$	48,521	$	—	$	64,887	$	373

126

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



December 31	2013										2012
(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 loans:
Residential 1-4 family	$	9,708	$	12,144	$	—	$	11,674	$	386	$	14,633	$	20,247	$	—	$	16,688	$	294
Commercial real estate	—		—		—		802		—		2,929		2,929		—		7,771		237
Home equity line of credit	672		1,227		—		623		2		581		1,374		—		632		1
Residential land	2,622		3,612		—		6,675		482		7,691		10,624		—		21,589		1,185
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	3,466		4,715		—		4,837		12		4,265		6,994		—		24,605		986
Consumer loans	19		19		—		20		—		21		21		—		23		—
	16,487		21,717		—		24,631		882		30,120		42,189		—		71,308		2,703
With an allowance recorded
Real estate loans:
Residential 1-4 family	6,216		6,236		642		6,455		372		4,803		4,803		384		4,204		250
Commercial real estate	4,604		4,686		1,118		5,745		152		3,821		3,840		535		1,295		—
Home equity line of credit	—		—		—		—		—		—		—		—		26		—
Residential land	7,452		7,623		1,332		6,844		409		9,984		10,364		3,221		7,428		575
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	17,759		20,640		2,246		15,635		139		16,033		16,912		2,659		8,429		23
Consumer loans	—		—		—		—		—		—		—		—		—		—
	36,031		39,185		5,338		34,679		1,072		34,641		35,919		6,799		21,382		848
Total
Real estate loans:
Residential 1-4 family	15,924		18,380		642		18,129		758		19,436		25,050		384		20,892		544
Commercial real estate	4,604		4,686		1,118		6,547		152		6,750		6,769		535		9,066		237
Home equity line of credit	672		1,227		—		623		2		581		1,374		—		658		1
Residential land	10,074		11,235		1,332		13,519		891		17,675		20,988		3,221		29,017		1,760
Commercial construction	—		—		—		—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—		—		—		—
Commercial loans	21,225		25,355		2,246		20,472		151		20,298		23,906		2,659		33,034		1,009
Consumer loans	19		19		—		20		—		21		21		—		23		—
	$	52,518	$	60,902	$	5,338	$	59,310	$	1,954	$	64,761	$	78,108	$	6,799	$	92,690	$	3,551

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 principal payments. ASB generally does not reduce the interest rate on commercial loan TDR modifications. Occasionally,

127

additional collateral and/or guaranties are obtained.

All TDR loans are classified as impaired and are segregated and reviewed separately when assessing the adequacy of the allowance for loan losses based on the appropriate method of measuring impairment: (1) present value of expected future cash flows discounted at the loan’s effective original contractual rate, (2) fair value of collateral less cost to sell, or (3) observable market price. The financial impact of the calculated impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.

Loan modifications that occurred were as follows for the indicated periods:



	2013					2012					2011
	Number	Outstanding recorded investment				Number	Outstanding recorded investment				Number	Outstanding recorded investment
(dollars in thousands)	of contracts	Pre-modification		Post-modification		of contracts	Pre-modification		Post-modification		of contracts	Pre-modification		Post-modification
Troubled debt restructurings
Real estate loans:
Residential 1-4 family	34	$	8,876	$	8,957	35	$	8,805	$	8,232	42	$	11,233	$	9,853
Commercial real estate	—	—		—		—	—		—		—	—		—
Home equity line of credit	5	637		390		—	—		—		1	93		93
Residential land	20	6,215		6,206		26	6,149		5,484		46	9,965		9,946
Commercial loans	7	4,646		4,646		19	2,583		2,583		56	35,349		35,349
Consumer loans	—	—		—		—	—		—		1	25		25
	66	$	20,374	$	20,199	80	$	17,537	$	16,299	146	$	56,665	$	55,266

Loans modified in TDRs that experienced a payment default of 90 days or more in 2013, 2012 and 2011, and for which the payment default occurred within one year of the modification, were as follows:



	2013			2012			2011
(dollars in thousands)	Number of contracts	Recorded investment		Number of contracts	Recorded investment		Number of contracts	Recorded investment
Troubled debt restructurings that subsequently defaulted
Real estate loans:
Residential 1-4 family	—	$	—	—	$	—	—	$	—
Commercial real estate	—	—		—	—		—	—
Home equity line of credit	1	67		—	—		—	—
Residential land	—	—		—	—		1	528
Commercial loans	2	660		1	482		4	799
Consumer loans	—	—		—	—		—	—
	3	$	727	1	$	482	5	$	1,327

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 $0.3 million at December 31, 2013.

128

Deposit liabilities.



December 31	2013				2012
(dollars in thousands)	Weighted-average stated rate		Amount		Weighted-average stated rate		Amount
Savings	0.06	%	$	1,826,907	0.06	%	$	1,758,547
Other checking
Interest-bearing	0.02		721,700		0.02		641,970
Noninterest-bearing	—		643,628		—		621,806
Commercial checking	—		570,790		—		542,502
Money market	0.13		182,546		0.13		191,398
Term certificates	0.80		426,906		0.86		473,693
	0.11	%	$	4,372,477	0.13	%	$	4,229,916

As of December 31, 2013 and 2012, certificate accounts of $100,000 or more totaled $102 million and $106 million, respectively.

The approximate amounts of term certificates outstanding as of December 31, 2013 with scheduled maturities for 2014 through 2018 were $244 million in 2014, $94 million in 2015, $46 million in 2016, $22 million in 2017, $16 million in 2018, and $5 million thereafter.

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



(in thousands)	2013		2012		2011
Term certificates	$	3,702	$	4,865	$	6,393
Savings	1,052		1,128		1,756
Money market	232		319		650
Interest-bearing checking	106		111		184
	$	5,092	$	6,423	$	8,983

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 a 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, 2013	$	145	$	—	$	145
December 31, 2012	146		—		146

129



	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, 2013
Financial institution	$	51	$	51	$	—	$	—
Commercial account holders	94		94		—		—
Total	$	145	$	145	$	—	$	—
December 31, 2012
Financial institution	$	50	$	50	$	—	$	—
Commercial account holders	96		96		—		—
Total	$	146	$	146	$	—	$	—



December 31, 2013
Maturity	Repurchase liability			Weighted-average interest rate		Collateralized by mortgage-related securities and federal agency obligations– fair value plus accrued interest
(dollars in thousands)
Overnight	$	94,224		0.15	%	$	127,293
1 to 29 days	—			—		—
30 to 90 days	—			—		—
Over 90 days	50,290		¹	4.75		60,233
	$	144,514		1.75	%	$	187,526


¹	Callable quarterly at par until maturity in 2016.

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)	2013			2012			2011
Amount outstanding as of December 31	$	145		$	146		$	183
Average amount outstanding during the year	$	147		$	173		$	183
Maximum amount outstanding as of any month-end	$	151		$	189		$	186
Weighted-average interest rate as of December 31	1.75		%	1.74		%	1.56		%
Weighted-average interest rate during the year	1.74		%	1.56		%	1.61		%
Weighted-average remaining days to maturity as of December 31	367			489			490

130

Advances from Federal Home Loan Bank.



December 31, 2013	Weighted-average stated rate		Amount
(dollars in thousands)
Due in
2014	—	%	$	—
2015	—		—
2016	—		—
2017	4.28		50,000		¹
2018	1.95		50,000
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. 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, 2013 and 2012.

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, 2013, 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, 2013, ASB was in compliance with the minimum capital requirements under OCC regulations.

In 2013, ASB paid cash dividends of $40 million to HEI, compared to cash dividends of $45 million in 2012. The FRB and OCC approved the dividends.

Related-party transactions. HEI charged ASB $2.3 million, $1.9 million and $1.4 million for general management and administrative services in 2013, 2012 and 2011, respectively. The amounts charged by HEI for services performed by HEI employees to its subsidiaries are allocated primarily on the basis of time expended in providing such services.

Derivative Financial Instruments. ASB enters into interest rate lock commitments 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 interest rate lock commitments (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.

131

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 as of December 31, 2013 and 2012 were as follows:



	2013				2012
(dollars in thousands)	Notional amount		Fair value		Notional amount		Fair value
Interest rate lock commitments	$	25,070	$	464	$	60,428	$	—
Forward commitments	26,018		139		86,563		—

The following table presents ASB’s derivative financial instruments, their fair values, and balance sheet location as of December 31, 2013 and 2012:



Derivative Financial Instruments Not Designated
as Hedging Instruments ¹	2013				2012
(dollars in thousands)	Asset derivative		Liability derivative		Asset derivative		Liability derivative
Interest rate lock commitments	$	488	$	24	$	—	$	—
Forward commitments	141		2		—		—
	$	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 for the years ended December 31, 2013, 2012 and 2011.



Derivative Financial Instruments Not Designated	Location of net gains
as Hedging Instruments	(losses) recognized in
(dollars in thousands)	the Statement of Income	2013		2012		2011
Interest rate lock commitments	Mortgage banking income	$	464	$	—	$	—
Forward commitments	Mortgage banking income	139		—		—
		$	603	$	—	$	—

There were no significant gains or losses on derivatives in 2012 or 2011.

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 have filed a notice of appeal shortly after the approval was issued. As of December 31, 2013, ASB had accrued $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.

Federal Deposit Insurance Corporation restoration plan. In November 2009, the Board of Directors of the Federal Deposit Insurance Corporation (FDIC) approved a restoration plan that required banks to prepay, by December 30, 2009, their estimated quarterly, risk-based assessments for the fourth quarter of 2009, and for all of 2010, 2011 and 2012. For the fourth quarter of 2009 and all of 2010, the prepaid assessment rate was assessed according to a risk-based premium schedule adopted earlier in 2009. The prepaid assessment rate for 2011 and 2012 was the current assessment rate plus 3 basis points. The prepaid assessment was recorded as a prepaid asset as of December 30, 2009, and each quarter thereafter ASB recorded a charge to earnings for its regular quarterly assessment and offset the prepaid expense until the asset was exhausted. ASB’s prepaid assessment was approximately $24 million. For the year ended December 31, 2010, ASB’s assessment rate was 14 basis points of deposits, or $5.7 million.

In February 2011, the 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-

132

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, 2013 and 2012, ASB’s FDIC insurance assessments were $2.9 million and $3.0 million, respectively. In June 2013, the FDIC returned the remaining amount of the prepaid assessment. The cash received was included in the change in other assets and liabilities on HEI’s consolidated statements of cash flows.

The FDIC may impose additional 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.

Litigation. 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. The lawsuit is still in its preliminary stage. ASB filed a motion to dismiss the lawsuit on the basis that as a bank chartered under federal law, ASB believes its business practices are governed by federal regulations established for federal savings banks and not by state law. In July 2011, the Circuit Court denied ASB’s motion and ASB appealed that decision. ASB’s appeal is currently pending before the Hawaii Supreme Court. The probable outcome and range of reasonably possible loss remains indeterminable at this time.

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.

5 · 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, 2013 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 2013 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, 2013, the Utilities had six 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:

133



Years ended December 31	2013		2012		2011
(in millions)
AES Hawaii	$	134	$	146	$	133
Kalaeloa	301		310		310
HEP	51		65		59
HPOWER	61		65		62
Other IPPs	164		138		126
Total IPPs	$	711	$	724	$	690

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 2013, the Utilities sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa later agreed to provide the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as Hawaii Electric Light and Maui Electric do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Consolidated Financial Statements. The consolidation of any significant IPP could have a material effect on the Consolidated Financial Statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Utilities determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Utilities would retrospectively apply accounting standards for VIEs.

Kalaeloa Partners, L.P. In October 1988, Hawaiian Electric entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that Hawaiian Electric would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, Hawaiian Electric and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that Hawaiian Electric makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that Hawaiian Electric makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

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, 2013, Hawaiian Electric’s accounts payable to Kalaeloa amounted to $23 million.

134

6 · Interest rate swap agreements

In June 2010, HEI entered into multiple Forward Starting Swaps (FSS) with notional amounts totaling $125 million to hedge against interest rate fluctuations on medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to better forecast its future interest expense. The FSS entitled HEI to receive/(pay) the present value of the positive/(negative) difference between three-month LIBOR and a fixed rate at termination applied to the notional amount over a five-year period. The outstanding FSS were designated and accounted for as cash flow hedges. Changes in fair value were recognized (1) in other comprehensive income to the extent that they were considered effective, and (2) in “Interest expense—other than on deposit liabilities and other bank borrowings” for any portion considered ineffective.

In 2011, HEI settled the FSS for payments totaling $5.2 million, of which $3.3 million was the ineffective portion ($2.5 million recognized in 2011) and $1.9 million being amortized to interest expense over 5 years beginning March 24, 2011 (the date that HEI issued $125 million of Senior Notes via a private placement).

7 · Short-term borrowings

As of December 31, 2013 and 2012, HEI had $105 million and $84 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 0.7% and 0.9%, respectively, and Hawaiian Electric had no commercial paper outstanding.

As of December 31, 2013, HEI and Hawaiian Electric each maintained a syndicated credit facility of $125 million and $175 million, respectively. HEI borrowed under its facility in August 2012 and repaid such borrowings in the same month. HEI had no borrowings under its facility during 2013 and Hawaiian Electric had no borrowings under its facility during 2013 and 2012. None of the facilities are collateralized.

Credit agreements.

HEI. Effective December 5, 2011, HEI and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of HEI’s $125 million line of credit facility (with a letter of credit sub-facility) and extended the term of the facility to December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 basis points; or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement contains customary conditions which must be met in order to draw on it, including compliance with its 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, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements may result in an event of default. For example, under its agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 18% as of December 31, 2013, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.8 billion as of December 31, 2013, as calculated under the agreement), or if HEI no longer owns Hawaiian Electric.

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. Effective December 5, 2011, Hawaiian Electric and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of Hawaiian Electric’s $175 million line of credit facility (with a letter of credit sub-facility). The credit agreement, as amended, has a term which expires on December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 basis points; or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement contains customary conditions that must be met in order to draw on the credit facility, 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

135

guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for Hawaii Electric Light and 43% for Maui Electric as of December 31, 2013, 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 56% as of December 31, 2013, as calculated under the credit agreement), or if Hawaiian Electric is no longer owned by HEI.

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

8 · Long-term debt



December 31	2013		2012
(dollars in thousands)
Long-term debt of Utilities¹	$	1,217,945	$	1,147,872
HEI medium-term note 5.25%, due 2013	—		50,000
HEI medium-term note 6.51%, due 2014	100,000		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		—
	$	1,492,945	$	1,422,872


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

As of December 31, 2013, the aggregate principal payments required on the Company's long-term debt for 2014 through 2018 are $111 million in 2014, nil in 2015, $75 million in 2016, nil in 2017 and $50 million in 2018. As of December 31, 2013, the aggregate payments of principal required on the Utilities' long-term debt for 2014 through 2018 are $11 million in 2014, nil in 2015, 2016 and 2017, and $50 million in 2018.

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 December 5, 2016. 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 December 5, 2016.

March 6, 2013 senior notes. On March 6, 2013, HEI entered into a First Supplement (the First Supplement) to the Master Note Purchase Agreement dated March 24, 2011. Under the First Supplement, HEI issued $50 million of its unsecured, 3.99% Series 2013A Senior Notes, due March 6, 2023, via a private placement. The net proceeds from the issuance of the Notes were used by HEI to refinance $50 million of its unsecured, 5.25% Medium-Term Notes, Series D, which matured on March 7, 2013.

October 3, 2013 senior notes. On October 3, 2013, Hawaiian Electric, Hawaii Electric Light and Maui Electric each entered into its separate note purchase agreement with various purchasers of their taxable unsecured senior notes (Notes) with an aggregate principal amount of $236 million. The Utilities issued through a private placement the following notes:

136



(in millions)	Maturity	Hawaiian Electric		Hawaii Electric Light		Maui Electric		Hawaiian Electric Consolidated
3.83% Senior Notes ¹	July 1, 2020	$	—	$	14	$	—	$	14
4.45% Senior Notes ¹	December 1, 2022	40		12		—		52
4.84% Senior Notes ¹	October 1, 2027	50		30		20		100
5.65% Senior Notes ²	October 1, 2043	50		—		20		70
Total		$	140	$	56	$	40	$	236


¹	Proceeds were used in October 2013 to redeem the following special purpose revenue bonds (SPRBs) and refunding SPRBs of the same maturities issued by the Department of Budget and Finance of the State of Hawaii for the benefit of the Utilities in an aggregate principal amount of $166 million:



Series	Year of maturity
4.75% Refunding Series 2003A Bonds	2020
5.00% Refunding Series 2003B Bonds	2022
5.65% Series 1997A Bonds	2027


²	Proceeds were used by the respective utility to finance their capital expenditures and/or for the reimbursement of funds used for the payment of capital expenditures.

Hawaiian Electric has guaranteed the obligations of Hawaii Electric Light and Maui Electric under their respective Notes.

9 · Shareholders’ equity

Reserved shares. As of December 31, 2013, HEI had reserved (a) a total of 16,231,674 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 5.7 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.

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. The equity forward transactions must be settled fully by March 25, 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 March 25, 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 480, "Distinguishing Liabilities from Equity," and ASC 815, "Derivatives and Hedging," and that they qualified for an exception from derivative accounting under ASC 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. HEI anticipates settling the remaining 5.7 million shares remaining under the equity forward transactions through physical settlement.

137

At December 31, 2013, the 5.7 million shares remaining under the equity forward transactions could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $141 million. At December 31, 2013, the shares remaining under the equity forward transactions could also have been cash settled, with delivery of cash of approximately $5 million (which amount includes $6 million of underwriting discount) to the forward counterparty, or net share settled with delivery of approximately 188,000 shares of common stock to the forward counterparty.

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 at the end of that reporting period). 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 2013, the equity forward transactions did not have a material dilutive effect on HEI’s EPS.

Accumulated other comprehensive income/(loss). Reclassifications out of AOCI were as follows:



	Amount reclassified from AOCI
Years ended December 31	2013			2012			2011			Affected line item in the Statement of Income
(in thousands)
HEI consolidated
Net realized gains on securities	$	(738	)	$	(81	)	$	(224	)	Revenues-bank (net gains on sales of securities)
Derivatives qualified as cash flow hedges
Interest rate contracts (settled in 2011)	235			236			181			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	23,280			15,291			9,364			See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(222,595		)	75,471			100,692			See Note 10 for additional details
Total reclassifications	$	(199,818	)	$	90,917		$	110,013
Hawaiian Electric consolidated
Retirement benefit plan items
Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost	$	20,694		$	13,673		$	8,372		See Note 10 for additional details
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets	(222,595		)	75,471			100,692			See Note 10 for additional details
Total reclassifications	$	(201,901	)	$	89,144		$	109,064

138

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. The elimination of the electric discount benefit will generate credits through other benefit costs over the next few years as the total amendment credit is amortized. 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

139

expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.2 million in 2013 and $1.6 million in 2012) 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 $(364) million pretax and $124 million pretax for 2013 and 2012, 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, 2013, 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 2013, 2012 and 2011 was $30 million, $32 million and $34 million, respectively.

Retirement benefit plan changes. On March 11, 2011, the Utilities’ bargaining unit employees ratified a new benefit agreement, which included changes to retirement benefits. Changes to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a modified defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries) (with a lower payment formula than the formula in the plan for employees hired before May 1, 2011) and the addition of a 50% match by the applicable employer on the first 6% of employee elective deferrals by such employees through the defined contribution plan (under the HEIRSP). In addition, new eligibility rules and contribution levels applicable to existing and new HEI and utility employees were adopted for postretirement welfare benefits. In general, defined pension benefits are based on the employees’ years of service and compensation.

140

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 2013 and 2012 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, 2013 and 2012 were as follows:



	2013						2012
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
HEI consolidated
Benefit obligation, January 1	$	1,590,304		$	194,135		$	1,322,430		$	190,549
Service cost	56,405			4,306			43,221			4,211
Interest cost	64,788			7,569			67,480			9,009
Actuarial losses (gains)	(203,302		)	(21,743		)	217,205			(1,991		)
Benefits paid and expenses	(61,904		)	(8,168		)	(60,032		)	(7,643		)
Benefit obligation, December 31	1,446,291			176,099			1,590,304			194,135
Fair value of plan assets, January 1	971,314			156,731			839,580			142,992
Actual return on plan assets	194,130			29,164			115,794			18,477
Employer contributions	82,083			954			74,923			2,780
Benefits paid and expenses	(60,858		)	(7,519		)	(58,983		)	(7,518		)
Fair value of plan assets, December 31	1,186,669			179,330			971,314			156,731
Accrued benefit asset (liability), December 31	$	(259,622	)	$	3,231		$	(618,990	)	$	(37,404	)
Other assets	$	24,948		$	7,200		$	—		$	—
Defined benefit pension and other postretirement benefit plans liability	(284,570		)	(3,969		)	(618,990		)	(37,404		)
Accrued benefit asset (liability), December 31	$	(259,622	)	$	3,231		$	(618,990	)	$	(37,404	)
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)	$	680,781		$	18,846		$	533,537		$	28,684
Recognized during year – net recognized transition obligation	—			—			(1		)	—
Recognized during year – prior service credit	97			1,793			325			1,793
Recognized during year – net actuarial losses	(38,438		)	(1,602		)	(25,675		)	(1,498		)
Occurring during year – net actuarial losses (gains)	(324,896		)	(40,759		)	172,595			(10,133		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	317,544			(21,722		)	680,781			18,846
Cumulative impact of PUC D&Os	(294,266		)	19,206			(621,310		)	(18,123		)
AOCI debit/(credit), December 31	$	23,278		$	(2,516	)	$	59,471		$	723
Net actuarial loss (gain)	$	317,639		$	(5,840	)	$	680,973		$	36,521
Prior service gain	(95		)	(15,882		)	(192		)	(17,675		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	317,544			(21,722		)	680,781			18,846
Cumulative impact of PUC D&Os	(294,266		)	19,206			(621,310		)	(18,123		)
AOCI debit/(credit), December 31	23,278			(2,516		)	59,471			723
Income taxes (benefits)	(9,180		)	980			(23,489		)	(281		)
AOCI debit/(credit), net of taxes (benefits), December 31	$	14,098		$	(1,536	)	$	35,982		$	442

141



	2013						2012
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Hawaiian Electric consolidated
Benefit obligation, January 1	$	1,449,445		$	187,110		$	1,203,943		$	184,240
Service cost	54,482			4,163			41,603			4,014
Interest cost	59,119			7,288			61,453			8,703
Actuarial losses (gains)	(185,185		)	(20,900		)	197,718			(2,301		)
Benefits paid and expenses	(57,051		)	(8,082		)	(55,272		)	(7,546		)
Benefit obligation, December 31	1,320,810			169,579			1,449,445			187,110
Fair value of plan assets, January 1	861,778			154,186			752,285			140,764
Actual return on plan assets	172,822			28,700			103,941			18,206
Employer contributions	80,325			839			60,442			2,634
Benefits paid and expenses	(56,665		)	(7,434		)	(54,890		)	(7,418		)
Fair value of plan assets, December 31	1,058,260			176,291			861,778			154,186
Accrued benefit asset (liability), December 31	$	(262,550	)	$	6,712		$	(587,667	)	$	(32,924	)
Other assets	$	—		$	7,200		$	—		$	—
Other liabilities (short-term)	(388		)	(488		)	(386		)	—
Defined benefit pension and other postretirement benefit plans liability	(262,162		)	—			(587,281		)	(32,924		)
Accrued benefit asset (liability), December 31	$	(262,550	)	$	6,712		$	(587,667	)	$	(32,924	)
AOCI debit/(credit), January 1 (excluding impact of PUC D&Os)	$	623,588		$	17,432		$	488,556		$	27,390
Recognized during year – net recognized transition asset	—			—			—			9
Recognized during year – prior service credit	464			1,803			689			1,803
Recognized during year – net actuarial losses	(34,597		)	(1,544		)	(23,428		)	(1,455		)
Occurring during year – net actuarial losses (gains)	(293,482		)	(39,598		)	157,771			(10,315		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	295,973			(21,907		)	623,588			17,432
Cumulative impact of PUC D&Os	(294,266		)	19,206			(621,310		)	(18,123		)
AOCI debit/(credit), December 31	$	1,707		$	(2,701	)	$	2,278		$	(691	)
Net actuarial loss (gain)	$	295,825		$	(6,001	)	$	623,904		$	35,141
Prior service cost (gain)	148			(15,906		)	(316		)	(17,709		)
AOCI debit/(credit) before cumulative impact of PUC D&Os, December 31	295,973			(21,907		)	623,588			17,432
Cumulative impact of PUC D&Os	(294,266		)	19,206			(621,310		)	(18,123		)
AOCI debit/(credit), December 31	1,707			(2,701		)	2,278			(691		)
Income taxes (benefits)	(664		)	1,050			(886		)	269
AOCI debit/(credit), net of taxes (benefits), December 31	$	1,043		$	(1,651	)	$	1,392		$	(422	)

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2013, 2012 and 2011.

On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding and administration of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. 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 April 1, 2011 to September 30, 2012) for HEI and the Utilities. MAP-21 caused the minimum required funding under ERISA to be less than the net periodic cost for 2013 and is expected to have the same effect in 2014; therefore, to satisfy the requirements of the Utilities pension and OPEB tracking mechanisms, the Utilities expect to contribute the net periodic cost in 2014.

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 fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. However, the

142

HEI Retirement Plan met the threshold requirements in each of 2012 and 2013 so that the more conservative assumptions do 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 weighted-average asset allocation of defined benefit retirement plans was as follows:



	Pension benefits							Other benefits
					Investment policy							Investment policy
December 31	2013		2012		Target		Range	2013		2012		Target		Range
Asset category
Equity securities	73	%	69	%	70	%	65-75	74	%	70	%	70	%	65-75
Fixed income	27		31		30		25-35	26		30		30		25-35
	100	%	100	%	100	%		100	%	100	%	100	%

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	2013		2012		2011		2013		2012		2011
Benefit obligation
Discount rate	5.09	%	4.13	%	5.19	%	5.03	%	4.07	%	4.90	%
Rate of compensation increase	3.5		3.5		3.5		NA		NA		NA
Net periodic benefit cost (years ended)
Discount rate	4.13		5.19		5.68		4.07		4.90		5.60
Expected return on plan assets	7.75		7.75		8.00		7.75		7.75		8.00
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 2014 NPBC and December 31, 2013 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, 2013. In selecting the expected rate of return on plan assets of 7.75% for 2014 NPBC, the Company 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.

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%. As of December 31, 2012, the assumed health care trend rates for 2013 and future years were as follows: medical, 8.0%, grading down to 5% for 2019 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 2013 through 2014 and 3% higher in 2015.

The components of NPBC were as follows:

143



	Pension benefits									Other benefits
(in thousands)	2013			2012			2011			2013			2012			2011
HEI consolidated
Service cost	$	56,405		$	43,221		$	35,016		$	4,306		$	4,211		$	4,409
Interest cost	64,788			67,480			64,966			7,569			9,009			9,534
Expected return on plan assets	(72,537		)	(71,183		)	(68,901		)	(10,147		)	(10,336		)	(10,650		)
Amortization of net transition obligation	—			1			2			—			—			—
Amortization of net prior service gain	(97		)	(325		)	(389		)	(1,793		)	(1,793		)	(1,494		)
Amortization of net actuarial loss	38,438			25,675			16,987			1,602			1,498			234
Net periodic benefit cost	86,997			64,869			47,681			1,537			2,589			2,033
Impact of PUC D&Os	(38,104		)	(15,754		)	(3,516		)	(1,458		)	(2,227		)	2,674
Net periodic benefit cost (adjusted for impact of PUC D&Os)	48,893			49,115			44,165			79			362			4,707
Hawaiian Electric consolidated
Service cost	$	54,482		$	41,603		$	33,627		$	4,163		$	4,014		$	4,238
Interest cost	59,119			61,453			59,077			7,288			8,703			9,228
Expected return on plan assets	(64,551		)	(64,004		)	(61,615		)	(10,002		)	(10,195		)	(10,508		)
Amortization of net transition obligation	—			—			—			—			(9		)	(8		)
Amortization of net prior service gain	(464		)	(689		)	(747		)	(1,803		)	(1,803		)	(1,505		)
Amortization of net actuarial loss	34,597			23,428			15,752			1,544			1,455			212
Net periodic benefit cost	83,183			61,791			46,094			1,190			2,165			1,657
Impact of PUC D&Os	(38,104		)	(15,754		)	(3,516		)	(1,458		)	(2,227		)	2,674
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	45,079		$	46,037		$	42,578		$	(268	)	$	(62	)	$	4,331

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 2014 is as follows:



	HEI consolidated					Hawaiian Electric consolidated
(in millions)	Pension benefits		Other benefits			Pension benefits		Other benefits
Estimated prior service cost (credit)	$	0.1	$	(1.8	)	$	0.1	$	(1.8	)
Net actuarial loss	20.2		—			18.2		—
Net transition obligation	—		—			—		—

The Company recorded pension expense of $34 million, $35 million and $32 million and OPEB expense of $0.4 million, $1 million and $4 million in 2013, 2012 and 2011, respectively, and charged the remaining amounts primarily to electric utility plant. The Utilities recorded pension expense of $30 million, $32 million and $31 million and OPEB expense of nil, $0.4 million and $3 million in 2013, 2012 and 2011, 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, 2013, 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 $0.3 million and the accumulated postretirement benefit obligation (APBO) by $4.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the APBO by $4.9 million. As of December 31, 2013, 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 $0.3 million and the APBO by $4.5 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the APBO by $4.8 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, 2013 and 2012, had aggregate ABOs of $1.2 billion and $1.4 billion, respectively, and plan assets of $1.1 billion and $1.0 billion, respectively. 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, 2012, all the defined benefit pension plans shown in the table above had PBOs in excess of plan assets. The other postretirement benefit plans with ABOs in excess of plan assets as of December 31, 2013 had aggregate ABOs of $0.4 million and plan assets of nil. As of December 31, 2012, all the other postretirement benefit plans shown in the table above had ABOs in excess of plan assets.

144

The Company estimates that the cash funding for the qualified defined benefit pension plans in 2014 will be $59 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 2014 is de minimis.

As of December 31, 2013, the benefits expected to be paid under all retirement benefit plans in 2014, 2015, 2016, 2017, 2018 and 2019 through 2023 amounted to $72 million, $75 million, $78 million, $81 million, $85 million and $483 million, respectively.

Hawaiian Electric consolidated. The defined benefit pension plans with ABOs in excess of plan assets as of December 31, 2013 and 2012, had aggregate ABOs of $1.2 billion and $1.2 billion, respectively, and plan assets of $1.1 billion and $0.9 billion, respectively. All the defined benefit pension plans shown in the table above had PBOs in excess of plan assets as of December 31, 2013 and 2012. As of December 31, 2013, the other postretirement benefit plan shown in the table above had plan assets in excess of ABO. As of December 31, 2012, the other postretirement benefit plan shown in the table above had an ABO in excess of plan assets.

The Utilities estimate that the cash funding for the qualified defined benefit pension plan in 2014 will be $58 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 2014 is nil.

As of December 31, 2013, the benefits expected to be paid under all retirement benefit plans in 2014, 2015, 2016, 2017, 2018 and 2019 through 2023 amounted to $67 million, $69 million, $72 million, $75 million, $77 million and $441 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 2013, 2012 and 2011, the Company’s expense for its defined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was $5 million, $4 million and $3 million, respectively, and cash contributions were $4 million for each year. The Utilities’ expense for its defined contribution pension plan under the HEIRSP Plan for 2013 was $0.6 million and for 2012 and 2011 was de minimis.

11 · Share-based compensation

Under the 2010 Equity and Incentive Plan (EIP) HEI can issue shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted stock units, performance shares and other share-based and cash-based awards.

As of December 31, 2013, there were 3.6 million shares remaining available for future issuance under the EIP of which an estimated 2.2 million shares could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals under long-term incentive plans (based on the assumption that long-term incentive plan (LTIP) awards are achieved at maximum levels).

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), there are possible future issuances of an estimated 2,000 shares upon exercise of outstanding stock appreciation rights (SARs) and dividend equivalents based on the market price of shares on December 31, 2013. As of May 11, 2010 (when the EIP 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.

145

The restricted shares that have been issued under the EIP 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.

Restricted stock units awarded under the EIP in 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 EIP 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 the 2011-2013, 2012-2014 and 2013-2015 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, 2013, there were 202,460 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)	2013		2012		2011
Share-based compensation expense ¹	$	7.8	$	6.7	$	4.3
Income tax benefit	2.8		2.4		1.5


¹	The Company has not capitalized any share-based compensation cost.

The Company has revised its prior year disclosure to correct for an error that excluded from the disclosure amounts for stock awards to non-employee directors of HEI, Hawaiian Electric and ASB. The amounts excluded from the disclosure were not considered to be material to previously issued financial statements. The table below illustrates the effects of this revision on the previous disclosure (the revised disclosure had no impact on the Company’s Consolidated Balance Sheets, Consolidated Statements of Income or Consolidated Statements of Cash Flows):



	2012						2011
(in millions)	As previously filed		As revised		Difference		As previously filed		As revised		Difference
Share-based compensation expense	$	5.9	$	6.7	$	0.8	$	3.8	$	4.3	$	0.5
Income tax benefit	2.0		2.4		0.4		1.3		1.5		0.2

Stock awards. HEI granted HEI common stock to nonemployee directors of HEI, Hawaiian Electric and ASB under the 2011 Director Plan as follows:



($ in millions)	2013		2012		2011
Shares granted	33,184		29,448		34,908
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.

146

Nonqualified stock options. Information about HEI’s NQSOs was as follows:



	2013				2012				2011
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	14,000		$	20.49	55,500		$	20.92	215,500		$	20.76
Granted	—		—		—		—		—		—
Exercised	(14,000	)	20.49		(41,500	)	21.06		(160,000	)	20.70
Forfeited	—		—		—		—		—		—
Expired	—		—		—		—		—		—
Outstanding, December 31	—		$	—	14,000		$	20.49	55,500		$	20.92
Exercisable, December 31	—		$	—	14,000		$	20.49	55,500		$	20.92


(1)	Weighted-average exercise price

As of December 31, 2013, there were no NQSOs outstanding.

NQSO activity and statistics were as follows:



(dollars in thousands)	2013		2012		2011
Cash received from exercise	$	287	$	874	$	3,312
Intrinsic value of shares exercised ¹	128		354		1,270
Tax benefit realized for the deduction of exercises	50		138		181


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:



	2013			2012				2011
	Shares	(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	164,000	$	26.12	282,000		$	26.14	450,000		$	26.13
Granted	—	—		—		—		—		—
Exercised	—	—		(114,000	)	26.17		(110,000	)	26.09
Forfeited	—	—		—		—		—		—
Expired	—	—		(4,000	)	26.18		(58,000	)	26.13
Outstanding, December 31	164,000	$	26.12	164,000		$	26.12	282,000		$	26.14
Exercisable, December 31	164,000	$	26.12	164,000		$	26.12	282,000		$	26.14


(1)	Weighted-average exercise price



December 31, 2013		Outstanding & Exercisable (Vested)
Year of Grant	Range of exercise prices	Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price
2004	$26.02	62,000	0.3	$	26.02
2005	26.18	102,000	1.3	26.18
	$26.02 –26.18	164,000	0.9	$	26.12

As of December 31, 2013, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.1 million.

SARs activity and statistics were as follows:



(dollars in thousands, except prices)	2013		2012		2011
Intrinsic value of shares exercised ¹	$	—	$	197	$	64
Tax benefit realized for the deduction of exercises	—		77		25


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.

147

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



	2013				2012				2011
	Shares		(1)		Shares		(1)		Shares		(1)
Outstanding, January 1	9,005		$	22.21	46,807		$	24.45	89,709		$	24.64
Granted	—		—		—		—		—		—
Vested	(4,502	)	22.21		(37,802	)	24.99		(40,102	)	24.83
Forfeited	—		—		—		—		(2,800	)	24.93
Outstanding, December 31	4,503		$	22.21	9,005		$	22.21	46,807		$	24.45


(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 2013, 2012 and 2011, total restricted stock vested had a grant-date fair value of $0.1 million, $0.9 million and $1.0 million, respectively, and the tax benefits realized for the tax deductions related to restricted stock awards were nil for 2013, $0.2 million for 2012 and $0.2 million for 2011.

As of December 31, 2013, there was $0.1 million of total unrecognized compensation cost related to nonvested restricted shares and restricted stock awards. The cost is expected to be recognized over a weighted-average period of 0.9 years.

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



	2013					2012					2011
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	315,094			$	22.82	247,286			$	21.80	146,500			$	19.80
Granted	111,231			26.88		98,446			25.99		101,786			24.68
Vested	(118,885		)	20.48		(25,728		)	24.68		—			—
Forfeited	(19,289		)	25.62		(4,910		)	24.92		(1,000		)	22.60
Outstanding, December 31	288,151			$	25.17	315,094			$	22.82	247,286			$	21.80
Total weighted-average grant-date fair value of shares granted ($ millions)	$	3.0				$	2.6				$	2.5


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

For 2013 and 2012, total restricted stock units that vested and related dividends had a grant-date fair value of $2.4 million and $0.7 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively.

As of December 31, 2013, there was $3.7 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.

LTIP payable in stock. The 2011-2013 LTIP, 2012-2014 LTIP and 2013-2015 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 2011-2013 LTIP, 2012-2014 LTIP and 2013-2015 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on average common equity (ROACE), Hawaiian Electric consolidated net income, Hawaiian Electric consolidated ROACE, ASB net income and ASB return on assets – all based on the applicable three-year averages.

148

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



	2013					2012					2011
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	239,256			$	29.12	197,385			$	25.94	126,782			$	20.33
Granted	91,038			32.69		81,223			30.71		75,015			35.46
Vested (settled or lapsed)	(87,753		)	22.45		(35,397		)	14.85		—			—
Forfeited	(10,414		)	32.72		(3,955		)	30.82		(4,412		)	29.56
Outstanding, December 31	232,127			$	32.88	239,256			$	29.12	197,385			$	25.94
Total weighted-average grant-date fair value of shares granted ($ millions)	$	3.0				$	2.5				$	2.7


(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:



	2013			2012			2011
Risk-free interest rate	0.38		%	0.33		%	1.25		%
Expected life in years	3			3			3
Expected volatility	19.4		%	25.3		%	27.8		%
Range of expected volatility for Peer Group	12.4% to 25.3%			15.5% to 34.5%			21.2% to 82.6%
Grant date fair value (per share)	$	32.69		$	30.71		$	35.46

For 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $2.2 million and $0.6 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively. 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, 2013, there was $2.4 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 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:



	2013					2012					2011
	Shares			(1)		Shares			(1)		Shares			(1)
Outstanding, January 1	247,175			$	25.04	182,498			$	22.63	161,310			$	18.66
Granted	120,399			26.89		125,157			26.05		113,831			24.96
Vested and settled	(18,280		)	18.95		—			—		—			—
Cancelled	(41,599		)	24.97		(50,786		)	18.95		(81,908		)	18.38
Forfeited	(10,852		)	26.20		(9,694		)	24.44		(10,735		)	20.12
Outstanding, December 31	296,843			$	26.14	247,175			$	25.04	182,498			$	22.63
Total weighted-average grant-date fair value of shares granted (at target performance levels) ($ millions)	$	3.2				$	3.3				$	2.8


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

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

149

As of December 31, 2013, there was $3.1 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	2013			2012			2011			2013			2012			2011
(in thousands)
Federal
Current	$	(1,520	)	$	(15,411	)	$	(7,639	)	$	1,313		$	(26,965	)	$	(10,820	)
Deferred	73,680			82,138			73,495			58,024			79,437			64,646
Deferred tax credits, net	224			187			—			224			186			—
	72,384			66,914			65,856			59,561			52,658			53,826
State
Current	(1,555		)	(4,654		)	2,437			(3,720		)	(4,940		)	1,226
Deferred	6,719			8,710			5,949			6,483			7,441			4,445
Deferred tax credits, net	6,793			5,889			1,690			6,793			5,889			2,087
	11,957			9,945			10,076			9,556			8,390			7,758
Total	$	84,341		$	76,859		$	75,932		$	69,117		$	61,048		$	61,584

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	2013			2012			2011			2013			2012			2011
(in thousands)
Amount at the federal statutory income tax rate	$	86,711		$	76,092		$	75,618		$	67,914		$	56,812		$	57,248
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	7,772			6,464			6,550			6,211			5,453			5,042
Other, net	(10,142		)	(5,697		)	(6,236		)	(5,008		)	(1,217		)	(706		)
Total	$	84,341		$	76,859		$	75,932		$	69,117		$	61,048		$	61,584
Effective income tax rate	34.0		%	35.4		%	35.1		%	35.6		%	37.6		%	37.7		%

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”). The Company's effective tax rate increased slightly from 2011 to 2012 due primarily to lower utility tax credit amortization and its lower relative impact on higher operating income in 2012, and tax-free bank-owned life insurance proceeds received in 2011.

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

150



	HEI consolidated				Hawaiian Electric consolidated
December 31	2013		2012		2013		2012
(in thousands)
Deferred tax assets
Allowance for loan losses	$	16,172	$	17,254	$	—	$	—
Retirement benefits	—		266		—		—
Net operating loss	—		—		19,848		6,413
Other	41,067		34,354		17,295		13,986
Total deferred tax assets	57,239		51,874		37,143		20,399
Deferred tax liabilities
Property, plant and equipment related	378,280		316,900		375,771		315,409
Goodwill	23,781		23,781		—		—
Regulatory assets, excluding amounts attributable to property, plant and equipment	33,251		33,071		33,251		33,071
FHLB stock dividend	18,847		20,062		—		—
Repairs deduction	75,127		69,514		75,127		69,514
Retirement benefits	29,280		—		23,851		8,688
Other	27,933		27,875		15,602		11,328
Total deferred tax liabilities	586,499		491,203		523,602		438,010
Net deferred income tax liability	$	529,260	$	439,329	$	486,459	$	417,611
Prepayments and other	$	—	$	—	$	20,702	$	—
Deferred income taxes	529,260		439,329		507,161		417,611
Net deferred income tax liability	$	529,260	$	439,329	$	486,459	$	417,611

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, 2013, the valuation allowance for deferred tax benefits is not significant. In 2013, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation (resulting from the American Taxpayer Relief Act of 2012). 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) 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, 2013, standalone Hawaiian Electric consolidated expects a $55 million (pretax) NOL for federal tax purposes in accordance with the HEI tax sharing agreement. The deferred tax asset associated with this NOL is included in “Prepayments and other.”

HEI consolidated. In 2013, 2012 and 2011, 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 $0.3 million, $1.4 million and $1.2 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, 2013 and 2012, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and dividends payable” was $0.4 million and $0.3 million, respectively.

As of December 31, 2013, the total amount of liability for uncertain tax positions was $0.9 million and, of this amount, $0.7 million, if recognized, would affect the Company’s effective tax rate. The Company’s unrecognized tax benefits are primarily the result of differences relating to the tax basis of property and equipment.

Hawaiian Electric consolidated. In 2013, 2012 and 2011, credit adjustments to interest expense on income taxes was reflected in “Interest and other charges” in the amount of $0.3 million, $0.5 million and $1.0 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 2013 and 2012, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and preferred dividends payable” was de minimis.

151

As of December 31, 2013, the total amount of liability for uncertain tax positions was $0.5 million and, if recognized, would affect the Utilities' effective tax rate. The Utilities' unrecognized tax benefits are primarily the result of differences relating to the tax basis of property and equipment.

The changes in total unrecognized tax benefits were as follows:



	HEI consolidated									Hawaiian Electric consolidated
(in millions)	2013			2012			2011			2013			2012			2011
Unrecognized tax benefits, January 1	$	0.8		$	5.7		$	15.4		$	0.4		$	3.7		14.2
Additions based on tax positions taken during the year	—			0.3			—			—			0.3			—
Reductions based on tax positions taken during the year	—			—			(0.6		)	—			—			(0.6		)
Additions for tax positions of prior years	0.5			—			0.1			0.5			—			—
Reductions for tax positions of prior years	(0.4		)	(4.1		)	(8.1		)	(0.4		)	(3.6		)	(8.8		)
Settlements	—			—			—			—			—			—
Lapses of statute of limitations	—			(1.1		)	(1.1		)	—			—			(1.1		)
Unrecognized tax benefits, December 31	$	0.9		$	0.8		$	5.7		$	0.5		$	0.4		$	3.7

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. The 2011 reduction in unrecognized tax benefits was primarily due to the IRS’s issuance of guidance (Revenue Procedure 2011-43, issued in August 2011) on the deductibility of costs of repairs to utility transmission and distribution (T&D) property, including a “safe harbor” method under which taxpayers could transition and minimize the uncertainty of the repairs expense deduction for T&D property. The Company elected the “safe harbor” method in its 2011 tax return, which resulted in the reduction of associated unrecognized tax benefits for 2011.

The IRS is currently auditing tax years 2010 and 2011. Tax years 2007 to 2012 remain subject to examination by the Department of Taxation of the State of Hawaii.

As of December 31, 2013, 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 is currently evaluating the impact of these new regulations, but 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. 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 continues to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when an election should be made.

152

13 · Cash flows



Years ended December 31	2013			2012			2011
(in millions)
Supplemental disclosures of cash flow information
HEI consolidated
Interest paid to non-affiliates	$	85		$	84		$	97
Income taxes paid (refunded)	14			(14		)	(22		)
Hawaiian Electric consolidated
Interest paid to non-affiliates	59			57			58
Income taxes refunded	(26		)	(3		)	(23		)
Supplemental disclosures of noncash activities
HEI consolidated
Common stock dividends reinvested in HEI common stock ¹	24			24			12
Increases in common stock related to director and officer compensatory plans	5			6			8
Loans transferred from held for investment to held for sale	25			—			6
Real estate acquired in settlement of loans	4			11			12
Hawaiian Electric consolidated
Electric utility property, plant and equipment
AFUDC-equity	6			7			6
Estimated fair value of noncash contributions in aid of construction	5			10			7
Unpaid invoices and other	24			37			45


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, 2013, the Utilities could not transfer approximately $674 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 ASHI). 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, 2013, ASB could transfer approximately $91 million of net assets to HEI in the form of dividends and still maintain its “well-capitalized” position.

HEI management expects that the regulatory restrictions will not materially affect the operations of the Company nor HEI’s ability to pay common stock dividends.

15 · Significant group concentrations of credit risk

Most of the Company’s business activity is with customers located in the State of Hawaii.

The Utilities are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. The Utilities provide the only electric public utility service on the islands they serve. The Utilities grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

Most of ASB’s financial instruments are based in the State of Hawaii, except for the investment and mortgage-related 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.

153

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:

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.

The Company and/or the Utilities used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

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

Investment and mortgage-related securities. To determine the fair value of investment securities held in ASB’s available-for-sale portfolio, independent third-party vendor or broker pricing is used on an unadjusted basis. Prices for investments and mortgage-related securities are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The third party pricing service uses applications, models and pricing matrices that correlate security prices to benchmark securities which are adjusted for various inputs. Inputs include: benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark security bids and offers, TBA (to be announced) prices, monthly payment information, and reference data including market research. The pricing service may prioritize inputs differently on any given day for any security, and not all inputs are available for use in the evaluation process on any given day or for each security. The pricing vendor corroborates its finding on an on-going basis by monitoring market activity and events.

Loans receivable. The estimated fair value of loans receivable is determined based on characteristics such as loan category, repricing features and remaining maturity, and includes prepayment estimates.

For residential real estate loans, fair values were estimated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics and remaining maturity.

154

For other types of loans, fair values were estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.

The fair value of all loans was adjusted to reflect current assessments of loan collectability. Also see “Fair value measurements on a nonrecurring basis” below.

Deposit liabilities. The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. 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 bank borrowings. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

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.

Derivative financial instruments. See “Fair value measurements on a recurring basis” below.

Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements.

155

The estimated fair values of certain of the Company’s and the Utilities' financial instruments were as follows:



			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, 2013
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment and mortgage-related securities	529,007		—		529,007		—		529,007
Investment in stock of 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
December 31, 2012
Financial assets
Money market funds	$	10	$	—	$	10	$	—	$	10
Available-for-sale investment and mortgage-related securities	671,358		—		671,358		—		671,358
Investment in stock of Federal Home Loan Bank of Seattle	96,022		—		96,022		—		96,022
Loans receivable, net	3,763,238		—		—		3,957,752		3,957,752
Financial liabilities
Deposit liabilities	4,229,916		—		4,235,527		—		4,235,527
Short-term borrowings—other than bank	83,693		—		83,693		—		83,693
Other bank borrowings	195,926		—		212,163		—		212,163
Long-term debt, net—other than bank	1,422,872		—		1,481,004		—		1,481,004
The Utilities' long-term debt, net (included in amount above)	1,147,872		—		1,181,631		—		1,181,631

As of December 31, 2013 and 2012, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.6 billion and $1.5 billion, respectively, and their estimated fair value on such dates were $0.2 million and $1.2 million, respectively. As of December 31, 2013 and 2012, loans serviced by ASB for others had notional amounts of $1.4 billion and $1.3 billion, respectively, and the estimated fair value of the servicing rights for such loans was $15.7 million and $11.9 million, respectively.

Fair value measurements on a recurring basis.

Securities. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on

156

market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.

Derivative financial instruments. ASB enters into interest rate lock commitments (IRLC) 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. 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.

ASB utilizes forward commitments as economic hedges against potential changes in the values of the IRLCs and loans held for sale. To reduce the impact of price fluctuations of IRLC and mortgage loans held for sale, ASB will purchase to be announced (TBA) mortgage-backed securities forward commitments, mandatory and best effort commitments. These commitments help protect ASB's loan sale profit margin from fluctuations in interest rates. The changes in the fair value of these commitments are recognized as part of mortgage banking income on the consolidated statements of income. TBA 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 similarly to the IRLCs using quoted prices in the market place that are observable and are classified as Level 2 measurements.

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



	December 31, 2013						December 31, 2012
	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 securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	369,444	$	—	$	—	$	417,383	$	—
Federal agency obligations	—		80,973		—		—		171,491		—
Municipal bonds	—		78,590		—		—		82,484		—
	$	—	$	529,007	$	—	$	—	$	671,358	$	—
Derivative assets ¹
Interest rate lock commitments	$	—	$	488	$	—	$	—	$	—	$	—
Forward commitments	98		43		—		—		—		—
	$	98	$	531	$	—	$	—	$	—	$	—
Derivative liabilities ¹
Interest rate lock commitments	$	—	$	24	$	—	$	—	$	—	$	—
Forward commitments	—		2		—		—		—		—
	$	—	$	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.

Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments based on the current appraised value of the collateral securing the loans or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. See “Goodwill and other intangibles” in Note 1 for ASB’s goodwill valuation methodology. During 2013 and 2012, goodwill was not measured at fair value.

From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. 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 3).

157

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
Loans
December 31, 2013	$	4	$	—	$	—	$	4
December 31, 2012	21		—		—		21
Real estate acquired in settlement of loans
December 31, 2013	—		—		—		—
December 31, 2012	3		—		—		3

For 2013 and 2012, there were no adjustments to fair value for ASB’s loans held for sale.

Residential loans. The fair value of ASB’s residential loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

Home equity lines of credit. The fair value of ASB’s home equity lines of credit that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

Commercial loans. The fair value of ASB’s commercial loans that were written down due to impairment was determined based on the value placed on the assets of the business, and therefore, is classified as a Level 3 measurement.

Real estate acquired in settlement of loans. The fair value of ASB’s real estate acquired in settlement of loans that were written down due to impairment was determined based on third party appraisals, which include the appraisers’ assumptions and judgment, and therefore, is classified as a Level 3 measurement.

For loans and real estate acquired in settlement of loans classified as Level 3 as of December 31, 2013, the significant unobservable inputs used in the fair value measurement were as follows:



	Fair value at				Significant unobservable input value ¹
($ in thousands)	December 31, 2013		Valuation technique	Significant unobservable input	Range	Weighted Average
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:

158



	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
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	$	—
Receivables and payables, net	(46		)							(1		)
Fair value of plan assets	$	1,187								$	179
2012
Equity securities	$	513		$	513	$	—	$	—	$	83		$	83	$	—	$	—
Equity index funds	95			95		—		—		15			15		—		—
Fixed income securities	338			125		213		—		47			41		6		—
Pooled and mutual funds and other	78			1		76		1		13			—		13		—
Total	1,024			$	734	$	289	$	1	158			$	139	$	19	$	—
Receivables and payables, net	(53		)							(1		)
Fair value of plan assets	$	971								$	157

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 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, 2013 and 2012.

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 2013 and 2012, the changes in Level 3 assets were as follows:



	2013					2012
(in thousands)	Pension benefits			Other benefits		Pension benefits			Other benefits
Balance, January 1	$	581		$	18	$	217		$	7
Realized and unrealized losses	(1		)	—		(24		)	(1		)
Purchases and settlements, net	—			—		388			12
Balance, December 31	$	580		$	18	$	581		$	18

159

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
2013
Revenues	$	784,064	$	796,730	$	831,229	$	826,447	$	3,238,470
Operating income	70,657		82,370		90,099		72,293		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
2012
Revenues	$	814,860	$	854,268	$	867,720	$	838,147	$	3,374,995
Operating income	75,816		79,406		91,702		37,272		284,196
Net income ⁴	38,789		39,273		48,177		14,309		140,548
Net income for common stock ⁴	38,316		38,800		47,706		13,836		138,658
Basic earnings per common share ¹	0.40		0.40		0.49		0.14		1.43
Diluted earnings per common share ²	0.40		0.40		0.49		0.14		1.42
Dividends per common share	0.31		0.31		0.31		0.31		1.24
Market price per common share ³
High	26.79		28.87		29.24		26.75		29.24
Low	24.86		24.65		26.26		23.65		23.65
Hawaiian Electric consolidated
2013
Revenues	$	719,273	$	730,688	$	766,115	$	764,096	$	2,980,172
Operating income	52,953		61,138		71,914		59,508		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
2012
Revenues	749,610		789,552		801,095		769,182		3,109,439
Operating income	57,254		61,496		74,819		19,443		213,012
Net income ⁴	27,799		29,875		38,873		4,724		101,271
Net income for common stock ⁴	27,300		29,376		38,375		4,225		99,276

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.


⁴	In the fourth quarter of 2012, as part of a settlement agreement with the Consumer Advocate, the Utilities recorded a writedown of $24 million (net of taxes) of CIS project costs in lieu of conducting regulatory audits of the CIP CT-1 and CIS projects

160



ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

HEI and Hawaiian Electric: None



ITEM 9A.	CONTROLS AND PROCEDURES

HEI:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of December 31, 2013. Based on their evaluations, as of December 31, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:


(1)	is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and


(2)	is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Annual Report of Management on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting was designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of 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, 2013 based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2013.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 77.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Hawaiian Electric:

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Richard M. Rosenblum, Hawaiian Electric Chief Executive Officer, and Tayne S. Y. Sekimura, Hawaiian Electric Chief Financial Officer, have evaluated the disclosure controls and procedures of Hawaiian Electric as of December 31, 2013. Based on their evaluations, as of December 31, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective in ensuring that information required to be disclosed by Hawaiian Electric in reports Hawaiian Electric files or submits under the Securities Exchange Act of 1934:


(1)	is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

161


(2)	is accumulated and communicated to Hawaiian Electric management, including Hawaiian Electric’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Annual Report of Management on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended. Hawaiian Electric’s internal control over financial reporting was designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of 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, 2013 based on on criteria established in Internal Control - Integrated Framework (1992) issued by COSO. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2013.

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, Hawaiian Electric’s internal control over financial reporting.



ITEM 9B.	OTHER INFORMATION

HEI and Hawaiian Electric: None

PART III



ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

HEI:

Information regarding HEI’s executive officers is provided in the “Executive Officers of the Registrant” section following Item 4 of this report.

The remaining information required by this Item 10 for HEI is incorporated herein by reference to the following sections in the HEI 2014 Proxy Statement:


•	“Nominees for Class III directors whose terms expire at the 2017 Annual Meeting”


•	“Continuing Class I directors whose terms expire at the 2015 Annual Meeting”


•	“Continuing Class II directors whose terms expire at the 2016 Annual Meeting”


•	“Committees of the Board” (portions regarding whether HEI has an audit committee and identifying its members; no other portion of the Committees of the Board section is incorporated herein by reference)


•	“Audit Committee Report” (portion identifying audit committee financial experts who serve on the HEI Audit Committee only; no other portion of the Audit Committee Report is incorporated herein by reference)

Family relationships; director arrangements

There are no family relationships between any HEI director or director nominee and any other HEI director or director nominee or any HEI executive officer. There are no arrangements or understandings between any HEI director or director nominee and any other person pursuant to which such director or director nominee was selected.

162

Code of Conduct

The HEI Board has adopted a Corporate Code of Conduct that includes a code of ethics applicable to, among others, its principal executive officer, principal financial officer and principal accounting officer. The Corporate Code of Conduct is available on HEI’s website at www.hei.com. HEI elects to disclose the information required by Form 8-K, Item 5.05, “Amendments to the Registrant’s Code of Ethics, or Waiver of a Provision of the Code of Ethics,” through this website and such information will remain available on this website for at least a 12-month period.

Section 16(a) beneficial ownership reporting compliance

Information required to be reported under this caption is incorporated herein by reference to the “Stock Ownership Information—Section 16(a) Beneficial Ownership Reporting Compliance” section in the HEI 2014 Proxy Statement.

Hawaiian Electric:

The information required by this Item 10 for Hawaiian Electric is incorporated herein by reference to pages 1 to 7 of Hawaiian Electric Exhibit 99.1.



ITEM 11.	EXECUTIVE COMPENSATION

HEI:

The information required by this Item 11 for HEI is incorporated herein by reference to the information relating to executive and director compensation in the HEI 2014 Proxy Statement.

Hawaiian Electric:

The information required by this Item 11 for Hawaiian Electric is incorporated herein by reference to:


•	Pages 7 to 33 of Hawaiian Electric Exhibit 99.1;


•	The discussion of “What is Hawaiian Electric’s 2012-2014 long-term incentive plan?” at pages 19-20 of Hawaiian Electric’s Exhibit 99.3 to Annual Report on Form 10-K for the year ended December 31, 2012; and


•	Information concerning compensation paid to directors of Hawaiian Electric who are also directors of HEI under the section of the HEI 2014 Proxy Statement entitled, “Director Compensation.”

Compensation Committee Interlocks and Insider Participation

HEI:

The information required to be reported under this caption for HEI is incorporated herein by reference to the “Compensation Committee Interlocks and Insider Participation” section in the HEI 2014 Proxy Statement.

Hawaiian Electric:

The information required to be reported under this caption for Hawaiian Electric is incorporated herein by reference to page 21 of Hawaiian Electric Exhibit 99.1.

163



ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

HEI:

Security Ownership of Certain Beneficial Owners

The information required by this Item 12 for HEI is incorporated herein by reference to the “Stock Ownership Information—Security Ownership of Certain Beneficial Owners” section in the HEI 2014 Proxy Statement.

Equity compensation plan information

Information as of December 31, 2013 about HEI Common Stock that may be issued under all of the Company’s equity compensation plans was as follows:



Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	(b) Weighted-average exercise price of outstanding options, warrants and rights (2)		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (3)
Equity compensation plans approved by shareholders	1,304,255	$	26.02	1,581,169
Equity compensation plans not approved by shareholders	—	—		—
Total	1,304,255	$	26.02	1,581,169

(1)This column includes the number of shares of HEI Common Stock which may be issued under the HEI 2010 Equity Incentive Plan (EIP) and the 1987 Stock Option and Incentive Plan (SOIP) on account of awards outstanding as of December 31, 2013, including:



SOIP	EIP	TOTAL
2,366	—	2,366	Stock appreciation rights plus accrued dividend equivalent rights
—	313,206	313,206	Restricted stock units plus estimated compounded dividend equivalents (if applicable) *
—	75,309	75,309	Shares issued in February 2014 under the 2011-2013 LTIP plus compounded dividend equivalents
—	913,374	913,374	Shares issuable at maximum payouts under the 2012-2014 and 2013-2015 LTIPs, including estimated compounded dividend equivalents
2,366	1,301,889	1,304,255


*	Under the EIP as of December 31, 2013, RSUs count against the shares authorized for issuance as four shares for every share issued. Accordingly, the 313,206 RSU shares in the table are counted as 1,252,824 shares in determining the 1,581,169 shares available for future issuance under the EIP.

(2)

The weighted average exercise price in this column relates to the outstanding 62,000 stock appreciation rights which were granted in 2004. Excluded from the weighted average exercise price calculation are 102,000 stock appreciation rights whose exercise price was greater than the share price on December 31, 2013 and shares that may be issued without the payment of additional consideration (including the LTIP and restricted stock unit awards).


(3)	This represents the number of shares available as of December 31, 2013 for future awards, including 1,378,709 shares available for future awards under the EIP and 202,460 shares available for future awards under the 2011 Nonemployee Director Plan. As of May 11, 2010, no new awards may be granted under the SOIP.

Hawaiian Electric:

The information required by this Item 12 for Hawaiian Electric is incorporated herein by reference to pages 34 to 35 of Hawaiian Electric Exhibit 99.1.

164



ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

HEI:

The information required by this Item 13 for HEI is incorporated herein by reference to the sections relating to related person transactions and director independence in the HEI 2014 Proxy Statement.

Hawaiian Electric:

The information required by this Item 13 for Hawaiian Electric is incorporated herein by reference to pages 35 to 36 of Hawaiian Electric Exhibit 99.1.



ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

HEI:

The information required by this Item 14 for HEI is incorporated herein by reference to the relevant information in the Audit Committee Report in the HEI 2014 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated herein by reference).

Hawaiian Electric:

The information required by this Item 14 for Hawaiian Electric is incorporated herein by reference to page 37 of Hawaiian Electric Exhibit 99.1.

PART IV



ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial statements

See Item 8 for the financial statements of HEI and Hawaiian Electric.

(a)(2) and (c) Financial statement schedules

The following financial statement schedules for HEI and Hawaiian Electric are included in this report on the pages indicated below:



		Page/s in Form 10-K
		HEI	Hawaiian Electric
Schedule I	Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2013 and 2012 and Years ended December 31, 2013, 2012 and 2011	166-168	NA
Schedule II	Valuation and Qualifying Accounts, Hawaiian Electric Industries, Inc. and subsidiaries and Hawaiian Electric Company, Inc. and subsidiaries, Years ended December 31, 2013, 2012 and 2011	169	169
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.

165

Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS



December 31	2013			2012
(dollars in thousands)
Assets
Cash and cash equivalents	$	571		$	18,021
Accounts receivable	1,661			1,836
Property, plant and equipment, net	5,419			5,814
Deferred income tax assets	1,594			8,517
Other assets	23,679			8,390
Investments in subsidiaries, at equity	2,122,841			1,978,283
	$	2,155,765		$	2,020,861
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	817		$	24,086
Interest payable	4,630			4,781
Notes payable to subsidiaries	7,936			7,722
Commercial paper	105,482			83,694
Long-term debt, net	275,000			275,000
Deferred income taxes	11,385			—
Retirement benefits liability	21,559			28,004
Other	1,886			3,709
	428,695			426,996
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: 101,259,800 shares and 97,928,403 shares	1,488,126			1,403,484
Retained earnings	255,694			216,804
Accumulated other comprehensive loss	(16,750		)	(26,423		)
	1,727,070			1,593,865
	$	2,155,765		$	2,020,861
Note to Balance Sheets
HEI medium-term note 5.25%, due 2013	$	—		$	50,000
HEI medium-term note 6.51%, due 2014	100,000			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			—
	$	275,000		$	275,000

The aggregate payments of principal required subsequent to December 31, 2013 on long-term debt are $100 million in 2014, nil in 2015, $75 million in 2016 and nil in 2017 and 2018.

As of December 31, 2013, 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 $0.5 million self-insured automobile bond.

166

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	2013		2012		2011
(in thousands)
Revenues	$	288	$	221	$	253
Equity in net income of subsidiaries	180,359		157,883		158,722
Expenses:
Operating, administrative and general	16,063		16,191		15,401
Depreciation of property, plant and equipment	596		672		227
Taxes, other than income taxes	497		421		409
Interest expense	16,207		16,695		22,013
Income before income tax benefits	147,284		124,125		120,925
Income tax benefits	14,232		14,533		17,305
Net income	$	161,516	$	138,658	$	138,230

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.

167

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,	2013			2012			2011
(in thousands)
Cash flows from operating activities
Net income	$	161,516		$	138,658		$	138,230
Adjustments to reconcile net income to net cash provided by operating activities
Equity in net income	(180,359		)	(157,883		)	(158,722		)
Common stock dividends/distributions received from subsidiaries	121,578			118,044			128,558
Depreciation of property, plant and equipment	596			672			227
Other amortization	800			845			981
Increase in deferred income taxes	15,228			150			276
Excess tax benefits from share-based payment arrangements	(430		)	(61		)	—
Changes in assets and liabilities
Decrease (increase) in accounts receivable	(2,167		)	(475		)	412
Increase (decrease) in accounts and interest payable	(23,420		)	19,995			1,324
Change in prepaid and accrued income taxes	(15,604		)	(4,861		)	3,550
Increase (decrease) in defined benefit pension and other postretirement benefit plans liability	(6,449		)	1,805			5,313
Changes in other assets and liabilities	10,985			10,229			(1,880		)
Net cash provided by operating activities	82,274			127,118			118,269
Cash flows from investing activities
Capital expenditures	(201		)	(410		)	(110		)
Investments in subsidiaries	(78,500		)	(44,000		)	(40,000		)
Other	—			—			(4,206		)
Net cash used in investing activities	(78,701		)	(44,410		)	(44,316		)
Cash flows from financing activities
Net decrease in notes payable to subsidiaries with original maturities of three months or less	56			(1,797		)	(1,757		)
Net increase in short-term borrowings with original maturities of three months or less	21,788			14,873			43,897
Proceeds from issuance of long-term debt	50,000			—			125,000
Repayment of long-term debt	(50,000		)	(7,000		)	(150,000		)
Excess tax benefits from share-based payment arrangements	430			61			—
Net proceeds from issuance of common stock	55,086			23,613			15,979
Common stock dividends	(98,383		)	(96,202		)	(106,812		)
Other	—			—			(35		)
Net cash used in financing activities	(21,023		)	(66,452		)	(73,728		)
Net increase (decrease) in cash and equivalents	(17,450		)	16,256			225
Cash and cash equivalents, January 1	18,021			1,765			1,540
Cash and cash equivalents, December 31	$	571		$	18,021		$	1,765

Supplemental disclosures of noncash activities:

In 2013, 2012 and 2011, $2.3 million, $1.8 million and $1.3 million, respectively, of HEI accounts receivable from ASHI were reduced with a corresponding reduction in HEI notes payable to ASHI in noncash transactions.

In 2013, 2012 and 2011, $2.5 million, $2.5 million and $2.0 million, respectively, were contributed as equity by HEI into ASHI with a corresponding increase in HEI notes payable to ASHI 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 $24 million, $24 million and $12 million in 2013, 2012 and 2011, respectively. HEI satisfied the requirements of the HEI DRIP, Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and ASB 401(k) Plan (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.

168

Hawaiian Electric Industries, Inc. and subsidiaries

and Hawaiian Electric Company, Inc. and subsidiaries

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2013, 2012 and 2011



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
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	)	(a)	$	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
2011
Allowance for uncollectible accounts – electric utility	$	1,278	$	4,419	$	1,857		(a)	$	5,333	(b)	$	2,221
Allowance for uncollectible interest – bank	$	4,397	$	—	$	428			$	—		$	4,825
Allowance for losses for loans receivable – bank	$	40,646	$	15,009	$	1,741		(a)	$	19,490	(b)	$	37,906
Allowance for mortgage-servicing assets – bank	$	128	$	121	$	—			$	74		$	175
Deferred tax valuation allowance – HEI	$	—	$	278	$	—			$	—		$	278


(a)	Primarily recoveries.


(b)	Bad debts charged off.

The Company has revised its previously issued "Schedule II - Valuation and Qualifying Accounts" to correct for an error that resulted from the exclusion of the following line items: (a) Allowance for mortgage servicing assets - bank and (b) Deferred tax valuation allowance - HEI. The amounts excluded from the schedule were not considered to be material to previously issued financial statement schedules and the revisions to the schedule had no impact on the Company's Consolidated Balance Sheets, Consolidated Statements of Income or Consolidated Statements of Cash Flows.

169

(a)(3) and (b) Exhibits

The Exhibit Index attached to this Form 10-K is incorporated herein by reference. The exhibits listed for HEI and Hawaiian Electric are listed in the index under the headings “HEI” and “Hawaiian Electric,” respectively, except that the exhibits listed under “Hawaiian Electric” are also exhibits for HEI.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The execution of this report by registrant Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.



HAWAIIAN ELECTRIC INDUSTRIES, INC.		HAWAIIAN ELECTRIC COMPANY, INC.
	(Registrant)		(Registrant)


By	/s/ James A. Ajello	By	/s/ Tayne S. Y. Sekimura
	James A. Ajello		Tayne S. Y. Sekimura
	Executive Vice President and Chief Financial Officer		Senior Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer of HEI)		(Principal Financial Officer of Hawaiian Electric)

Date:	February 21, 2014	Date:	February 21, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities indicated on February 21, 2014. The execution of this report by each of the undersigned who signs this report solely in such person’s capacity as a director or officer of Hawaiian Electric Company, Inc. shall be deemed to relate only to matters having reference to such registrant and its subsidiaries.



Signature		Title

/s/ Constance H. Lau		President of HEI and Director of HEI
Constance H. Lau		Chairman of the Board of Directors of Hawaiian Electric
		(Chief Executive Officer of HEI)

/s/ Richard M. Rosenblum		President and Director of Hawaiian Electric
Richard M. Rosenblum		(Chief Executive Officer of Hawaiian Electric)


/s/ James A. Ajello		Executive Vice President and Chief Financial Officer of HEI
James A. Ajello		(Principal Financial and Accounting Officer of HEI)


/s/ Tayne S. Y. Sekimura		Senior Vice President and
Tayne S. Y. Sekimura		Chief Financial Officer of Hawaiian Electric
		(Principal Financial Officer of Hawaiian Electric)

/s/ Cathlynn L. Yoshida		Controller of Hawaiian Electric
Cathlynn L. Yoshida		(Principal Accounting Officer of Hawaiian Electric)

170

SIGNATURES (continued)



Signature		Title

/s/ Don E. Carroll		Director of Hawaiian Electric
Don E. Carroll


/s/ Thomas B. Fargo		Director of HEI and Hawaiian Electric
Thomas B. Fargo


/s/ Peggy Y. Fowler		Director of HEI and Hawaiian Electric
Peggy Y. Fowler


/s/ Timothy E. Johns		Director of Hawaiian Electric
Timothy E. Johns


/s/ Micah A. Kane		Director of Hawaiian Electric
Micah A. Kane


/s/ Bert A. Kobayashi, Jr.		Director of Hawaiian Electric
Bert A. Kobayashi, Jr.


/s/ A. Maurice Myers		Director of HEI
A. Maurice Myers


/s/ Keith P. Russell		Director of HEI
Keith P. Russell


/s/ James K. Scott		Director of HEI
James K. Scott


/s/ Kelvin H. Taketa		Director of HEI and Hawaiian Electric
Kelvin H. Taketa


/s/ Barry K. Taniguchi		Director of HEI
Barry K. Taniguchi


/s/ Jeffrey N. Watanabe		Chairman of the Board of Directors of HEI
Jeffrey N. Watanabe

171

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:
	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	Indenture, dated as of October 15, 1988, between HEI and Citibank, N.A., as Trustee (Exhibit 4 to Registration Statement on Form S-3, Registration No. 33-25216).

	4.3(a)	First Supplemental Indenture dated as of June 1, 1993 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4(a) to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993, File No. 1-8503).

	4.3(b)	Second Supplemental Indenture dated as of April 1, 1999 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, File No. 1-8503).

	4.3(c)	Third Supplemental Indenture dated as of August 1, 2002 between HEI and Citibank, N.A., as Trustee, to Indenture dated as of October 15, 1988 between HEI and Citibank, N.A., as Trustee (Exhibit 4 to HEI’s Current Report on Form 8-K, dated August 16, 2002, File No. 1-8503).

	4.4(a)	Pricing Supplement No. 1 to Registration Statement on Form S-3 of HEI (Registration No. 333-73225) filed on May 3, 1999 in connection with the sale of Medium-Term Notes, Series C, 6.51% due May 5, 2014.

	4.5	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).

	4.5(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).

	4.6	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).

	4.7	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).

	4.8	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).

	4.8(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).

	4.9	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).

	4.10	American Savings Bank 401(k) Plan, restatement effective January 1, 2013 (Exhibit 4.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).



Exhibit no.		Description
	10.1	Conditions for the Merger and Corporate Restructuring of Hawaiian Electric Company, Inc. dated September 23, 1982. (Exhibit 10.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8503).

	10.2	Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988, between HEI, HEIDI and the Federal Savings and Loan Insurance Corporation (by the Federal Home Loan Bank of Seattle) (Exhibit (28)-2 to HEI’s Current Report on Form 8-K dated May 26, 1988, File No. 1-8503).

	10.3	OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).

HEI Exhibits 10.4 through 10.21 are management contracts or compensatory plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of this report. HEI Exhibits 10.4 through 10.19 are also management contracts or compensatory plans or arrangements with Hawaiian Electric participants.

	10.4	HEI Executive Incentive Compensation Plan amended as of February 4, 2013 (Exhibit 10.4 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 1-8503).

	10.5	HEI Executives’ Deferred Compensation Plan (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

	10.6	Hawaiian Electric Industries, Inc. 2010 Equity and Incentive Plan, as amended and restated November 16, 2010 (Exhibit 10.6 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-8503).

	10.6(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).



Exhibit no.		Description
	10.9(a)	Amendments to the HEI Supplemental Executive Retirement Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.9(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.10	HEI Excess Pay Plan amended and restated as of January 1, 2009 (Exhibit 10.10 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.10(a)	HEI Excess Pay Plan Addendum for Constance H. Lau (Exhibit 10.10(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

	10.10(b)	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).



Exhibit no.		Description
	10.22	Credit Agreement, dated as of May 7, 2010, among HEI, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank National Association, as Co-Syndication Agent, and Wells Fargo Bank, National Association, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agent, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-8503).

	10.23	Amendment No. 1, dated as of December 5, 2011, to the Credit Agreement, dated as of May 7, 2010, among HEI, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank National Association, as Co-Syndication Agent, and Wells Fargo Bank, National Association, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agent, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.1 to HEI’s Current Report on Form 8-K dated December 5, 2011, File No. 1-8503).

	10.24	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).

	10.25	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).

	*11	HEI - Computation of Earnings per Share of Common Stock.

	*12.1	HEI - Computation of Ratio of Earnings to Fixed Charges.

	*21.1	HEI - Subsidiaries of the Registrant.

	*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 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).



Exhibit no.		Description
	3(ii)	Hawaiian Electric’s Amended and Restated Bylaws (as last amended August 6, 2010) (Exhibit 3(ii) to Hawaiian Electric’s Current Report on Form 8-K dated August 9, 2010, File No. 1-4955).

	4.1	Agreement to provide the SEC with instruments which define the rights of holders of certain long-term debt of Hawaiian Electric, Hawaii Electric Light and Maui Electric (Exhibit 4.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-4955).

	4.2	Certificate of Trust of HECO Capital Trust III (incorporated by reference to Exhibit 4(a) to Registration No. 333-111073).

	4.3	Amended and Restated Trust Agreement of HECO Capital Trust III dated as of March 1, 2004 (Exhibit 4(c) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.4	Hawaiian Electric Junior Indenture with The Bank of New York, as Trustee, dated as of March 1, 2004 (Exhibit 4(f) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.5	6.500% Quarterly Income Trust Preferred Security issued by HECO Capital Trust III, dated March 18, 2004 (Exhibit 4(d) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	4.6	6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by Hawaiian Electric, dated March 18, 2004 (Exhibit 4(g) to Hawaiian Electric’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

	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).



Exhibit no.		Description
	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).

	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).



Exhibit no.		Description
	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).

	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).



Exhibit no.		Description
	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).

	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).

	10.7(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).

	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).

	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 no.		Description
	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	Energy Agreement among the State of Hawaii, Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and the Hawaiian Electric Companies (Exhibit 10.12 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-4955).

	10.14	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).

	10.15	Credit Agreement, dated as of May 7, 2010, among Hawaiian Electric, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank, National Association, as Co-Syndication Agent, and Wells Fargo Bank, National Association, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agent, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-4955).

	10.16	Amendment No. 1, dated as of December 5, 2011, to the Credit Agreement, dated as of May 7, 2010, among Hawaiian Electric, as Borrower, the Lenders Party Hereto and Bank of Hawaii, as Co-Syndication Agent, and U.S. Bank National Association, as Co-Syndication Agent, and Wells Fargo Bank, National Association, as Co-Syndication Agent, and Bank of America, N.A., as Co-Documentation Agent, and Union Bank, N.A., as Co-Documentation Agent, and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and J.P. Morgan Securities Inc., as Sole Lead Arranger and Sole Book Runner (Exhibit 10.2 to Hawaiian Electric’s Current Report on Form 8-K dated December 5, 2011, File No. 1-4955).

	11	Computation of Earnings Per Share of Common Stock (See note on Hawaiian Electric’s Item 6. Selected Financial Data).

	*12.2	Hawaiian Electric - Computation of Ratio of Earnings to Fixed Charges.

	*21.2	Hawaiian Electric - Subsidiaries of the Registrant

	*31.3	Certification Pursuant to Section 13a-14 of the Securities Exchange Act of 1934 of Richard M. Rosenblum (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.