Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

 

x

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

OR

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

THE SECURITIES EXCHANGE ACT OF 1934

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

For the fiscal year ended December 31, 2010

OR

o

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

900 Richards Street, 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 Registrant Hawaiian Electric Industries, Inc.the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

 

Hawaiian Electric Industries Inc.  Yes   X     No 

Hawaiian Electric Company, Inc.  Yes    No   X  

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if Registrant Hawaiian Electric Industries, Inc.registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

 

Indicate by check mark if Registrant Hawaiian Electric Company, Inc. is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Hawaiian Electric Industries Inc.  Yes    No   X  

Hawaiian Electric Company, Inc.  Yes    No   X 

 

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc.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. Yes x  No o

 

Hawaiian Electric Industries Inc.  Yes   X     No 

Hawaiian Electric Company, Inc.  Yes   X     No 

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (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. Yes x  No o

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. 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).  Yes x  No o

 

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. 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).  Yes o No o

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.  o[   ]

 

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc.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 X 

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

Smaller reporting company  

Hawaiian Electric Company, Inc.

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x X 

Smaller reporting company o

(Do not check if a smaller reporting company)

Smaller reporting company  

 

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc.the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x

 

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes o No x

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, 2010

 

June 30, 2010

 

February 10, 2011

 

 

 

 

 

 

 

 

 

Hawaiian Electric Industries, Inc. (HEI)

 

$2,132,661,527

 

93,619,909

 

94,867,765

 

 

 

 

 

(Without par value)

 

(Without par value)

 

 

 

 

 

 

 

 

 

Hawaiian Electric Company, Inc. (HECO)

 

None

 

13,786,959
($6 2/3 par value)

 

13,830,823
($6 2/3 par value)

 



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, 2012

June 30, 2012

February 7, 2013

Hawaiian Electric Industries, Inc. (HEI)

$2,767,100,181

97,023,148

(Without par value)

98,101,019

(Without par value)

Hawaiian Electric Company, Inc. (HECO)

None

14,233,723
($6 2/3 par value)

14,665,264
($6 2/3 par value)

 

DOCUMENTS INCORPORATED BY REFERENCE

 

HECO’s Exhibit 99.2, consisting of:

HECO’s Consolidated Selected Financial Data—Part II

HECO’s Management’s Discussion and Analysis of Financial Condition and Results of Operations—Parts I and II

HECO’s Quantitative and Qualitative Disclosures about Market Risk—Parts I and II

HECO’s Consolidated Selected Financial Data—Part II

HECO’s Consolidated 20102012 Financial Statements—Parts I, II, III and IV

HECO’s Exhibit 99.3, consisting of:

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

HECO’s Executive Compensation—Part III

HECO’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Part III

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

HECO’s Principal Accounting Fees and Services—Part III

 

Selected sections of Proxy Statement of HEI for the 20112013 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. HECO makes no representations as to any information not relating to itself.

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. HECO makes no representations as to any information not relating to it or its subsidiaries.

 



Table of Contents

TABLE OF CONTENTS

 

 

 

Page

 

 

 

Glossary of Terms

ii

Forward-Looking Statements

v

 

 

 

PART I

 

 

 

Item 1.

Business

1

Item 1A.

Risk Factors

28

26

Item 1B.

Unresolved Staff Comments

38

35

Item 2.

Properties

38

35

Item 3.

Legal Proceedings

38

35

Item 4.

Mine Safety Disclosures

36

Executive Officers of the Registrant (HEI)

38

36

 

 

 

PART II

 

 

 

Item 5.

Market for Registrants’Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

40

37

Item 6.

Selected Financial Data

41

38

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

42

39

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

90

82

Item 8.

Financial Statements and Supplementary Data

92

84

Item 9.

ChangeChanges in and Disagreements with Accountants on Accounting and Financial Disclosure

154

148

Item 9A.

Controls and Procedures

154

148

Item 9B.

Other Information

155

149

 

 

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

156

149

Item 11.

Executive Compensation

165

150

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

193

151

Item 13.

Certain Relationships and Related Transactions, and Director Independence

195

152

Item 14.

Principal Accounting Fees and Services

197

152

 

 

 

PART IV

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

198

153

ReportsReport of Independent Registered Public Accounting Firm - HEI

199

154

ReportsReport of Independent Registered Public Accounting Firm - HECO

201

155

Index to Exhibits

207

160

Signatures

207

160

 

i



Table of Contents

GLOSSARY OF TERMS

 

Defined below are certain terms used in this report:

 

Terms

Definitions

 

 

2005 Act

 

Public Utility Holding Company Act of 2005

ABO

Accumulated benefit obligations

AES Hawaii

 

AES Hawaii, Inc.

AFUDC

 

allowanceAllowance for funds used during construction

AOCI

 

accumulatedAccumulated other comprehensive income (loss)

AOS

 

adequacyAdequacy of supply

APBO

Accumulated postretirement benefit obligation

ASB

 

American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc. Former subsidiaries of ASB (other than former subsidiaries dissolved prior to 2006) include AdCommunications, Inc. (dissolved in May 2007) and American Savings Investment Services Corp. (and its subsidiary, Bishop Insurance Agency of Hawaii, Inc.) (dissolved in October 2010).

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.

BIF

 

Bank Insurance Fund

Btu

 

British thermal unit

CAA

 

Clean Air Act

CERCLA

 

Comprehensive Environmental Response, Compensation and Liability Act

CESP

 

Clean Energy Scenario Planning

Chevron

 

Chevron Products Company, a fuel oil supplier

CHP

 

Combined heat and power

CIP

Campbell Industrial Park

CIS

 

Customer Information System

Company

 

When used in Hawaiian Electric Industries, Inc. sections, the “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 HECO); American Savings Holdings, Inc. and its subsidiary, American Savings Bank, F.S.B. and its subsidiaries (listed under ASB); Pacific Energy Conservation Services, Inc.; HEI Properties, Inc.; HEI Investments, Inc. (dissolved in 2008); 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.). Former subsidiaries of HEI (other than former subsidiaries of HECO and ASB and former subsidiaries of HEI sold or di ssolved prior to 2006) include Hycap Management, Inc. (dissolved in 2007) and HEI Power Corp. (discontinued operations, dissolved in 2006) and its dissolved subsidiaries.

When used in Hawaiian Electric Company, Inc. sections, the “Company” refers to Hawaiian Electric Company, Inc. and its direct subsidiaries.

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

DBF

State of Hawaii Department of Budget and Finance

DG

 

Distributed generation

DOD

 

Department of Defense federal

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 clausesclause

EIP

 

2010 Executive Incentive Plan, as amended

Energy Agreement

 

Agreement dated October 20, 2008 and 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 HECO, 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

ERISA

 

Employee Retirement Income Security Act of 1974, as amended

 

ii



Table of ContentsGLOSSARY OF TERMS (continued)

 

Terms

Definitions

 

ERL

 

Environmental Response Law of the State of Hawaii

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

FNMA

 

Federal National Mortgage Association

FRB

Federal Reserve Board

GAAP

 

U. S.U.S. generally accepted accounting principles

GDP

gross domestic product

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.

HECO

 

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 subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.

HECO’s Consolidated Financial Statements

 

Hawaiian Electric Company, Inc.’s Consolidated Financial Statements, which are incorporated into Parts I, II, III and IV of this Form 10-K by reference to HECO Exhibit 99.2

HECO’s MD&A

 

Hawaiian Electric Company, Inc.’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is incorporated into Part I, Item 1 and Part II, Item 7 of this Form 10-K by reference to HECO Exhibit 99.2

HEI

 

Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., HEI Investments, Inc. (dissolved in 2008), Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries (other than those sold or dissolved prior to 2006) are listed under Company.

HEI 20112013 ProxyStatement

 

Selected sections of Hawaiian Electric Industries, Inc.’s 20112013 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 ConsolidatedFinancial Statements

 

Hawaiian Electric Industries, Inc.’s Consolidated Financial Statements, including notes, in Item 8 of this Form 10-K

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

HEIII

HEI Investments, Inc. (formerly HEI Investment Corp.) (dissolved in 2008), a direct subsidiary of Hawaiian Electric Industries, Inc. since January 2007 and formerly a wholly-owned subsidiary of HEI Power Corp.

HEIPI

 

HEI Properties, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.

HEIRSP

 

Hawaiian Electric Industries Retirement Savings Plan

HELCO

 

Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.

HEP

 

Hamakua Energy Partners, L.P., formerly known as Encogen Hawaii, L.P.

HITI

 

Hawaiian Interisland Towing, Inc.

HTB

 

Hawaiian Tug & Barge Corp. On November 10, 1999, HTB sold substantially all of its operating assets and the stock of Young Brothers, Limited, and changed its name to The Old Oahu Tug Services, Inc.

IPP

 

Independent power producer

IRP

 

Integrated resource plan

IRR

Interest rate risk

Kalaeloa

 

Kalaeloa Partners, L.P.

kV

 

kilovoltKilovolt

KWH

 

Kilowatthour

LSFO

 

Low sulfur fuel oil

LTIP

 

Long-term incentive plan

 

iii



Table of ContentsGLOSSARY OF TERMS (continued)

 

Terms

Definitions

 

 

MBtu

 

Million British thermal unit

MD&A

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

MECO

 

Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.

Moody’s

 

Moody’s Investors Service’s

MSFO

 

Medium sulfur fuel oil

MW

 

Megawatt/s (as applicable)

NA

 

Not applicable

NAAQS

 

National Ambient Air Quality Standard

NM

 

Not meaningful

NPBC

Net periodic benefits costs

NQSO

 

nonqualifiedNonqualified stock options

O&M

 

operationOperation and maintenance

OCC

 

Office of the Comptroller of the Currency

OPA

 

Federal Oil Pollution Act of 1990

OPEB

 

postretirementPostretirement benefits other than pensions

OTS

 

Office of Thrift Supervision, Department of Treasury

OTTI

 

other-than-temporaryOther-than-temporary impairment

PBO

 

projectedProjected benefit obligation

PCB

 

Polychlorinated biphenyls

PECS

 

Pacific Energy Conservation Services, Inc., a wholly-owned subsidiary of Hawaiian Electric Industries, Inc.

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

RCRA

 

Resource Conservation and Recovery Act of 1976

REG

 

Renewable Energy Group Marketing & Logistics Group LLC

Registrant

 

Each of Hawaiian Electric Industries, Inc. and Hawaiian Electric Company, Inc.

RHI

 

Renewable Hawaii, Inc., a wholly owned 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

SAIF

 

Savings Association Insurance Fund

SAR

 

Stock appreciation right

SEC

 

Securities and Exchange Commission

See

 

Means the referenced material is incorporated by reference to HECO Exhibit 99.2 or HECO Exhibit 99.3 as if fully set forth herein (or means refer to the referenced section in this document or the referenced exhibit or other document)

SOIP

 

1987 Stock Option and Incentive Plan, as amended

ST

 

Steam turbine

state

 

State of Hawaii

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.

UBC

 

Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc.

UST

 

Underground storage tank

VIE

 

variableVariable interest entity

 

iv



Table of Contents

Forward-Looking Statements

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) 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, th ethe Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-lookingstatements 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, and the implications and potential impacts of currentU.S. and foreign capital and credit market conditions and federal, state and stateinternational responses to those conditions;conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, unrest, conflict and the overthrow of governmental regimes in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);

·           weather and natural disasters such as(e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming, (suchsuch as more severe storms and rising sea levels);

·global developments,, including terrorist acts,their impact on Company operations and the war on terrorism, continuing U.S. presence in Afghanistan, potential conflict or crisis with North Korea or in the Middle East;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 over the next several months;promulgated;

·            increasing competition in the electric utility and banking industriesindustry (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and 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), revenue decoupling 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 like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cable (to bring power to Oahu from Lanai and/or Molokai),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, (DG), combined heat and power (CHP) or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

·the risk to generation reliability when generation peak reserve margins on Oahu are strained;

·            fuel oil price changes, performance by suppliers of their fuel oil delivery obligations 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;

 

v



Table of Contents

 

·            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 fuel supply and collective bargaining agreements;

·            new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB) or their competitors;

·            cyber security risks and the potential for cyber incidents, including potential incidents at HEI, ASB and HECO and their subsidiaries (including at ASB branches and at the 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 changes in laws, rules and regulations applicable to HEI, HECO, 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), the regulation of greenhouse gas (GHG) emissions, (GHG), healthcare reform, 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)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 and 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 Thrift Supervision (OTS) (or its regulatory successors, the Office of the Comptroller of the Currency, and the Federal Reserve Board) andBoard (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);

·            ability to recover and earn on 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 (first(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, HECO, 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 HECO 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 servicingmortgage-servicing assets of ASB;

·            changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of 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, HECO, 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;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 HECO 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, HECO, 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.otherwise.

 

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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, HECO, 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, HECO became an HEI subsidiary and common shareholders of HECO became common shareholders of HEI.

HECO and its operating utility subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are regulated electric public utilities. HECO 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 HECO, HELCO and MECO. In December 2002, HECO formed a subsidiary, Renewable Hawaii, Inc., to invest in renewable energy projects, but it has made no investments and has been inactive recently.currently is inactive. In September 2007, HECO 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 HECO and its subsidiaries, HEI also currently owns directly or indirectly the following subsidiaries: American Savings Holdings, Inc. (ASHI) (a holding company) and its subsidiary, ASB; Pacific Energy Conservation Services, Inc. (PECS); HEI Properties, Inc. (HEIPI); HEI Investments, Inc.; Hawaiian Electric Industries Capital Trusts II and III (formed(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 $4.8$5.0 billion as of December 31, 2010.

2012.

HEIPI, whose predecessor company was formed in February 1998, holds venture capital investments (in companies based in Hawaii and on the U.S. mainland) with a carrying value of $1.3$0.5 million as of December 31, 2010.2012.

PECS was formed in 1994 and was a contract services company providing windfarm operational and maintenance services to an affiliated electric utility that ceased such services when the windfarm was dismantled in 2010. The Company expects to dissolve PECS in 2011.

In November 1999, Hawaiian Tug & Barge Corp. (HTB) sold substantially all of its operating assets and the stock of Young Brothers, Limited (YB) for a nominal gain, changed its name to TOOTS and ceased maritime freight transportation operations. TOOTS currently administers certain employee and retiree-related benefitsbenefit programs and monitors matters related to its predecessor’s former operations and the operations of its former subsidiary.

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, (including Note 2, “Segment financial information”), and also see HECO’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (HECO’s MD&A) and HECO’s Consolidated Financial Statements and HECO’s “Quantitative and Qualitative Disclosures About Market Risk,”Risk” and HECO’s Consolidated Financial Statements, which are incorporated by reference to HECO Exhibit 99.2.

The Company’s website address is www.hei.com. 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 HECO 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 HECO intend to continue to use HEI’s website as a means of disclosing additional information. Such disclosures will be included on HEI’s website under the

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headings “Company Overview” and “News & Events” in the Investor Relations section. Accordingly, investors should routinely monitor such portions of HEI’s website, in addition to following HEI’s, HECO’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–Selected contractual obligations and commitments” in HEI’s MD&A, and HECO’s “Commitments and contingencies” below.below and Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

1



Regulation.  HEI and HECO are each holding companies within the meaning of the Public Utility Holding Company Act of 2005 and implementing regulations (2005 Act) and filed a required notification of that status on February 21, 2006.. The 2005 Act 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 has granted HEI and HECO 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.

As a result of the acquisition of ASB, HEI and ASHI are subject to OTSFederal 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 OTSOCC 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 OTSOCC is authorized under the Home Owners’ Loan Act of 1933, as amended, 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) theany 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.

OTSBank 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 OTS regulations provide for an exemption whichunitary savings and loan holding company relationship among HEI, ASHI and ASB is available to“grandfathered” under the Gramm-Leach-Bliley Act of 1999 (Gramm Act) so that HEI and ASHI ifits subsidiaries will be 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 2010;2012; however, the failure of ASB to satisfy the QTL test in the future could result in a need for HEI to divest ASB. As a result of the enactment of the Dodd-Frank Act, supervision and regulation of HEI, as a thrift holding company, will move to the Federal Reserve, and supervision and regulation of ASB, as a federally chartered savings bank, will move to the Office of the Comptroller of the Currency (OCC) in July 2011 (unle ss the date is extended). 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, further restricting proxy voting by brokers in the absence of instructions and permitting the SEC to adopt rules in its discretion requiring public companies under specified conditions to include shareholder nominees in management’s proxy solicitation materials. See “Bank—Legislation and regulation” in HEI’s MD&A for a discussion of the 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.

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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 u tilityutility subsidiaries. As of December 31, 2010,2012, the consolidated common stock equity of HEI’s electric utility subsidiaries was 55%56% of their total capitalization (as calculated for purposes of the PUC

2



Agreement). As of December 31, 2010,2012, HECO and its subsidiaries had common stock equity of $1.3$1.5 billion of which approximately $588$637 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 a prior indication of no objection by the OTS (andapproval by the OCC from July 2011, unless the date is extended).and FRB. Also see Note 13 to HEI’s 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 Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI’s and HECO’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 rat ingrating may have an adverse effect on the market price or marketability of HEI’s and/or HECO’s securities, which could increase the cost of capital of HEI and HECO. Neither HEI nor HECO management can predict future rating agency actions or their effects on the future cost of capital of HEI or HECO.

Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii for the benefit of HECO and its subsidiaries, but the source of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’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, - see the discussion of the downgrades ofbut the ratings of theseveral of these insurers underhave declined to ratings below HECO ratings—see “Electric Utility—Liquidity and capital resources” in HEI’s MD&A.

 

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

 

December 31

 

2010

 

2009

 

2008

 

2007

 

2006

 

HEI

 

34

 

34

 

41

 

42

 

41

 

HECO and its subsidiaries

 

2,318

 

2,297

 

2,203

 

2,145

 

2,085

 

ASB and its subsidiaries

 

1,075

 

1,117

 

1,313

 

1,330

 

1,318

 

Other subsidiaries

 

 

3

 

3

 

3

 

3

 

 

 

3,427

 

3,451

 

3,560

 

3,520

 

3,447

 

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December 31

 

2012

 

2011

 

2010

 

2009

 

2008

 

HEI

 

42

 

40

 

34

 

34

 

41

 

HECO and its subsidiaries

 

2,658

 

2,518

 

2,317

 

2,297

 

2,203

 

ASB and its subsidiaries

 

1,170

 

1,096

 

1,075

 

1,119

 

1,313

 

Other subsidiaries

 

 

 

 

3

 

3

 

 

 

3,870

 

3,654

 

3,426

 

3,453

 

3,560

 

 

The employees of HEI and its direct and indirect subsidiaries, other than the electric utilities, are not covered by any collective bargaining agreement. A substantial number of employees of HECO and its subsidiaries are covered by collective bargaining agreements, which have been recently renegotiated, but are subject to ratification by the union employees.agreements. See “Collective bargaining agreements” in Note 3 toof HEI’s Consolidated Financial Statements.

 

Properties.  HEI leases office space from nonaffiliated lessors in downtown Honolulu under leases that expire in March 2016.2016 and December 2017. Until April 2012, HEI also subleasessubleased office space in a downtown Honolulu building leased by HECO under a lease that expires in November 2021, with an option to extend to November 2024.HECO. See the discussions under “Electric Utility” and “Bank” below for a description of properties owned by HEI subsidiaries.

3



Electric utility

 

HECO and subsidiaries and service areas.  HECO, HELCO and MECO 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. HECO acquired MECO in 1968 and HELCO in 1970. In 2010,2012, the electric utilities’ revenues and net income amounted to approximately 89%92% and 67%72%, respectively, of HEI’s consolidated revenues and net income, compared to approximately 88%92% and 96%72% in 20092011, and approximately 89% and 102%67% in 2008,2010, respectively.

The islands of Oahu, Hawaii, Maui, Lanai and Molokai have a combined population estimated at 1.21.3 million, or approximately 95% of the total population of the State of Hawaii, population, and comprise a service area of 5,7665,815 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 HECO, HELCO and MECO 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.

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

 

Sales of electricity.The following table sets forth the number of electric customer accounts as of December 31, 2010, 2009 and 2008 and electric sales revenues by company for each of the years then ended:

 

Years ended December 31

 

2012

 

2011

 

2010

 

 

 

Customer

 

Electric sales

 

Customer

 

Electric sales

 

Customer

 

Electric sales

 

(dollars in thousands)

 

accounts*

 

revenues

 

accounts*

 

revenues

 

accounts*

 

revenues

 

HECO

 

297,529

 

$2,216,675

 

296,800

 

$2,103,859

 

296,422

 

$1,645,328

 

HELCO

 

81,792

 

439,249

 

81,199

 

443,189

 

80,695

 

371,746

 

MECO

 

68,922

 

436,836

 

68,230

 

417,451

 

67,739

 

343,562

 

 

 

448,243

 

$3,092,760

 

446,229

 

$2,964,499

 

444,856

 

$2,360,636

 

 

 

 

2010

 

2009

 

2008

 

Years ended December 31

 

Customer

 

Electric sales

 

Customer

 

Electric sales

 

Customer

 

Electric sales

 

(dollars in thousands)

 

accounts*

 

revenues

 

accounts*

 

revenues

 

accounts*

 

revenues

 

HECO

 

296,422

 

$

1,645,328

 

295,282

 

$

1,379,208

 

293,740

 

$

1,948,243

 

HELCO

 

80,695

 

371,746

 

79,813

 

342,982

 

79,606

 

445,214

 

MECO

 

67,739

 

343,562

 

67,489

 

296,433

 

67,065

 

451,042

 

 

 

444,856

 

$

2,360,636

 

442,584

 

$

2,018,623

 

440,411

 

$

2,844,499

 


* As of December 31.

 

SeasonalityKilowatthour (KWH) sales of HECO and its subsidiaries follow a seasonal pattern, but they do not experience the extreme seasonal variationvariations due to extreme weather variations likeexperienced 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 customersHECO and its subsidiaries derived approximately 10% in 2010, 200911%, 11% and 200810% of their operating revenues in 2012, 2011 and 2010, respectively, from the sale of electricity to various federal government agencies.

Under a Basic Ordering Agreement (BOA) with the federal DepartmentEnergy Policy Act of Defense (DOD) entered into in 2007, which expires in 2012, and earlier BOAs and other agreements, HECO has completed energy conservation and other projects for federal agencies over the years.  The Navy Facilities Engineering Command Pacific developed a Hawaii Navy Energy Program which establishes energy goals for meeting energy reduction standards set forth in2005, the Energy Independence and Security Act of 2007 which requiredand/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% aper year or 30% by the end of 2015, beginning in 2006. The Navy must also meet renewable energy requirements set forth in the National Defense Authorization Act of

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2007 (by 2025, 25% of the energy consumed at an installation must be produced or procured from renewable energy sources).

The Energy Policy Act of 2005 mandated that federal buildings reduce energy consumption by up to 20%30% by fiscal year 2015 relative to base fiscal year 2003, consumption to the extent that these measures are cost effective. The Act also establishesand (3) renewable energy conservation goals at the state levelwere established for federally funded programs, stricter conservation measures for a variety of large energy-consuming products and tax credits for energy efficient homes, solar energy, fuel cells and microturbine power plants; and includes other energy-related provisions. Executive Order 13514, adopted in 2009, expanded upon energy reduction and environmental performance requirements set forth in Executive Orders 13123, 13149 and 13423. The Order sets the framework for sustainability goals for Federal agencies including making improvements in environmental, energy, and economic performance. The Order requires agencies to se t agency-defined targets for the reduction of greenhouse gas emissions, as well as measure and manage steps to meet those targets.electricity consumed by federal agencies. HECO 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 decouplingOn October 20, 2008, the Governor, the Hawaii Department of Business Economic Development and Tourism, 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 conse rvation.conservation. See Note 3 of HEI’s 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 saving 4,300 GWH of electricity use reductions by 2030. The PUC openedissued 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.

4



These goals may be revised through goal evaluations scheduled every five years or as the result of recommendations by an EEPS docket, which is on-going.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 on December 29, 2010, the PUC approved the implementation of revenue decoupling for HECOthe utilities under which HECO isthey are allowed to recover PUC-approved revenue requirements without being dependentthat are not based on the amount of electricity sold. See “Decoupling proceeding” under “Electric utility” in HEI’s MD&A. Both the establishment of an EEPS and the implementation of revenue decoupling could have an impact on sales. However, neither HEI nor HECO management can predict with certainty the impact of these or other govern mentalgovernmental mandates, the HCEI or the Energy Agreement on HEI’s or HECO’s future financial condition, results of operations, financial condition or cash flows.liquidity.

 

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Selected consolidated electric utility operating statistics.

Years ended December 31

 

2012

 

2011

 

2010

 

2009

 

2008

 

KWH sales (millions)

 

 

 

 

 

 

 

 

 

 

 

Residential

 

2,582.0

 

2,769.7

 

2,830.0

 

2,893.3

 

2,924.7

 

Commercial

 

3,074.4

 

3,203.8

 

3,185.0

 

3,221.7

 

3,326.3

 

Large light and power

 

3,499.8

 

3,503.4

 

3,512.8

 

3,524.5

 

3,632.9

 

Other

 

49.8

 

50.0

 

50.8

 

50.2

 

52.3

 

 

 

9,206.0

 

9,526.9

 

9,578.6

 

9,689.7

 

9,936.2

 

 

 

 

 

 

 

 

 

 

 

 

 

KWH net generated and purchased (millions)

 

 

 

 

 

 

 

 

 

 

 

Net generated

 

5,601.7

 

6,022.2

 

6,053.6

 

6,117.6

 

6,261.8

 

Purchased

 

4,093.2

 

4,009.7

 

4,062.8

 

4,119.8

 

4,248.2

 

 

 

9,694.9

 

10,031.9

 

10,116.4

 

10,237.4

 

10,510.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Losses and system uses (%)

 

4.8

 

4.8

 

5.1

 

5.1

 

5.2

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy supply (December 31)

 

 

 

 

 

 

 

 

 

 

 

Net generating capability—MW 1

 

1,787

 

1,787

 

1,785

 

1,815

 

1,687

 

Firm purchased capability—MW

 

545

 

540

 

540

 

532

 

540

 

 

 

2,332

 

2,327

 

2,325

 

2,347

 

2,227

 

 

 

 

 

 

 

 

 

 

 

 

 

Net peak demand—MW 2

 

1,535

 

1,530

 

1,562

 

1,618

 

1,590

 

Btu per net KWH generated

 

10,533

 

10,609

 

10,617

 

10,753

 

10,700

 

Average fuel oil cost per Mbtu (cents)

 

2,210.4

 

1,986.7

 

1,404.8

 

1,026.4

 

1,840.0

 

 

 

 

 

 

 

 

 

 

 

 

 

Customer accounts (December 31)

 

 

 

 

 

 

 

 

 

 

 

Residential

 

392,025

 

390,133

 

388,307

 

385,886

 

383,042

 

Commercial

 

54,005

 

53,904

 

54,374

 

54,527

 

55,243

 

Large light and power

 

577

 

567

 

548

 

558

 

543

 

Other

 

1,636

 

1,625

 

1,627

 

1,613

 

1,583

 

 

 

448,243

 

446,229

 

444,856

 

442,584

 

440,411

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric revenues (thousands)

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$   952,159

 

$   946,653

 

$   781,467

 

$   690,656

 

$   935,061

 

Commercial

 

1,060,983

 

1,024,725

 

814,109

 

694,087

 

973,048

 

Large light and power

 

1,062,226

 

976,949

 

752,056

 

623,159

 

921,321

 

Other

 

17,392

 

16,172

 

13,004

 

10,721

 

15,069

 

 

 

$3,092,760

 

$2,964,499

 

$2,360,636

 

$2,018,623

 

$2,844,499

 

Average revenue per KWH sold (cents)

 

33.60

 

31.12

 

24.65

 

20.83

 

28.63

 

Residential

 

36.88

 

34.18

 

27.61

 

23.87

 

31.97

 

Commercial

 

34.51

 

31.99

 

25.56

 

21.54

 

29.25

 

Large light and power

 

30.35

 

27.89

 

21.41

 

17.68

 

25.36

 

Other

 

34.93

 

32.37

 

25.63

 

21.36

 

28.81

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential statistics

 

 

 

 

 

 

 

 

 

 

 

Average annual use per customer account (KWH)

 

6,596

 

7,117

 

7,317

 

7,523

 

7,640

 

Average annual revenue per customer account

 

$2,432

 

$2,433

 

$2,021

 

$1,796

 

$2,443

 

Average number of customer accounts

 

391,437

 

389,160

 

386,767

 

384,600

 

382,821

 

 

Years ended December 31

 

2010

 

2009

 

2008

 

2007

 

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

KWH sales (millions)

 

 

 

 

 

 

 

 

 

 

 

Residential

 

2,830.0

 

2,893.3

 

2,924.7

 

3,035.5

 

3,022.2

 

Commercial

 

3,185.0

 

3,221.7

 

3,326.3

 

3,340.6

 

3,313.3

 

Large light and power

 

3,512.8

 

3,524.5

 

3,632.9

 

3,690.2

 

3,728.8

 

Other

 

50.8

 

50.2

 

52.3

 

51.8

 

51.5

 

 

 

9,578.6

 

9,689.7

 

9,936.2

 

10,118.1

 

10,115.8

 

 

 

 

 

 

 

 

 

 

 

 

 

KWH net generated and purchased (millions)

 

 

 

 

 

 

 

 

 

 

 

Net generated

 

6,053.6

 

6,117.6

 

6,261.8

 

6,478.6

 

6,610.8

 

Purchased

 

4,062.8

 

4,119.8

 

4,248.2

 

4,228.0

 

4,094.4

 

 

 

10,116.4

 

10,237.4

 

10,510.0

 

10,706.6

 

10,705.2

 

 

 

 

 

 

 

 

 

 

 

 

 

Losses and system uses (%)

 

5.1

 

5.1

 

5.2

 

5.3

 

5.3

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy supply (December 31)

 

 

 

 

 

 

 

 

 

 

 

Net generating capability—MW (1)

 

1,785

 

1,815

 

1,687

 

1,685

 

1,669

 

Firm purchased capability—MW

 

540

 

532

 

540

 

538

 

535

 

 

 

2,325

 

2,347

 

2,227

 

2,223

 

2,204

 

 

 

 

 

 

 

 

 

 

 

 

 

Net peak demand—MW (2)

 

1,562

 

1,618

 

1,590

 

1,635

 

1,685

 

Btu per net KWH generated

 

10,617

 

10,753

 

10,700

 

10,807

 

10,848

 

Average fuel oil cost per Mbtu (cents)

 

1,404.8

 

1,026.4

 

1,840.0

 

1,108.2

 

1,094.1

 

 

 

 

 

 

 

 

 

 

 

 

 

Customer accounts (December 31)

 

 

 

 

 

 

 

 

 

 

 

Residential

 

388,307

 

385,886

 

383,042

 

381,964

 

376,783

 

Commercial

 

54,374

 

54,527

 

55,243

 

55,869

 

55,493

 

Large light and power

 

548

 

558

 

543

 

554

 

567

 

Other

 

1,627

 

1,613

 

1,583

 

1,510

 

1,499

 

 

 

444,856

 

442,584

 

440,411

 

439,897

 

434,342

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric revenues (thousands)

 

 

 

 

 

 

 

 

 

 

 

Residential

 

$

781,467

 

$

690,656

 

$

935,061

 

$

713,241

 

$

690,425

 

Commercial

 

814,109

 

694,087

 

973,048

 

714,218

 

695,247

 

Large light and power

 

752,056

 

623,159

 

921,321

 

652,298

 

648,066

 

Other

 

13,004

 

10,721

 

15,069

 

10,791

 

10,530

 

 

 

$

2,360,636

 

$

2,018,623

 

$

2,844,499

 

$

2,090,548

 

$

2,044,268

 

 

 

 

 

 

 

 

 

 

 

 

 

Average revenue per KWH sold (cents)

 

24.65

 

20.83

 

28.63

 

20.66

 

20.21

 

Residential

 

27.61

 

23.87

 

31.97

 

23.50

 

22.85

 

Commercial

 

25.56

 

21.54

 

29.25

 

21.38

 

20.98

 

Large light and power

 

21.41

 

17.68

 

25.36

 

17.68

 

17.38

 

Other

 

25.63

 

21.36

 

28.81

 

20.81

 

20.44

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential statistics

 

 

 

 

 

 

 

 

 

 

 

Average annual use per customer account (KWH)

 

7,317

 

7,523

 

7,640

 

7,996

 

8,056

 

Average annual revenue per customer account

 

$

2,021

 

$

1,796

 

$

2,443

 

$

1,879

 

$

1,840

 

Average number of customer accounts

 

386,767

 

384,600

 

382,821

 

379,621

 

375,143

 


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

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

 

65



Table of Contents

 

Generation statistics.  The following table contains certain generation statistics as of, and for the year ended, December 31, 2010.2012. 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-
HECO

 

Island of
Hawaii-
HELCO

 

Island of
Maui-
MECO

 

Island of 
Lanai-
MECO

 

Island of 
Molokai-

MECO

 

Total

 

 

Island of
Oahu-
HECO

 

Island of
Hawaii-
HELCO

 

Island of
Maui-
MECO

 

Island of
Lanai-

MECO

 

Island of
Molokai-

MECO

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net generating and firm purchased capability (MW) as of December 31, 2010(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

Net generating and firm purchased capability (MW) as of December 31, 20121

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional oil-fired steam units

 

1,106.8

 

62.2

 

35.9

 

 

 

1,204.9

 

 

1,106.8

 

63.8

 

35.9

 

– 

 

– 

 

1,206.5

 

Diesel

 

 

30.8

 

96.8

 

10.1

 

9.6

 

147.3

 

 

– 

 

30.8

 

96.8

 

10.1

 

9.6

 

147.3

 

Combustion turbines (peaking units)

 

101.8

 

 

 

 

 

101.8

 

 

214.8

 

– 

 

– 

 

– 

 

– 

 

214.8

 

Other combustion turbines

 

113.0

 

46.3

 

 

 

2.2

 

161.5

 

 

– 

 

46.3

 

– 

 

– 

 

2.2

 

48.5

 

Combined-cycle unit

 

 

56.2

 

113.6

 

 

 

169.8

 

 

– 

 

56.2

 

113.6

 

– 

 

– 

 

169.8

 

Firm contract power(2)

 

434.0

 

90.0

 

16.0

 

 

 

540.0

 

Firm contract power2

 

434.0

 

94.6

 

16.0

 

– 

 

– 

 

544.6

 

 

1,755.6

 

285.5

 

262.3

 

10.1

 

11.8

 

2,325.3

 

 

1,755.6

 

291.7

 

262.3

 

10.1

 

11.8

 

2,331.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net peak demand (MW)

 

1,162.0

 

190.6

 

199.4

 

4.8

 

5.6

 

1,562.4

(3)

 

1,141.0

 

189.3

 

194.8

 

4.6

 

5.5

 

1,535.2

3

Reserve margin

 

52.9

%

49.8

%

31.5

%

110.8

%

111.5

%

52.6

%

 

58.1

%

54.1

%

34.6

%

120.0

%

115.4

%

56.0

%

Annual load factor

 

75.2

%

71.5

%

69.0

%

62.4

%

70.4

%

73.9

%

 

73.1

%

70.6

%

67.7

%

64.7

%

68.6

%

72.1

%

KWH net generated and purchased (millions)

 

7,657.0

 

1,194.2

 

1,204.4

 

26.3

 

34.5

 

10,116.4

 

 

7,311.0

 

1,170.4

 

1,154.4

 

26.1

 

33.0

 

9,694.9

 

 


(1)1     HECO units at normal ratings; MECO and HELCO units at reserve ratings.

(2)2                    Nonutility generators— HECO: 208 MW (Kalaeloa Partners, L.P., oil-fired), 180 MW (AES Hawaii, Inc., coal-fired) and 46 MW (HPower, refuse-fired); HELCO: 3034.6 MW (Puna Geothermal Venture, geothermal) and 60 MW (Hamakua Energy Partners, L.P., oil-fired); MECO: 16 MW (Hawaiian Commercial & Sugar Company, primarily bagasse-fired).

(3)3     Noncoincident and nonintegrated.

Generating reliability and reserve margin.  HECO serves the island of Oahu and HELCO serves the island of Hawaii. MECO has three separate electrical systems—one each on the islands of Maui, Molokai and Lanai. HECO, HELCO and MECO 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.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 purchased power adjustment clauses (PPACs) that allow them to recover purchase power expenses. The PUC approved the PPACs for HECO, HELCO and MECO 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.

HECO firm capacity PPAsHECO currently has three major PPAs.PPAs that provide a total of 434 MW of firm capacity, representing 25% of HECO’s total net generating and firm purchased capacity on Oahu as of December 31, 2012. In March 1988, HECO 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, HECO will

6



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, HECO filed an application with the PUC seeking a declaratory order that HECO is exempt from the rules under the PUC’s Competitive Bidding Framework, or in the alternative that HECO be granted a waiver from the rules, 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 has not yet issued a declaratory order, but HECO has begun preliminary discussions with AES Hawaii.

In October 1988, HECO 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 HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991.1991 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, and is designed to sell sufficient steam to be a QF.turbines. Following two additional amendments, effective in 2005, Kalaeloa currently supplies HECO with 208 MW of firm capacity.

7



Table In January 2011, HECO initiated renegotiation of Contents

the agreement with Kalaeloa (exempt from the rules under the PUC’s Competitive Bidding Framework).

HECO also entered into a PPA in March 1986 and a firm capacity amendment in April 1991 (the original PPA) with the City and County of Honolulu with respect to a refuse-fired plant (HPower). TheUnder the amended PPA, the HPower facility currently supplies HECO with 46 MW of firm capacity. UnderIn May 2012, HECO entered into an amended and restated PPA with the amendment, HECO willCity and County of Honolulu to purchase firm capacity until mid-2015. HPOWER is proceeding with its plan to expand its facility in order to provide an additional 27 MW net to HECO beginning in 2012.

HECO purchases energy on an as-available basis from three nonutility generators, two of which are qualifying cogeneration facilities at two oil refineries, Chevron USA, Inc. (10 MW) and Tesoro Hawaii Corporation (19 MW). These two contracts continue unless a party elects to terminate upon 90 days notice. The third nonutility generator, Kahuku Wind Power (30 MW), is a wind facility classified as an eligible resource under Hawaii’s RPS Law and as a QF under PURPA. The contract with Kahuku Wind Power is for a period of 20 years following the commercial operations date, which is expected to be in the first quarter of 2011.

The PUC has allowed rate recovery for the purchased energy costs related to HECO’s as-available energy PPAs and for the firm capacity and purchased energy costs related to HECO’s three major PPAs that provide a total of 43473 MW of firm capacity representing 25%(including the current 46 MW) from the expanded HPower facility for a term of HECO’s total net generating20 years from the commercial operation date, which will occur once certain conditions precedent and firm purchased capacity on Oahu as of December 31, 2010.further requirements have been satisfied. The PPA was approved by the PUC in January 2013.

HELCO and MECO firm capacity PPAsAs of December 31, 2010,2012, HELCO has PPAs for 9098 MW (of which 94.6 MW are currently available) and MECO has PPAsa PPA for 16 MW (includes(including 4 MW of system protection) of firm capacity, which PPAs have been approved by the PUC.capacity.

HELCO 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. Since April 2009, PGV’s output had been reduced due to problems with two of its production wells, but its output was restored to 30 MW in June 2010. In February 2011, HELCO and PGV amended the current PPA for the pricing on a portion of the energy payments and entered into a new PPA for HELCO to acquire an additional 8 MW of firm, dispatchable capacity from the facility. Both the amendment and the new PPA are subject towere approved by the PUC approval.

on December 30, 2011. PGV’s expansion became commercially operational in March 2012 for a total facility capacity of 34.6 MW.

In October 1997, HELCO entered into an agreement with Encogen, which has been succeeded by Hamakua Energy Partners, L. P. (HEP). The agreement requires HELCO 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.

MECO 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, on not less thanwith two years’ prior written notice, by either party.except that the parties have agreed that notice of termination on December 31, 2014 may be given on or before June 30, 2013.

 

HELCO and MECO purchase energy on an as-available basis from a number of nonutility generators, including hydroelectric facilities, windfarms and photovoltaic systems. The PUC has allowed rate recovery for the firm capacity and purchased energy costs for HELCO’s and MECO’s approved firm capacity and as-available energy PPAs.7



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—policies–Revenues” in HEI’s MD&A.

HECO’s steam generating units burn LSFO. HECO’s combustion turbine peaking units burn diesel fuel (diesel) and B99 grade biodiesel (biodiesel) and diesel engine generating units burn diesel.. HECO’s new CIP CT-1 is being operated exclusively on biodiesel. A HECO steam unit is currently employed inhas successfully completed a co-firing project to test burn mixtures of LSFO and crude palm oil purchased under a PUC-approved spot contract with Sime Darby Biodiesel Sdn. Bhd. (Sime Darby) dated June 3, 2009 and physically received in December 2010.

8



Table of Contents

biofuel.

MECO’s and HELCO’s steam generating units burn medium sulfur fuel oil (MSFO) and theirHELCO’s and MECO’s Maui combustion turbine generating units burn diesel. HELCO’s and MECO’s Maui, Molokai and Lanai diesel engine generating units burn ultra-low-sulfur diesel and biodiesel. A MECO combustion turbinediesel generating unit is being prepared tohas successfully completed a biodiesel test fire biodiesel for an assessment of the longer-term impact on unit performance. This biodiesel is expected to be supplied to MECO in early 2011 by Sime Darby under the terms of a spot contract dated June 26, 2009.

The diesel supplies acquired by the Lanai Division of MECO are purchased under the provisions of a contract with a local petroleum wholesaler, Lanai Oil Co., Inc., which provides for automatic one-year term extensions unless terminated by either party with 180 days notice. On May 26, 2010, MECO and Lanai Oil amended the fuel supply contract to provide for the supply of the Ultra Low Sulfur grade of diesel, which was to be consumed in the new Manele Bay combined heat and power (CHP) facility and other of Lanai Division’s generating units, in accordance with State and federal regulations applicable October 1, 2010. In October 2010, the PUC approved this amendment.

project.

See the fuel oil commitments information set forth in the “Fuel contracts” section in Note 3 toof HEI’s Consolidated Financial Statements, including discussions of contracts with Chevron Products Company, a division of Chevron USA, Inc. (Chevron), Tesoro Hawaii Corporation (Tesoro), Renewable Energy Group Marketing & Logistics Group LLC (REG) and Aina Koa Pono-Ka’u LLC.

Statements.

The following table sets forth the average cost of fuel oil used by HECO, HELCO and MECO to generate electricity in the years 2010, 20092012, 2011 and 2008:2010:

 

 

 

HECO

 

HELCO

 

MECO

 

Consolidated

 

 

 

$/Barrel

 

¢/MBtu

 

$/Barrel

 

¢/MBtu

 

$/Barrel

 

¢/MBtu

 

$/Barrel

 

¢/MBtu

 

2010

 

85.49

 

1,352.1

 

89.33

 

1,460.4

 

95.17

 

1,595.8

 

87.62

 

1,404.8

 

2009

 

60.90

 

966.5

 

68.28

 

1,109.0

 

73.54

 

1,231.9

 

63.91

 

1,026.4

 

2008

 

110.89

 

1,763.0

 

108.89

 

1,758.8

 

132.25

 

2,216.2

 

114.50

 

1,840.0

 

 

 

HECO

 

HELCO

 

MECO

 

Consolidated

 

 

 

$/Barrel

 

¢/MBtu

 

$/Barrel

 

¢/MBtu

 

$/Barrel

 

¢/MBtu

 

$/Barrel

 

¢/MBtu

 

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

 

2010

 

85.49

 

1,352.1

 

89.33

 

1,460.4

 

95.17

 

1,595.8

 

87.62

 

1,404.8

 

 

The average per-unit cost of fuel oil consumed to generate electricity for HECO, HELCO and MECO reflects a different volume mix of fuel types and grades as follows:

 

 

 

HECO

 

HELCO

 

MECO

 

 

 

LSFO

 

Diesel/Biodiesel

 

MSFO

 

Diesel

 

MSFO

 

Diesel/Biodiesel

 

2010

 

99

%

1

%

58

%

42

%

24

%

76

%

2009

 

98

 

2

 

67

 

33

 

25

 

75

 

2008

 

99

 

1

 

75

 

25

 

24

 

76

 

 

 

HECO

 

HELCO

 

MECO

 

 

LSFO

 

Diesel/Biodiesel

 

MSFO

 

Diesel

 

MSFO

 

Diesel/Biodiesel

2012

 

99%

 

1%

 

59%

 

41%

 

22%

 

78

%

2011

 

99  

 

1

 

56

 

44

 

22

 

78

 

2010

 

99  

 

1

 

58

 

42

 

24

 

76

 

 

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. During 2010,In 2012, prices of all petroleum fuels trended higher through the spring, peaked in early summer and then moved gradually lower through the remainder of the year. Though prices ended 2012 slightly lower than at the end of the previous year, on average the prices of LSFO, MSFO and diesel trendedwere higher in 2012 as a whole, increasing by approximately 8%, 7% and 4%, respectively. The per-unit price of biodiesel exhibited a trend similar to petroleum fuels but peaked in late summer 2012, before falling steadily through the first half of 2010 and then weakened in the fall months before rising at year-end. The prices of these fuels rose approximately by 30% and 15%, respectively, over the courseend of the year. MSFO and biodiesel prices exhibited a less pronounced volatility during 2010 asThe average price for 2012 was approximately comparable to the prior year after the retroactive application of the $1 per unit prices of each increased steadily, if gradually, such that their prices ended the period about 6% above their respective starting places.

gallon federal blenders credit enacted in early 2013.

In December 2000, HELCO and MECO executed contracts of private carriage with Hawaiian Interisland Towing, Inc. (HITI) 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 extended for a second 5-year term commencing January 1, 2007 and contain options for two additional 5-year extensions. On August 14, 2007 the equity interest of Smith Maritime, Ltd., the parent company of HITI, was acquired by a subsidiary of K-Sea Transportation Partners L.P. (K-Sea)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.

K-SeaKirby 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, K-SeaKirby is generally contractually obligated to indemnify HELCO and/or MECO for resulting clean-up costs, fines and damages. K-Sea hasKirby maintains liability insurance coverage for oil spill related damagean amount in excess of $1 billion.billion for oil spill related damage. State law provides a cap of $700 million on liability for

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releases of heavy fuel oil transported interisland by tank barge. In the event of a

8



release, HELCO and/or MECO may be responsible for any clean-up, damages, and/or fines that K-Sea orKirby and its insurance carrier doesdo not cover.

The prices that HECO, HELCO and MECO 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 Tesoro Hawaii Corporation (Tesoro), vary primarily with world LSFOAsian fuel oil prices. The HPower, HC&S and PGV energy prices are based on the electric utilities’ respective PUC-filed 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 HELCO’s diesel costs.

The utilities estimate that 75%73% of the net energy they generate or purchase will generate and purchase in 2011 will be generatedcome from the burning of fossil fuel oil.in 2013. HECO generally maintains an average system fuel inventory level equivalent to 47 days of forward consumption. HELCO and MECO 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.  HECO, HELCO and MECO are subject to the regulatory jurisdiction of the PUC with respect to rates, issuance of securities, accounting and certain other matters. See “Regulation” below.

All rateRate schedules of HECO and its subsidiaries contain ECACs as described previously.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—utility–Most recent rate requests,”proceedings, “Electric utility—Decoupling proceeding,” “Electric utility—utility–Certain factors that may affect future results and financial condition—condition–Regulation of electric utility rates” and “Electric utility—utility–Material estimates and critical accounting policies—policies–Revenues” in HEI’s MD&A and “Interim increases” and “Major projects—Campbell Industrial Park combustion turbine No. 1and transmission line”projects” under “Commitments and contingencies” in Note 3 toof HEI’s Consolidated Financial Statements.

Public Utilities Commission and Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs of the State of Hawaii.  On February 3, 2011, the Governor of the State of Hawaii announced the appointment of State Representative Hermina M. Morita asis the Chairman of the PUC (for a term that expireswill expire in June 2014), subject to confirmation by the and was formerly a State Senate.Representative. The other commissioners are Carlito P. CalibosoMichael E. Champley (for a term that expireswill expire in June 2016), an attorneywho previously in private practice,was a senior energy consultant and John E. Colea senior executive with DTE Energy, and Lorraine H. Akiba (for a term that expireswill expire in June 2012)2018), an attorney in private practice who previously served as the Executive Director of the DivisionState Department of Consumer Advocacy.Labor and Industrial Relations.

Since January 2011, theThe Executive Director of the Division of Consumer Advocacy has beenis Jeffrey T. Ono, an attorney previously in private practice.

Competition.  See “Electric utility—utility–Certain factors that may affect future results and financial condition—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. HECO and its subsidiaries 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 dis tributiondistribution facilities. Management cannot predict the impact, if any, the EMF issue may have on HECO, HELCO and MECO in the future.

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Global climate change and greenhouse gas (GHG) emissions reduction.  The Company shares the concerns of many regarding the potential effects of global warming and the human contributions to this

9



phenomenon, including burning of fossil fuels for electricity production, transportation, manufacturing and agricultural activities, as well as deforestation. Recognizing that effectively addressing global warming requires commitment by the private sector, all levels of government, and the public, the Company is committed to taking direct action to mitigate greenhouse gasGHG emissions from its operations. See “Environmental regulation—regulation–Global climate change and greenhouse gas emissions reduction” under “Commitments and contingencies” in Note 3 toof HEI’s Consolidated Financi alFinancial Statements.

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

Commitments and contingencies.  See “Selected contractual obligations and commitments” in HECO’s MD&A and “Electric utility—utility–Certain factors that may affect future results and financial condition—condition–Other regulatory and permitting contingencies” in HEI’s MD&A, Item 1A. Risk Factors, and Note 3 toof HEI’s 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 HECO and its electric utility subsidiaries. See the previous discussion under “Rates” and the discussions under “Electric utility—utility–Results of operations—operations–Most recent rate requests”proceedings” and “Electric utility—utility–Certain factors that may affect future results and financial condition—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 HECO’s and the Company’s financial condition, results of operations, financial condition or cash flows.

liquidity.

On October 20, 2008, HECO signed an Energy Agreement (see “Hawaii Clean Energy Initiative” under “Commitments and contingencies” in Note 3 toof HEI’s 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. One of the proceedings has resulted in the adoption of a new framework that will substantially change the manner in which the utilities obtain rate relief. See “Decoupling” in HEI’s MD&A.

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 (HECO, HELCO and MECO) and HEI and affiliated interests (as defined by statute) are subject to regulation by the PUC. An “affiliated interest” is defined by statute and includes officers and directors of a public utility, every person owning or holding, directly or indirectly, 10% or more of the voting securities of a public utility, and corporations which have in common with a public utility more than one-third of the directors of that public utility. All contracts (including summaries of unwritten agreements) made on or after July 1, 1988 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 paymentscontract 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.

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In December 1996, the PUC issued an order in a docket that had been opened to review the relationship between HEI and HECO and the effects of that relationship on the operations of HECO. The order adopted the report of the consultant the PUC had retained and ordered HECO 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 HECO). HECO files such status reports annually. In the order, the PUC also required HECO, HELCO and MECO to present a comprehensive analysis of the impact that the holding company structure and investments

10



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 PUC has not disputed,HECO, HELCO and MECO have made presentations in their subsequent rate cases the presentations made by HECO, HELCO and MECOto support their positions that there was no evidence that would modify the PUC’s finding that HECO’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 HECO’s utility customers.

HECO and its electric utility subsidiaries are not subject to regulation by the Federal Energy Regulatory CommissionFERC 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 Federal Energy Regulatory CommissionFERC 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 HECO and its electric utility subsidiaries. HECO and its electric utility subsidiaries are also required to file various operational reports with the Federal Energy Regulatory Commission. The Company cannot predict the extent to which cogeneration or transmiss ion access will reduce its electrical loads, reduce its current and future generating and transmission capability requirements or affect its financial condition, results of operations or cash flows.

FERC.

Because they are located in the State of Hawaii, HECO 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—“HEI–Regulation” above.

Environmental regulation.  HECO, HELCO and MECO, 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. When the corrective or other necessary action is taken, no further regulatory action is expected. Except as otherwise disclosed in this report (see “Certain factors that may affect future results and financial condition—condition–Environmental matters” for HEI Consolidated, the Electric utility and the Bank sections in HEI’s MD&A and Note 3 toof HEI’s 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 HECO.

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), and other regulations associated with discharges of oil and other substances to surface waterwater..

OPA governs actual or threatened oil releases and establishes strict and joint and several liability for responsible parties for (1) oil removal costs incurred by the federal government or the state, and (2) damages to natural resources and real or personal property, as well as compensation for certain economic damages. Responsible parties include vessel owners and operators of on-shore facilities. OPA imposes fines and jail terms ranging in severity depending on how the release was caused.

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In 20102012 and 20112013 to date, HECO, HELCO and MECO did not experience any significant petroleum releases. See the discussion concerning the ongoing Honolulu Harbor investigation under “Environmental regulation” in Note 3 to HEI’s Consolidated Financial Statements. Except as otherwise disclosed, theThe 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.

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.  CertainThe determination of whether SPCC Plan requirements are applicable to a facility depends on the amount of petroleum stored at the facility and whether a release of petroleum could reach waters of the facilities ofU.S.  The HECO, HELCO, and MECO facilities that are subject to the SPCC program (includingPlan requirements, including most power plants, base yards, and certain baseyards)substations, are in compliance with theseSPCC Plan requirements. The utilities expect to complete and implement their SPCC Plans for other facilities subject to these requirements (principally their substations) by the current compliance deadline of November 10, 2011.

As required by section 316(b) of the Clean Water Act, proposed regulations governing protection of aquatic organisms in cooling water intake structures at three of HECO’s power plants are expected in 2011. Depending on the ultimate regulations adopted by the EPA, the cost of compliance could be significant.

 

Air quality controls.  The generating stations of the utility subsidiaries operate under air pollution control permits issued by the Department of Health of the State of Hawaii (DOH) and, in a limited number of cases, by the EPA. The entire electric utility industry has been affected by the 1990 amendments to the Clean Air Act (CAA), changes to the National Ambient Air Quality Standard (NAAQS) for ozone, adoption of a NAAQS for fine particulate matter, and the EPA’s 1-hour NAAQS for nitrogen dioxide and sulfur dioxide (adopted in 2010). Regulations are expected to be issued in 2011 proposing Maximum Available Control Technology (MACT) standards for hazardous air pollutants (HAPs) emitted by electrical steam generating units (EGUs) that may be applicable to all HECO steam units. Depending on the HAPs covered by th e final regulations and the MACT standards adopted for those HAPs, the cost of compliance for HECO could be significant. By the terms of a federal court consent decree, the EPA is required to issue proposed EGU MACT regulations in March 2011 and final regulations in November 2011. The EPA has also required HELCO (for its Hill Power Plant) and MECO (for its Kahului Power Plant) to develop evaluations of emission controls for units at those plants that the EPA believes contribute to Regional Haze. Depending on final Regional Haze rules that the EPA will issue for Hawaii, the cost of compliance for HELCO and MECO could be significant.

The 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. The more stringent NAAQS will affect new or modified generating units

11



requiring a permit to construct under the PSDPrevention 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 leak detection, spill prevention and new tank standard retrofit requirements. All HECO, HELCO and MECO USTs currently meet these standards.

The Emergency Planning and Community Right-to-Know Act under SARA Title III requires HECO, HELCO and MECO 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 HECO, HELCO and MECO 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 HECO, HELCO and MECO 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

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apply to responses to releases of PCB to the environment. HECO, HELCO and MECO 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 HECO, HELCO and MECO 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.

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 comes to beis 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.

HECO, HELCO and MECO 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 impacts due to the releases in compliance with applicable regulatory requirements.

 

Research and development.  HECO and its subsidiaries expensed approximately $4.0 million, $4.4$4.3 million and $4.0 million in 2010, 20092012, 2011 and 2008,2010, respectively, for research and development (R&D). In 2010, 20092012, 2011 and 2008,2010, the electric utilities’ contributions to the Electric Power Research Institute accounted for approximately half of the R&D expenses. There were also utility expenditures in 2010, 20092012, 2011 and 20082010 related to new technologies, biofuels, energy efficiency and conservation,storage, demand response, customer use and pricing (e.g., peak pricing and tiered rates based on usage), biofuels, energy storage,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 HECO, see HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures about Market Risk” and HECO’s Consolidated Financial Statements.

12



Properties.

 

HECO owns and operates four generating plants on the island of Oahu at Honolulu, Waiau, Kahe and Campbell Industrial Park.Park (CIP). These plants have an aggregate net generating capability of 1,321.6 MW as of December 31, 2010.2012. The four plants are situated on HECO-owned land having a combined area of 535 acres and one 3.5-acre parcelthree parcels of land totaling 5.5 acres under a leaseleases expiring between June 30, 2016 and December 31, 2018.2018, with options to extend to June 30, 2026. In addition, HECO owns a total of 132 acres of land on which substations, transformer vaults, distribution baseyards and the Kalaeloa cogeneration facility are located.

 

HECO owns overhead transmission lines, overhead distribution lines, underground cables, poles (fully owned or jointly owned) and steel or aluminum high voltage transmission towers. The transmission system operates at 46 kilovolt (kV) and 138 kV.

HECO owns buildings and approximately 11.6 acres of land located in Honolulu which houseshouse its operating, engineering and information services departments and a warehousing center. It also leases an office building and certain office spacesspace in Honolulu. The lease for the office building expires in November 2021, with an option to extend through November 2024. The leasesLeases for certain office and warehouse spaces expire on various dates from DecemberAugust 31, 20112013 through November 30, 2017July 31, 2025 with options to extend to various dates through July 31, 2021.2030.

 

HECO owns land at Campbell Industrial Park (CIP)CIP used to situate central fuel storage facilities adjacent to its CIP CT-1combustion turbine No. 1 (CT-1) generating unit facility with an aggregate usable capacity of 786,632954,036 barrels of fuel, which land is included in the power plant acreage above. HECO also has fuel storage facilities at each of its plant sites with a combined usable capacity of 869,093 barrels, as well as underground fuel pipelines that transport fuel from HECO’s central fuel storage at CIP to fuel storage facilities at HECO’s generating stations at Waiau and Kahe. HECO also owns a fuel storage facility at Iwilei, which receives fuel trucked from the central storage facility, with a combined usable capacity of 76,735 barrels, and an under-ground pipeline that transports fuel from that site to its Honolulu generating station.

 

HELCO 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 195.5197.1 MW as of December 31, 20102012 (excluding several small run-of-river hydro units and a small windfarm)units). The plants are situated on HELCO-owned land having a combined

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area of approximately 44 acres. The distributed generators are located within HELCO-owned substation sites having a combined area of approximately 4 acres. HELCO also owns fuel storage facilities at these sites with a total maximum usable storage capacity of 66,38751,500 barrels of bunker oil and 83,81981,802 barrels of diesel. There are an additional 30,34119,200 barrels of diesel and 22,770 barrels of bunker oil storage capacity for HELCO-owned fuel off-site at Chevron-ownedChevron Products Company (Chevron)-owned terminalling facilities. HELCO pays a storage fee to Chevron and has no other interest in the property, tanks or other infrastructure situated on Chevron’s property. HELCO 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. HELCO als oalso leases 3.7 acres of land for its baseyard in Hilo under a lease expiring in 2030. In addition, HELCO 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.

 

MECO owns and operates two generating plants on the island of Maui, at Kahului and Maalaea, with an aggregate net generating capability of 246.3 MW as of December 31, 2010.2012. The plants are situated on MECO-owned land having a combined area of 28.6 acres. MECO also owns fuel oil storage facilities at these sites with a total maximum usable capacity of 176,35581,272 barrels of fuel.bunker oil, and 94,586 barrels of diesel. MECO owns two 1 MW stand-by diesel generators and a 6,000 gallon fuel storage tank located in Hana. MECO owns 65.7 acres of undeveloped land at Waena. Most of this Waena land is used for agricultural purposes by the former landowner under an amended license agreement, which is effective on a month-to-month basis, but terminable by either party upon 30 days written notice until the area is required for development by MECO for utility purposes, (e. g., proposed biofuel plant), or until DecemberJuly 31, 2011,2013, whichever occurs first.

 

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

 

MECO also owns and operates smaller distribution systems, generation systems (with an aggregate net capability of 21.9 MW as of December 31, 2010)2012) and fuel storage facilities on the islands of Lanai and Molokai, primarily on land owned by MECO.

 

13



Other properties.  The utilities own overhead transmission lines,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 kV,kilovolt (kV), 69 kV or 138 kV lines can be constructed overhead or must be placed underground.

 

See “HECO and subsidiaries and service areas” above for a discussion of the nonexclusive franchises of HECO and subsidiaries. Most of the leases, easements and licenses for HECO’s, HELCO’s and MECO’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, 2010,2012, ASB was one of the largest financial institutions in the State of Hawaii based on total assets of $4.8$5.0 billion and deposits of $4.0$4.2 billion. In 2010,2012, ASB’s revenues and net income amounted to approximately 11%8% and 51%42% of HEI’s consolidated revenues and net income, respectively, compared to approximately 12%8% and 26%43% in 20092011 and approximately 11% and 20%51% in 2008,2010, 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, 2010,2012, as a result of certain HEI contributions of capital to ASB, HEI’s maximum obligation under the agreement to contribute additional capital has been

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reduced to approximately $28.3 million. ASB is subject to OTSOCC regulations on dividends and other distributions and ASB must receive a letter of non-objection from the OTSOCC and FRB before it can declare and pay a dividend to HEI.

 

ASB’s earnings depend primarily on its net interest income—the difference between the interest income earned on earning assets (loans receivable and investment and mortgage-related securities) and the interest expense incurred on costing liabilities (deposit liabilities and other borrowings, including advances from the Federal Home Loan Bank (FHLB) of Seattle and securities sold under agreements to repurchase). Other factors affecting ASB’s operating results include its provision for loan losses, fee income, other noninterest income (including gains and losses on sales of loans, securities and notes and other-than-temporary impairments of securities) and noninterest expenses (including losses resulting from the early extinguishment of debt such as the loss resulting from a balance sheet restructuring in June 2008).

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 to HEI’s Consolidated Financial Statements.

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

 

Years ended December 31

 

2010

 

2009

 

2008

 

 

2012  

 

2011  

 

2010

 

Common equity to assets ratio

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average common equity divided by average total assets

 

10.34

%

9.38

%

9.20

%

 

10.14%

 

10.24%

 

10.34%

 

Return on assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock divided by average total assets

 

1.20

 

0.43

 

0.29

 

 

1.18

 

1.23

 

1.20

 

Return on common equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock divided by average common equity

 

11.62

 

4.54

 

3.17

 

 

11.68

 

11.99

 

11.62

 

Tangible efficiency ratio

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total noninterest expense, less amortization of intangibles, divided by net interest income and noninterest income

 

56

 

72

 

85

 

 

59

 

57

 

56

 

 

All of the foregoing ratios and returns for 2009 were adversely affected by ASB’s sale of its private-issue mortgage-related securities portfolio. All of the foregoing ratios and returns for 2008 were adversely affected by ASB’s restructuring of its balance sheet in June 2008.

ASB’s tangible efficiency ratio — the cost of earning $1 of revenue — decreased from 72% in 2009 to 56% in 2010, primarily due to losses related to the sale of the private-issue mortgage-related securities portfolio and other-than-temporary impairment (OTTI) charges on ASB’s securities portfolio in 2009 and lower noninterest expenses in 2010 due to the performance improvement project. The increase in tangible efficiency ratio for 2008 compared to 2009 was due to charges to noninterest income and noninterest expenses as a result of the restructuring of its balance sheet.

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

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

InterestConsolidated 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 for a table of average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid for certain categories of earning assets and costing liabilities for the years ended December 31, 2010, 2009 and 2008.&A.

 

16



Table of Contents

The following table shows for the periods indicated 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

14



average balance multiplied by prior period weighted-average interest rate). Any remaining change is allocated to the above two categories on a prorataprorata basis.

 

(in thousands)

 

2010 vs. 2009

 

2009 vs. 2008

 

Increase (decrease) due to

 

Rate

 

Volume

 

Total

 

Rate

 

Volume

 

Total

 

Income from earning assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Investment and mortgage-related securities

 

$

(9,847

)

$

(2,184

)

$

(12,031

)

$

(4,895

)

$

(33,336

)

$

(38,231

)

Loans receivable, net

 

(1,700

)

(20,946

)

(22,646

)

(15,431

)

(13,941

)

(29,372

)

 

 

(11,547

)

(23,130

)

(34,677

)

(20,326

)

(47,277

)

(67,603

)

Expense from costing liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Deposit liabilities

 

12,588

 

6,762

 

19,350

 

18,309

 

9,128

 

27,437

 

Other borrowings

 

(1,113

)

4,957

 

3,844

 

8,128

 

26,316

 

34,444

 

 

 

11,475

 

11,719

 

23,194

 

26,437

 

35,444

 

61,881

 

Net interest income

 

$

(72

)

$

(11,411

)

$

(11,483

)

$

6,111

 

$

(11,833

)

$

(5,722

)

(in thousands)

 

2012 vs. 2011

 

2011 vs. 2010

 

Increase (decrease) due to

 

Rate

 

Volume

 

Total

 

Rate

 

Volume

 

Total   

 

Income from earning assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Other investments

 

$         –

 

$     (73

)

$     (73

)

$     (23

)

$   (256

)

$    (279

)

Available-for-sale investment and mortgage-related securities

 

(375

)

(298

)

(673

)

(1,794

)

1,695

 

(99

)

Loans

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

(4,351

)

(6,501

)

(10,852

)

(4,260

)

(9,933

)

(14,193

)

Commercial real estate

 

(1,941

)

2,417

 

476

 

(131

)

1,400

 

1,269

 

Home equity line of credit

 

(947

)

3,118

 

2,171

 

(1,633

)

3,000

 

1,367

 

Residential land

 

255

 

(1,137

)

(882

)

(89

)

(1,603

)

(1,692

)

Commercial loans

 

(4,077

)

3,570

 

(507

)

(3,701

)

5,507

 

1,806

 

Consumer loans

 

(390

)

1,556

 

1,166

 

262

 

474

 

736

 

Total loans

 

(11,451

)

3,023

 

(8,428

)

(9,552

)

(1,155

)

(10,707

)

Total increase (decrease) in net interest income from earning assets

 

(11,826

)

2,652

 

(9,174

)

(11,369

)

284

 

(11,085

)

Expense from costing liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Savings

 

687

 

(59

)

628

 

578

 

(72

)

506

 

Interest-bearing checking

 

77

 

(4

)

73

 

160

 

(15

)

145

 

Money market

 

220

 

111

 

331

 

298

 

(64

)

234

 

Time certificates

 

724

 

804

 

1,528

 

2,638

 

2,190

 

4,828

 

Advances from Federal Home Loan Bank

 

(241

)

618

 

377

 

(7

)

20

 

13

 

Securities sold under agreements to repurchase

 

203

 

37

 

240

 

73

 

81

 

154

 

Total increase (decrease) in net interest income from costing liabilities

 

1,670

 

1,507

 

3,177

 

3,740

 

2,140

 

5,880

 

Total increase (decrease) in net interest income

 

$(10,156

)

$ 4,159

 

$ (5,997

)

$ (7,629

)

$ 2,424

 

$ (5,205

)

 

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.

GeneralLoansThe following table sets forth the composition of $3.5ASB’s loans receivable held for investment:

December 31

 

2012

 

 

 

2011

 

 

 

2010

 

 

 

2009

 

 

 

2008

 

 

 

(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

 

$1,866,450

 

49.2

 

$1,926,774

 

52.2

 

$2,087,813

 

58.9

 

$2,332,763

 

62.9

 

$2,812,177

 

66.5

 

Commercial real estate

 

375,677

 

9.9

 

331,931

 

9.0

 

300,689

 

8.5

 

255,716

 

6.9

 

243,109

 

5.8

 

Home equity line of credit

 

630,175

 

16.6

 

535,481

 

14.5

 

416,453

 

11.7

 

326,896

 

8.8

 

271,780

 

6.4

 

Residential land

 

25,815

 

0.7

 

45,392

 

1.2

 

65,599

 

1.8

 

96,515

 

2.6

 

126,963

 

3.0

 

Commercial construction

 

43,988

 

1.2

 

41,950

 

1.1

 

38,079

 

1.1

 

68,174

 

1.9

 

71,579

 

1.7

 

Residential construction

 

6,171

 

0.2

 

3,327

 

0.1

 

5,602

 

0.2

 

16,705

 

0.5

 

34,768

 

0.8

 

Total real estate loans, net

 

2,948,276

 

77.8

 

2,884,855

 

78.1

 

2,914,235

 

82.2

 

3,096,769

 

83.6

 

3,560,376

 

84.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

721,349

 

19.0

 

716,427

 

19.4

 

551,683

 

15.5

 

545,622

 

14.7

 

597,234

 

14.1

 

Consumer loans

 

121,231

 

3.2

 

93,253

 

2.5

 

80,138

 

2.3

 

64,360

 

1.7

 

72,524

 

1.7

 

 

 

3,790,856

 

100.0

 

3,694,535

 

100.0

 

3,546,056

 

100.0

 

3,706,751

 

100.0

 

4,230,134

 

100.0

 

Less: Deferred fees and discounts

 

(11,638

)

 

 

(13,811

)

 

 

(15,530

)

 

 

(19,494

)

 

 

(24,631

)

 

 

Allowance for loan losses

 

(41,985

)

 

 

(37,906

)

 

 

(40,646

)

 

 

(41,679

)

 

 

(35,798

)

 

 

Total loans, net

 

$3,737,233

 

 

 

$3,642,818

 

 

 

$3,489,880

 

 

 

$3,645,578

 

 

 

$4,169,705

 

 

 

Total loans as a % of assets

 

74.1

%

 

 

74.2

%

 

 

72.8

%

 

 

73.8

%

 

 

76.7

%

 

 

1Includes renegotiated loans.

15



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. In 2012, ASB ranked No. 1 in Hawaii for home equity line of credit loan production. Offsetting these loan portfolio increases was a decrease in the residential loan portfolio. Although ASB produced nearly $1.0 billion represented 72.8% of total assets as of December 31, 2010, comparednew, long-term residential loans in 2012, nearly double the level for 2011, it sold more than half those loans to $3.6 billion, or 73.8%,control interest rate risk and $4.2 billion, or 76.7%, as of December 31, 2009 and 2008, respectively.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 increase in loans receivable in 2008 was primarily due to growth in home equity lines of credit and commercial markets loans. ASB’s loan portfolio consists primarily of residential 1-4 family mortgage loans.

The following table sets forth the composition of ASB’s loan portfolio as of the dates indicated:

 

 

2010

 

2009

 

2008

 

2007

 

2006

 

December 31
(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

 

$

2,087,813

 

58.9

 

$

2,332,763

 

62.9

 

$

2,812,177

 

66.5

 

$

2,901,420

 

70.1

 

$

2,544,650

 

66.5

 

Commercial real estate

 

300,689

 

8.5

 

255,716

 

6.9

 

243,109

 

5.8

 

252,831

 

6.1

 

239,459

 

6.3

 

Home equity line of credit

 

416,453

 

11.7

 

326,896

 

8.8

 

271,780

 

6.4

 

194,549

 

4.7

 

186,209

 

4.9

 

Residential land

 

65,599

 

1.8

 

96,515

 

2.6

 

126,963

 

3.0

 

159,114

 

3.8

 

152,771

 

4.0

 

Commercial construction

 

38,079

 

1.1

 

68,174

 

1.9

 

71,579

 

1.7

 

34,184

 

0.8

 

110,517

 

2.9

 

Residential construction

 

5,602

 

0.2

 

16,705

 

0.5

 

34,768

 

0.8

 

55,867

 

1.4

 

58,259

 

1.5

 

Total real estate loans, net

 

2,914,235

 

82.2

 

3,096,769

 

83.6

 

3,560,376

 

84.2

 

3,597,965

 

86.9

 

3,291,865

 

86.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

551,683

 

15.5

 

545,622

 

14.7

 

597,234

 

14.1

 

471,576

 

11.4

 

453,151

 

11.9

 

Consumer loans

 

80,138

 

2.3

 

64,360

 

1.7

 

72,524

 

1.7

 

71,440

 

1.7

 

78,196

 

2.0

 

 

 

3,546,056

 

100.0

 

3,706,751

 

100.0

 

4,230,134

 

100.0

 

4,140,981

 

100.0

 

3,823,212

 

100.0

 

Less: Deferred fees and discounts

 

(15,530

)

 

 

(19,494

)

 

 

(24,631

)

 

 

(26,192

)

 

 

(22,033

)

 

 

Allowance for loan losses

 

(40,646

)

 

 

(41,679

)

 

 

(35,798

)

 

 

(30,211

)

 

 

(31,228

)

 

 

Total loans, net

 

$

3,489,880

 

 

 

$

3,645,578

 

 

 

$

4,169,705

 

 

 

$

4,084,578

 

 

 

$

3,769,951

 

 

 


(1)Includes renegotiated loans.

17



Table of Contents

 

The following table summarizes ASB’s loan portfolio as of December 31, 2010 and 2009, excluding loans receivable held for sale and including undisbursed commercial real estate construction and development loan funds,investment based upon contractually scheduled principal payments and expected prepayments allocated to the indicated maturity categories:

 

 

2010

 

2009

 

December 31

 

In
 1 year

 

After 1 year
through

 

After

 

 

 

In
 1 year

 

After 1 year
through

 

After

 

 

 

 

2012

 

2011

 

Due

 

or less

 

5 years

 

5 years

 

Total

 

or less

 

5 years

 

5 years

 

Total

 

 

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

 

$

486

 

$

981

 

$

540

 

$

2,007

 

$

560

 

$

1,088

 

$

597

 

$

2,245

 

 

$488

 

$   912

 

$   393

 

$1,793

 

$440

 

$   965

 

$  450

 

$1,855

 

Residential loans - Adjustable

 

37

 

38

 

5

 

80

 

42

 

39

 

7

 

88

 

 

36

 

33

 

4

 

73

 

37

 

32

 

3

 

72

 

 

523

 

1,019

 

545

 

2,087

 

602

 

1,127

 

604

 

2,333

 

Total residential loans

 

524

 

945

 

397

 

1,866

 

477

 

997

 

453

 

1,927

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial real estate loans-Fixed

 

9

 

56

 

24

 

89

 

13

 

60

 

55

 

128

 

 

19

 

64

 

39

 

122

 

13

 

54

 

15

 

82

 

Commercial real estate loans-Adjustable

 

46

 

115

 

89

 

250

 

62

 

104

 

30

 

196

 

 

56

 

100

 

142

 

298

 

56

 

113

 

123

 

292

 

Total commercial real estate loans

 

75

 

164

 

181

 

420

 

69

 

167

 

138

 

374

 

 

55

 

171

 

113

 

339

 

75

 

164

 

85

 

324

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consumer loans – Fixed

 

49

 

74

 

21

 

144

 

51

 

62

 

1

 

114

 

Consumer loans – Adjustable

 

48

 

68

 

529

 

645

 

49

 

85

 

431

 

565

 

Total consumer loans

 

97

 

142

 

550

 

789

 

100

 

147

 

432

 

679

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consumer loans — Fixed`

 

52

 

70

 

3

 

125

 

72

 

47

 

21

 

140

 

Consumer loans — Adjustable

 

44

 

92

 

309

 

445

 

44

 

99

 

227

 

370

 

 

96

 

162

 

312

 

570

 

116

 

146

 

248

 

510

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commercial loans — Fixed

 

33

 

71

 

14

 

118

 

94

 

178

 

35

 

307

 

Commercial loans — Adjustable

 

207

 

193

 

34

 

434

 

157

 

71

 

11

 

239

 

 

240

 

264

 

48

 

552

 

251

 

249

 

46

 

546

 

Commercial loans – Fixed

 

62

 

107

 

36

 

205

 

48

 

116

 

26

 

190

 

Commercial loans – Adjustable

 

220

 

266

 

30

 

516

 

212

 

268

 

46

 

526

 

Total commercial loans

 

282

 

373

 

66

 

721

 

260

 

384

 

72

 

716

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total loans - Fixed

 

580

 

1,178

 

581

 

2,339

 

739

 

1,373

 

708

 

2,820

 

 

618

 

1,157

 

489

 

2,264

 

552

 

1,197

 

492

 

2,241

 

Total loans - Adjustable

 

334

 

438

 

437

 

1,209

 

305

 

313

 

275

 

893

 

 

360

 

467

 

705

 

1,532

 

354

 

498

 

603

 

1,455

 

 

$

914

 

$

1,616

 

$

1,018

 

$

3,548

 

$

1,044

 

$

1,686

 

$

983

 

$

3,713

 

Total loans

 

$978

 

$1,624

 

$1,194

 

$3,796

 

$906

 

$1,695

 

$1,095

 

$3,696

 

 

The decrease in fixed rate residential loans was due to repayments in the portfolio and the sale of fixed rate loans in the secondary market.

 

Origination, purchase and sale of loansGenerally, residential and commercial real estate loans originated by ASB are securedcollateralized 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 14 toof HEI’s 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 lendingASB’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 lendingASB 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 securedcollateralized 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& #148;elements” and “Multifamily residential and commercial real estate lending” below.

16



 

Multifamily residential and commercial real estate lendingASB provides permanent financing and construction and development financing securedcollateralized by multifamily residential properties (including apartment buildings) and securedcollateralized 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.

 

18



Table of Contents

Consumer lendingASB offers a variety of secured and unsecured consumer loans. Loans securedcollateralized 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 lendingASB provides both secured and unsecured commercial loans to business entities. This lending activity is part of ASB’s strategic transformation to a full-service community bank and 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 incomeIn 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 toof HEI’s Consolidated Financial Statements.

 

Loan portfolio risk elementsWhen 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 securingcollateralizing 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, 2010, December 31, 20092012, 2011 and December 31, 2008,2010, ASB had $4.3$6.1 million, $4.0$7.3 million and $1.5$4.3 million, respectively, of real e stateestate 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 (renegotiated(troubled debt restructured loans). ASB loans that were 90 days or more past due on which interest was being accrued as of December 31, 2012, 2011, 2010, 2009 2008, 2007 and 20062008 were immaterial or nil. The following table sets forth certain information with respect to nonaccrual and renegotiated loans as of the dates indicated:troubled debt restructured loans:

December 31

 

2010

 

2009

 

2008

 

2007

 

2006

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Nonaccrual loans—

 

 

 

 

 

 

 

 

 

 

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

36,420

 

$

31,848

 

$

7,468

 

$

1,027

 

$

413

 

Commercial real estate

 

 

344

 

 

 

 

Home equity line of credit

 

1,659

 

2,755

 

759

 

464

 

130

 

Residential land

 

15,479

 

25,164

 

7,652

 

89

 

495

 

Residential construction

 

 

326

 

326

 

 

 

Total real estate loans

 

53,558

 

60,437

 

16,205

 

1,580

 

1,038

 

Consumer loans

 

341

 

715

 

523

 

342

 

215

 

Commercial loans

 

4,956

 

4,171

 

2,766

 

1,273

 

1,144

 

Total nonaccrual loans

 

$

58,855

 

$

65,323

 

$

19,494

 

$

3,195

 

$

2,397

 

Nonaccrual loans to end of period loans

 

1.7

%

1.8

%

0.5

%

0.1

%

0.1

%

Renegotiated loans not included above—

 

 

 

 

 

 

 

 

 

 

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

5,150

 

$

1,986

 

$

1,913

 

$

2,536

 

$

2,540

 

Commercial real estate

 

1,963

 

513

 

 

 

3,274

 

Residential land

 

27,689

 

15,665

 

2,125

 

 

 

Total real estate loans

 

34,802

 

18,164

 

4,038

 

2,536

 

5,814

 

Commercial loans

 

4,035

 

2,904

 

4,612

 

571

 

467

 

Total renegotiated loans

 

$

38,837

 

$

21,068

 

$

8,650

 

$

3,107

 

$

6,281

 

Nonaccrual and renegotiated loans to end of period loans

 

2.8

%

2.3

%

0.7

%

0.2

%

0.2

%

 

1917



Table of Contents

December 31

 

2012

 

2011

 

2010

 

2009

 

2008

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Nonaccrual loans—

 

 

 

 

 

 

 

 

 

 

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

26,721

 

$

28,298

 

$

36,420

 

$

31,848

 

$

7,468

 

Commercial real estate

 

6,750

 

3,436

 

– 

 

344

 

– 

 

Home equity line of credit

 

2,349

 

2,258

 

1,659

 

2,755

 

759

 

Residential land

 

8,561

 

14,535

 

15,479

 

25,164

 

7,652

 

Residential construction

 

– 

 

– 

 

– 

 

326

 

326

 

Total real estate loans

 

44,381

 

48,527

 

53,558

 

60,437

 

16,205

 

Consumer loans

 

284

 

281

 

341

 

715

 

523

 

Commercial loans

 

20,222

 

17,946

 

4,956

 

4,171

 

2,766

 

Total nonaccrual loans

 

$

64,887

 

$

66,754

 

$

58,855

 

$

65,323

 

$

19,494

 

Nonaccrual loans to end of period loans

 

1.7

%

1.8

%

1.7

%

1.8

%

0.5

%

Troubled debt restructured loans not included above—

 

 

 

 

 

 

 

 

 

 

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

6,759

 

$

5,029

 

$

5,150

 

$

1,986

 

$

1,913

 

Commercial real estate

 

– 

 

– 

 

1,963

 

513

 

– 

 

Residential land

 

11,090

 

24,828

 

27,689

 

15,665

 

2,125

 

Total real estate loans

 

17,849

 

29,857

 

34,802

 

18,164

 

4,038

 

Commercial loans

 

43

 

15,386

 

4,035

 

2,904

 

4,612

 

Total troubled debt restructured loans

 

$

17,892

 

$

45,243

 

$

38,837

 

$

21,068

 

$

8,650

 

Nonaccrual and troubled debt restructured loans to end of period loans

 

2.2

%

3.1

%

2.8

%

2.3

%

0.7

%

 

ASB realized $3.6$3.0 million, $2.0$6.3 million and $1.0$3.6 million of interest income on nonaccrual and renegotiatedtroubled debt restructured (TDR) loans in 2010, 20092012, 2011 and 2008,2010, respectively. If these loans would have earned interest in accordance with their original contractual terms ASB would have realized $6.7 million, $9.9 million and $3.8 million $2.9 millionin 2012, 2011 and $0.7 million in 2010, 2009 and 2008, respectively.

 

In 2007,2012, 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 is 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 due to decreases of $15.3 million and $13.7 million of commercial loans and residential land loans, respectively, classified as TDR. ASB evaluates the 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 2011, nonaccrual loans increased by $0.8 million when compared to 2006 due to higher delinquencies in the residential and consumer loan portfolios. In 2008, nonaccrual loans increased by $16.3$7.9 million due to higher residential loan delinquencies and the reclassification of 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 their weakening credit quality. In 2009, nonaccrualtwo commercial loans increased by $45.8 million primarily due to an increase in residential 1-4 family and residential land loans 90+ days delinquent.that were renegotiated. In 2010, nonaccrual loans decreased by $6.5 million due to a decrease in residential land loans that were 90+ days delinquent and the renegotiation of certain residential land loans that had been on nonaccrual status. In 2009, nonaccrual loans increased by $45.8 million primarily due to an increase in residential 1-4 family and residential land loans 90+ days delinquent.

18



 

Allowance for loan lossesSee “Allowance for loan losses” in Note 1 toof HEI’s Consolidated Financial Statements.

 

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

 

(dollars in thousands)

 

2010

 

2009

 

2008

 

2007

 

2006

 

 

2012

 

2011

 

2010

 

2009

 

2008

 

Allowance for loan losses, January 1

 

$

41,679

 

$

35,798

 

$

30,211

 

$

31,228

 

$

30,595

 

 

$37,906

 

$40,646

 

$41,679

 

$35,798

 

$30,211

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Provision for loan losses

 

20,894

 

32,000

 

10,334

 

5,700

 

1,400

 

 

12,883

 

15,009

 

20,894

 

32,000

 

10,334

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Charge-offs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

6,142

 

3,129

 

51

 

 

 

 

3,183

 

5,528

 

6,142

 

3,129

 

51

 

Home equity line of credit

 

2,517

 

2,331

 

21

 

89

 

 

 

716

 

1,439

 

2,517

 

2,331

 

21

 

Residential land

 

6,487

 

4,217

 

282

 

 

 

 

2,808

 

4,071

 

6,487

 

4,217

 

282

 

Total real estate loans

 

15,146

 

9,677

 

354

 

89

 

 

 

6,707

 

11,038

 

15,146

 

9,677

 

354

 

Commercial loans

 

6,261

 

14,853

 

3,447

 

6,301

 

766

 

 

3,606

 

5,335

 

6,261

 

14,853

 

3,447

 

Consumer loans

 

3,408

 

2,436

 

1,825

 

1,334

 

1,119

 

 

2,517

 

3,117

 

3,408

 

2,436

 

1,825

 

Total charge-offs

 

24,815

 

26,966

 

5,626

 

7,724

 

1,885

 

 

12,830

 

19,490

 

24,815

 

26,966

 

5,626

 

 

 

 

 

 

 

 

 

 

 

 

Recoveries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

744

 

151

 

46

 

68

 

200

 

 

1,328

 

110

 

744

 

151

 

46

 

Home equity line of credit

 

63

 

 

 

4

 

3

 

 

108

 

25

 

63

 

– 

 

– 

 

Residential land

 

63

 

 

 

 

 

 

1,443

 

170

 

63

 

– 

 

– 

 

Total real estate loans

 

870

 

151

 

46

 

72

 

203

 

 

2,879

 

305

 

870

 

151

 

46

 

Commercial loans

 

1,537

 

404

 

548

 

623

 

482

 

 

649

 

869

 

1,537

 

404

 

548

 

Consumer loans

 

481

 

292

 

285

 

312

 

433

 

 

498

 

567

 

481

 

292

 

285

 

Total recoveries

 

2,888

 

847

 

879

 

1,007

 

1,118

 

 

4,026

 

1,741

 

2,888

 

847

 

879

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for loan losses, December 31

 

$

40,646

 

$

41,679

 

$

35,798

 

$

30,211

 

$

31,228

 

 

$41,985

 

$37,906

 

$40,646

 

$41,679

 

$35,798

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of allowance for loan losses, December 31, to end of period loans

 

1.15

%

1.12

%

0.84

%

0.73

%

0.82

%

 

1.11

%

1.03

%

1.15

%

1.12

%

0.84

%

 

 

 

 

 

 

 

 

 

 

 

Ratio of provision for loan losses during the year to average loans outstanding

 

0.58

%

0.81

%

0.25

%

0.15

%

0.04

%

 

0.35

%

0.42

%

0.58

%

0.81

%

0.25

%

 

 

 

 

 

 

 

 

 

 

 

Ratio of net charge-offs during the year to average loans outstanding

 

0.61

%

0.66

%

0.11

%

0.17

%

0.02

%

 

0.24

%

0.49

%

0.61

%

0.66

%

0.11

%

 

20



Table of Contents

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 asloans:

December 31

 

2012

 

2011

 

2010

 

(dollars in thousands)

 

Balance

 

Allowance
to loan
receivable
%

 

Loan
receivable
% of
total

 

Balance

 

Allowance
to loan
receivable
%

 

Loan
receivable
% of
total

 

Balance

 

Allowance
to loan
receivable
%

 

Loan
receivable
% of
total

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$  6,068

 

0.33

 

49.2

 

$  6,500

 

0.34

 

52.2

 

$  6,497

 

0.31

 

58.9

 

Commercial real estate

 

2,965

 

0.79

 

9.9

 

1,688

 

0.51

 

9.0

 

1,474

 

0.49

 

8.5

 

Home equity line of credit

 

4,493

 

0.71

 

16.6

 

4,354

 

0.81

 

14.5

 

4,269

 

1.03

 

11.7

 

Residential land

 

4,275

 

16.56

 

0.7

 

3,795

 

8.36

 

1.2

 

6,411

 

9.77

 

1.8

 

Commercial construction

 

2,023

 

4.60

 

1.2

 

1,888

 

4.50

 

1.1

 

1,714

 

4.50

 

1.1

 

Residential construction

 

9

 

0.15

 

0.2

 

4

 

0.12

 

0.1

 

7

 

0.12

 

0.2

 

Total real estate loans, net

 

19,833

 

0.67

 

77.8

 

18,229

 

0.63

 

78.1

 

20,372

 

0.70

 

82.2

 

Commercial loans

 

15,931

 

2.21

 

19.0

 

14,867

 

2.08

 

19.4

 

16,015

 

2.90

 

15.5

 

Consumer loans

 

4,019

 

3.32

 

3.2

 

3,806

 

4.08

 

2.5

 

3,325

 

4.15

 

2.3

 

 

 

39,783

 

1.05

 

100.0

 

36,902

 

1.00

 

100.0

 

39,712

 

1.12

 

100.0

 

Unallocated

 

2,202

 

 

 

 

 

1,004

 

 

 

 

 

934

 

 

 

 

 

Total allowance for loan losses

 

$41,985

 

 

 

 

 

$37,906

 

 

 

 

 

$40,646

 

 

 

 

 

19



December 31

 

2009

 

2008

 

(dollars in thousands)

 

Balance

 

Allowance
to loan
receivable
%

 

Loan
receivable
% of
total

 

Balance

 

Allowance
to loan
receivable
%

 

Loan
receivable
% of
total

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$  5,522

 

0.24

 

62.5

 

$  4,024

 

0.14

 

66.2

 

Commercial real estate

 

861

 

0.34

 

6.9

 

2,229

 

0.92

 

5.7

 

Home equity line of credit

 

4,679

 

1.43

 

8.8

 

548

 

0.20

 

6.4

 

Residential land

 

4,252

 

4.41

 

2.6

 

1,953

 

1.54

 

3.0

 

Commercial construction

 

3,068

 

4.50

 

1.8

 

1,748

 

2.44

 

1.7

 

Residential construction

 

19

 

0.11

 

0.5

 

88

 

0.25

 

0.8

 

Total real estate loans, net

 

18,401

 

0.59

 

83.1

 

10,590

 

0.30

 

83.8

 

Commercial loans

 

19,498

 

3.57

 

14.6

 

22,294

 

3.73

 

14.0

 

Consumer loans

 

2,590

 

4.02

 

2.3

 

2,190

 

3.02

 

2.2

 

 

 

40,489

 

1.09

 

100.0

 

35,074

 

0.83

 

100.0

 

Unallocated

 

1,190

 

 

 

 

 

724

 

 

 

 

 

Total allowance for loan losses

 

$41,679

 

 

 

 

 

$35,798

 

 

 

 

 

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

 

 

 

2010

 

2009

 

2008

 

2007

 

2006

 

December 31
(dollars in thousands)

 

Balance

 

% of
total

 

Balance

 

% of
total

 

Balance

 

% of
total

 

Balance

 

% of
total

 

Balance

 

% of
total

 

Real estate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

6,497

 

58.9

 

$

5,522

 

62.5

 

$

4,024

 

66.2

 

$

3,906

 

69.8

 

$

5,092

 

66.2

 

Commercial real estate

 

1,474

 

8.5

 

861

 

6.9

 

2,229

 

5.7

 

2,760

 

6.1

 

4,289

 

6.3

 

Home equity line of credit

 

4,269

 

11.7

 

4,679

 

8.8

 

548

 

6.4

 

412

 

4.7

 

1,287

 

4.9

 

Residential land

 

6,411

 

1.8

 

4,252

 

2.6

 

1,953

 

3.0

 

256

 

3.9

 

466

 

4.0

 

Commercial construction

 

1,714

 

1.1

 

3,068

 

1.8

 

1,748

 

1.7

 

1,483

 

0.8

 

3,633

 

2.9

 

Residential construction

 

7

 

0.2

 

19

 

0.5

 

88

 

0.8

 

68

 

1.3

 

101

 

1.5

 

Total real estate loans, net

 

20,372

 

82.2

 

18,401

 

83.1

 

10,590

 

83.8

 

8,885

 

86.6

 

14,868

 

85.8

 

Commercial loans

 

16,015

 

15.5

 

19,498

 

14.6

 

22,294

 

14.0

 

18,820

 

11.4

 

13,936

 

11.9

 

Consumer loans

 

3,325

 

2.3

 

2,590

 

2.3

 

2,190

 

2.2

 

2,167

 

2.0

 

2,224

 

2.3

 

 

 

39,712

 

100.0

 

40,489

 

100.0

 

35,074

 

100.0

 

29,872

 

100.0

 

31,028

 

100.0

 

Unallocated

 

934

 

 

 

1,190

 

 

 

724

 

 

 

339

 

 

 

200

 

 

 

Total allowance for loan losses

 

$

40,646

 

 

 

$

41,679

 

 

 

$

35,798

 

 

 

$

30,211

 

 

 

$

31,228

 

 

 

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 arewere still signs of financial stress in the Hawaii and U.S. mainland markets. The slowdown in the economy, both nationally and locally, has 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 remain and the outlook for the Hawaii economy is for a slow, steady recovery. Consumers and businesses are expected t o recover slowly in 2011 as gradual improvement in measures such as job growth, unemployment and real personal income are expected.remained.

 

In 2009, ASB’s allowance for loan losses increased by $5.9 million from 2008 as a result of higher residential 1-4 family, residential land and home equity lines of credit delinquencies and increases in the historical loss ratios for these loan types. ASB’s loan quality weakened in 2009, although not to the same level of decline in loan quality seen in many mainland U.S. markets. The slowdown in the economy, both nationally and locally, had caused increased levels of financial stress on the part of ASB’s customers, resulting in higher levels of loan delinquencies and losses. ASB’s 2009 provision for loan losses was $32 million, which included a provision for loan loss on a commercial loan that was subsequently sold.

 

In 2008, ASB’s allowance for loan losses increased by $5.6 million from 2007 as a result of higher residential loan delinquencies, the reclassification of certain commercial loans due to their weakening credit quality and an increase in the loan portfolio. ASB had good credit quality in 2008 despite the weakening economy and slowing real estate market. Although new home purchase and home resale transaction volumes in Hawaii had fallen off, the Hawaii real estate market had not experienced as steep a decline in values as seen in many U.S. mainland markets. However, the slowdown in the economy, both nationally and locally, caused increased levels of financial stress on ASB’s customers, resulting in higher levels of loan delinquencies and losses. As a result, ASB’s 2008 provision for loan losses was $10.3 million, following several years of historically low loan losses and loan los s allowances.

In 2007, ASB’s allowance for loan losses decreased by $1.0 million when compared to 2006, primarily due to the charge-off of loans to one commercial borrower. ASB’s asset quality remained high due to the strength of the Hawaii economy and stability of the Hawaii real estate market, resulting in lower historical loss ratios and release of reserves for residential real estate and consumer loans. The decrease in allowance for loan losses for commercial real estate loans was due to the release of reserves on construction loans that had been repaid. The increase in allowance for loan losses for commercial loans was due to loan growth and the reclassification of certain commercial loans. A provision for loan losses of

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$5.7 million was recorded in 2007, primarily due to specific reserves for the one commercial borrower and the reclassified commercial loans that continued to be current on loan payments but had identified weaknesses.

 

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 issued by the FNMA and FHLMC. See “Balance sheet restructure” and “Investment and mortgage-related securities” in Note 4 to HEI’s Consolidated Financial Statements for a discussion of mortgage-related security sales.obligations. The weighted-average yield on investments during 2012, 2011 and 2010 2009was 1.99%, 2.01% and 2008 was 2.18%, 3.67% and 4.24%, respectively. ASB did not maintain a portfolio of securities held for trading during 2010, 20092012, 2011 and 2008.2010.

 

As of December 31, in each of2012, 2011 and 2010, 2009 and 2008, ASB’s investment in stock of the FHLB of Seattle amounted to $97.8 million.$96 million, $98 million and $98 million, respectively. The amount that ASB is required to invest in FHLB of Seattle stock is determined by regulatory requirements and ASB’s investment is in excess of that requirement. In third and fourth quarters 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 was $2 million. See “FHLB of Seattle stock” in HEI’s MD&A for a discussion of dividends on ASB’s investment in FHLB of Seattle Stock and recent events that have adversely affected those dividends.&A. Also, see “Regulation—“Regulation–Federal Home Loan Bank System” below.

 

With the sale of the private-issue mortgage-related securities in 2009, ASB does not have any exposure to securities backed by subprime mortgages. See “Investment and mortgage-related securities” in Note 4 toof HEI’s Consolidated Financial Statements for a discussion of other-than-temporarily impaired securities.

 

The following table summarizes ASB’s investment portfolio (excluding stock of the FHLB of Seattle, which has no contractual maturity), as of December 31, 2010,2012, 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

 

 

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

 

$

260

 

$

48

 

$

10

 

$

 

$

318

 

 

$  75

 

$  74

 

$  14

 

$  5

 

$ 168

 

Mortgage-related securities - FNMA, FHLMC and GNMA

 

90

 

170

 

38

 

8

 

306

 

 

118

 

186

 

76

 

21

 

401

 

Municipal bonds

 

1

 

9

 

29

 

2

 

41

 

 

 

16

 

55

 

 

71

 

 

$

351

 

$

227

 

$

77

 

$

10

 

$

665

 

 

$193

 

$276

 

$145

 

$26

 

$640

 

Weighted average yield

 

1.86

%

2.92

%

3.34

%

3.29

%

 

 

 

2.50%

 

1.69%

 

2.29%

 

2.36%

 

 

 

 

Deposits and other sources of funds.

 

GeneralDeposits 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 of fundssource than deposits.

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Table of Contents

 

DepositsASB’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 $160 million in 2012 compared to an inflow of $95 million in 2011 and an outflow of $83 million in 2010 compared to outflows of $121 million in 2009 and $167 million in 2008.2010.

21



 

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

 

 

2010

 

2009

 

2008

 

 

 

 

% of

 

Weighted

 

 

 

% of

 

Weighted

 

 

 

% of

 

Weighted

 

Years ended December 31

 

Average

 

total

 

average

 

Average

 

total

 

average

 

Average

 

total

 

average

 

 

2012

 

2011

 

2010

 

(dollars in thousands)

 

balance

 

deposits

 

rate %

 

balance

 

deposits

 

rate %

 

balance

 

deposits

 

rate %

 

 

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

 

$

1,608,650

 

40.2

%

0.14

%

$

1,504,758

 

36.5

%

0.33

%

$

1,415,588

 

33.2

%

0.61

%

 

$1,727,754

 

41.9%

 

0.07%

 

$1,672,033

 

41.5%

 

0.11%

 

$1,608,650

 

40.2%

 

0.14%

 

Checking

 

1,392,698

 

34.8

 

0.02

 

1,292,516

 

31.4

 

0.06

 

1,196,555

 

28.1

 

0.13

 

 

1,672,750

 

40.6

 

0.01

 

1,510,848

 

37.5

 

0.01

 

1,392,698

 

34.8

 

0.02

 

Money market

 

232,809

 

5.8

 

0.38

 

180,967

 

4.4

 

0.49

 

168,518

 

4.0

 

1.06

 

 

202,539

 

4.9

 

0.16

 

250,682

 

6.2

 

0.26

 

232,809

 

5.8

 

0.38

 

Certificate

 

768,991

 

19.2

 

1.46

 

1,140,997

 

27.7

 

2.40

 

1,478,624

 

34.7

 

3.35

 

 

517,752

 

12.6

 

0.94

 

598,360

 

14.8

 

1.07

 

768,991

 

19.2

 

1.46

 

Total deposits

 

$

4,003,148

 

100.0

%

0.37

%

$

4,119,238

 

100.0

%

0.83

%

$

4,259,285

 

100.0

%

1.44

%

 

$4,120,795

 

100.0%

 

0.16%

 

$4,031,923

 

100.0%

 

0.22%

 

$4,003,148

 

100.0%

 

0.37%

 

 

As of December 31, 2010,2012, ASB had $152.5$105.9 million in certificate accounts of $100,000 or more, maturing as follows:

 

(in thousands)

 

Amount

 

Three months or less

 

$

41,104

 

Greater than three months through six months

 

23,613

 

Greater than six months through twelve months

 

38,237

 

Greater than twelve months

 

49,565

 

 

 

$

152,519

 

(in thousands)

Amount

Three months or less

$  22,265

Greater than three months through six months

13,237

Greater than six months through twelve months

23,791

Greater than twelve months

46,563

$105,856

 

This compares with $208$119.2 million in such certificate accounts in 2009.2011.

 

Deposit-insurance premiums and regulatory developmentsOn February 8, 2006, the Federal Deposit Insurance Reform Act of 2005 (the Reform Act) became law. One of the provisions of the Reform Act was to merge the Savings Association Insurance Fund (SAIF) and the Bank Insurance Fund (BIF) into a new fund, the Deposit Insurance Fund. This change was made effective March 31, 2006. The Financing Corporation (FICO) will continue to impose an assessment on deposits.

For a discussion of recent changes to the deposit insurance system, premiums and FICOFinancing Corporation (FICO) assessments, see “Regulation—“Regulation–Deposit insurance coverage” below.

 

Other borrowingsSee “Other borrowings” in Note 4 of HEI’s Consolidated Financial Statements. ASB may obtain advances from the FHLB of Seattle provided that certain standards related to creditworthiness have been met. Advances are securedcollateralized 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. See “Other borrowings—Advances from Federal Home Loan Bank” in Note 4 to HEI’s Consolidated Financial Statements.

As of December 31, 2010, 2009 and 2008, advances from the FHLB amounted to $0.1 billion, $0.1 billion and $0.4 billion, respectively. The weighted-average rates on the advances from the FHLB outstanding as of December 31, 2010, 2009 and 2008 were 3.90%, 3.90% and 2.52%, respectively. The maximum amount of advances outstanding at any month-end during 2010, 2009 and 2008 was $0.1 billion, $0.4 billion and $1.0 billion, respectively. Advances from the FHLB averaged $0.1 billion during 2010, $0.2 billion during 2009 and $0.7 billion during 2008 and the approximate weighted-average rate on the advances was 3.95%, 3.05% and 4.28%, respectively.

See “Other borrowings—Securities sold under agreements to repurchase” in Note 4 to HEI’s Consolidated Financial Statements.

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Table of Contents

The following table sets forth information concerning ASB’s advances from the FHLB and securities sold under agreements to repurchase as of the dates indicated:

December 31

 

2010

 

2009

 

2008

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Advances from the FHLB

 

$

65,000

 

$

65,000

 

$

439,550

 

Securities sold under agreements to repurchase

 

172,319

 

232,628

 

241,423

 

Total other borrowings

 

$

237,319

 

$

297,628

 

$

680,973

 

Weighted-average rate

 

2.31

%

1.93

%

2.29

%

 

The decrease in other borrowings in 20102012 compared to 20092011 was primarily due to a decrease in retail repurchase agreements. The decrease in total other borrowings in 20092011 compared to 20082010 was primarily due to the payoff of a maturing advances from the FHLB with excess liquidity.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, 2010,2012, there were 9 financial institutions insured by the Federal Deposit Insurance Corporation (FDIC),FDIC in the State of Hawaii, of which 2 were thrifts and 7 were commercial banks, and numerous credit unions in Hawaii.unions. 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 have beenare subject to the regulatory supervision of the OTS, which regulatory jurisdiction will be transferred to the OCC in July 2011 (unless the date is extended),and FRB, respectively, and in certain respects, the FDIC. See “HEI—“HEI–Regulation” above and “Bank—“Bank–Certain factors that may affect future results and financial condition—condition–Regulation” in HEI’s MD&A. In addition, ASB must comply with Federal Reserve Board (FRB)FRB reserve requirements.

22



 

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. Previously, the standard maximum deposit insurance amount of $100,000 had been temporarily raised to $250,000 through December 31, 2013. 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.

 

Among the major reforms in the last few years to the deposit insurance system were the merger of the BIF and the SAIF; indexing the deposit insurance to inflation beginning in 2010 and every five years thereafter; and authorizing the FDIC to assess risk-based premiums. Under the FDIC rules assessing risk-based premiums, which became effective on January 1, 2007, ASB is classified in Risk Category I, the lowest risk group. Based upon its component ratings under the Uniform Financial Institutions Ratings System (i.e., the CAMELS rating system) and five financial ratios specified in the new FDIC rules, ASB’s assessment rate for 2010 was 14 basis points, which resulted in an assessment amount of approximately $5.7 million, compared to an assessment rate of 14 basis points and an assessment amount of $5.8 million in 2009. See “Federal Deposit Insurance Corporation (FDI C) restoration plan” in Note 4 toof HEI’s 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 proposed changes to the assessment rates and base. FICO will continue to impose an assessment on deposits to service the interest on FICO bond obligations. ASB’s annual FICO assessment is 1.020.66 cents per $100 of deposits as of December 31, 2010.2012.

 

Federal thrift charter.  See “Bank—“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 issuancesSee “Bank—“Bank–Legislation and regulation” in HEI’s MD&A.

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Table of Contents

 

Capital requirements.  The OTSOCC has set three capital standards for thrifts, each of which must be no less stringent than those applicable to national banks.financial institutions. As of December 31, 2010,2012, ASB was in compliance with all of the minimum standards with a core capital ratio of 9.2%9.1% (compared to a 4.0% requirement), a tangible capital ratio of 9.2%9.1% (compared to a 1.5% requirement) and total risk-based capital ratio of 13.9%12.8% (based on risk-based capital of $474.1$496.3 million, $200.3$185.3 million in excess of the 8.0% requirement).

 

The OTSOCC requires that thriftsfinancial 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, 2010,2012, ASB met the applicable minimum core capital requirement.

 

Other capital standards based on an international framework have been adopted for institutions that are much larger in size than ASB or that have substantial foreign exposures. ASB is not currently required to be, and has elected not to be, governed by these other standards.

 

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 RiskASB is subject to OTSOCC rules relating to derivatives activities, such as interest rate swaps. Currently ASB does not use interest rate swaps to manage interest rate risk (IRR), but may do so in the future. Generally speaking, the OTSOCC rules permit thriftsfinancial 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 Thrift Bulletin 13a (TB 13a) provides guidance onto the management of interest rate risks, investment securitiesOCC, ASB has adopted terminology and derivatives activities. TB 13a also describes the guidelines OTS examiners use in assigning the “Sensitivity to Market Risk” component rating under the Uniform Financial Institutions Rating System (i.e., the CAMELS rating system). TB 13a updated the OTS’ minimum standards for thrift institutions’ interest rate riskIRR 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 also contains guidance on thrifts’ investmentappropriate with earnings and derivatives activities by describing the types of analysis institutions should perform prior to purchasing securities or financial derivatives.capital levels, balance sheet complexity, business model and risk tolerance.

 

Liquidity.  OTSOCC 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

23



extent it provides qualifying collateral and holds sufficient FHLB of Seattle stock. As of December 31, 2010,2012, ASB’s unused FHLB of Seattle borrowing capacity was approximately $1.3$0.9 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, 2010,2012, ASB had loan commitments, undisbursed loan funds and unused lines and letters of credit of $1.2$1.5 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.

 

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Table of Contents

Prompt corrective actionThe FDICIA establishes a statutory framework that is triggered by the capital level of a savings associationfinancial institution and subjects it to progressively more stringent restrictions and supervision as capital levels decline. The OTSOCC 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 savings associationfinancial institution that is “undercapitalized” or “significantly undercapitalized” is subject to additional mandatory supervisory actions and a number of discretionary actions if the OTSOCC 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 savings associationfinancial institution that is “critically undercapitalized” must be placed in conservatorship or receivership within 90 days, unless the OTSOCC and the FDIC concur that other action would be more appropriate. As of December 31, 2010,2012, ASB was “well-capitalized.”

 

Interest ratesFDIC 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, 2010,2012, ASB was “well capitalized” and thus not subject to these interest rate restrictions.

 

Qualified thrift lender testIn order to satisfy the QTL test, a thriftASB 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 2010,2012, ASB was in compliance with the QTL test. As of December 31, 2010, 80%2012, 76% of ASB’s portfolio assets were “qualified thrift investments.” See “HEI Consolidated—Regula tion.Consolidated–Regulation.

 

Federal Home Loan Bank SystemASB 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 securedcollateralized 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 thereo f;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 securedcollateralized by such other real estate-related collateral may not exceed 30% of ASB’s capital.

 

As mandated by the Gramm-Leach-BlileyGramm Act, of 1999 (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

24



mortgage loans and pass through securities. As of December 31, 2010,2012, ASB was required under the capi talcapital plan to own capital stock in the FHLB of Seattle in the amount of $15$14 million and owned capital stock in the amount of $98$96 million, or $83$82 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 ReinvestmentThe Community Reinvestment Act (CRA) requires banks and thriftsfinancial institutions to help meet the credit needs of their communities, including low- and moderate-income areas, consistent with safe and sound lending practices. The OTSOCC will consider ASB’s CRA record in evaluating an application for a new

26



Table of Contents

deposit facility, including the establishment of a branch, the relocation of a branch or office, or the acquisition of an interest in another bank or thrift.bank. ASB currently holds an “outstanding” CRA rating.

 

Other lawsASB 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 UVESTLPL Financial ServicesLLP is also governed by regulations adopted by the Federal Reserve BoardFRB 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 legislationSee the discussion of proposed legislation in “Bank—“Bank–Legislation and regulation” in HEI’s MD&A. There is additional proposed legislation pending in Congress that relates to regulatory reform; ASB’s management will continue to monitor its progress.

 

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 HEI’s 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

 

Number of branches

December 31, 2010

 

Owned

 

Leased

 

Total

 

December 31, 2012

 

Owned

 

Leased

 

Total

 

Oahu

 

7

 

32

 

39

 

 

7

 

 

32

 

 

39

 

 

Maui

 

3

 

4

 

7

 

 

3

 

 

4

 

 

7

 

 

Kauai

 

2

 

2

 

4

 

 

2

 

 

2

 

 

4

 

 

Hawaii

 

2

 

4

 

6

 

 

2

 

 

4

 

 

6

 

 

Molokai

 

 

1

 

1

 

 

– 

 

 

1

 

 

1

 

 

 

14

 

43

 

57

 

 

14

 

 

43

 

 

57

 

 

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As of December 31, 2010,2012, the net book value (NBV) of branches and office facilities is approximately $44 million. Of this amount, $31$46 million represents the net book value($39 million NBV of the land and improvements for the branches and office facilities owned by ASB and $13$7 million represents the net book valueNBV of ASB’s leasehold improvements.improvements). The leases expire on various dates through JulyFebruary 2033, but many of the leases have extension provisions.

 

As of December 31, 2010,2012, ASB owned 138118 automated teller machines.

 

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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” in Item 7A,, HEI’s Consolidated Financial Statements, HECO’s MD&A, HECO’s “Quantitative and Qualitative Disclosures About Market Risk” in Exhibit 99.2 and HECO’s Consolidated Financial Statements.

 

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 abili tyability 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, HECO, to pay dividends to HEI in the event that the consolidated common stock equity of the electric public utility subsidiaries 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, 2010) 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 OTS that are applicable to ASB;

·the receipt of a letter from the OTS stating it has no objection to the payment of any dividend ASB proposes to declare and pay to HEI; and

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

the provisions of an HEI agreement with the PUC, which could limit the ability of HEI’s principal electric public utility subsidiary, HECO, to pay dividends to HEI in the event that the consolidated common stock equity of the electric public utility subsidiaries 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, 2012) 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;

·

the receipt of a letter from the OCC and FRB stating it has no objection to the payment of any dividend ASB proposes to declare and pay to 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 th ethe military). Because the core businesses of HEI’s subsidiaries are providing local public electric utility services (through HECO and its subsidiaries) and banking services (through ASB and its subsidiaries)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. presence in Afghanistan) on federal government spending in Hawaii.

The 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 into 2010)2010, 2011 and 2012), an increase in uncollected billings of HECO and its subsidiaries, higher delinquencies in ASB’s loan portfolio and other adverse effects on HEI’s businesses. Both the U. S. and Hawaii economies, however, experienced growth in 2010. The utilities’ 2011 KWH sales are currently expected to increase by 2.4% from 2010.

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If S&P or Moody’s were to downgrade HEI’s or HECO’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 HECO’s ability to borrow and raise capital could be constrained and their future b orrowingborrowing costs would likely increase with resulting reductions in HEI’s consolidated net income in future periods. Further,

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if HEI’s or HECO’s commercial paper ratings were to be further downgraded, HEI and HECO 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 electric 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.

 

Because the earnings of ASB depend primarily on net interest income, interest rate risk is a significant risk of ASB’s operations. 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. 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. In 2008 and 2009,instruments, respectively. Disruptions in the credit markets, experienced significant disruptions,a liquidity on many financial instruments declined andcrisis in the banking industry or increased levels of residential mortgage delinquencies and defaults increased. These disruptions negatively impactedmay result in decreases in the fair value of ASB’s investment portfoliosecurities and ledan impairment that is other-than-temporary, requiring ASB in the fourth quarter of 2009, to sell all private-issue mortgage-related securities inwrite down its investment portfolio in order to further improve its credit risk profilesecurities. As of December 31, 2012, 88% of ASB’s investment securities were securities and reduceobligations issued by a federal agency or government sponsored entity that have an implicit guarantee from the potential volatility of future earnings.U.S. government.

 

HEI and HECO 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 electric utilities, however, retirement benefits expenses, as adjusted by the pension and OPEBpostretirement 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 electric utilities or higher default rates on loans held by ASB.  The business of HECO and its electric utility subsidiaries 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 HECO and its subsidiaries are interconnected with the systems on the other islands they serve. Because of this lack of interconnections, it is necessar ynecessary 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 electric utility subsidiaries. For example, in December 2008, an island-wide outage (likely the result of a severe lightning storm) occurred on the island of Oahu that resulted in a loss of electric service to HECO customers ranging from approximately 7 to 20 hours.

 

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

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developments or natural disasters affecting Hawaii and the ability of ASB’s customers to make payments of principal and interest on their lo ans.

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Table of Contentsloans.

 

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.

·                 HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration. The PUC issued a decision in its investigative proceeding on competitive bidding as a mechanism for acquiring or building new electric generating capacity. With the exception of certain identified projects, the utilities are now required to use competitive bidding to acquire a future generation resource unless the PUC finds competitive bidding to be unsuitable. The PUC also issued a decision in its DG investigative proceeding, in which it set policies for DG interconnection agreements and standby rates, and established conditions under which electric utilities can provide DG services o non customer-owned sites as a regulated service. The electric utilities cannot predict the ultimate effectresults of the PUC’s decisions in the competitive bidding, and DG proceedings, the impact they will have on competition from IPPs, and customer self-generation orand the rate at which technological developments facilitating non-utility generation of electricity will occur.occur may adversely affect the utilities and the results of their operations.

·                 New technological developments, such as the commercial development of fuel cells,energy storage, may render the operations of HEI’s electric utility subsidiaries 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 reputationThe Company is subject to cyber security risks and the potential for cyber incidents, including potential incidents at ASB branches and at the HECO, HELCO and MECO 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 HECO 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 dedu ctiblesdeductibles or has limits on the maximum amounts that may be recovered. For example, the electric utilities’ overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $5$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 electric utilities have no business interruption insurance as the premiums for such insurance would be cost prohibitive, particularly since the utilities are not interconnected to

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other systems. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the affected electric 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 incom eincome 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 and state environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health and safety, which regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous

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waste and toxic substances. Compliance with these legal requirements requires HEI’s utility subsidiaries to commit significant resources and funds toward 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 greenh ouse gasGHG 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. At the present time, HECO is a named party in an ongoing environmental matter that includes an investigation to determine the nature and extent of actual or potential release of hazardous substances, oil, pollutants or contaminants at or near Honolulu Harbor and their remediation where applicable. Management cannot predict the ultimate cost or outcome of that investigation and the accompanying remedial efforts.

 

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 res ervesreserves 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 theseaccounting 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 electric utilities’ consolidated financial positionresults of operations and/or results of operations.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.

 

HECO and its subsidiaries’ 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

29



such costs through rates be met. If events or circumstances should change so that the criteria are no longer satisfied, the electric utilities’ regulatory assets (amounting to $478$865 million as of December 31, 2010)2012) may need to be charged to expense, which could result in significant reductions in the electric utilities’ net income, and the electric utilities’ regulatory liabilities (amounting to $297$322 million as of December 31, 2010)2012) may need to be refunded to ratepayers immediately.

 

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 HECO’s consolidated financial statements, the consolidation could have a material effect on HECO’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

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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 electric utility subsidiaries and could result in inadequate or untimely rate relief,increases, in rate reductions or refunds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects.  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 the electric utilities’ financial condition, results of operations, financial condition and cash flows.liquidity. The PUC has broad discretion over the rates that the electric utilities charge their customers. The electric utilities currently have rate cases pen dingpending before the PUC. Further, the trend of increased O&M expenses, which management expects will continue, increased plant-in-service and other factors are likely to result in the electric utilities continuing to seek rate relief frequently. Also,In addition, as part of the decoupling mechanism that the electric utilities will be implementing,have implemented, each of the electric utilities will alternately 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 HECO’s consolidated financial condition, results of operations, financial condition and cash flows.liquidity.

 

To improve the timing and certainty of the recovery of their costs, the electric 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 purchased power adjustment clause,PPAC, and a renewable energy infrastructure program surcharge. A change in, or the elimination of, any of these cost recovery mechanisms could have a material adverse effect on the electric utilities.

 

The electric 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, IRPintegrated resource plan cost recovery dockets and other proceedings, if and to the extent they exceed the amounts allowed in final orders. As of December 31, 2010, the electric utilities had recognized an aggregate of $4 million of such revenues with respect to interim 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. For example, two major capital improvement projects — HECO’s East Oahu Transmission Project and the expansion of HELCO’s Keahole generating plant — encountered substantial opposition and consequent delay, increased costs and increased cost.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, subject to approval by the PUC, to write off $40 million of costs in lieu of conducting PUC-ordered regulatory audits of the CIP CT-1 and the CIS projects. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of thea project, project costs may need to be written off in amounts that could result i nin significant reductions in HECO’s consolidated net income.

 

Energy cost adjustment clauses. The rate schedules of each of HEI’s electric 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.

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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 affecteffect on the electric utilities.

 

Electric utility operations are significantly influenced by weather conditions.  The electric utilities’ results of operations can be affected by changes in 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

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result of global warming, 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 electric utilities rely on fuel oil suppliers and shippers and IPPs to deliver fuel oil and power, respectively, in accordance with contractual agreements. Approximately 76%73% of the net energy generated or purchased by the electric utilities in 20102012 was generated from the burning of fossil fuel oil, and purchases of power by the electric utilities provided about 40%42% 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 th ethe firm capacity anticipated in its PPA, could disrupt the ability of the electric utilities to deliver electricity and require the electric 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 electric 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, inabil ityinability 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 electric utilities’ generating facilities or transmission and distribution systems. Global warming may result in rising sea levels, which could pose a threat to facilities of the utilities, particularly those located in coastal or other low-lying areas. The utilities have taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding new utility generation, adding distributed generation and encouraging energy conservation. The costs of supplying energy to meet high demand and maintenance costs required to sustain high availability of aging generation units have been increasing and the trend of cost increases is not likely to ease, putting pressure on earnings to the extent timely rate reliefcost recovery is not achieved.

 

The electric utilities may be adversely affected by new legislation.  Congress and the Hawaii Legislature periodically consider legislation that could have positiveuncertain or negative effects on the electric utilities and their customers. In addition to the ECAC provisions of Act 162 discussed above, theThe Hawaii Legislature has adopted a number of measures that maywill significantly affect the electric utilities, as described below.

 

Renewable Portfolio Standards law.  In 2009, Hawaii’s Renewable Portfolio Standards (RPS)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 expect to meetmet 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 electric 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

31



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. In addition, the PUC ordered that the utilities will be prohibited from recovering any RPS penalty costs through rates.

Net energy metering.  Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier

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of energy and will make payment to or receive credit from the electric utility accordingly). In the Energy Agreement, the parties agreed to seek to remove system-wide caps on net energy metering. Instead, they planned to seek to limit DG interconnections on a per-circuit basis and eventually to replace net energy metering with an appropriate feed-in tariff. The PUC recently indicated they plan to retain NEM even with feed-in tariffs. In January 2011, the PUC approved the replacement of the system-wide net metering caps with a 15% per circuit distribution threshold for DG penetration.

 

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 were more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source.

In 2008, a law was enacted to promote and encourage the use of solar thermal energy. This measure will require the installation of solar thermal water heaterssource, resulting in residences constructed after January 1, 2010, but allow for limited variances in cases where installation of solar water heating is deemed inappropriate. Also in 2008, a law was enacted that is intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects. The Energy Agreement includes several undertakings by the utilities to integrate solar energy into their electric grid.

In 2009, a Hawaii law (Act 185) was enacted authorizing preferential rates to agricultural energy producers selling electricity to utilities. This will help support the long-term development of locally grown biofuel crops, cultivating potential local renewable fuel sources for the utilities. In addition, pursuant to Act 50 (also adopted in 2009), avoided cost is no longer the primary consideration in determining a just and reasonable rate for non-fossil fuel generated electricity. This will allow the utilities to negotiate purchased power prices for renewable energy that have the potential to be more stable and less costly than current pricing tied to avoided cost.higher costs.

 

Global climate change and greenhouse gas emissions reduction.  National and international concern about climate change and the contribution of greenhouse gas (GHG)GHG emissions to global warming 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. EPA, 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 HECO, HELCO and MECO, requires that sources above certain threshold levels monitor GHG emissions beginning in 2010. The first reports on these emissions, which the Company is currently preparing, are due to the EPA by March 31, 2011.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. The utilities are evaluating the impact of the GHG Tailoring Rule and a three-year permit deferral for biomass-fired and other biogenic sources on the utilities’ operations.

 

Biofuels.  In 2007, a Hawaii law was enacted with the stated purpose of encouraging further production and use of biofuels in Hawaii. It established that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and established a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

In 2008, a law was enacted that encourages the development of biofuels by authorizing the Hawaii Board of Land and Natural Resources to lease public lands to growers or producers of plant and animal material used for the production of biofuels.

At this time, it is not possible to predict with certainty the impact on the utilities of theThe foregoing legislation or legislation that now is, or may in the future be, proposed.

34



Table of Contentsproposed present risks and uncertainties for the utilities.

 

The electric utilities may be subject to increased operational challenges and their results of operations, financial condition and cash flowsliquidity may be adversely impacted in meeting the commitments and objectives of the HCEI Energy AgreementOn October 20, 2008, 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 State of Hawaii Department of Commerce and Consumer Affairs and the electric 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 with the pu rposepurpose of decreasing the State of 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.

 

The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, and the implementation of a new regulatory model which decouples revenues from sales, presentpresents new increased 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 its 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 infrast ructureinfrastructure 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 cash flowsliquidity 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. ProgramsThese initiatives include, but are not limited to, decoupling revenues from sales; implementing feed-in tariffs to encourage development of renewable energy; removing the system-wide caps on net energy metering (but

32



studying distributed generation interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. Management cannot predict the ultimate impact or outcome of theThe implementation of these or other HCEI programs onmay adversely impact the results of operations, fin ancialfinancial condition and cash flowsliquidity of the electric 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 costi ngcosting 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 54%47% of ASB’s loan portfolio as of December 31, 20102012 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. The weak global, national and local economic environments have resulted in a persistent, low level of interest rates weak loan demand, and excess liquidity in the financial system. In addition, expectations are increasing that interestsystem have impacted the new loan production rates will rise rapidly once there are strong signs that the economic recovery is taking hold. ASB’s decisionand made it challenging to sell substantially all of its fixed rate mortgage production throughout 2009 and the first nine months of 2010 and challenges in findingfind investments with adequate risk-adjusted returns, which resulted in declining loan balances and an increase in ASB’s liquidity position, which had 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.

 

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

35



Table of Contents

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. Historically low interest rates in 2008, 20092010, 2011 and 20102012 resulted in high refinancings, which reduced the level of future interest income.

 

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;

·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;33



·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 potential legislative and regulatory changes affecting capital requirements and increasing oversight of, and reporting by, banks in response to the recent financial crisis and federal bailout of financial institutions;

·                 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, 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 OTSOCC and the Federal Deposit Insurance Corporation,FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. As a result of the Dodd-Frank Act, the OTS will be abolished and the OCC will become ASB’s primary regulator in July 2011 (unless the date is extended). In addition, the Federal Reserve will be madeFRB is responsible for regulating ASB’s holding company, HEI. T hecompanies, 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

36



Table of Contents

dividends to HEI may also be restricted by the OTSOCC 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.” Savings associationsInstitutions 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. There isFederal legislation has also been proposed federal legislationin 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 affecteffect on ASB’s businessThe Dodd-Frank Act, which became law in July 2010, is expected to have 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 ASB in substantial and unpredictable ways. A major component of the Dodd-Frank Act is the creation of the Consumer Financial Protection Bureau that will havehas the responsibility for setting and enforcing clear, consistent rules relating to consumer financial products and services and will havehas the authority to prohibit practices it finds to be u nfair,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, financial condition, results of operations, financial condition and cash flows.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 conditions may result in loan losses and adversely affect the Company’s profitabilityAs of December 31, 20102012 approximately 82%78% 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 18% during 2012 and now comprises 21% 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 employme ntemployment conditions, the monetary and fiscal policies of the federal and state government and other significant external

34



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, 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

37



Table of Contents

example, a tenant may seek the protection of bankruptcy laws, which could result in termination of the tenant’s lease.

In addition to the inherent risks of commercial and commercial real estate lending described above, the expansion of these new lines of business present execution risks, including the ability of ASB to attract personnel experienced in underwriting such loans and the ability of ASB to appropriately evaluate credit risk associated with such loans in determining the adequacy of its allowance for loan losses.

 

ITEM 1B.       UNRESOLVED STAFF COMMENTS

 

HEI:  None.

 

HECO:  Not applicable.

ITEM 2.          PROPERTIESPROPERTIES

 

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

 

ITEM 3.          LEGAL PROCEEDINGS

 

HEI and HECO:  HEI subsidiaries (including HECO 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 toNotes 3 and 4 of HEI’s Consolidated Financial Statements. CertainManagement believes that, other than these proceedings, the likelihood that HEI subsidiaries (including HECO andor its subsidiaries would incur material losses or write-offs in excess of insurance coverage and ASB)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 also involvednecessarily uncertain and there is a risk that the outcome of such matters could have a material adverse effect

35



on the financial position, results of operations or liquidity of HEI or one or more of its subsidiaries for a particular period in ordinary routine PUC proceedings, environmental proceedingsthe future.

ITEM 4.          MINE SAFETY DISCLOSURES

HEI and litigation incidental to their respective businesses.HECO:  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 connection withaddition to their current positions listed below.

 

38



Table of Contents

Name

Age

Age

Business experience for last 5 years and prior positions with the Company

 

 

 

Constance H. Lau

58

60

HEI President and Chief Executive Officer since 5/06

HEI Director, 6/01 to 12/04 and since 5/06

HECO 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

·HECO Treasurer and HEI Assistant Treasurer, 12/87 to 4/89

·HECO Assistant Corporate Counsel, 9/84 to 12/87

 

 

 

James A. Ajello

59

57HEI Executive Vice President, Chief Financial Officer and Treasurer since 5/11

·HEI Senior Financial Vice President, Treasurer and Chief Financial Officer, since 1/09 to 5/11

·Prior to joining the Company:  Reliant Energy, Inc. Senior Vice President-Business Development, 8/06 to 1/09 and Reliant Energy, Inc. Senior Vice President and General Manager of Commercial & Industrial Marketing, 1/04 to 8/06

 

 

 

Chester A. Richardson

64

62HEI Executive Vice President, General Counsel, Secretary and Chief Administrative Officer since 5/11

·HEI Senior Vice President, General Counsel, Secretary and Chief Administrative Officer, since 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

·Prior to joining the Company: Alliant Energy Corp. Deputy General Counsel, 9/03 to 7/07

 

 

 

Richard M. Rosenblum

60

62

HECO President and Chief Executive Officer since 1/09

HECO Director since 2/09

·Prior to joining the Company:  Southern California Edison Company Senior Vice President of Generation and Chief Nuclear Officer, 11/05 until his retirement in 5/08

 

 

 

Richard F. Wacker

48

50

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;10, and Korea Exchange Bank, Chairman and Chief Executive Officer, 4/07 to 3/09; and Korea Exchange Bank, Chief Executive Officer, 1/05 to 3/0709

36



 

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.

 

39PART II



Table of Contents

 

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

ITEM 5.

MARKET FOR REGISTRANTS’ 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 13, “Regulatory restrictions on net assets” and Note 16, “Quarterly information (unaudited)” toof HEI’s Consolidated Financial Statements and Item 6 “Selected Financial Data” and “Item 12. Equity compensation plan information” 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 10, 2011,7, 2013, was 9,839.8,831.

 

In 2010, HEI issued an aggregate of 28,000 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 6, 2008 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,800 shares of HEI common stock (2,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (1,000 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

In 2009 and 2008, HEI issued an aggregate of 29,800 and 31,600 shares, respectively, of unregistered common stock pursuant to the HEI Nonemployee Director Plan.

HEI elected not to register the shares issued under the HEI Nonemployee Director Plan since their issuance did not involve a “sale” as defined under Section 2(3) of the Securities Act of 1933, as amended. Participation by nonemployee directors of HEI and subsidiaries in the director stock plan is mandatory and thus does not involve an investment decision.

HECO:

Since a corporate restructuring on July 1, 1983, all the common stock of HECO 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 HECO.

The dividends declared and paid on HECO’s common stock for the quarters of 20102012 and 20092011 were as follows:

Quarters ended

 

2010

 

2009

 

 

2012     

 

2011     

 

March 31

 

$

15,149,485

 

$

10,536,000

 

 

$18,260,844

 

$17,639,622

 

June 30

 

11,738,025

 

10,599,225

 

 

18,260,844

 

17,639,622

 

September 30

 

11,472,370

 

11,621,079

 

 

18,260,844

 

17,639,622

 

December 31

 

10,409,120

 

22,243,696

 

 

18,260,844

 

17,639,622

 

 

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

See the discussion of regulatory and other restrictions on dividends or other distributions in “Restrictions on dividends and other distributions” under “HEI—“HEI–Regulation” in Item 1. Business and in Note 13 toof HEI’s Consolidated Financial Statements.

 

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ITEM 6.          SELECTED FINANCIAL DATA

HEI:

 

Hawaiian Electric Industries, Inc. and Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Hawaiian Electric Industries, Inc. and Subsidiaries

 

 

 

 

 

 

 

 

 

Years ended December 31

 

2010

 

2009

 

2008

 

2007

 

2006

 

 

2012

 

2011

 

2010

 

2009

 

2008

 

(dollars in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Results of operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

2,664,982

 

$

2,309,590

 

$

3,218,920

 

$

2,536,418

 

$

2,460,904

 

 

$

3,374,995

 

$

3,242,335

 

$

2,664,982

 

$

2,309,590

 

$

3,218,920

 

Net income for common stock

 

$

113,535

 

$

83,011

 

$

90,278

 

$

84,779

 

$

108,001

 

 

$

138,658

 

$

138,230

 

$

113,535

 

$

83,011

 

$

90,278

 

Basic earnings per common share

 

$

1.22

 

$

0.91

 

$

1.07

 

$

1.03

 

$

1.33

 

 

$

1.43

 

$

1.45

 

$

1.22

 

$

0.91

 

$

1.07

 

Diluted earnings per common share

 

$

1.21

 

$

0.91

 

$

1.07

 

$

1.03

 

$

1.33

 

 

$

1.42

 

$

1.44

 

$

1.21

 

$

0.91

 

$

1.07

 

Return on average common equity

 

7.8

%

5.9

%

6.8

%

7.2

%

9.3

%

 

8.9

%

9.2

%

7.8

%

5.9

%

6.8

%

 

 

 

 

 

 

 

 

 

 

 

Financial position *

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

9,085,344

 

$

8,925,002

 

$

9,295,082

 

$

10,293,916

 

$

9,891,209

 

 

$

10,149,132

 

$

9,594,477

 

$

9,087,409

 

$

8,925,002

 

$

9,296,828

 

Deposit liabilities

 

3,975,372

 

4,058,760

 

4,180,175

 

4,347,260

 

4,575,548

 

 

4,229,916

 

4,070,032

 

3,975,372

 

4,058,760

 

4,180,175

 

Other bank borrowings

 

237,319

 

297,628

 

680,973

 

1,810,669

 

1,568,585

 

 

195,926

 

233,229

 

237,319

 

297,628

 

680,973

 

Long-term debt, net

 

1,364,942

 

1,364,815

 

1,211,501

 

1,242,099

 

1,133,185

 

 

1,422,872

 

1,340,070

 

1,364,942

 

1,364,815

 

1,211,501

 

Preferred stock of subsidiaries — not subject to mandatory redemption

 

34,293

 

34,293

 

34,293

 

34,293

 

34,293

 

Preferred stock of subsidiaries – not subject to mandatory redemption

 

34,293

 

34,293

 

34,293

 

34,293

 

34,293

 

Common stock equity

 

1,483,637

 

1,441,648

 

1,389,454

 

1,275,427

 

1,095,240

 

 

1,593,865

 

1,528,706

 

1,480,394

 

1,438,405

 

1,386,211

 

 

 

 

 

 

 

 

 

 

 

 

Common stock

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Book value per common share *

 

$

15.70

 

$

15.58

 

$

15.35

 

$

15.29

 

$

13.44

 

 

$

16.28

 

$

15.92

 

$

15.63

 

$

15.55

 

$

15.31

 

Market price per common share

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

High

 

24.99

 

22.73

 

29.75

 

27.49

 

28.94

 

 

29.24

 

26.79

 

24.99

 

22.73

 

29.75

 

Low

 

18.63

 

12.09

 

20.95

 

20.25

 

25.69

 

 

23.65

 

20.59

 

18.63

 

12.09

 

20.95

 

December 31

 

22.79

 

20.90

 

22.14

 

22.77

 

27.15

 

 

25.14

 

26.48

 

22.79

 

20.90

 

22.14

 

Dividends per common share

 

1.24

 

1.24

 

1.24

 

1.24

 

1.24

 

 

1.24

 

1.24

 

1.24

 

1.24

 

1.24

 

 

 

 

 

 

 

 

 

 

 

 

Dividend payout ratio

 

102

%

137

%

116

%

120

%

93

%

 

87

%

86

%

102

%

137

%

116

%

Market price to book value per common share *

 

145

%

134

%

144

%

149

%

202

%

 

154

%

166

%

146

%

134

%

144

%

Price earnings ratio **

 

18.7

x

23.0

x

20.7

x

22.1

x

20.4

x

 

17.6

x

18.3

x

18.7

x

23.0

x

20.7

x

Common shares outstanding (thousands) *

 

94,691

 

92,521

 

90,516

 

83,432

 

81,461

 

 

97,928

 

96,038

 

94,691

 

92,521

 

90,516

 

Weighted-average

 

93,421

 

91,396

 

84,631

 

82,215

 

81,145

 

 

96,908

 

95,510

 

93,421

 

91,396

 

84,631

 

Shareholders ***

 

32,624

 

33,302

 

33,588

 

34,281

 

35,021

 

 

31,349

 

32,004

 

32,624

 

33,302

 

33,588

 

Employees *

 

3,427

 

3,453

 

3,560

 

3,520

 

3,447

 

 

3,870

 

3,654

 

3,426

 

3,453

 

3,560

 

 


*                                           At December 31. The Company has revised its electric utilities’ previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years prior to 2008. See “Reclassifications and revisions” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

**                                      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. RegisteredRepresents registered shareholders plus participants in the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) who are not registered shareholders. As of February 10, 2011,7, 2013, HEI had 32,5428,831 registered shareholders (i.e., holders of record of HEI common stock), 27,284 DRIP participants and participants.total shareholders of 31,294.

See “Commitments and contingencies” in Note 3 and “Balance sheet restructure” and “Private-issue mortgage-related securities” in Note 4 of HEI’s “Notes to 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.

On December 8, 2008, HEI completed the issuance and sale of 5 million shares of HEI’s common stock (without par value) under an omnibus shelf registration statement. The net proceeds from the sale amounted to approximately $110 million and were primarily used to repay HEI’s outstanding short-term debt and to make loans to HECO (principally to permit HECO to repay its short-term debt).

For 2012, 2011, 2010, 2009 2008, 2007 and 2006,2008, 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 $0.19, $0.21, $(0.02), $(0.33), and $(0.17), $(0.21) and $0.09 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For 2012, 2011, 2010, 2009 2008, 2007 and 2006,2008, 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 $0.18, $0.20, $(0.03), $(0.33), and $(0.17), $(0.21) and $0.09 per share, respectively, for both unvested restricted stock awards and unrestricted common stock.

HECO:

The information required by this itemItem 6 for HECO is incorporated herein by reference to “Selected Financial Data” on page 4 of HECO Exhibit 99.2.

 

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ITEM 7.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS

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

 

The following discussion should be read in conjunction with Hawaiian Electric Industries, Inc.’s (HEI’s) consolidated financial statements and accompanying notes.notes and, in the case of HECO, in conjunction with HECO’s consolidated financial statements and accompanying notes which are incorporated by reference to pages 5 to 47 of HECO Exhibit 99.2. The general discussion of HEI’s consolidated results should be read in conjunction with the segment discussions ofthe electric utilities and the bank 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 operating companies (the electric utilities and the bank)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 subsidiary, Hawaiiansubsidiaries (Hawaiian Electric Company, Inc. (HECO), and HECO’s electric utilityits subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO)), 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, American Savings Bank, F.S.B. (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 2010,2012, net income for HEI common stock was $114$139 million, compared to $83up slightly from $138 million in 2009. Basic earnings per share were $1.22 per share in 2010, up 34% from $0.91 per share in 20092011 due to higher earningslower losses for the bank“other” segment, partly offset by slightly lower earnings atfor the electric utility segment and higher losses for the “other” segment andbank segments. Basic earnings per share were $1.43 per share in 2012, down 1% from $1.45 per share in 2011 due to the effects of the higher weighted average number of shares outstanding.

The electric 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 20102012 of $76.6$99 million decreased 4%1% from the prior year due primarily to lower kilowatthour (KWH) sales and higher other operation and maintenance (O&M) and depreciation expenses,a writedown of $24 million (net of taxes) of project costs in lieu of conducting regulatory audits, partly offset by higher rate relief and interest income due to a federal tax settlement.increases. Key to results for 20112013 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 approximately 1,100 megawatts (MW) of new generation from a variety of renewable energy sources into the utility systems, and implementingmanaging O&M 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 new regulatory rate-making model that decouples revenues from KWH sales.

constantly changing banking industry and remain competitive.ASB’s earnings in 20102012 of $58.5$58.6 million increased $36.7decreased $1.2 million overcompared to prior year net income due primarily to lower net interest income and includedhigher noninterest expenses, partly offset by higher noninterest income and a $12.6 million net charge forlower provision for loan losses. Net income for 2009 reflected a $19.3 million after-tax charge related to the sale of ASB’s private issue mortgage-related securities portfolio, a $9.3 million net charge for other-than-temporary impairment (OTTI) of securities and a $19.3 million net charge for provision for loan losses. 2008 earnings included a $35.6 million net charge related to ASB’s balance sheet restructuring, a $4.7 million net charge for OTTI of securities and a $6.2 million net charge for provision for loan losses. In 2010, management focused on increasing revenues and reducing costs through ASB’s performance improvement project, which has been completed. ASB’s future financial results will cont inuecontinue to be impacted by the interest rate environment and the quality of ASB’s loan portfolio, and the ongoing results of the performance improvement project.

portfolio.

HEI’s “other” segment had a net loss in 20102012 of $21.5$19 million, compared to athe net loss of $18.2$22 million in 2009. HEI’s consolidated effective tax rate was 37% in 2010 compared to 34% in 2009. In 2010, HEI recognized $2 million in tax expense for the write-off of a deferred tax asset due to the expiration of capital loss carryforwards.

2011.

Shareholder dividends are declared and paid quarterly by HEI at the discretion of HEI’s Board of Directors. HEI and its predecessor company, HECO, 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, 20102012 was 5.4%4.9%. The dividend payout ratios based on net income for common stock for 2010,

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Table of Contents

20092012, 2011 and 20082010 were 102%87%, 137%86% and 116%102%, 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.

39



 

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.

 

See the discussions below of the Electric Utility and Bank segments for their respective executive overviews and strategies.

Economic conditions.

 

Note:  The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism;Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; Blue Chip Financial Forecasts;U.S. Energy Information Administration; Hawaii Tourism Authority; 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 new records in 2012. State visitor arrivals grew by 9.6% in 2012 over 2011. Total State visitor arrivals reached a new record in 2012. State visitor expenditures also continued to grow, increasing by 18.7% in 2012 over 2011, achieving another record for the State. Hotel occupancies and room rates also continued to rise. The U.S. economy, as measured by gross domestic product (GDP), grew 2.6% inoutlook for the third quarter of 2010,visitor industry remains positive with the “advance” estimate of fourth quarter growth at 3.2%. According to the February 2011 Blue Chip Economic Indicators, GDP growth is estimated to be 3.5%Hawaii Tourism Authority expecting a 9.4% increase in airline seat capacity for the first quarter of 2011. 2010 annual growth was 2.9%, an improvement2013 over the 2.6% contraction in 2009. The outlook for 2011 has improved, with growth now projected at 3.2% in 2011 compared to 2.6% growth in the December 2010 Blue Chip consensus forecast. The more positive outlook reflects increased consumer spending and gains in the manufacturing and service sectors, which suggest that the economy may be starting a transition from recovery to expansion.2012.

Economic growth has not yet translated into job growth. The U.S.Hawaii’s unemployment rate was 9.4%5.2% in December 2010, down from 9.8%2012, lower than the state’s 6.6% rate in November 2010. Since December 2009, total payroll employment has increased by 1.1 million, averaging a very low 94,000 jobs per month. Although 2010 was2011 and the best year for job growth since 2007, the growth remains small relative to the 8.5 million jobs lost since the Great Recession began. The February 2011 Blue Chip consensus is for theDecember 2012 national unemployment rate to average 9.3%of 7.8%. Hawaii’s unemployment rate has slowly improved after reaching a high of 7.1% in 2011.2009.

Japan’s economic growth was a strong 3.1%Hawaii real estate activity improved in 2010, but is forecast to decline to 1.5% in 2011 according to2012 as indicated by the government. Slower growth is expected due to the end of government stimulus measures and a decline in exports. Deflation is also expected to continue in 2011, but consumer prices should fall at a lower rate than in 2009 and 2010.

In 2010, the Hawaii economy benefited from economic growth in both the U.S. and Japan. UHERO projects that following a 0.1% contraction in 2009, Hawaii’s economy (real GDP) grew by 1.1% in 2010 and will continue to expand by 2.7% in 2011.

The visitor industry has provided a much needed boost to Hawaii’s economy. In 2010, total visitor arrivals were up 8.7% over 2009. Total visitor expenditures rose 16.2% in 2010 due to the increase in visitor arrivals as well as higher average daily visitor spending. In 2011, UHERO projects further growth with arrivals up 3.8%, with the growth moderated by challenging global economic conditions.

Hawaii’s construction industry continued to struggle in 2010, but UHERO economists believe we are at the cycle’s bottom. For the first eleven months of 2010, the value of total private building permits in the State of Hawaii declined by 0.8% from the same period in 2009 (permits for new residential construction and additions and alterations declined, but commercial and industrial permit values increased). Statewide, construction jobs were down 5.5% year-to-date in November 2010 compared to 2009, however, for the last two months there has been year-over-year growth. UHERO is forecasting that construction jobs will increase by 0.9% in 2011.

Hawaii’shome resale housing market in 2010 improved based on number of sales, but has struggled in terms of price. For the year 2010, Oahu single-family home resales were up 13.4% compared to 2009, with condominium resales up 10.3%.market. The median sales price for single-familysingle family residential homes was up 3.1% year-over-year, while theon Oahu increased by 7.8% and home sales increased 6.5% over 2011. The 2012 median sales price for Oahu condominiums remained flat. Similarly on Maui, Kauairose 5.8% above 2011 and closed sales increased 8.2%.

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the island of Hawaii, residential and condominium sales volumes were up by double digit percentages in 2010 compared to 2009. However, median sale prices were down on all three islands with the exception of residential sales on

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Table of Contents

Kauai. The neighbor island markets have been affected by the downturn more than Oahu due to a higher proportion of vacation home development and purchases during the last real estate boom.

In 2010, the Hawaii job market had not yet benefited from the positive trends in the visitor industry. Although job losses slowed from the 4.4% decline experienced in 2009, UHERO projects total payroll jobs will end 2010 down 0.5%, followed by an increase of 1.3% in 2011. Furloughs for county employees in all four counties were implemented for the fiscal year beginning July 1, 2010 and state employee furloughs, with the exception of teachers, continued. Hawaii’s preliminary seasonally adjusted unemployment rate in December 2010 was 6.4%, which remains well below the national unemployment rate of 9.4% and is seventh lowest in the nation, but is much higher than the 4.1% rate experienced just two years ago. There is some reason for optimism, according to UHERO economists, “Gradual progress in the transition to a jobs recovery is confirmed by lower initial unemployment insuran ce claims in recent months.”

Real personal income (which includes unemployment compensation) growth in Hawaii in 2010 is expected to be 0.3% according to UHERO’s estimate, following two consecutive years of decline. The expectation is for growth of 2.3% in 2011 as the recovery in the visitor industry and resumption of job growth start to have an impact.

The price of a barrel of West Texas Intermediate crude oil averaged $79 in 2010international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and $85tsunami in March 2011 has increased regional demand for energy supplies, including petroleum, and the fourth quarterprices of 2010 according to the U.S. Energy Information Administration Januaryutilities’ fuels have accordingly remained at the elevated 2011 Short-Term Energy Outlook. The forecast for 2011 is an average of $93 per barrel.level throughout 2012.

Interest rates during 2011 are expected to remain low, putting downward pressure on yields of loans and investments. Although still at historical lows, long-term rates increased during the fourth quarter of 2010, dampening the momentum gained in the housing market during previous quarters. Based on comments fromthe current moderate economic outlook, the Federal Open Market Committee (FOMC) maintained their efforts to stimulate the FedU.S. economy in a meeting on December 11-12, 2012. The FOMC held the federal funds rate target at 0% to 0.25% and expects to maintain the record low rates at least as long as the unemployment rate is above 6.5% and inflation remains under control. The FOMC will continue to supportpurchase additional agency mortgage-backed securities out of concern that economic growth may not be strong enough to generate sustained improvement in labor market conditions. In an effort to assist broader accommodative financial conditions, the current low rate environment until a broader recoveryFOMC announced it will initially purchase $45 billion per month of longer-term Treasury securities after its program to extend the average maturity of its holdings is completed at the end of 2012. The FOMC stated it will closely monitor economic information in the coming months and may take additional steps to improve the labor market and overallin a context of price stability.

Overall, Hawaii’s economy is realized, as long as core inflationexpected to see only modest growth in 2012 and 2013 with local economic growth supported by moderate improvement in the U.S. economy and impeded by continued uncertainty in global economies. Based on updated economic projections and expectations of renewable self-generation and energy-efficiency additions, the electric utilities’ 2013 kilowatthour sales are expected to decline slightly from 2012 levels and then remain reasonable.

With the recession over, Hawaii showed signs of positive economic activity in 2010, while one of the key indicators, job growth, continued to lag behind. The outlook for 2011 is for continued improvement and for the recovery to spread beyond just the visitor industry.relatively flat until 2022.

 

MajorRecent tax legislation in 2010.  developments.Congress enacted several bills in 2010 dealing with health care reform, job creation and economic stimulus. Two bills enacted in the latter half of the year contained major tax provisions directly affecting the Company.  The first was the Small Business Jobs Act of 2010, which included the extension of 50% bonus depreciation for all businesses retroactive to January 1, 2010. The second was the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010. This legislation included2010 contained major tax provisions that impacted the extension ofCompany through 2012, including the lower individual income tax rates on income, dividends and capital gains; the increase in the estate and gift tax exemption amounts; and a 2% reduction in Social Security tax on employees and self-employed individuals. Also, businesses received an extension of 50% bonus depreciation fo r property placed into service before January 1, 2013 and 100% bonus depreciation provisions for qualified property acquired between September 8, 2010 and January 1, 2012. For the Company, the bonus depreciation provisionsthat resulted in an estimated net increase in federal tax depreciation of approximately $75$116 million for 2010,2012, primarily attributable to HECOthe utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and its subsidiaries. The Company is still evaluating the impactprovided a one year extension of this additional50% bonus depreciation, which is estimated to increase the Company’s federal tax depreciation for 2011 since the transition rules related2013 by $138 million, primarily attributable to the definition of property qualified for 100% bonus depreciation are still unclear. A number of energy-related tax breaks were also extended, including the biodiesel credit through 2012 and the grants in lieu of the electricity production credit through 2011.utilities.

 

The Company will continue to analyze these 2010 Acts for their impacts on results of operations, financial condition and cash flows and for the opportunities they present.

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Table

In December 2011, the Internal Revenue Service (IRS) issued regulations that provide a framework for determining whether expenditures are deductible as repairs, effective January 1, 2012. But in December 2012, the IRS delayed the effective date of Contentsthese regulations until January 1, 2014. The Company will review these regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for 2012 and future years.

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)

 

2010

 

% change

 

2009

 

% change

 

2008

 

 

2012

 

% change

 

2011

 

% change

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

2,665

 

15

 

$

2,310

 

(28

)

$

3,219

 

 

$

3,375

 

4

 

$

3,242

 

22

 

$

2,665

 

Operating income

 

256

 

37

 

188

 

(8

)

204

 

 

284

 

(2)

 

290

 

13

 

256

 

Net income for common stock

 

114

 

37

 

83

 

(8

)

90

 

 

139

 

 

138

 

22

 

114

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) by segment:

 

 

 

 

 

 

 

 

 

 

 

Electric utility

 

$

77

 

(4

)

$

79

 

(14

)

$

92

 

 

$

99

 

(1)

 

$

100

 

31

 

$

77

 

Bank

 

58

 

169

 

22

 

22

 

18

 

 

59

 

(2)

 

60

 

2

 

58

 

Other

 

(21

)

NM

 

(18

)

NM

 

(20

)

 

(19)

 

NM

 

(22)

 

NM

 

(21)

 

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

$

114

 

37

 

$

83

 

(8

)

$

90

 

 

$

139

 

 

$

138

 

22

 

$

114

 

Basic earnings per share

 

$

1.22

 

34

 

$

0.91

 

(15

)

$

1.07

 

 

$

1.43

 

(1)

 

$

1.45

 

19

 

$

1.22

 

Diluted earnings per share

 

$

1.21

 

33

 

$

0.91

 

(15

)

$

1.07

 

 

$

1.42

 

(1)

 

$

1.44

 

19

 

$

1.21

 

Dividends per share

 

$

1.24

 

 

$

1.24

 

 

$

1.24

 

 

$

1.24

 

 

$

1.24

 

 

$

1.24

 

Weighted-average number of common shares outstanding (millions)

 

93.4

 

2

 

91.4

 

8

 

84.6

 

 

96.9

 

1

 

95.5

 

2

 

93.4

 

Dividend payout ratio

 

102

%

 

 

137

%

 

 

116

%

 

87%

 

 

 

86%

 

 

 

102%

 

 

NMNot meaningful.

 

See “Executive overview and strategy” above for a discussion ofand the HEI consolidated results of operations. Also, see “Other segment,” “Electric utility” and “Bank” sections below for discussions of those segments.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, changes tofor example, the qualified retirement plan for employees of HEI and HECO was changed for employees hired on or after May 1, 2011. Those employees will receive lower benefit accruals, different early retirement reduction factors are being phased in with regard to new retirement benefit accruals.and no automatic cost of living increases. The change is expected to decrease ongoing costcosts through a reduction in service cost. (See Note 9 of HEI’s “Notes to Consolidated Financial Statements” for a listing of plans that ha ve been frozen in prior years. No other changes were made to the retirement benefit plans’ provisions in 2010, 2009 and 2008 that have had a significant impact on costs.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 HECO and its subsidiaries 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 2010,2012, the Company’s retirement benefit plans’ assets generated a gain of 13.9%, net of investment management fees, of 16.6%, resulting in net earnings and unrealized gains of $145$140 million, compared to net losses and unrealized losses of $7 million for 2011 and net earnings and unrealized gains of $186$145 million for 2009 and net losses and unrealized losses of $287 million for 2008.2010. The

41



market value of the retirement benefit plans’ assets as offor December 31, 2010 was2012 and 2011 were $1.1 billion and $983 million. See “Liquidity and Capital Resources” below for the Company’s cashmillion, respectively.

The Company intends to make contributions to the retirement benefit plans.

The Company expects thatqualified pension plan for HEI and HECO equal to the calculated net periodic pension cost for the year. However, if the minimum required contribution to the qualified retirement plans calculated in accordance with the Pension Protection Act of 2006 and the expected timing of the cash requirement based on the value of plan assets as of December 31, 2010 will be as set forth below for plan years 2011 and 2012. The minimum required contributionmay differ from the cash funding for each plan year because the rulesdetermined under the Internal Revenue Code allow the Company to make its last installment contributionas late as September of the following year. In addition, the Company is allowed to elect to apply any credit balance against the minimum required contribution. Further, pension tracking mechanisms

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Table of Contents

generally require the electric utilities to fund only the minimum level required under the law until the existing pension assets are reduced to zero, at which time the electric utilities would make contributions to the pension trust in the amount of the actuarially calculated net periodic pension costs, except when limited by the Employee Retirement Income Security Act of 1974 (ERISA), as amended (ERISA), minimum contribution requirements or the maximum contribution limitation on deductible contributions imposed by the Internal Revenue Code. AsPension 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 2013. 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 2013. Based on plan assets as of December 31, 2010, HECO’s prepaid pension asset was $3 million, HELCO’s was $2 million2012 and MECO’s had been eliminated. The “Cash funding requirement” in the following table considers the utilities’ funding commitment (based on various assumptions described in Note 9 of HEI’s “Notes to Consolidated Financial Statement s”).

(in millions)

 

2011

 

2012

 

Pension Protection Act minimum required contribution:

 

 

 

 

 

(net of applied credit balances)

 

 

 

 

 

Based on plan assets as of December 31, 2010

 

 

 

 

 

Consolidated HECO

 

$

85

 

$

79

 

Consolidated HEI

 

$

86

 

$

80

 

 

 

 

 

 

 

Cash funding to satisfy the Pension Protection Act minimum required contribution:

 

 

 

 

 

Based on plan assets as of December 31, 2010

 

 

 

 

 

Consolidated HECO

 

$

46

 

$

116

 

Consolidated HEI

 

$

47

 

$

117

 

See Note 9 of HEI’s “NotesStatements,” the Company estimates the net periodic pension cost contribution to Consolidated Financial Statements”be $85 million ($2 million for factors which could cause changes toHEI and $83 million for the required contribution levels.

utilities).

Based on various assumptions in Note 9 of HEI’s “Notes to Consolidated Financial Statements” and assuming no further changes in retirement benefit plan provisions, information regarding consolidated HEI’s, consolidated HECO’s and ASB’s (i) accumulated other comprehensive income (AOCI) balance, net of tax benefits, related to the liability for retirement benefits (ii) retirement benefits expense, net of income tax benefits and (iii) retirement benefits paid and plan expenses were,was, or areis estimated to be, as follows, as of the dates or for the periods indicated:and constitutes “forward-looking statements”:

 

 

 

AOCI balance, net of tax
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

 

 

 

 

 

 

 

(Estimated)

 

 

 

 

 

 

 

 

 

 

 

 

 

(in millions)

 

2010

 

2009

 

2011 (1)

 

2010

 

2009

 

2008

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated HEI

 

$

(15

)

$

(12

)

$

24

 

$

24

 

$

21

 

$

17

 

64

 

$

61

 

$

59

 

Consolidated HECO

 

1

 

2

 

23

 

24

 

19

 

17

 

60

 

57

 

55

 

ASB

 

(10

)

(10

)

 

(1

)

 

(1

)

3

 

3

 

2

 


(1) Forward-looking statements subject to risks and uncertainties, including the impact of plan changes during the year, if any, and the impact of actual information when received (e.g., actual participant demographics as of January 1, 2011).

 

 

AOCI balance, net of tax
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)

 

2012

 

2011

 

(Estimated)

2013

 

2012 

 

2011

 

2010

 

2012

 

2011

 

2010

Consolidated HEI

 

$36

 

$28

 

$26

 

$22

 

$22

 

$24

 

$68

 

$66

 

$64

Consolidated HECO

 

1

 

 

23

 

20

 

21

 

24

 

63

 

61

 

60

ASB

 

24

 

19

 

1

 

 

 

(1)

 

3

 

3

 

3

 

The following table reflects theBased on various assumptions in Note 9 of HEI’s “Notes to Consolidated Financial Statements”, sensitivities of the projected benefit obligation (PBO) and accumulated postretirement benefit obligation (APBO) as of December 31, 2010,2012, associated with a change in certain actuarial assumptions, by the indicated basis pointswere as follows and constitute “forward-looking statements.” Each sensitivity below reflects the impact of a change in that assumption.

 

Actuarial assumption

Change in assumption
in basis points

Impact on
PBO or APBO

(dollars in millions)

Pension benefits

 

 

Discount rate

+/–   50

$(72)(114)/$80129

Other benefits

 

 

Discount rate

+/–   50

(10)(13)/1214

Health care cost trend rate

+/– 100

3/(3)6/(6)

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Table of Contents

Baseline assumptions: 5.68% discount rate for pension benefits; 5.60% discount rate for other benefits; 8% asset return rate; 9% medical trend rate for 2011, grading down to 5% for 2019 and thereafter; 5% dental trend rate; and 4% vision trend rate.

 

The impact on 20112013 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 9 of HEI’s “Notes to Consolidated Financial Statements” for further retirement benefits information.

 

Other segment.

 

(dollars in millions)

 

2010

 

%  change

 

2009

 

%  change

 

2008

 

2012

%  change

 

2011

%  change

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues (1)

 

$

 

NM

 

$

 

NM

 

$

 

Operating income (loss)

 

(15

)

NM

 

(14

)

NM

 

(14

)

Revenues 1

$ –

NM

 

$ (1)

NM

 

$ –

Operating loss

(17)

NM

 

(17)

NM

 

(15)

Net loss

 

(22

)

NM

 

(18

)

NM

 

(20

)

(19)

NM

 

(22)

NM

 

(22)

 


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

 

NMNot meaningful.

42



 

The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; HEI Investments,Properties, Inc. (HEIII)(HEIPI), a company previously holding passive, venture capital investments (venture capital investments valued at $0.5 million as of December 31, 2012); The Old Oahu Tug Service, Inc. (TOOTS), a maritime freight transportation company that ceased operations in leveraged leases but whose wind-down was substantially completed during 2009;1999; and Pacific Energy Conservation Services, Inc. (PECS), 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; HEI Properties, Inc. (HEIPI), a company holding passive, venture capital investments (venture capital investments valued at $1.3 million as2010 and dissolved in the second quarter of December 31, 2010); and The Old Oahu Tug Service, Inc. (TOOTS), a maritime freight transportation company that ceased operations in 1999;2011; as well as eliminations of intercompany transactions.

HEI corporate-level operating, general and administrative expenses were $13.3$16 million in 20102012 compared to $12.7$15 million in each of 20092011 and 2008.$13 million in 2010. In 2010,2012, HEI had higher executive compensation and employee benefits expenses, including retirement benefits. In 2011, expense increased primarily due to higher compensation expense, partly offset by lower retirement benefit expense and anthe accrual in 2009of $3 million of contributions to dismantle a windfarm in 2010. In 2009, expenses decreased slightly from 2008 duebe made to not funding the HEI Charitable Foundation and lower consulting fees, partly offset by the accrual to dismantle a windfarm.

in 2012.

The “other” segment’s interest expenses were $20.0$16 million in 2010, $18.42012, $22 million in 20092011 and $21.4$20 million in 2008.2010. In 2012, HEI had lower average borrowings and interest rates. In 2011 and 2010, financing costs were higher due in part to the higher level of borrowings and the recognition of the ineffective portion of the change in fair value of the forward starting swapsswaps. Also in 2010, there was a higher level of borrowings. The “other” segment’s income tax benefits were $15 million in 2012, $17 million in 2011 and $13 million in 2010. In 2009, financing costs were lower thanThe increase in 2008income tax benefits in 2011 was primarily due to lower levelshigher operating losses, higher interest expense and a favorable settlement in 2011 in an IRS appeal related to the character (ordinary versus capital) of short-term borrowings after HEI’s common stock salea foreign loss, and the write-off in December 2008.2010 of a deferred tax asset due to the expiration of a capital loss carryforward period.

 

Effects of inflation.  U.S. inflation, as measured by the U.S. Consumer Price Index (CPI), averaged 2.1% in 2012, 3.2% in 2011 and 1.6% in 2010, (0.4%) in 2009 and 3.8% in 2008.2010. Hawaii inflation, as measured by the Honolulu CPI, was 3.7% in 2011, 2.1% in 2010 and 0.5% in 2009 and 4.3% in 2008.2009. The Department of Business, Economic Development and Tourism estimates average Honolulu CPI to have been 2.2%2.5% in 20102012 and forecasts it to be 2.2%2.4% for 2011.2013.

Inflation continues to have an impact on HEI’s operations. Inflation increases operating costs and the replacement cost of assets. Subsidiaries with significant physical assets, such as the electric utilities, replace assets at much higher costs and must request and obtain rate increases to maintain adequate earnings. In the past, the PUC has granted rate increases in part to cover increases in construction costs and operating expenses due to inflation.

 

Recent accounting pronouncements. See “Recent accounting pronouncements and interpretations” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

 

Legislation.  On March 23, 2010, the Affordable Care Act became law and mandated that employers provide medical coverage to all their employees. The Company provides health insurance benefits to their employees under the provisions of the Hawaii Prepaid Health Care Act. Thus, the financial impact of the Affordable Care Act is not expected to be significant to the Company. In January 2011, a bill was introduced, which, if implemented as written, would repeal the Affordable Care Act.

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Liquidity and capital resources.

 

Selected contractual obligations and commitmentsThe following tables present informationInformation about total payments due during the indicated periods under the specified contractual obligations and commercial commitments:commitments of HEI and its subsidiaries was as follows:

 

December 31, 2012

 

Payments due by period

(in millions)

 

Total

 

Less than
1 year

 

1-3
years

 

3-5
years

 

More than
5 years

Contractual obligations

 

 

 

 

 

 

 

 

 

 

Deposit liabilities1

 

$ 4,230

 

$4,040

 

$   134

 

$  46

 

$     10

Other bank borrowings

 

196

 

96

 

 

100

 

Long-term debt

 

1,423

 

50

 

111

 

75

 

1,187

Interest on certificates of deposit, other bank borrowings and long-term debt

 

1,162

 

80

 

144

 

129

 

809

Operating leases, service bureau contract and maintenance agreements

 

125

 

28

 

44

 

24

 

29

Open purchase order obligations 2

 

110

 

84

 

17

 

9

 

Fuel oil purchase obligations (estimate based on December 31, 2012 fuel oil prices)

 

2,643

 

921

 

1,315

 

407

 

Power purchase obligations–minimum fixed capacity charges

 

1,255

 

118

 

249

 

195

 

693

Liabilities for uncertain tax positions

 

1

 

 

1

 

 

Total (estimated)

 

$11,145

 

$5,417

 

$2,015

 

$985

 

$2,728

 

 

 

Payments due by period

 

December 31, 2010
(in millions)

 

Total

 

Less than
1 year

 

1-3
years

 

3-5
years

 

More than
5 years

 

Contractual obligations

 

 

 

 

 

 

 

 

 

 

 

Deposit liabilities(1)

 

$

3,975

 

$

3,745

 

$

115

 

$

100

 

$

15

 

Other bank borrowings

 

237

 

137

 

 

 

100

 

Long-term debt

 

1,366

 

150

 

115

 

111

 

990

 

Interest on certificates of deposit, other bank borrowings and long-term debt

 

1,089

 

83

 

143

 

124

 

739

 

Operating leases, service bureau contract and maintenance agreements

 

108

 

20

 

33

 

24

 

31

 

Open purchase order obligations (2)

 

110

 

69

 

40

 

1

 

 

Fuel oil purchase obligations (estimate based on December 31, 2010 fuel oil prices)

 

3,335

 

967

 

1,715

 

653

 

 

Power purchase obligations—minimum fixed capacity charges

 

1,249

 

118

 

234

 

232

 

665

 

Liabilities for uncertain tax positions

 

12

 

 

10

 

2

 

 

Total (estimated)

 

$

11,481

 

$

5,289

 

$

2,405

 

$

1,247

 

$

2,540

 


(1) 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) 2                   Includes contractual obligations and commitments for capital expenditures and expense amounts.

 

December 31, 2010

 

Total

 

December 31, 2012

 

Total

(in millions)

 

 

 

 

 

Other commercial commitments to ASB customers

 

 

 

 

Loan commitments (primarily expiring in 2011)

 

$

22

 

Other commercial commitments to ASB customers
Loan commitments (primarily expiring in 2012)

$

31

Loans in process

 

56

 

 

67

Unused lines and letters of credit

 

1,136

 

 

1,416

Total

 

$

1,214

 

$

1,514

 

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 under interim D&Osdecision and orders (D&Os) of the PUC. As of December 31, 2010,2012, 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 2011 and 2012.

2013.

See Note 3 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of fuel and power purchase commitments.

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 $9.1$10.1 billion as of December 31, 20102012 and $8.9$9.6 billion as of December 31, 2009.2011.

 

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

 

December 31

 

2010

 

2009

 

 

2012

 

2011

(dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term borrowings—other than bank

 

$

25

 

1

%

$

42

 

2

%

 

$     84

 

3%

 

$     69

 

2%

Long-term debt, net—other than bank

 

1,365

 

47

 

1,365

 

47

 

 

1,423

 

45

 

1,340

 

45

Preferred stock of subsidiaries

 

34

 

1

 

34

 

1

 

 

34

 

1

 

34

 

1

Common stock equity

 

1,484

 

51

 

1,442

 

50

 

 

1,594

 

51

 

1,529

 

52

 

$

2,908

 

100

%

$

2,883

 

100

%

 

$3,135

 

100%

 

$2,972

 

100%

 

HEI’s short-term borrowings and HEI’s line of credit facility were as follows for the period and as of the dates indicated:follows:

 

 

 

Year ended
December 31, 2010

 

 

 

(in millions)

 

Average
balance

 

End-of-period
balance

 

December 31,
2009

 

 

 

 

 

 

 

 

 

Short-term borrowings (1)

 

 

 

 

 

 

 

HEI commercial paper

 

$

34

 

$

25

 

$

42

 

HEI line of credit draws

 

 

 

 

 

 

$

34

 

$

25

 

$

42

 

Line of credit facility (expiring May 7, 2013)

 

 

 

$

125

 

$

100

 

Undrawn capacity under HEI’s line of credit facility

 

 

 

125

 

100

 

 

Year ended
December 31, 2012

 

 

(in millions)

 

Average
balance

 

End-of-period
balance

 

 

December 31,
2011

Short-term borrowings 1

 

 

 

 

 

 

 

   Commercial paper

 

$ 47

 

$ 84

 

 

$ 69

   Line of credit draws

 

 

 

 

Undrawn capacity under HEI’s line of credit facility (expiring December 5, 2016)

 

 

 

125

 

 

125

 


(1)1          This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are discusseddisclosed below under “Electric utility—Financial Condition—Liquidity and capital resources. At February 10, 2011,7, 2013, HEI’s outstanding commercial paper balance was $26$93 million and its line of credit facility was undrawn. The maximum amount of HEI’s short-term borrowings in 20102012 was $50$99 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 HECO to meet HECO’s cash requirements, including the funding of loans by HECO to HELCO and MECO, but no such short-term loans to HECO were outstanding as of December 31, 2010.2012. 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 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.

Effective May 7, 2010,On March 24, 2011, HEI entered intoissued $125 million of Senior Notes via a revolving noncollateralized credit agreement establishingprivate placement ($75 million of 4.41% notes due March 24, 2016 and $50 million of 5.67% notes due March 24, 2021). HEI used part of the net proceeds from the issuance of the Senior Notes to pay down commercial paper (originally issued to refinance $50 million of 4.23% medium-term notes that matured on March 15, 2011) and ultimately used the remaining proceeds to refinance part of the $100 million of 6.141% medium-term notes that matured on August 15, 2011.

HEI has a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on May 7, 2013, with a syndicate of eight financial institutions.million. See Note 7 of HEI’s “Notes to 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 102.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts. 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 s ubsidiaries 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 (actual ratio of 18% as of December 31, 2010, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (actual Net Worth of $1.5 billion as of December 31, 2010, as calculated under the agreement).

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Table of Contents

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,

45



debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities. On July 30, 2010,August 1, 2012, Moody’s changed HEI’s rating outlook to stable from negative and affirmedmaintained HEI’s long-term and short-term (commercial paper) ratings and stable outlook, indicating that the ratings affirmation and outlook changelong-term rating reflects the progress being mad erelatively stable earnings and cash flow historically provided by its vertically integrated utility businesses and banking operation, improving financial performance, particularly at the company and various stakeholdersutility which has helped to transformlower the regulatory framework for HEI’s electric utilities to adividend payout ratio. The stable rating outlook factors in Moody’s belief that (1) the decoupling structure thatmechanism will reduce sales volume riskregulatory lag and produce more timelybetter match cost recovery of investedexpenses and capital investment such that HECO’s consolidated ROE will approach authorized returns over time and operations and maintenance (O&M) costs.(2) the expectation that profitability initiatives at ASB will produce fairly predictable earnings enabling ASB to provide regular dividends to HEI without jeopardizing the bank’s strong capital position. Moody’s indicated that the rating could be downgraded if the PUC does not follow through with the regulatory transformation contemplated under the HCEI, including all elements of the decoupling mechanism, or if HEI’s cash flow to debt declined to below 15% (16.5% last twelve months as of March 31, 2012 – latest reported by Moody’s) and its cash flow coverage of interest fell below 3.3 times (4.3 times last twelve months as of March 31, 2012 – latest reported by Moody’s) on a sustainable basis. On November 15, 2010,29, 2012, S&P issued an update in which it lowered itsmaintained HEI’s long-term ratings forand corporate credit rating of “BBB-”, short-term (commercial paper) rating of “A-3”, stable outlook, “strong” business risk profile and “aggressive” financial risk profile. The stable outlook reflects S&P’s view that the consolidated credit profile will remain consistent with the HEI to “BBB-” from “BBB,”ratings and indicatedincorporates the outlook as “stable.” In addition, S&P affirmed its “A-3” short-term rating on HEIbenefits of decoupling, expectations of supportive rate case outcomes and revised HEI’s financial profile to “aggressive” from “significant.”a balanced funding approach that supports the current capital structure. S&P indicated the corporate credit rating do wngrade reflects an “aggressive”would be lowered if HEI’s financial profile combined with weak cash flow generation at HEI’s electric utilities, delays in implementing new utility rate recovery mechanisms, the growing risks of regulatory disallowances in future rate cases,performance weakens so that funds from operations (FFO) to total debt is less than 12% and debt to capital approaches 60% on a protracted recession.

consistent basis.

As of February 10, 2011,7, 2013, the S&P and Moody’s ratings of HEI securities were as follows:

 

S&P

S&P

Moody’s

 

 

 

Commercial paper

A-3

P-2

Senior unsecured debt

BBB-

Baa2

 

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 wouldcould be more difficult andand/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 wouldcould be more difficult and moreand/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 cash flowsliquidity of HEI and its subsidiariessubsidiaries..

See the electric utilities’ and bank’s respective “Liquidity and capital resources” sections below for the ratings of HECO and ASB.

In November 2008, HEI filed an omnibus registration statement to register an indeterminate amount of debt, equity and hybrid securities. Under Securities and Exchange Commission (SEC) regulations, this registration statement expires on November 4, 2011. On December 2, 2008, HEI offered and priced under the registration a public offering of 5,000,000 shares of its common stock at $23 per share for net proceeds of approximately $110 million, which were used in part to repay its outstanding short-term indebtedness and to make loans to HECO.

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 have been important sources of capital for HEI. Issuances of common stock through DRIP, HEIRSP and the ASB 401(k) Plan (which was split off from HEIRSP in 2009) provided new capital of $47 million (approximately 1.8 million shares) in 2012, $24 million (approximately 1.0 million shares) in 2011 and $43 million (approximately 1.9 million shares) in 2010 and $43 million (approximately 1.8 million shares) in 2008.2010. From August 18, 2011 to January 1, 2009 through April 15, 2009, issuances of common stock through these plans increased significantly, with8, 2012, HEI raising $14 million of new capital throughsatisfied the issuance of approximately

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1.0 million shares for these plans during this period. HEI ceased new issuances of stock through DRIP and HEIRSP effective April 16, 2009 and began satisfying the HEI common stockshare purchase requirements of DRIP and HEIRSP (and the ASB 401(k) Plan upon its inception on May 7, 2009) through open market purchases. On September 4, 2009, HEI resumed satisfying the HEI common stock requirements of DRIP, HEIRSP and the ASB 401(k) Plan through new issuancesopen market purchases of its common stock and raised $18 million ofrather than new capital through the issuance of approximately 1.0 million shares to these plans from September 4 to December 31, 2009.

issuances.

Operating activities provided net cash of $235 million in 2012, $250 million in 2011 and $341 million in 2010, $284 million in 2009 and $260 million in 2008.2010. Investing activities provided (used)used net cash of $(279)$427 million in 2010, $4422012, $327 million in 20092011 and $1.1 billion$279 million in 2008.2010. In 2010,2012, net cash used in investing activities was primarily due to purchases of investment and mortgage-related securities, and HECO’s consolidated capital expenditures (net of contributions in aid of construction), and a net increase in loans held for investment, partly offset by the repayments of, and the proceeds from sales of, investment and mortgage-related securities and a net decrease in loans held for investment.securities. Financing activities usedprovided (used) net cash of $235$142 million in 2010, $4062012, $16 million in 2009,2011 and $1.4 billion$(235) million in 2008.2010. In 2010,2012, net cash used inprovided by financing activities included net decreasesincreases in deposits, long-term debt and short-term borrowings other bank borrowings and deposits and the payment of common and preferred stock d ividends, partly offset by proceeds from the issuance of common stock under HEI plans.plans, offset by the net decrease in retail repurchase agreements and the payment of common

46



and preferred stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), HECO’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 2012, HECO and ASB (via ASHI) paid cash dividends to HEI of $73 million and $45 million, respectively.

 

A portion of the net assets of HECO 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 HECO and HEI requires that HECO maintain a consolidated common equity to total capitalization ratio of not less than 35% (actual ratio of 55% at December 31, 2010)2012), and restricts HECO 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 13 of HEI’s “Notes to Consolidated Finan cialFinancial Statements.”

 

Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 20112013 through 20132015 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction programs (see “Electric utility—utility–Liquidity and capital resources”), approximately $207$150 million will be required during 20112013 through 20132015 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 issued under Company plans, and/or dividends from subsidiaries. Medium-term notes of $50 million maturing in March 2013 are expected to be replaced with new debt. In addition, $57.5 million of HECO special purpose revenue bonds (SPRBs) totaling $11 million will be maturing in 2012, which bondsduring 2013 through 2015 and are expected to be repaid with proceeds from issuances of long-term de bt.debt. 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 20112013 through 20132015 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 9 of HEI’s “Notes to Consolidated Financial Statements,” the Company maintains pension and other postretirement benefitOPEB plans. The Company was required to makeCompany’s contributions of $19.1 million for 2010, but was not required to make any contributions for 2009 and 2008 to the qualified pensionretirement benefit plans totaled $78 million in 2012 ($63 million by the utilities, $2 million by HEI and $13 million by ASB), $75 million in 2011 ($73 million by the utilities, $2 million by HEI and nil by ASB) and $32 million in 2010 ($31 million by the utilities, $1 million by HEI and nil by ASB) and are expected to meettotal $86 million in 2013 ($84 million by the utilities, $2 million by HEI and nil by ASB). These contributions satisfied the minimum funding requirements pursuant to ERISA, including changes promulgated by the Pension Protection Act of 2006. The Company made voluntary contributions in 2010, 20092006, and 2008. Contributions to the retirement benefit plans totaled $32 million in 2010 (comprisedrequirements of $31 million by the utilities, $1 million by HEIelectric utilities’ pension and nil by ASB), $25 million in 2009 and $15 million in 2008 and are expected to total $64 million in 2011 ($63 million by the utilities, $1 million b y HEI and nil by ASB).OPEB tracking mechanisms. In addition, the Company paid directly $2$1 million of benefits in 2010 and

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$12012, $2 million of benefits in each of 20092011 and 2008$2 million in 2010 and expects to pay $2 million of benefits in 2011.2013. 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.

 

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,47


(2)retained or contingent interests in assets transferred to an unconsolidated entity or similar arrangements that serves 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.

(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 (e.g., Afghanistan war) on federal government spending in Hawaii. The two largest components of Hawaii’s eco nomyeconomy 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. GDP declined by 2.6% in 2009, but grew by 2.9% in 2010.

 

If S&P or Moody’s were to further downgrade HEI’s or HECO’s debt ratings, or if future events were to adversely affect the availability of capital to the Company, HEI’s and HECO’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 as further explained in “Retirement benefits” above and Notes 1 and 9 of HEI’s “Notes to Consolidated Financial Statements,” 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 electric 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

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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.

 

Changes in interest rates and credit spreads also affect the fair value of ASB’s investment securities. In 2009, the credit markets experienced significant disruptions, liquidity on many financial instruments declined and residential mortgage delinquencies and defaults increased. These disruptions negatively impacted the fair value of ASB’s investment portfolio in 2009. However, with the fourth quarter 2009 sale of ASB’s remaining private-issue mortgage-related securities portfolio and substantial residential loan production in 2009 and 2010, the Company’s exposure to credit and interest rate risks have been reduced.

Limited insuranceIn 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. HECO, HELCO and MECO’s transmission and distribution systems (excluding substation buildings and contents) have a replacement value roughly estimated at $5$6 billion and are uninsured. Similarly, HECO, HELC OHELCO and MECO 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

48



and cash flowsliquidity 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’ sCompany’s results of operations, financial condition and cash flows.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 financial condition and 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

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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 HECO Audit Committee.

 

For additional discussion of the Company’s accounting policies, see Note 1 of HEI’s “Notes to 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, AOCIaccumulated other comprehensive income (loss) (AOCI) charges and sensitivity analyses, see “Retirement benefits” in “Consolidated—Results of operations” above and Notes 1 and 9 of HEI’s “Notes to 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.

 

49



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 “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements” for a description of the Honolulu Harbor investigation.

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 “Income taxes” in Notes 1 and 11 of HEI’s “Notes to Consolidated Financial Statements.”

Following are discussions of the electric utility and bank segments. Additional segment information is shown in Note 2 of HEI’s “Notes to Consolidated Financial Statements.” The discussion concerning Hawaiian Electric Company, Inc. should be read in conjunction with its consolidated financial statements and accompanying notes.

Electric utility

Executive overview and strategy.  The electric utilities are vertically integrated and regulated by the PUC. The separate island utility systems are not currently interconnected, which requires that additional reliability be built into each system, but also means that the utilities are not exposed to the risks of inter-ties. The electric utilities’ strategic focus has been to meet Hawaii’s growing energy needs through a combination of diverse activities—modernizing and adding needed infrastructure through capital investment, placing emphasis on

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energy efficiency and conservation, pursuing renewable energy generation (including the use of biofuels) and taking the necessary steps to secure regulatory support for their plans.

 

Reliability projects remain a priority for HECO and its subsidiaries. HECO has completed construction of a new generating unit designed to operate usingthat uses biodiesel fuel and has completed the first phase and is currently constructing the remaining phaseboth phases of the East Oahu Transmission Project (EOTP)—a needed alternative route to move power from the west side of Oahu to load centers on the east side—and is working with the State and U.S. Department of Energy on an undersea cable system to interconnect proposed independent power producer (IPP) wind farms on the islands of Lanai and Molokai with the Oahu grid.side.

 

Major infrastructure projects can have a pronounced impact on the communities in which they are located. The electric utilities continue to expand their community outreach and consultation process so they can better understand, evaluate and address community concerns early in the process.

With large power users in the electric utilities’ service territories, such as the U.S. military, hotels and state and local government, management believes that retaining customers by offering them specialized services and energy efficiency audits to help them save on energy costs is critical to long-term success.

Hawaii Clean Energy Initiative.  On October 20, 2008, 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 State of Hawaii Department of Commerce and Consumer Affairs, and HECO on behalf of itself and its subsidiaries HELCO and MECO (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). The Energy Agreement provides that the parties shall pursue a wide range of actions with the purpose of decreasing the State of 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 ene rgy efficiency and conservation. See “Hawaii Clean Energy Initiative” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

Decoupling.  Decoupling is a new method of setting electric rates that is designed to support Hawaii’s efforts to reduce its dependence on imported oil. In December 2010, the PUC allowed HECO to implement decoupling, which removes the link between electricity usage and utility revenues. This aligns the utility with public policy to promote energy efficiency and conservation. Customers will still have an incentive to conserve energy because their bills continue to be based on how much electricity they use. Decoupling also allows the utility to recover on a more timely basis the investments and costs to further support reliability and clean energy. See “Decoupling proceeding” below.

Renewable energy strategy.  The electric utilities have been taking actions intended to protect Hawaii’s island ecology and reduce greenhouse gas (GHG) emissions, while continuing to provide reliable power to customers, and committed to a number of related actions in the Energy Agreement.customers. A three-pronged strategy supports attainment of the requirements and goals of the State of Hawaii Renewable Portfolio Standards (RPS), the Hawaii Global Warming Solutions Act of 2007 and the HCEI by: (1) the “greening” of existing assets, (2) the expansion of renewable energy generation and (3) the acceleration ofembracing energy efficiency and load management programs. Major initiatives are being pursued in each category.

 

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. For the eleven months ended November 30, 2010, HECO’s consolidated RPS was 16.2%, including electrical energy savings. Accordingly, the utilities are expected to meet the 2010 RPS.This was accomplished through a combination of municipal solid waste, geothermal, wind, biomass, hydro, photovoltaic and biodiesel renewable generation resources; renewable energy displacement technologies; and energy savings from efficiency technologies. Demand-side management (DSM) programs contributed significantly to achieving the 16.2% RPS level and, without including the DSM energy savings, the RPS would have been 9.1%. Energy savi ngs resulting from energy efficiency programs will not count toward the RPS after 2014.

In January 2007, the PUC opened a docket (RPS Docket) to examine Hawaii’s RPS law. In December 2007, the PUC issued a D&O approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. In the D&O, the PUC deferred an RPS incentive framework to a new generic

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TableUtility strategic progress.  In 2012, the utilities continued to make significant progress in implementing their clean energy strategies and the PUC issued several important regulatory decisions, all of Contentswhich are key steps to support Hawaii’s efforts to reduce its dependence on oil. Included in the PUC decisions were a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below). Additional PUC decisions are needed that will allow the utilities to recover their increasing expenditures for clean energy and reliability on a more timely basis.

 

docket (Renewable Energy Infrastructure Program (REIP) Docket)RegulatoryIn December 2008,With PUC approval, decoupling was implemented by HECO on March 1, 2011, by HELCO on April 9, 2012 and by MECO on May 4, 2012. Decoupling is a regulatory model that is intended to facilitate meeting the PUC approvedState of Hawaii’s goals to transition to a potential penaltyclean 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 $20revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for every MWhmore timely cost recovery and earning on investments. The implementation of decoupling has resulted in an improvement in the utilities’ under-earning situation that an electric utility is deficient underhas existed over the RPS law. The PUC must evaluatelast several years. Prior to and during the standards every five years, beginning in 2013,transition to determine whetherdecoupling, however, the standards remain effective and achievable or should be revised.utilities’ returns have been well below PUC-allowed returns.

 

The electric utilities are actively pursuingUnder decoupling, the use of biofuelsmost significant drivers for existing and planned company-owned generating units. HECO’s new 110 MW generating unit began on-going operations in 2010 with 100% biodiesel supplied under a two-year biodiesel supply contract with Renewable Energy Group Marketing & Logistics, LLC (REG) as approved by the PUC in June 2010. HECO is also moving toward operating some of its steam generating units with a blend of fossil and biofuels (co-firing). In June 2010, the PUC approved HECO’s and MECO’s biofuel supply contracts for their respective biofuel demonstration projects. HECO completed installation of capital equipment in 2010 in preparation for a co-firing test completed in February 2011 at its Kahe Power Plant. MECO plans to test biodiesel at its Maalaea Power Plant in 2011.improving earnings are:

 

In March 2010, HECO1.completing major capital projects within PUC approved amounts and its subsidiaries issued a request for proposal (RFP) for biofuels produced from feedstock grown in, made in, or otherwise originating in Hawaii (local biofuel) to potentially supply multiple locations. In January 2011, HELCO signed a 20-year contract with Aina Koa Pono-Ka’u LLC to supply 16 million gallons of biodiesel per year with initial consumption at HELCO’s Keahole Power Plant to begin by 2015. HECO is continuing negotiations with other bidders. In January 2011, HECO issued a RFP for biodiesel to supply CIP CT-1 upon the expiration of the REG contract in July 2012. HECO expects to issue a RFP in 2011 for commercial supplies of biofuel to co-fire with fossil fuel at HECO’s Kahe Power Plant by 2015. Under current RPS law, biofuel use in existing and new generating units counts toward the RPS.on schedule;

 

The electric utilities also support renewable energy through the negotiation2.managing O&M expenses relative to authorized O&M adjustments; and execution of power purchase agreements (PPAs) with non-utility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric, photovoltaic and wind turbine generating systems).

 

On April 30, 2009, HECO filed an application with the PUC for approval of a Photovoltaic (PV) Host Pilot Program, which would be a two-year pilot program whereby HECO, HELCO3.regulatory outcomes that cover O&M requirements and MECO would lease rooftops or other space from property owners, with a focus on governmental facilities, for the installation of third-party owned PV systems. The PV developer would own, operate and maintain the system and sell the energy to the utilities at a fixed rate under a long-term contract. On August 31, 2010, HECO proposed several modifications to the pilot program, including deferment of HELCO’s and MECO’s participationbase items not included in the program and utilization of select PV Host projects on Oahu as test platforms to evaluate grid integration technologies (as well as to help address grid integration issues associated with existing and growing penetration levels of distributed intermittent generation).RAMs.

 

In 2008, HECO issued an Oahu Renewable Energy Request for Proposals (2008 RFP) for combined renewable energy projects upJanuary 2013, the utilities and Consumer Advocate signed a settlement agreement, subject to 100 MW. HECOPUC approval, to write off $40 million of CIS project costs, in lieu of conducting regulatory audits of two major projects. See “Subsequent event” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

Future earnings growth is currently negotiating PPAs with the biddersalso dependent on rate base growth. The utilities’ five-year 2013-2017 forecast reflects net capital expenditures of $2.9 billion and a compounded annual rate base growth rate in the Award Group—a proposed wind project (70 MW)range of 5% to 10%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Major initiatives which comprise approximately 35% of the 5-year plan include projects relating to: (1) environmental compliance; (2) fuel infrastructure investments; (3) new generation; and a proposed solar project (5 MW).(4) infrastructure investments to integrate more energy from renewables into the system. Estimates for these initiatives could change over time, based on external factors such as the timing and scope of environmental regulations, unforeseen delays in permitting and the outcome of competitive bidding for new generation.

 

IncludedActual and PUC-allowed returns were as follows:

%

 

Return on rate base (RORB)*

 

ROACE**

Year ended December 31, 2012

 

HECO

 

HELCO

 

MECO

 

HECO

 

HELCO

 

MECO

Utility returns

 

8.15

 

6.99

 

5.95

 

7.6

 

5.9

 

5.4

PUC-allowed returns

 

8.11

 

8.31

 

7.91

 

10.0

 

10.0

 

10.0

     Difference

 

0.04

 

(1.32)

 

(1.96)

 

(2.4)

 

(4.1)

 

(4.6)

*  Based on recorded operating income and average rate base, both adjusted for items not included in the bids received in response to the 2008 RFP were proposalsdetermining electric rates.

**Recorded net income divided by average common equity for two large scale neighbor island wind projects that would produce energy to be imported from Lanai and Molokai to Oahu via a yet-to-be-built undersea transmission cable system (Interisland Wind projects). In accordance with the Energy Agreement, the proposals for the Interisland Wind Projects were bifurcated from the Oahu Renewable Energy RFP for separate negotiation. Subsequently, HECO received a PUC waiver from the competitive bidding framework for the two non-conforming proposals and negotiations are ongoing.2012.

 

In September 2010 and January 2011, MECO executed PPAs with Kaheawa Wind Power II, LLC and Auwahi Wind Energy, LLC, respectively, for the purchase of 21 MW (each) of as available wind energy. The PPA with Auwahi Wind Energy, LLC is subject to PUC approval. In January 2011, MECO requested that the PUC open a docket for MECO’s plans to acquire up to 50 MW of renewable, firm dispatchable capacity generation resources on Maui, with the initial increment coming on line in 2015.

On September 30, 2010, the PUC approved the electric utilities’ proposed Electric Vehicle (EV) Charging Time of Use Pilot Rates, which are now available to 1,000 HECO, 300 HELCO and 300 MECO customers for charging highway-capable, four-wheeled EVs. The EV Pilot Rates will remain in effect for three years and are designed to encourage early adoption of EVs and incentivize customers to charge EVs during off-peak times of the day.

5651



Table

The approval of Contentsdecoupling by the PUC will help the utilities to gradually improve their ROACEs beyond 2012, which will facilitate the utilities’ ability to effectively raise capital for needed infrastructure investments. However, the utilities continue to expect an ongoing gap between their PUC-allowed ROACEs and the ROACEs they actually achieve. The timing of general rate case decisions, the effective date of the RAMs and the PUC’s consistent exclusion of certain expenses from rates are estimated to have a consolidated ROACE impact of 120 to 150 basis points per year. In addition, there are other items that are not covered by the annual RAMs that could also have an ongoing impact on the ROACEs actually achieved by the utilities. For example, investments in software projects, O&M in excess of indexed escalations and changes in fuel inventory must be addressed in a general rate case. While the specific magnitude of the impact can fluctuate depending on the size of the projects and exogenous factors, the utilities anticipate that these items could incrementally impact consolidated ROACE by 50 to 75 basis points in each of the next two years.

As part of decoupling, HECO also tracks its rate-making ROACE as calculated under the earnings sharing mechanism and which includes only items considered in establishing rates. Earnings over and above the ROACE allowed by the PUC are shared between HECO and its ratepayers on a tiered basis. For 2012, HECO’s rate-making ROACE was 10.56%, which was above the PUC allowed 10% ROACE and triggered its earnings sharing mechanism. As a result, HECO will credit its customers $2 million for their portion of the earnings sharing. HECO’s 2012 rate-making ROACE of 10.56% included various adjustments to HECO’s actual ROACE of 7.6% such as the exclusion of the partial writedown of CIS project costs to reflect the settlement agreement, subject to PUC approval, and of other expenses not considered in establishing electric rates (e.g., executive bonuses and advertising). HELCO’s rate-making ROACE was 7.79% and MECO’s rate-making ROACE was 6.69%, which did not trigger the earnings sharing mechanism.

Decoupling implementation.  Effective March 1, 2011, as part of the decoupling implementation, HECO established the RBA and started recording the difference between target revenues from its HECO 2009 rate case and actual revenues. Under the decoupling tariff order HECO will accrue and collect 7/12ths of the annual RAM adjusted revenues in one year and the remaining 5/12ths in the following year. HECO’s 2012 annual decoupling filing for the tariff that is effective June 1, 2012 through May 31, 2013 reflects a RAM adjustment of $7.0 million ($3.7 million for O&M costs and $3.3 million for invested capital). The filing also includes the collection of the accrued RBA balance as of December 31, 2011 and associated revenue taxes of $22.4 million. Under the January 2013 settlement agreement with the Consumer Advocate, subject to PUC approval, the parties agreed that, starting in 2014, HECO will be allowed to record RAM revenues starting January 1 of each year through 2016. See “Subsequent event” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

 

The electric utilities promote researchHELCO and developmentMECO began tracking their target revenues and actual recorded revenues via RBAs on April 9, 2012 and May 4, 2012, respectively, when their 2010 test year final rates went into effect.

HELCO’s tariff for its annual RAM for 2012 reflects a revenue adjustment that results in a reduction in annual revenues of $2.1 million, effective through May 31, 2013. MECO filed its 2012 RAM (calculated to be $0.1 million) for informational purposes only since the areas supporting renewable energy such as biofuels, ocean energy, energy storage, smart grids and integration of non-firm power into the separate island electric grids. The utilities are evaluating several potential energy storage and smart grid demonstration projects, and conducting various integration studies.pending interim D&O for its 2012 test year rate case was anticipated to be issued shortly. MECO’s interim D&O for its 2012 test year rate case was issued on May 21, 2012.

52



Results of operations.

 

(dollars in millions, except per barrel amounts)

 

2010

 

% change

 

2009

 

% change

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues (1)

 

$

2,382

 

17

 

$

2,035

 

(29

)

$

2,860

 

Expenses

 

 

 

 

 

 

 

 

 

 

 

Fuel oil

 

900

 

34

 

672

 

(45

)

1,229

 

Purchased power

 

549

 

10

 

500

 

(28

)

690

 

Other

 

755

 

9

 

694

 

(8

)

750

 

Operating income

 

178

 

5

 

170

 

(11

)

191

 

Allowance for funds used during construction

 

9

 

(51

)

17

 

33

 

13

 

Net income for common stock

 

77

 

(4

)

79

 

(14

)

92

 

Return on average common equity

 

5.8

%

 

 

6.4

%

 

 

8.0

%

Average fuel oil cost per barrel (1)

 

$

87.62

 

37

 

$

63.91

 

(44

)

$

114.50

 

Kilowatthour sales (millions)

 

9,579

 

(1

)

9,690

 

(2

)

9,936

 

Cooling degree days (Oahu)

 

4,661

 

(3

)

4,815

 

(3

)

4,943

 

Number of employees (at December 31)

 

2,318

 

1

 

2,297

 

4

 

2,203

 

·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 HECO for the 2011 test year, partly offset by the 2011 test year refund

 

 

 

 

 

7

 

Interim rate increases granted to MECO 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

 

 

 

 

 

 

 

 

272

 

257

 

15

 

 

Other operation 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

 

 

 

 

 

 

 

 

122

 

121

 

1

 

 

Maintenance expense. Increase largely due to higher overhaul costs at HELCO and MECO

 

 

 

 

 

 

 

 

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 Customer Information System (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 HECO and MECO.

 

 

 

 

 

 

 

 

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 DSM

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)

53



2011 vs. 2010

2011

 

2010

 

Increase
(decrease)

 

(in millions)

$2,979

 

$2,382

 

$597

 

 

Revenues. Increase largely due to:

 

 

 

 

 

$567

 

Higher fuel prices

 

 

 

 

 

26

 

Rate increases granted to HECO for the 2011 and 2009 test years and 2009 test year refund

 

 

 

 

 

10

 

Interim rate increases granted to HELCO ($6 million) and MECO ($4 million) for the 2010 test year

 

 

 

 

 

10

 

Decoupling revenue adjustments net of sales impacts at HECO

 

 

 

 

 

2

 

Rate base RAM and O&M RAM at HECO

 

 

 

 

 

(4)

 

Heat rate deadband and lower fuel efficiency at HECO

 

 

 

 

 

9

 

Fuel related revenues at HELCO and fuel efficiency savings at HELCO and MECO

 

 

 

 

 

(6)

 

Lower KWH sales at HELCO and MECO

 

 

 

 

 

(3)

 

Purchase power adjustment clause (PPAC) adjustment at HECO

 

 

 

 

 

(10)

 

Interest income due to a federal tax settlement in 2010

 

 

 

 

 

 

 

 

1,265

 

900

 

 365

 

 

Fuel oil expense. Increase largely due to higher fuel costs, partly offset by less KWHs generated

 

 

 

 

 

 

 

 

690

 

549

 

 141

 

 

Purchased power expense. Increase largely due to higher purchased energy costs, partly offset by less KWHs purchased

 

 

 

 

 

 

 

 

257

 

251

 

6

 

 

Other operation expense. Increase largely due to:

 

 

 

 

 

6

 

Higher transmission and distribution expense, which includes costs related to the Asia-Pacific Economic Cooperation (APEC) forum held in Honolulu

 

 

 

 

 

6

 

Higher bad debt expenses

 

 

 

 

 

(5)

 

Regulatory change for the capitalization of administrative costs, which lowered administrative and general expenses

 

 

 

 

 

 

 

 

121

 

127

 

(6)

 

 

Maintenance expense. Decrease largely due to:

 

 

 

 

 

(11)

 

Lower overhaul costs at HELCO and MECO

 

 

 

 

 

4

 

Higher overhaul and station maintenance at HECO

 

 

 

 

 

2

 

Higher vegetation management

 

 

 

 

 

 

 

 

431

 

377

 

54

 

 

Other expenses. Increase largely due to:

 

 

 

 

 

54

 

Higher taxes, other than income taxes, primarily resulting from higher revenues

 

 

 

 

 

9

 

Partial writedown of the East Oahu Transmission Project Phase 1 costs in December 2011

 

 

 

 

 

(7)

 

Decrease in depreciation expense resulting from lower depreciation rates implemented in conjunction with the most recent interim D&Os

 

 

 

 

 

 

 

 

215

 

178

 

37

 

 

Operating income. Increase largely due to the interim rate increases for HECO, HELCO and MECO, decoupling revenue adjustments net of sales impacts at HECO and lower depreciation expense, partly offset by the impact of higher other expenses (see above) and lower interest income due to a tax settlement in 2010.

 

 

 

 

 

 

 

 

8

 

9

 

(1)

 

 

Allowance for funds used during construction

 

 

 

 

 

 

 

 

100

 

77

 

 23

 

 

Net income for common stock. Increase largely due to:

 

 

 

 

 

20

 

Interim and final rate increases

 

 

 

 

 

7

 

Decoupling revenue adjustments (including rate base RAM and O&M RAM) net of sales impacts at HECO

 

 

 

 

 

(4)

 

Heat rate deadband and lower fuel efficiency at HECO

 

 

 

 

 

6

 

Fuel efficiency savings at HELCO and MECO

 

 

 

 

 

(6)

 

Partial writedown of the East Oahu Transmission Project Phase 1 costs

 

 

 

 

 

(6)

 

Interest income due to a federal tax settlement in 2010

 

 

 

 

 

(1)

 

Lower KWH sales at HELCO and MECO net of energy cost savings

 

 

 

 

 

4

 

Lower depreciation expense

7.3%

 

5.8%

 

 

1.5%

 

Return on average common equity

123.63

 

87.62

 

 

36.01

 

Average fuel oil cost per barrel 1

9,527

 

9,579

 

 

(52)

 

Kilowatthour sales (millions) 2

4,954

 

4,661

 

 

293

 

Cooling degree days (Oahu)

2,518

 

2,317

 

 

201

 

Number of employees (at December 31)

54



(1)1        The rate schedules of the electric utilities currently contain ECACsenergy cost adjustment clauses (ECACs) through which changes in fuel oil prices and certain components of purchased energy costs are passed on to customers.

·2        Net income for common stock for HECO and its subsidiaries was $77 million in 2010 compared to $79 million in 2009. The net income decrease in 2010 compared to 2009 was primarily due to higher O&M spending (excluding DSM program expenses) to maintain system reliability, lower KWH sales for 2012 were lower than 2011 due largely to cooler, less humid weather, continued conservation efforts and lower allowance for funds used during construction (AFUDC), partly offset by higher interim rate increases that became effective for HECO (test year 2009) in August 2009 and February 2010 and for MECO (test year 2010) in August 2010 and $6 millionincreasing levels of interest income, net of taxes, due to a federal tax settlement.

In 2010, the electric utilities’ revenues increased by 17%, or $347 million, from 2009 primarily due to higher fuel prices ($326 million), interim rate relief granted by the PUC to HECO for its 2009 test year ($43 million) and interim rate relief granted by the PUC to MECO for its 2010 test year ($4 million) (see “Most recent rate requests” below), partly offset by the impact of lowercustomer-sited renewable generation. KWH sales ($22 million) andfor 2011 were lower DSM program recovery revenues ($20 million) (see “Demand-side management programs” below). KWH sales were 1.1% lower when compared to 2009than 2010 due largely to cooler, less humid weather and continued conservation efforts by customers.

Operating income in 2010 was $9 million higher than in 2009 due primarily to the interim rate relief for HECO and MECO, partly offset by the impact of lower KWH sales, higher other expenses, including higher O&M expenses and higher depreciation expense.

Fuel oil expense in 2010 increased by 34% due primarily to higher fuel costs, partly offset by lower KWHs generated and improved operating unit efficiency. Purchased power expenses in 2010 increased by 10% due primarily to higher purchased energy costs, partly offset by lower KWHs purchased. Higher fuel costs are generally passed on to customers.

Other expenses increased 9% ($61 million) (12% and $78 million excluding DSM expenses) in 2010 due primarily to increases of 16% ($30 million) in taxes, other than income taxes, primarily due to the increase in revenues, 6% ($22 million) in other O&M expenses and 4% ($5 million) in depreciation expenses due to 2009 plant additions. “Other operation” expenses increased by $3 million in 2010 when compared to 2009 due primarily to higher administrative and general expenses ($17 million) including higher employee benefits expense due to higher retirement benefit expense ($7 million) and higher production and transmission and distribution expense ($6 million) to maintain reliable operations, offset in part by lower DSM ($17 million) and bad debt expenses ($5 million). Maintenance expense increased $20 million from 2009 due primarily to incr eased production maintenance expenses ($13 million), including generating unit overhauls ($9 million), full year operation of CT-1 ($2 million), increased maintenance on boiler plant equipment ($2 million) and

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Table of Contents

 

higher transmission and distribution expenses ($7 million) due to increased levels of work to address aging infrastructure.

·Net income for common stock for HECO and its subsidiaries was $79 million in 2009 compared to $92 million in 2008. The decrease in 2009 compared to 2008 was primarily due to lower KWH sales and certain higher expenses (other O&M, depreciation and interest), partly offset by higher AFUDC.

In 2009, the electric utilities’ revenues decreased by 29%, or $825 million, from 2008 primarily due to lower fuel prices ($766 million), lower KWH sales ($77 million) and lower DSM program recovery revenues ($13 million), partly offset by interim rate relief granted by the PUC to HECO for its 2009 test year ($26 million). KWH sales were 2.5% lower when compared to 2008, due largely to customer conservation efforts and the impact of cooler weather, partially offset by new load growth (i.e., increase in number of customers) and the impact of a drop in the average electricity price. Cooling degree days for Oahu were 2.6% lower in 2009 compared to 2008.

Operating income in 2009 was $22 million lower than in 2008 due primarily to lower KWH sales, higher other expenses, including higher O&M expenses and higher depreciation expense, partly offset by the interim rate relief for HECO granted by the PUC.

Fuel oil expense in 2009 decreased by 45% due primarily to lower fuel costs and lower KWHs generated. Purchased power expenses in 2009 decreased by 28% due primarily to lower purchased energy costs and lower KWHs purchased. Lower fuel costs are generally passed on to customers.

Other expenses decreased 8% in 2009 (6% excluding DSM expenses) due to a 27% (or $70 million) decrease in taxes, other than income taxes, primarily due to the decrease in revenues, partly offset by a 3% (or $11 million) increase in other O&M expenses. “Other operation” expenses increased by $5 million in 2009 when compared to 2008 due primarily to higher administrative and general expense ($9 million), including higher employee benefit expense due to higher retirement benefit expense ($5 million) and a retrospective medical plan premium adjustment ($2 million) and higher production and transmission and distribution expense to maintain reliable operations ($6 million), including more employees for CIP CT-1, offset in part by lower DSM expense ($12 million). Maintenance expense increased $6 million from 2008 due primarily to higher transmission and distrib ution expense for substation maintenance, overhead and underground line maintenance and vegetation management.

·O&M expenses (excluding DSM program costs) for the year 2011 are expected to be approximately 7% higher than 2010 as the electric utilities expect higher production expenses and higher contract services. Transmission and distribution expenses are expected to increase consistent with the new asset management initiatives to modernize the infrastructure. Also, additional expenses are expected for the costs to operate and maintain CIP CT-1, and are expected to be incurred for environmental compliance in response to existing compliance programs as well as numerous new, more stringent regulatory requirements, and to execut e the provisions of the Energy Agreement. HCEI-related initiatives appear to be progressing at a pace to achieve the state’s clean energy goals under the HCEI.

Most recent rate requests.proceedings  The.  Unless otherwise agreed or ordered, each electric utilitiesutility may initiate a PUC proceedings from time to timeproceeding every third year (on a staggered basis) 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 return on average common equity (ROACE)ROACE and return on rate base (RORB))RORB) for purposes o fof an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

ROACEsThe following table summarizes certain details of 10.0% (reflects implementationeach utility’s most recent rate cases, including the details of decoupling), 10.7% (without decoupling)the increases requested, whether the utility and 10.7% (without decoupling) were foundthe Consumer Advocate reached a settlement that they proposed to be reasonable by the PUC, in the most recent final rate decisions issued in December 2010, October 2010 and July 2010 in HECO, HELCO and MECO rate cases based on 2009, 2006 and 2007 test years, respectively. The ROACE used by the PUC for the purposesdetails of the most recent

58



Table of Contents

interim rate increases issued in November 2010 and July 2010 in HELCO and MECO rate cases, respectively, based on 2010 test years was 10.5% (without decoupling).

For 2010, the actual ROACEs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates, and reported to the PUC) for HECO, HELCO and MECO were 6.15%, 6.24% and 3.90%, respectively. The utilities’ actual ROACEs were lower than their final and interim D&O ROACEs primarily due to lower KWH sales than the sales used to determine the interim rates and increased O&M expenses.

The RORBs found to be reasonable by the PUC in the most recent final rate decisions were 8.16% for HECO, 8.33% for HELCO and 8.67% for MECO (final D&Os noted above). The RORBs used by the PUC for purposes of the most recent interim increases were 8.59% for HELCO and 8.43% for MECO (interim D&Os noted above). For 2010, the actual RORBs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates, and reported to the PUC) for HECO, HELCO and MECO were 5.93%, 5.86% and 4.86%, respectively.

In the most recentany 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/
imple-
mented)

Amount

% over
rates in
effect

ROACE
(%)

RORB
(%)

Rate base

Common
equity

%

Stipulated
agreement
reached with Consumer
Advocate

Reflects
decoupling

HECO

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

 

Request 1

7/3/08

$97.0

5.2

11.25

8.81

$1,408

54.30

Yes

No

Interim increase

8/3/09

61.1

4.7

10.50

8.45

1,169

55.81

 

No

Interim increase (adjusted)

2/20/10

73.8

5.7

10.50

8.45

1,251

55.81

 

No

Final increase 2

3/1/11

66.4

5.1

10.00

8.16

1,250

55.81

 

Yes

2011 3

 

 

 

 

 

 

 

 

 

Request

7/30/10

$113.5

6.6

10.75

8.54

$1,569

56.29

Yes

Yes

Interim increase

7/26/11

53.2

3.1

10.00

8.11

1,354

56.29

 

Yes

Interim increase (adjusted)

4/2/12

58.2

3.4

10.00

8.11

1,385

56.29

 

Yes

Interim increase (adjusted)

5/21/12

58.8

3.4

10.00

8.11

1,386

56.29

 

Yes

Final increase

9/1/12

58.1

3.4

10.00

8.11

1,386

56.29

 

Yes

HELCO

 

 

 

 

 

 

 

 

 

2010 4

 

 

 

 

 

 

 

 

 

Request

12/9/09

$20.9

6.0

10.75

8.73

$487

55.91

Yes

Yes

Interim increase

1/14/11

6.0

1.7

10.50

8.59

465

55.91

 

No

Interim increase (adjusted)

1/1/12

5.2

1.5

10.50

8.59

465

55.91

 

No

Final increase

4/9/12

4.5

1.3

10.00

8.31

465

55.91

 

Yes

2013

 

 

 

 

 

 

 

 

 

Request  5

8/16/12

$19.8

4.2

10.25

8.30

$455

57.05

 

Yes

MECO

 

 

 

 

 

 

 

 

 

2010 6

 

 

 

 

 

 

 

 

 

Request

9/30/09

$28.2

9.7

10.75

8.57

$390

56.86

Yes

Yes

Interim increase

8/1/10

10.3

3.3

10.50

8.43

387

56.86

 

No

Interim increase (adjusted)

1/12/11

8.5

2.7

10.50

8.43

387

56.86

 

No

Final increase

5/4/12

4.7

1.5

10.00

8.15

387

56.86

 

Yes

2012

 

 

 

 

 

 

 

 

 

Request 7

7/22/11

$27.5

6.7

11.00

8.72

$393

56.85

Yes

Yes

Interim increase

6/1/12

13.1

3.2

10.00

7.91

393

56.86

 

Yes

Note:  The “Request Date” reflects the application filing date for the rate decisions,proceeding. All other line items reflect the PUC allowed the use by each utility of pension and postretirement benefits other than pensions (OPEB) tracking mechanisms (with varied treatmenteffective dates of the pension assets of each utility)revised schedules and allowed the continuation of each utility’s energy cost adjustment clauses (ECAC).

HECO.

2007 test year rate case.  On December 22, 2006, HECO filed a request for a general rate increase of $99.6 million, or 7.1% over the electric rates then in effect, based on a 2007 test year, an 11.25% ROACE and an 8.92% RORB on a $1.214 billion average rate base. HECO’s application included a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage.

On September 6, 2007, HECO, the Consumer Advocate and the federal Department of Defense (DOD) (collectively, the parties) executed and filed an agreement on most of the issues in this rate case, and on October 22, 2007, the PUC issued, and HECO implemented, an interim D&O granting HECO an increase of $70 million in annual revenues over rates effective at the time of the interim D&O, subject to refund with interest. The interim increase was based on the settlement agreement which included, as a negotiated compromise of the parties’ respective positions, an ROACE of 10.7%, an 8.62% RORB, a $1.158 billion average rate base and a capital structure which includes a 55.1% common equity capitalization. In May 2008, the interim increase was adjusted from $70 million to $77.9 million in annual revenues to take into account the changes in current effective ratestariffs as a result of the final D&O in the 2005 test year rate case. In September 2008, the interim increase was corrected to $77.5 million based on a filing submitted by HECO.PUC-approved increases.

 

On September 14, 2010, the PUC issued a final D&O that confirmed the interim increase of $77.5 million and approved the stipulated rate design, which includes the new tiered rate structure for residential customers. Decoupling was not addressed in1In April 2009, HECO reduced this proceeding and the final D&O did not address the implementation of decoupling.

2009 test year rate case.  In July 2008, HECO filed a request for a general rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 3 of $97 million, or 5.2% over the electric rates then in effect, based on a 2009 test year, an 11.25% ROACE and an 8.81% RORB on a $1.408 billion average rate base. The requested rate increase was based on higher O&M costs required for HECO’s electrical system, higher depreciation expenses since the last rate case and anticipated plant additions estimated at the time of filing of $375 million in 2008 and 2009 (including the new CIP CT-1 and related transmission line in 2009)HEI’s “Notes to maintain and improve system reliability.Consolidated Financial Statements”).

 

In May 2009, HECO,2Because the Consumer Advocate and the DOD (the parties) executed an agreement (the Settlement Agreement) on most of the issues in the rate case, representing a negotiated compromise of the parties’ respective positions. The Settlement Agreement included an interim increase of $79.8 million annually, or a 6.2% increase over the rates then in effect. As part of the settlement, the parties also agreed that the PUC should allow HECO to establish a revenue balancing account, which would provide a

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mechanism to adjust revenues (increases/decreases) for the differences (shortages/overages) between the actual revenues and the revenues determined in the interim D&O.

In July 2009, the PUC issued an interim D&O, which approved an interim rate increase, but directed that adjustments be made to reduce the Settlement Agreement increase for several items, including certain labor expenses and costs related to CIP CT-1. HECO calculated an interim increase of $61.1 million annually, or a 4.7% increase, based on an ROACE of 10.50% and an 8.45% RORB on a rate base of $1.169 billion. The interimfinal increase was implemented on August 3, 2009.

In February 2010, the PUC issued a second interim D&O in this proceeding granting an additional increase of $12.7$7.4 million less in annual revenues, (implemented effective February 20, 2010) to recover costs associated with CIP CT-1 and related transmission facilities. The increase was based on an ROACE of 10.50% and an RORB of 8.45%, both of which were used for the first interim increase.

The two interim increases granted totaled $73.8 million, or a 5.7% increase.

On December 29, 2010, the PUC issued a final D&O, which allowed HECO to implement the decoupling mechanism approved by the PUC in the decoupling proceeding described below. The PUC determined that, in view of implementing decoupling, the appropriate ROACE is 10.0% and RORB is 8.16% (which reflects a capital structure that includes 55.8% common equity). The PUC also approved a purchased power adjustment clause (PPAC) that will allow HECO to recover purchase power expenses through a surcharge mechanism rather than through base rates as currently recovered. The PPAC provides a mechanism that more closely aligns cost recovery with costs incurred, thus reducing HECO’s risk profile associated with its PPAs. The PPAC is expected to enhance HECO’s credit quality, help HECO maintain access to capital markets at reasonable costs and help position HECO to invest in infrastructure to bo th facilitate the addition of new renewable resources from IPPs and to maintain reliable electrical service.

Based on the final D&O, HECO will be refundingrefunded $2.1 million to customers (including interest) duringin February 2011. In December 2010, HECO recorded charges of $1.9 million related to this refund, which reduced net income by approximately $1 million.

 

On January 24, 2011, HECO filed tariffs for the final rates for the PUC’s review and approval and requested the tariffs become effective on March 1, 2011. The tariffs included provisions to establish the decoupling revenue balancing account (which removes the historic link between electricity usage and revenues), the revenue adjustment mechanism (which allows the utility to recover its investments and costs in a timelier manner) and the PPAC. The tariffs also included a tiered rate structure. The final revenue requirements incorporate a ROACE of 10.0%, resulting in an annualized revenue increase of $66.4 million, or 5.1%, compared to the annualized interim increase of $73.8 million (a decrease in annual revenues of $7.4 million).

Management cannot predict when the tariffs implementing the final rate increase will be approved and become effective.

2011 test year rate case3.  On July 30, 2010, HECO filed a request with the PUC for a general rate increase of $94$113.5 million, or 5.4% over the electric rates then in effect (which included the interim increases in the HECO 2007 and 2009 rate cases), based on a 2011 test year and without the then estimated impacts of the implementation of decoupling as proposed in the PUC’s separate decoupling proceeding and depreciation rates and methodsmethodology as proposed by HECO. ExcludingHECO in a separate depreciation proceeding. Including the estimated effects of the implementation of decoupling at the time, the effective

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revenue request is $113.5was $94.0 million, or a 6.6% increase. The5.4%. HECO’s request includes an increase of $54 million, or 3.1% (or $74 million, or 4.3% without the implementation of decoupling),was primarily to pay for major capital projects (including investments in the 110 MW biofuel generating facility that were not part of the 2009 test year rate case and Phase 1 of the East Oahu Transmission Project, which was placed in service on June 29, 2010) and higher operating and maintenanceO&M costs to maintain and improve service reliability. The remainder of the request isreliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and increase 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.

4HELCO’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, HELCO 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. HELCO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. HELCO 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.

5HELCO’s request is required 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. Also see “Subsequent event” in Note 3 of HEI’s Consolidated Financial Statements.

6MECO’s interim increase, effective August 1, 2010, was based on a 10.75% ROACE,stipulated agreement reached with the Consumer Advocate and temporary approval of new depreciation rates and methodology in a separate depreciation proceeding. The adjustment to this increase, effective January 12, 2011, reflects the final rates from MECO’s 2007 test year rate case. On February 13, 2012, the PUC issued an 8.54% RORB,order instructing MECO and the Consumer Advocate to submit a $1.57 billion averagerevised stipulated agreement to incorporate the applicable rulings and decisions in D&Os issued in related proceedings since the first stipulation was filed. On March 29, 2012, MECO and the Consumer Advocate filed an updated agreement on all material issues in MECO’s 2010 test year rate base andcase proceeding. On May 2, 2012, the PUC issued a capital structure which includes a 56% common equity capitalization.

Management cannot predict the timing, or the ultimate outcome, of an interim or final D&O, which approved the updated agreement, and on May 4, 2012, the tariffs implementing the D&O became effective. MECO implemented the decoupling mechanism and began tracking the target revenues and actual recorded revenues via a revenue balancing account. MECO 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 this rate case.

annual revenue requirement than the interim increase due to factors that became effective concurrently with the revised tariffs (lower depreciation rates and lower ROACE) and therefore, no refund was required.

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TableMECO’s request is required 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 Contentsmore renewable energy generation. See the discussion below on interim decision and subsequent proposed adjustments to the interim increase.

HELCO.

2006HECO 2011 test year rate case.  In May 2006, HELCO filed a request for a general rate increase of $29.9 million, or 9.24% over the electric rates then in effect, based on a 2006 test year, an 8.65% RORB, an 11.25% ROACE and a $369 million average rate base. HELCO’s request included a proposed new tiered rate structure to reward residential customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase was requested to pay for improvements made to increase reliability, including transmission and distribution lineimprovements and the two generating units at the Keahole power plant (CT-4 and CT-5), and increased O&M expenses.

In March 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement issues in the rate case proceeding. HELCO agreed to write off a portion of CT-4 and CT-5 costs, which resulted in an after-tax charge of approximately $7 million in the first quarter of 2007.

On April 4, 2007,July 22, 2011, the PUC issued an interim D&O in HECO’s 2011 test year rate case, which became effective July 26, 2011, granting HELCOa total annual interim increase of $53.2 million, or 3.1%, or an increase of 7.58%, or $24.6$38.2 million in annual revenues, overor 2.2%, net of the $15 million of revenues at present rates.currently being recovered through the decoupling Revenue Adjustment Mechanism (RAM). The interim increase reflectedis based on, and is substantially the same as, the increase proposed in the settlement of the revenue requirement issues reached between HELCOagreement executed and filed on July 5, 2011 by HECO, the Consumer Advocate and was based on an average rate basethe Department of $357 million (which reflects the write-off of a portion of CT-4 and CT-5 costs) and an RORB of 8.33% (incorporating an ROACE of 10.7%).

On October 28, 2010, the PUC issued a final D&O that confirmed the interim increase of $24.6 million and approved the stipulated rate design, which includes the new tiered rate structure. Decoupling was not addressed in this proceeding nor the final D&O. In November 2010, HELCO filed its revised tariff sheets and rate schedules, which the PUC approved on January 7, 2011 and became effective on January 14, 2011.

On December 17, 2010, Keahole Defense Coalition (KDC) filed a notice of appeal of the final D&O with the Intermediate Court of Appeals. KDC had been granted participant status(the parties in the rate case, limited to issues pertinent to HELCO’s expansion of the Keahole generating station, and proposed a number of disallowances of costs associated with CT-4 and CT-5, but did not propose a total amount of disallowances. The appeal is pending, and management cannot predict the timing, or the ultimate outcome, of this appeal. However, the pendency of the appeal has not affected implementation of the rate increase approved in the final D&O.

2010 test year rate caseproceeding).    On December 9, 2009, HELCO filed a request for a general rate increase of $20.9 million, or 6.0% over the electric rates then in effect, based on a 2010 test year, a 10.75% ROACE and an 8.73% RORB on a $487 million average rate base. The proposed rate increase would cover investments for system upgrade projects, including an 18 MW heat recovery steam generator (ST-7) and two major transmission line upgrades, as well as increasing O&M expenses. HELCO’s proposed RORB and ROACE assume (1) the establishment of a revenue balancing account and a revenue adjustment mechanism, based on the Joint Decoupling Proposal (see “Decoupling proceeding” below), (2) the implementation of the REIP/CEIS, which the PUC has approved in a separate proceeding, and ( 3) a purchased power adjustment clause to recover non-energy PPA costs proposed in the proceeding. If the cost recovery mechanisms are not approved, the test year revenue requirements would be $22.1 million, based on an 8.87% RORB and an 11.0% ROACE.

HELCO’s filing also proposed adoption of inverted tiered rates and an optional residential time-of-use service rate to enable customers to manage their energy usage.

HELCO and the Consumer Advocate executed and filed a settlement agreement on all material issues in this rate case proceeding on September 16, 2010, and filed a Joint Statement of Probable Entitlement (JSPE) on October 5, 2010, both of which are subject to approval by the PUC. If the settlement were to be approved by the PUC, the net interim increase in annual revenues would amount to $4.4 million, or a 1.2% increase. As part of the settlement agreement, HELCO would reset the heat rate used in its ECAC calculation when the interim rates become effective, which would shift $13.9 million of revenues that would have been included in the ECAC revenues to the interim increase and result in a total interim increase of $18.3 million. The agreement included a 10.125% ROACE, an 8.38% RORB, a $465 million average rate base and a capital structure which includes 56% of common equ ity. In the settlement agreement, the parties agreed to accept the

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ROACE authorized in the final D&O for HECO’s 2009 test year rate case (10.0%, reflecting decoupling) as the final ROACE in this rate case.

The difference between the amounts requested in the initial application and the $4.4 million net increase under the settlement relates primarily to changes in expenses since the rate case was filed and changes in the ROACE and RORB.

On November 3, 2010, the PUC issued an interim D&O granting an interim rate increase as set forth in the JSPE, but adjusting recovery for labor costs downward to 2008 levels, reducing medical, dental and vision benefit costs by approximately 50%, deferring the implementation of decoupling for HELCO until the final D&O, and deferring resetting of the heat rate used in HELCO’s ECAC calculation. Since the interim D&O deferred implementation of decoupling, the PUC found that a 10.5% ROACE and an 8.593% RORB (which reflects a capital structure that includes 56% common equity), was reasonable for purposes of the interim D&O.

On January 7, 2011, the PUC approved HELCO’s revised revenue requirements resulting in an interim increase of approximately $6.0 million in annual revenues. The difference between the $4.4 million increase in the JSPE and the $6.0 million increase as a result of the interim D&O relates primarily to an adjustment of $1.5 million to the JSPE interim increase amount to take into account the changes in current effective rates as a result of the final rates from the HELCO 2006 test year rate case issued subsequent to the JSPE. The HELCO 2010 test year interim D&O adjustments to the JSPE for lower expenses were largely offset by the higher allowed ROACE. The interim increase reflectsreflected the new depreciation rates and methods proposed by HELCO and approved by the PUC on a temporary basis which will result in a $4.7separate proceeding, which resulted in a $2 million annualized decrease in depreciation expense effective with interim rates.rates to the end of 2011. The PUC did not approve the portion of the settlement agreement with the Consumer Advocate allowing deferral of certain costs and HECO filed a motion for clarification and/or partial reconsideration of the interim D&O’s findings and conclusions on the deferral of costs.

 

HELCO implementedOn February 24, 2012, the interim rate increasePUC issued an order which: (1) approved the deferral of interisland wind project support costs of up to $5.89 million; (2) denied HECO’s request to defer certain consultant expenses associated with the Enterprise Resource Planning/Enterprise Asset Management (ERP/EAM) system costs, but allowed HECO to include $552,000 in its 2011 test year expenses for such costs; and (3) granted HECO’s request to defer Customer Information System (CIS) project operation and maintenance (O&M) expenses (limited to $2,258,000 per year in 2011 and 2012 under the final rates assettlement agreement) that are to be subject to a regulatory audit of project costs, and allowed HECO to accrue AFUDC on these deferred costs until the completion of the regulatory audit. As a result of the 2006 test year rate case on January 14, 2011.order, HECO reflected in the first quarter of 2012 the deferral of $2.3 million ($1.4 million for the interisland wind project support costs and $0.9 million for CIS project O&M expenses) incurred from July 22, 2011 through December 31, 2011 that were previously expensed and deferred any 2012

 

Management cannot predict56



costs incurred up to the ultimate outcome or timinglimitations stated in the order. For a discussion of a final D&OJanuary 2013 settlement agreement resulting in this rate case.the write off of $40 million of CIS project costs, see “Subsequent event” in Note 3 of HEI’s Consolidated Financial Statements.

 

MECO.

2007 test year rate case.  InOn February 2007, MECO filed a request for a general rate increase of $19.0 million, based on a 2007 test year. In September 2007, MECO proposed an updated lower increase in annual revenues of $18.3 million, or 5.1% over3, 2012, the electric rates then in effect based on an 11.25% ROACE and an 8.98% RORB on a $386 million rate base. MECO’s request included a proposed new tiered rate structure to reward residential customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase would pay for improvements to increase reliability, including two new generating units, and transmission and distribution infrastructure improvements.

In December 2007, MECO and the Consumer Advocateparties reached a settlement agreement on the EOTP Phase 1 project costs, agreeing that, in lieu of a regulatory audit, HECO would write off $9.5 million of gross plant in service EOTP Phase 1 costs and associated adjustments and carrying charges. The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties also agreed to stipulate to an additional annual interim increase of $5 million to be effective March 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously included in rates and offset by other minor adjustments to the revenue requirement issues in this rate case, andinterim increase that became effective on July 26, 2011. On March 29, 2012, the PUC issued an interim D&O based onapproved the settlement agreement, granting MECOand ordered that the regulatory audit for EOTP Phase 1 need not be conducted. A revised tariff to reflect an increase in the interim increase became effective April 2, 2012.

On May 14, 2012, the PUC approved HECO’s requested adjustment of $13.2 million$607,000 (i.e., $552,000 grossed up for revenue taxes) to its interim increase to include the ERP/EAM system evaluation costs in annual revenues, or 3.7%, based on a 10.7% ROACE and an 8.67% RORB on a $383 million rate base. its 2011 test year expenses. Revised rates became effective May 21, 2012.

On July 30, 2010,June 29, 2012, the PUC issued a final D&O in HECO’s 2011 test year proceeding, which finalized approval of the previous interim increases already in effect. It also approved a second stipulated settlement agreement entered into on June 27, 2012 by HECO, the Consumer Advocate and the Department of Defense (parties in the proceeding) to reflect an additional reduction in the test year rate case confirmingincrease of $755,000 to remove parent company non-incentive executive compensation and administrative costs.

On September 1, 2012, the December 2007 interimfinal revised tariffs reflecting the final D&O became effective. Since the final rate increase.increase as a result of the second stipulated supplement to the settlement agreement was lower than the interim increase then currently in effect, HECO refunded to customers, effective September 1, 2012 through September 30, 2012, approximately $0.9 million (which included accrued interest since July 26, 2011).

 

2010MECO 2012 test year rate case.  On September 30, 2009, MECO filed a request for a general rate increase of $28.2 million, or 9.7% over the electric rates then in effect, based on a 2010 test year, a 10.75% ROACE and an 8.57% RORB on a $390 million rate base. The proposed rate increase was requested to cover investments to improve service reliability, including the replacement and upgrade of power plant control systems, installation of a new 150-kW photovoltaic system, replacement and upgrade of underground lines, new or expanded substations to support growth and improve service, and higher O&M expenses due to MECO’s aging infrastructure. MECO’s proposed RORB and ROACE assumed the establishment of a revenue balancing account and a revenue adjustment mechanism, based on the Joint Decoupling Proposal. If the Joint Decoupling Proposal is not approved, the test year revenue requirements would be recalculated using an 11% ROACE and an 8.72% RORB.

On JuneMay 21, 2010, MECO and the Consumer Advocate executed and filed a settlement agreement on all material issues in this rate case proceeding, which agreement is subject to approval by the PUC. On July 27, 2010,2012, the PUC issued an interim D&O granting MECO an increase of $10.3 million in annual revenues, or 3.3% over revenues currently in effect (implemented effective on August 1, 2010). The interim increase was

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based on the settlement agreement, which included a 10.5% ROACE, an 8.43% RORB, a $387 million average rate base and a capital structure which includes 56.9% of common equity. The interim increase also reflected the new depreciation rates and methods proposed by MECO and approved by the PUC on a temporary basis in a separate depreciation proceeding, but did not reflect the implementation of decoupling. In the settlement agreement, the parties agreed to accept the ROACE authorized in the final D&O for HECO’s 2009MECO’s 2012 test year rate case, (10.0%, reflecting decoupling) as the final ROACE in this rate case.

Under the settlement agreement,which became effective June 1, 2012. The D&O authorized MECO agreed to limitreset its target heat rates by fuel type to $3.5 million the amount to be included in rate base2012 test year levels for the investment in plant for a combined heat and power (CHP) system installed at a hotel site in September 2009, resulting in a chargepurpose of calculating the energy cost adjustment clause (ECAC) adjustment factor, which will help to expenseensure MECO’s continuing recovery of approximately $1.3 million inits fuel costs. The interim increase is based on MECO’s updated stipulated agreement with the second quarter of 2010.

Consumer Advocate filed on May 14, 2012. On November 24, 2010,July 20, 2012, MECO and the Consumer Advocate filed a joint motionstipulated supplement to adjust the interim increase, based onstipulated agreement to reduce the final rates approved in the MECO 2007 test year rate case on July 30, 2010. On January 5, 2011, the PUC approved MECO’s request to adjust the 2010 test year interim increase to $8.5revenue requirement by $0.1 million or 2.7% over revenues based on the rates approved in the MECO 2007 test year rate case. The downward adjustment resulted from a shift in recovery from the interim surcharges to the final 2007 base rates, with no net impact on total rates. On January 12, 2011, the adjusted interim rates (2010 test year)administrative and the final rates (2007 test year) became effective.

Management cannot predict the ultimate outcome or the timing of a final D&O in this rate case.

Decoupling proceeding.  In the Energy Agreement, the parties agreed to seek approval from the PUC to implement, beginning with the HECO 2009 test year rate case interim D&O, a decoupling mechanism, similar to that in place for several California utilities, which decouples revenues from KWH sales and provides for revenue adjustments between rate cases. Overall, general rate cases for each utility would be expected to be less frequent than in the utilities’ recent history. The decoupling mechanism would be subject to review at any time by the PUC or upon request of any utility or the Consumer Advocate.

In October 2008, the PUC opened an investigative proceeding to examine implementing a decoupling mechanism for the utilities. In May 2009, the utilities and the Consumer Advocate filed their joint proposal (Joint Decoupling Proposal) for a decoupling mechanism with 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. The RBA mechanism provides for revenue adjustments (increases or decreases) between rate cases to account for the difference between the revenues allowed in the most recent rate case (target revenues) and the revenues actually received by the utility. The RAM provides for changes in revenue requirements between r ate cases for changes in O&M expenses and to allow for the return on and return of plant additions between rate cases (excluding plant additions for projects recovered through the REIP Surcharge. The RAM provides more timely recovery of invested capital and O&M costs because the utilities’ revenue requirements will reflect some portion of the increased costs without the need for a rate proceeding. The earnings sharing mechanism would provide for a reduction of rates between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case.

On August 31, 2010, the PUC issued a Final D&O, which approved the decoupling mechanism proposed in the Joint Decoupling Proposal, subject to certain modifications. Those modifications excluded merit wage increases and cost overruns for major capital projects (capital projects greater than or equal to $2.5 million) from the RAM (with recovery of such increases and overruns to be considered in the utility’s next rate case), required additional information related to capital projects less than $2.5 million, and required the utilities and the Consumer Advocate to jointly file an outreach plan. Implementation of the decoupling mechanism is to occur when rates that reflect a reduced rate of return due to decoupling are approved by the PUC in either an interim or final D&O in the utilities’ pending rate cases.

In the final D&O in HECO’s 2009 test year rate case issued on December 29, 2010, the PUC approved a reduced ROACE due to decoupling and allowed HECO to implement the approved decoupling mechanism and to immediately begin tracking target revenue and recorded adjusted revenue. In January 2011, HECO filed tariffs for final rates for the PUC’s review and approval and requested that the tariffs become effective on March 1, 2011. Upon approval and implementation offinal D&O for this rate case incorporate the adjustment into the final rates,2012 test year revenue requirement.

Clean 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 over time as they become less dependent on costly and price-volatile fossil fuel. The utilities’ clean 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. HECO 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 implementnot count toward the approved decoupling mechanism. Authorizations forRPS after 2014. Through September 2012, HECO achieved an RPS without DSM energy savings of 13.3%, primarily through a comprehensive portfolio of renewable energy power purchase agreements, net energy metering programs and biofuels. The utilities believe they are on track to meet the implementation of decoupling for HELCO and MECO are pending final D&Os or other action by the PUC in their pending rate2015 RPS.

 

63Recent developments in the utilities’ clean energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 3 of HEI’s “Notes to Consolidated Financial Statements”):

·In February 2011, the PUC opened dockets related to MECO’s and HECO’s plans to proceed with competitive bidding processes to acquire up to approximately 50 MW and 300 MW, respectively, of new, renewable firm dispatchable capacity generation resources, with the initial increments expected to come on line in 2015 and 2017, respectively. Due to a

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subsequent lowering of ContentsMECO’s forecasted peaks, the projected capacity need date on the island of Maui has been deferred to 2019 and the capacity requirement has been reduced to 30 MW. Due to a subsequent lowering of HECO’s forecasted sales and peaks, the projected capacity need and the timing will be dependent on the possible retirement of generating units. MECO and HECO plan to file draft Requests for Proposals (RFPs) for future capacity with the PUC in 2013.

·In August 2011, HECO signed a 20-year contract, subject to PUC approval, with Hawaii BioEnergy to supply 10 million gallons per year of biocrude at Kahe Power Plant with initial consumption to begin as early as 2015. In 2011, HECO also signed other contracts, subject to PUC approval, for lesser amounts of biocrude and for biodiesel for testing or operations.

·In September 2011, the PUC denied the utilities’ requested approval of HELCO’s contract with AKP citing the higher cost of the biofuel over the cost of petroleum diesel. In August 2012, HELCO signed a new 20-year contract with Aina Koa Pono-Ka’u LLC (AKP), subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption to begin within five years of PUC approval.

cases. Per·In May 2012, the decoupling D&O,PUC approved a 3-year biodiesel supply contract with Renewable Energy Group through July 2015 for continued biodiesel supply to CT-1 of 3 million to 7 million gallons per year.

·In May 2012, HECO signed a contract, which was approved by the utilities will file staggered rate cases every three years,PUC, with the first being HECO’sCity and County of Honolulu to purchase an additional 27 MW of capacity and energy from an expanded waste-to-energy HPower facility.

·In May 2012, HELCO signed a power purchase agreement, subject to PUC approval, 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 August 2012, the battery facility at a 30 MW Kahuku wind farm experienced a fire and HECO has not purchased wind energy from the wind farm since then.

·In August 2012, the PUC approved a waiver from the competitive bidding process to allow HECO to negotiate with the U.S. Department of the Army for construction of a 50 MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu.

·In September 2012, HECO 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 MECO under a 20-year contract.

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

·HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of December 31, 2012, there were 5,963 kW, 787 kW and 1,658 kW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.

·As of December 31, 2012, there were 83,610 kW, 20,275 kW and 23,554 kW of installed net energy metering capacity from renewable energy technologies (mainly PV) at HECO, HELCO and MECO, respectively. Net energy metering is proceeding at a record pace. The amount of net energy metering capacity installed in 2012 was more than twice the amount installed in 2011, test year filed in July 2010.which itself was at a record level.

 

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

 

Demand-side management programs.

Energy Efficiency Demand-side Management Programs.  In February 2007, the PUC required that the administration of all Energy Efficiency (EE) DSM programs be turned over to a non-utility, third-party administrator. The PUC executed a public benefits fund (PBF) administrator contract with Science Applications International Corporation (SAIC) and on July 1, 2009, SAIC began administering the EE DSM programs. A PBF surcharge on electric utility revenues (1% in 2010, 1.5% in 2011 and 2012 and 2% thereafter) is being used to fund EE DSM programs, incentives, program administration, and other related program costs.

The PUC continues to permit recovery of reasonably-incurred DSM implementation costs (within approved budgets), under the integrated resource plan framework. Through 2009, the PUC also provided for DSM utility incentives derived from a graduated performance-based schedule of net system benefits. In order to qualify for an incentive, the utility must have met cumulative MW and MWh reduction goals for its EE DSM programs in the commercial, industrial and residential sectors. The amount of the annual incentive has been subject to caps determined separately for each utility. The DSM utility incentive mechanism ended once the energy efficiency programs were transferred to the PBF administrator in July 2009.

HECO and MECO earned their maximum DSM utility incentives of $4 million and $0.3 million, respectively, in 2008. In a December 30, 2010 order, the PUC denied HECO’s request to increase its 2009 energy efficiency program budgets and the utilities’ request to reallocate a portion of the unspent funding between DSM programs to cover actual expenditures in 2009. Because the utilities were not able reallocate the unspent funding between programs and thus recover the entire amount of 2009 DSM program expenditures, the utilities recorded an expense of $1.3 million in December 2010. In addition, the PUC advised that the utilities cannot include any of the energy savings from the program applications that exceeded their budgets in the calculations of DSM utility incentives. Based on the order, HECO calculated revised 2009 DSM incentives of $0.6 million and has submitted th em for PUC review and approval.

Load Management DSM Programs.  Unlike the EE DSM programs, load management DSM programs continue to be administered by the utilities. HECO’s residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters or central air conditioning systems from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow to be controlled or interrupted by HECO. This program includes a small business direct load control element.

In December 2009, the PUC approved HECO’s requests to extend the Commercial and Industrial Direct Load Control (CIDLC) Program and the Residential Direct Load Control (RDLC) Program through 2012. The CIDLC Program application included an action plan for a load aggregator pilot program.

In October 2010, HECO filed an RDLC Program increase request to accommodate anticipated base expenses for the cost of a program impact evaluation needed to update the cost-effectiveness calculations identified by the PUC. In November 2010, HECO filed its 2011 CIDLC and RDLC Program budgets approval request. The PUC suspended both requests in order to gather additional information to further evaluate the requests.

In August 2010, HECO filed an application for a Fast Demand Response Pilot (Fast DR) Program—a two-year pilot program designed to test commercial and industrial market acceptance of load reductions within 10-minutes of event notification, and demonstrate the technical aspects of semi-automatic and automatic mechanisms to initiate customer reductions in load. The procedural steps in the docket will be completed in February 2011, after which the PUC can make a decision.

Renewable Energy Infrastructure Program.  The Renewable Energy Infrastructure Program (REIP) proposed by HECO in December 2007 consisted of two components: (1) renewable energy infrastructure

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projects that facilitate third-party development of renewable energy resources, maintain existing renewable energy resources and/or enhance energy choices for customers, and (2) the creation and implementation of a temporary renewable energy infrastructure surcharge to recover the capital costs, deferred costs for software development and licenses, and/or other relevant costs approved by the PUC. These costs would be removed from the surcharge and included in base rates in the utility’s next rate case. In December 2009, the PUC issued a D&O approving HECO’s proposed REIP, including the REIP surcharge, subject to certain conditions specified in the D&O. The PUC may review the benefits and continued need for the REIP every three years or earlier if necessary.

The PUC approved the use of the REIP surcharge to recover certain interconnection costs for a wind project. In July 2010, the utilities submitted (as directed by the PUC) proposed Standards and Guidelines for Utility Funding of Renewable Infrastructure Projects Associated with Independent Power Producers.

Delinking energy payment rates from oil costs.   On April 18, 2008, the PUC initiated a docket to examine the methodology for calculating Schedule Q electricity payment rates in the State of Hawaii. In general, Schedule Q rates are available to customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the electric utility. The proceeding was intended to examine new methodologies for calculating Schedule Q payment rates, with the intent of removing or reducing a ny linkages between the price of fossil fuels and the rate for non-fossil fuel generated electricity. The parties to the Energy Agreement agreed that all new renewable energy contracts are to be delinked from fossil fuel and that the utilities would seek to renegotiate existing PPAs with IPPs that are based on fossil fuel prices to delink their energy payment rates from oil costs. In December 2010, HECO, HELCO and MECO filed updated avoided energy costs rates and Schedule Q rates to be effective for 2011, subject to monthly adjustment of the fuel component of the rates for changes in fuel prices. A Stipulated Procedural Schedule for the Schedule Q proceeding, which calls for the filing of final statements of position in April 2012, was approved by the PUC in January 2011.

Clean energy scenario planning, integrated resource planning and requirements for additional generating capacity.  The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop integrated resource plans (IRPs),which would then be approved, rejected or modified by the PUC. The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost.

Under the PUC’s IRP framework, the utilities were entitled to recover all appropriate and reasonable integrated resource planning costs either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities were able to recover their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery in the docket for each year’s costs. HELCO (since February 2001), HECO (since September 2005) and MECO (since December 2007) recover IRP costs through base rates. Previously, HECO, HELCO and MECO recovered their costs through a surcharge. The Consumer Advocate had objected to recovery of $1.2 million (before interest) of the $4.0 million of incremental IRP costs incurred by the utilities d uring 2002-2007. In January 2011, the PUC issued a D&O that allowed the utilities to recover their 2002-2007 IRP planning costs, but disallowed certain costs, primarily costs incurred during a rate case test year. The utilities will be refunding to customers approximately $1.2 million (representing disallowed costs previously recovered through a surcharge and interest) to its customers in February 2011. The utilities had been reserving for a potential refund for portions of the cost previously recovered and related interest, based on final D&Os related to 1995-2001 IRP planning costs. In December 2010, the utilities recorded additional charges of $0.8 million to fully accrue for this refund.

The parties to the Energy Agreement agreed to seek to replace the IRP process with a new Clean Energy Scenario Planning (CESP) process intended to be used to determine future investments in generation and transmission that will be necessary to facilitate high levels of renewable energy production and reductions in electricity use through energy efficiency programs. In the fourth quarter of 2008, the PUC closed the IRP-4

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processes and directed the utilities to suspend all activities pursuant to the IRP framework to allow for resources to be diverted to the development of the CESP framework.

HECO and the Consumer Advocate filed a proposed CESP framework with the PUC in April 2009. In May 2009, the PUC opened an investigative proceeding to examine the proposed framework. As consensus between all parties and participants in the proceeding could not be reached, four revised proposed frameworks were separately filed by various parties and participants in August 2010 for the PUC’s consideration. The CESP framework filed jointly by HECO and its subsidiaries, the Consumer Advocate, Kauai Island Utility Cooperative and the County of Kauai proposes a planning process resulting in a 5-year Action Plan developed from multiple scenarios and associated 20-year resource plans for each scenario. The proposed focus on scenario planning and shorter-term action plans (rather than 20-year plans) recognizes that planning assumptions are uncertain and that the planning framework sh ould facilitate making adjustments to resource plans as circumstances change. PUC adoption of a CESP framework is pending.

 

Adequacy of supply.

 

HECO.  In February 2011,March 2012, HECO filed its 20112012 Adequacy of Supply (AOS) letter, which indicated that based on its May 20102011 sales and peak forecast, HECO’s generation capacity for 20112012 to 20152016 is sufficiently largesufficient to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. HECO anticipatesThe letter reported that, it will acquire 8 MW from a distributed standby generation facility to be located at the Honolulu International Airport and 27 MW from an expansion of the existing H-Power waste-to-energy facility located at Campbell Industrial Park within the next two years. Beginningbeginning in 2016,2018, HECO anticipates that based on expected increasing demand it will begin experiencing reserve capacity shortfalls if no more firm generating capacity is added to the system. Also, four existing g eneratingsystem and two generating units are retired at the end of 2017. These two generating units may be retired within the next 10 years. Waiau Units 3 and 4 are being considered for retirement because of their age. Honolulu Units 8 and 9 may need to be retired because ofage or more stringent environmental regulations. Also, two additional generating units may be retired in the 2020 timeframe. At the time of the filing, HECO estimatesestimated it willwould need approximately 300 MW of new, firm generating capacity to replace the capacity that would be lost with the retirement of these four units and to accommodate load growth. Subsequently, HECO plansdeveloped its May 2012 Sales and Peak Forecast, which was lower than its May 2011 sales and peak forecast. With this lower forecast, HECO expects the amount of new capacity needed to solicit proposals in 2011 for firm renewablerange from 150 MW to 200 MW and the timing to be dependent on the possible retirement of generating capacity.units.

 

HELCO.  In January 2011,2013, HELCO filed its 20112013 AOS letter, which indicated that HELCO’s generation capacity through 20132016 is sufficiently large to meet all reasonably expected demands for service and provide for reasonable reserves for emergencies. In March 2012, HELCO is currently negotiatingadded 8 MW of renewable capacity from Puna Geothermal Venture. In May 2012, HELCO executed a contract with two IPPsan independent power producer to supply additional firm renewable generating capacity to the HELCO grid. Should thesethis additional firm renewable facilitiesfacility come on line within the next threetwo years as anticipated, HELCO will not have a need for additional firm capacity in the foreseeable future. HELCO, however, may choose to add additional renewable generating capacity to replace existing nonrenewable generation. In January 2013, HELCO filed with the PUC a Proposed Final Geothermal RFP seeking up to 50 MW of firm, dispatchable geothermal capacity.

 

MECO.  In January 2011,2013, MECO filed its 20112013 AOS letter, which indicated that MECO’s generation capacity through 20142015 is sufficient to meet the forecasted demands on the islands of Maui, Lanai, and Molokai, butand also stated that additional increments ofMECO expects to have adequate firm capacity will be neededfor the period through 2018 and anticipates needing additional firm capacity on Maui in 2015 and 2018 should a major IPP cease providing capacity and energy to MECO after December 31, 2014. Also, in January 2011, MECO filed a request to open a new docket related tothe 2019 timeframe. MECO’s planactivities, such as its plans to proceed with a competitive bidding process to acquire up to approximately 50 MW of new, renewable firm dispatchable capacity generation resources on the island of Maui with the initial increment expected to comewill be based on line in the 2015 timeframe.

December 2008 outage.  On December 26, 2008, an island-wide outage occurred on the island of Oahu during a severe lightning storm that resulted in a loss of electric service to HECO customers ranging from approximately 7 to 20 hours. On January 12, 2009, the PUC initiated an investigation of the outage.

In March 2009, HECO submitted an outage report prepared by its expert consultant, which concluded that the island-wide outage was triggered by lightning strikes and found that: (1) the HECO system was in proper operating condition and was appropriately staffed at the time of the lightning storm, and (2) HECO’s restoration efforts were prudent and allowed for restoration of power as quickly as possible under the circumstances.

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In January 2010, the Consumer Advocate submitted its Statement of Position that HECO could not have anticipated or prevented the outage through reasonable measures and could not have reasonably shortened the outage and restored power more quickly to customers. The Consumer Advocate further stated that penalties should not be assessed for the outage, but recommended that numerous studies be performed with the objective of preventing or minimizing the scope and duration of future power outages.

Management cannot at this time predict the outcome of the PUC’s investigation of the 2008 outage or its impact on HECO.

Intra-governmental wheeling of electricity.  In June 2007, the PUC initiated a docket to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii. The PUC subsequently suspended this docket, but reinstated it in November 2010. In January 2011, the PUC adopted the procedural schedule proposed by the Parties and Participants, which includes a panel hearing around the fourth quarter of 2012.2019 estimated need date.

 

Collective bargaining agreements.  See “Collective bargaining agreements” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

 

Legislation and regulation.  Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. Also see “Hawaii Clean Energy Initiative” and “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements” and “Major“Recent tax legislation in 2010”developments” above.

Increase in oil tax.  On July 1, 2010, the state tax on petroleum products shipped to Hawaii increased from $0.05 to $1.05 per barrel. The higher tax, which is passed on to consumers, increased the price of gasoline and electricity and is expected to generate funds to reduce the state’s budget deficit and support local food production and renewable energy programs.

 

Renewable energy.  In 2007, a Hawaii law was enacted that stated 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 were more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source.

 

In 2008, a Hawaii law was enacted to promote and encourage the use of solar thermal energy. This measure requires the installation of solar thermal water heaters in residences constructed after January 1, 2010, but allows for limited variances in cases where installation of solar water heating is deemed inappropriate. The measure establishes standards for quality and performance of such systems. Also in 2008, a Hawaii law was enacted that is intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects. The Energy Agreement includes several undertakings by the utilities to integrate solar energy into the electric grid.

 

In 2009, a bill became Hawaii law (Act 185) that authorizes preferential rates to agricultural energy producers selling electricity to utilities. This will help support the long-term development of locally grown biofuel crops, cultivating potential local renewable fuel sources for the utilities. In addition, pursuant to Act 50 (also adopted in 2009), avoided cost is no longer a consideration in determining a just and reasonable rate for non-fossil fuel generated electricity. This will allow the utilities to negotiate purchased power prices for

59



renewable energy that have the potential to be more stable and less costly than current pricing tied to avoided cost.

 

Biofuels.In 2007, a Hawaii law was enacted with the stated purpose of encouraging further production and use of biofuels in Hawaii. It established that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and established a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).

In 2008,2011, a Hawaii law was enacted that encouragesgives the developmentPUC the authority to allow those electric utilities that aggregate their renewable portfolios to achieve the RPS (e.g., HECO, HELCO and MECO) to distribute the costs and expenses of biofuels by authorizingrenewable energy projects among those utilities. The bill also allows the Hawaii BoardPUC 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 Land and Natural Resources to lease public lands to growers or producers of plant and animal material used for the production of biofuels.

The utilities have agreedcustomer-sited, grid-connected renewable energy generation in the Energy Agreement to testRPS calculations after 2015. This is the use of biofuelscurrent practice in their generating units and, if economically feasible, to connect them to the use of biofuels. For its part, the State agrees to supportcalculating RPS levels, which provides electric utility ratepayers with a clear value from a program such as net energy metering.

 

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this testing and conversion by expediting all necessary approvals and permitting. The Energy Agreement recognizes that, if such conversion is possible, HECO’s requirements for biofuels would encourage the development of a local biofuels industry. HECO and MECO have received PUC approval to enter into and recover the costs of biodiesel fuel contracts under which they are purchasing biofuels to operate HECO’s CIP CT-1 and to test their use in other HECO and MECO generating units. HELCO has entered into a 20-year contract, subject to PUC approval, to purchase 16 million gallons of biodiesel per year beginning in 2015.

 

For additional discussion of environmental legislation and regulations, see “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” At this time, it is not possible to predict with certainty the impact of the foregoing legislation or legislation that is, or may in the future be, proposed.

Other developments.

Advanced Metering Infrastructure.  In December 2008, the utilities filed an Advanced Metering Infrastructure (AMI) project application with the PUC for approval of (1) implementation of an AMI project, covering approximately 451,000 meters (65% on Oahu, 20% on the island of Hawaii and 15% on Maui), and (2) a contract between Sensus Metering Systems, Inc. (Sensus) and HECO under which the utilities would purchase smart meters and pay Sensus to provide and maintain a radio frequency communication system to operate the smart meters and related equipment.

HECO submitted a proposal to the PUC in May 2010, describing an extended pilot test of the AMI system and smart meters involving 5,000 new Sensus AMI meters. HECO’s proposal also contained an update on developments in the Smart Grid, Customer Information System (CIS) and cyber-security areas.

On July 26, 2010, the PUC issued an Order denying the utilities’ request to defer certain costs for an extended pilot test of their AMI system and smart meters on Oahu, and dismissing the utilities’ AMI application, but without prejudice to the filing of a new application. In its Order, the PUC reiterated its support for an AMI and smart grid concept to reduce the state’s dependence on fossil fuels, but noted that future AMI and smart grid applications should include or be preceded by an overall smart grid plan or proposal filed with the PUC. As of December 31, 2010, the utilities did not have any deferred costs related to the AMI project proceeding.

The utilities, like the PUC and Consumer Advocate, continue to support a broad range of smart grid initiatives, including AMI, as important components of a clean energy strategy and are assessing, testing and deploying various smart grid technologies on its systems. HECO is actively working with Sensus on further testing of its AMI and broader smart grid capabilities. The cost of this testing will be expensed. HECO and Sensus have agreed that their respective rights to terminate their contract (based on the lack of PUC application approval) shall extend until March 31, 2011.

 

Commitments and contingencies.  See “Commitments and contingencies” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

 

Recent accounting pronouncements.  See “Recent accounting pronouncements and interpretations” in Note 1 of HEI’s “Notes to Consolidated Financial Statements.”

 

Liquidity and capital resources.  Management believes that HECO’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.

 

HECO’s consolidated capital structure was as follows as of the dates indicated:follows:

 

December 31

 

2010

 

2009

 

 

2012

 

2011

(dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term borrowings

 

$

 

%

$

 

%

 

$        

 

–%

 

$        

 

–%

Long-term debt, net

 

1,058

 

44

 

1,058

 

44

 

 

1,148

 

43

 

1,058

 

43

Preferred stock

 

34

 

1

 

34

 

1

 

 

34

 

1

 

34

 

1

Common stock equity

 

1,338

 

55

 

1,306

 

55

 

 

1,472

 

56

 

1,403

 

56

 

$

2,430

 

100

%

$

2,398

 

100

%

 

$2,654

 

100%

 

$2,495

 

100%

 

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Information about HECO’s short-term borrowings (other than from HELCO and MECO), HECO’s and line of credit facility and the principal amount of special purpose revenue bonds that have been authorized by the Hawaii legislature for future issuance by the DBF for the benefit of the utilities were as follows for the period and as of the dates indicated:follows:

 

 

 

Year ended
December 31, 2010

 

(in millions) 

 

Average
balance

 

End-of-period
balance

 

December 31,
2009

 

Short-term borrowings(1)

 

 

 

 

 

 

 

Commercial paper

 

$

4

 

$

 

$

 

Line of credit draws

 

 

 

 

Borrowings from HEI

 

 

 

 

Line of credit facilities

 

 

 

 

 

 

 

Undrawn capacity under line of credit facility expiring May 7, 2013

 

N/A

 

175

 

175

 

Special purpose revenue bonds authorized for issue

 

 

 

 

 

 

 

2005 legislative authorization (expired June 30, 2010)-HELCO

 

 

 

$

 

$

20

 

2007 legislative authorization (expiring June 30, 2012)

 

 

 

 

 

 

 

HECO

 

 

 

170

 

170

 

HELCO

 

 

 

55

 

55

 

MECO

 

 

 

25

 

25

 

Total special purpose revenue bonds available for issue

 

 

 

$

250

 

$

270

 

 

Year ended
December 31, 2012

 

 

(in millions)

 

Average
balance

 

End-of-period
balance

 

 

December 31,
2012

Short-term borrowings1

 

 

 

 

 

 

 

Commercial paper

 

$   41

 

$   –

 

 

$   –

Line of credit draws

 

 

 

 

Borrowings from HEI

 

 

 

 

Undrawn capacity under line of credit facility (expiring December 5, 2016)

 

 

 

175

 

 

175

 


(1)1       The maximum amount of external short-term borrowings in 20102012 was $19$124 million. At December 31, 2010,2012, HECO had $31 million and $30$18 million of short-term borrowings from HELCO and MECO respectively,had $9 million of short-term borrowings from HECO, which borrowings are eliminated in consolidation. At February 10, 2011,7, 2013, HECO had no$50 million of outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $31 million and $21$12 million from HELCO and MECO, respectively.a loan of $15 million to MECO.

 

HECO utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. HECO also borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the consolidation of HECO’s financial statements. HECO and its subsidiaries periodically utilize long-term debt, historically borrowings of the proceeds of special purpose revenue bondsSPRBs issued by the StateDBF and more recently the issuance of Hawaii Department of Budget and Finance (DBF),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 HECO, HELCO and MECO.

 

Due to market conditions since September 2008 (which resulted in a tightening of the commercial paper market, higher commercial paper rates and limitations on maturity options) and as a result of an S&P downgrade of HECO’s short-term borrowing rating to A-3 from A-2, HECO drew on its previous $175 million syndicated line of credit facility in June and July 2009, rather than issue commercial paper. All such draws/borrowings were repaid in August 2009. HECO re-entered the commercial paper market in March 2010, experiencing higher rates and shorter terms.

Effective May 7, 2010, HECO entered into a revolving noncollateralized credit agreement establishinghas a line of credit facility of $175 million, with a letter of credit sub-facility, with a syndicate of eight financial institutions.million. See Note 7 of HEI’s “Notes to 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 HECO’s Issuer Ratinglong-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 102.5 basis points and an interest rate decrease of 25 basis points on any drawn amounts. The agreement contains customary conditions that must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrow ings from, HECO, and restricting its ability as well as the ability of any of

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its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (actual ratio of 43% for HELCO and 43% for MECO as of December 31, 2010, as calculated under the agreement)). In addition to customary defaults, HECO’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 HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (actual ratio of 55% as of December 31, 2010, as calculated under the agreement).

 

In addition to their impact on pricing under HECO’s credit agreement, the ratings of HECO’s commercial paper and debt securities could significantly impact the ability of HECO 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 HECO securities. On July 30, 2010,August 1, 2012, Moody’s changed HECO’s rating outlook to stable from negative and affirmedmaintained HECO’s long-term and short-term (commercial paper) ratings and stable outlook, indicating that the ratings affirmation and outlook change reflectedfactor in the progress being made to transformanticipated cash flow stability of this vertically integrated utility, the long-term benefits of a more predictable regulatory framework for the utilities tobeing introduced, and a decoupling structure that will reduce sales volume risk and produce more timely recovery of invested capital and O&M costs.conservative financial management. Moody’s indicated the rating could be downgraded if the Hawaii PUC does not follow through with the regulatory transformation contemplated under the HCEI, including all elements of the decoupling mechanism or if the utilities’ cash flow to debt declined to below 17% on a sustainable basis(17.8% last twelve months as of March 31, 2012 – latest reported by Moody’s) and its cash flow coverage of interest fell below 3.5 times.times (4.8 times last twelve months as of March 31, 2012 – latest reported by Moody’s) for an extended period. On November 15, 2010,29, 2012, S&P issued an update in which it loweredmaintained its long-term ratings for HECO, HELCO and MECO toof “BBB-” from “BBB,” and indicated the outlook as “stable.”stable outlook. In addition, S&P affirmedmaintained its “A-3” short-term rating and “aggressive” financial risk and “strong” business risk profiles on HECO and revisedHECO. S&P indicated that although decoupling can benefit HECO’s financial profile to “aggressive” from “significant.” S&P indicatedover time, the rating downgrade reflects an “aggressive&# 148; financial profile combined with weak cash flow generation at HEI’s electric utilities, delays in implementing new utility rate recovery mechanisms, the growing risks of regulatory disallowancescompany will also need constructive outcomes in future rate cases, and a protracted recession.case filings. Also, HECO needs resolution of the pending regulatory audits for previous capital spending for which the costs are currently deferred.

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As of February 10, 2011,7, 2013, the S&P and Moody’s ratings of HECO securities were as follows:

 

S&P

S&P

Moody’s

 

Commercial paper

A-3

P-2

 

Special purpose revenue bonds-insured
(principal amount noted in parentheses, senior unsecured, insured as follows):

 

 

 

Ambac Assurance Corporation ($0.2 billion)

11.4 million)

BBB-

*

Baa1

*

Financial Guaranty Insurance Company ($0.3 billion)

BBB-

*

Baa1

*

MBIA Insurance Corporation ($0.30.1 billion)

BBB

*BBB**

Baa1

**

Syncora Guarantee Inc. (formerly XL Capital Assurance Inc.) ($0.1 billion)

BBB-

*

Baa1

*

Special purpose revenue bonds uninsured ($150 million)

BBB-

Baa1

 

HECO-obligated preferred securities of trust subsidiary

BB

Baa2

 

Cumulative preferred stock (selected series)

Not rated

Baa3

 

 

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.

 


*           Rating corresponds to HECO’s rating (senior unsecured debt rating by S&P or issuer rating by Moody’s) because, as a result of rating agency actions to lower or withdraw the ratings of these bond insurers after the bonds were issued, HECO’s current ratings are either higher than the current rating of the applicable bond insurer or the bond insurer is not rated.

 

**          Following MBIA Insurance Corporation’s (MBIA’s) announced restructuring in February 2009, the revenue bonds issued for the benefit of HECO and its subsidiaries and insured by MBIA have been reinsured by MBIA Insurance Corp. of Illinois (MBIA Illinois), whose name was subsequently changed to National Public Finance Guarantee Corp. (National). The financial strength rating of National by S&P is BBB. Moody’s ratings on securities that are guaranteed or “wrapped” by a financial guarantor are generally maintained at a level equal to the higher of the rating of the guarantor (if rated at the investment grade level) or the published underlying rating. The insurance financial strength rating of National by Moody’s is Baa1,Baa2, which is the same aslower than Moody’s issuer rating for HECO.

 

Management believes that, if HECO’s commercial paper ratings were to be further downgraded or if credit markets were to further tighten, it wouldcould be even more difficult andand/or expensive to sell commercial paper or secure other short-term borrowings. Similarly, management believes that if HECO’s long-term credit ratings

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were to be further downgraded, or if credit markets further tighten, it could be even more difficult and/or expensive for DBF and/or the Company to sell special purpose revenue bondsSPRBs 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, and financial condition and liquidity of HECO and its subsidiaries.

 

The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO. Revenue bonds are issued by the DBF to finance capital improvement projects of HECO and its subsidiaries, but the source of their repayment is the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the DBF, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on SPRBs currently outstanding and issued prior to 2009 are insured either by one of the following bond insurers: Ambac Assurance Corporation,Corporation; Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012 (in September 2012, a proposed Plan of Rehabilitation was filed); MBIA (which bonds have been reinsured by National Public Finance Guarantee Corp.); or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The insured outstanding revenue bonds were initially issued with S&P and Moody’s ratings of AAA and Aaa, re spectively,respectively, based on the ratings at the time of issuance of the applicable bond insurer. Beginning in 2008, however, ratings of the insurers (or their predecessors) were downgraded and/or withdrawn by S&P and Moody’s, resulting in a downgrade of the bond ratings of all of the bonds as shown in the ratings table above. The $150 million of SPRBs sold by the DBF for the benefit of HECO and HELCO on July 30, 2009, were sold without bond insurance. Management believes that if HECO’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be even more difficult and/or expensive to sell bonds in the future.

 

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

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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 HECO, HELCO and MECO during the period 2013 through 2015, subject to certain conditions. New long-term debt authorizations of $150 million (HECO $100 million, HELCO $25 million and MECO $25 million) can be requested under the expedited approval procedure through 2015.

In January 2013, HECO, HELCO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $90 million, $56 million and $20 million, respectively, of unsecured obligations bearing taxable interest to refinance select series of outstanding revenue bonds.

In February 2013, HECO and MECO filed with the PUC a letter request for the expedited authorization to issue prior to January 1, 2014 up to $50 million and $20 million, respectively, of unsecured obligations bearing taxable interest. The proceeds are expected to be used to fund capital expenditures, including repaying short-term indebtedness incurred to fund capital expenditures.

On April 19, 2012, HECO, HELCO and MECO issued through a private placement taxable unsecured senior notes of various maturities (the HECO Notes, HELCO Notes and MECO Notes, and together, the April Notes) in the aggregate principal amounts of $327 million, $31 million and $59 million, respectively, with stated interest rates ranging from 3.79% to 5.39%. Proceeds of $267 million of the April Notes, together with additional funds, were used to redeem an aggregate principal amount of $271 million of bonds (with stated interest rates ranging from 5.45% to 6.20%). The $150 million of proceeds of the remaining HECO Notes, bearing interest at 5.39%, were used to finance or refinance capital expenditures.

On September 13, 2012, HECO issued another series of taxable unsecured senior notes through a private placement (the HECO September Notes) in the aggregate principal amount of $40 million with a stated interest rate of 4.53%. Proceeds of the HECO September Notes, together with additional funds, were used to redeem the $40 million aggregate principal amount 5.10% Series 2002A SPRBs. See Note 8 of HEI’s “Notes to Consolidated Financial Statements.”

 

Operating activities provided $248$177 million in net cash during 2010.2012. Investing activities used net cash of $150$264 million, primarily for capital expenditures, net of contributions in aid of construction. Financing activities usedprovided net cash of $48$55 million forfrom net increase in long-term debt of $89 million and net proceeds from issuance of common stock of $44 million, partly offset by the payment of common and preferred stock dividends of $51 million, partly offset by $4 million net proceeds from issuance of common stock.$75 million.

 

For the five-year period 20112013 through 2015,2017, the utilities forecast $2.2$2.9 billion of grossnet capital expenditures, approximately 44%48% of which is for transmission and distribution projects, and 45%10% for generation projects with the remaining 11%and 7% for general plant and other projects. These estimates do not include expenditures,projects, with the remaining 35% anticipated for major initiatives (including environmental compliance and infrastructure investments for fuel and to integrate renewables into the system), which could be material, related to significant renewable energy infrastructure projects orchange over time based upon external factors such as the timing and scope of environmental compliance requirements not currently contemplatedregulations, unforeseen delays in permitting and the outcome of competitive bidding for that period. The electric utilities’ net capital expenditures (which exclude AFUDC and capital expenditures funded by third-party contributions in aid of construction) for 2011 through 2015 are currently estimated to total approximately $2.0 billion.new generation. HECO’s consolidated cash flows from operating activities (net income for common stock, adjusted for non-cash income and expense ite msitems 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 as well as to refinance maturing revenue bonds ($57.5 million in 2012 and $11.411.4 million in 2014) and to fund any unanticipated expenditures not included in the 20112013 through 20152017 forecast, such as increases in the costs or acceleration of the construction of capital projects, capital expenditures that may be required by new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses and significant increases in retirement benefit funding requirements and higher tax payments that would result if tax positions taken by the utilities do not prevail.requirements.

 

Proceeds from the issuances of debt and equity, cash flows from operating activities, temporary increases in short-term borrowings and existing cash and cash equivalents are expected to provide the forecast $260forecasted $380 million needed for the net capital expenditures in 2011.2013. For 2011, gross2013, net capital expenditures are estimated to be $300 million, includinginclude approximately $176$240 million for transmission and distribution projects, approximately $90 million for generation projects and approximately $34$50 million for general plant and other projects.

 

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projects. Consolidated net capital expenditures for HECO and subsidiaries for 2010, 2009 and 2008 were $173 million, $288 million and $257 million, respectively.

 

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 9 of HEI’s “Notes to Consolidated Financial Statements” and “Retirement benefits” above. The electric utilities were required to make contributions of $19.1$53 million for 2010, but not required to make any contributions2012, $71 million for 20092011 and 2008$19 million for 2010 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 2010, 20092012, 2011 and 2008.2010. Contributions by the electric utilities to the retirement benefit plans for 2012, 2011 and 2010 2009 and 2008 totaled $31$63 million, $24$73 million and $14$31 million, respectively, and are expected to total $63$84 million in 2011.2013. In addition, the electric utilities paid directly $1 million of benefits in 2012, $1 million of benefits in 2011 and $2 million of benefits in 2010 less thanand expect to $1 million of benefits in each of 2009 and 2008 and expect to pay less than $2 million of benefits in 2011.2013. 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.

 

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.  HECO, for itself and its subsidiaries, entered into the Energy Agreement on October 20, 2008. See “Hawaii Clean Energy Initiative” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.”

 

The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, and implementation of a new regulatory model which will decouple revenues from sales, present new increased 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 infra structureinfrastructure 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 materially impact the financial condition and cash flowsliquidity 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, decoupling revenues from sales; implementing feed-in tariffs to encourage development of renewable energy; 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 cash flowsliquidity of the electric utilities.

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Regulation of electric utility ratesThe 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 financial condition, results of operations, financial condition and cash flows.liquidity. The PUC has broad discretion over the rates the electric

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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 affecteffect on the Company’s and HECO’s consolidated results of operations, financial condition and cash flows.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. Interim&O and interim rate increas esincreases are subject to refund with interest pendingif the interim increase is greater than the increase approved in the final outcome of the case. Through December 31, 2010, HECO and its subsidiaries had recognized $4 million of revenues with respect to interim orders.

Management cannot predict when the final D&Os in pending or future rate cases will be rendered or the amount of any interim or final rate increase that may be granted. Further, the increasing levels of O&M expenses (including increased retirement benefit costs), increased plant-in-service, and other factors have and are likely to continue to result in the electric utilities seeking rate relief more often than in the past.&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 HEI’s “Notes to Consolidated Financial Statements.” The Company estimates that 75%73% of the net energy generated and purchased by HECO and its subsidiaries in 20112013 will be generated from the burning of fossil fuel oil. Purchased KWHs provided approximately 40.2%40% of the total net energy generated and purchased in 2010 compared to 40.2% in 20092012, 2011 and 40.4% in 2008.2010.

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. HECO generally maintains an average system fuel inventory level equivalent to 3547 days of forward consumption. HELCO and MECO 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 electric 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 a greements.agreements.

 

Other operation and maintenance expenses.  Other O&M expenses increased 6%, 3%4% in 2012, was essentially flat in 2011 and 8% forincreased 6% in 2010, 2009 and 2008, respectively, when compared to the prior year (12%(4%, 7%0% and 5%12% respectively, excluding DSM program expense)expenses). This trend of increased O&M expenses is expected(excluding expenses covered by surcharges or by third parties) for 2013 are projected to continue in 2011be approximately 1% higher than 2012 as the electric utilities expect higher productionto manage expenses (primarily to maintain and improve the efficiency of the production units), and higher costs for material and contract services. Transmission and distribution expenses are also expected to increase consistent with the new asset management initiatives to modernize the infrastructure. The timing and amount of these expenses can vary as circumstances change. For example, recent overhauls have been more expensive than in the past due to the larger scope of work necessary to maintain aging equipment, which has experienced heavier usage as demand has increased to currentnear-2012 levels. Also, the cost of overhauls can be higher than originally planned after full assessments of the repair work are performed. In addition, the costs of environmental compliance continue to increase with more stringent regulatory requirements. Increased O&M expenses were among the reasons HECO, HELCO and MECO filed requests with the PUC in recent years to increase base rates. The successful implementation of decoupling mechanisms may partially and more promptly mitigate the negative net income impact of rising other O&M expenses.

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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. TwoFor example, two major capital improvement utility projects, the Keahole project (consisting of CT-

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4,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 write-downwritedown being required for both the Keahole project.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 HEI’s “Notes to Consolidated Financial Statements” for a discussion of additional regulatory contingencies.

 

Competition.  Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration.

In October 2003, the The PUC opened investigative proceedings on two specific issues (competitive bidding and DG) to move towardhas promoted a more competitive electric industry environment under cost-based regulation.through its decisions concerning competitive bidding and distributed generation.

 

Competitive bidding proceeding.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 under the framework: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.

 

Management cannot currently predictThe Kalaeloa Solar Two photovoltaic energy PPA and the ultimate effect ofKawailoa Wind windfarm PPA are two renewable projects that resulted from HECO’s Renewable Energy Request for Proposals (RFP) under the framework on the ability of the utilities to acquire or build additional generating capacity in the future.Competitive Bidding Framework.

 

The utilities received PUC approval for waiversexemptions from the competitive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources.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.process, including the Kahuku Wind Power, Auwahi Wind Energy LLC, and Kaheawa Wind Power II wind farms. The PUC can also grant waivers on its own volition to renewable energy projects that are not exempt from the Competitive Bidding Framework (as was done in December 2010such as for four 5 MW solar facilities proposed for Oahu).the Hu Honua biomass facility.

 

Distributed generation proceeding.  In January 2006, the PUC issued a D&O indicating that its policy is to promote the development of a market structure that assures distributed generation (DG)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 PUC found that the “disadvantages outweigh the advantages” of allowing a utility to provide DG services on a customer’s site. However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the utilities from providing DG services at this early stage of DG market development. Therefore, 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.

 

In April 2006, the PUC provided clarification to the conditions under which the utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework).

In March 2010, the PUC approved the amended agreement between HECO and the State of Hawaii Department of Transportation to develop a dispatchable standby generation facility at the Honolulu International Airport that will be owned by the State and operated by HECO. The PUC also waived the project

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from the Competitive Bidding Framework. The dispatchable standby generation facility is projected to be in operation in July 2012.

HECO is also evaluating the potential to develop utility-owned DG at Oahu military bases in order to meet utility system needs and the energy objectives of the federal Department of Defense (DOD).

In February 2008, the PUC approved a MECO agreement for the installation at a hotel site on the island of Lanai of a CHP system, which was placed in service in September 2009.

DG tariff proceeding. In 2008, the PUC approved modifications to the utilities’ interconnection tariffs and a standby service tariff. In January 2010, the utilities requested modifications of the DG interconnection tariff. In May 2010, the PUC approved certain modifications that had been stipulated to by the parties, including (1) modifying requirements for conducting detailed interconnection studies; (2) establishing a standard three-party interconnection agreement; (3) including cross-limitation of liability and non-indemnification language with respect to projects where a State of Hawaii agency is the customer; and (4) requiring additional info rmation regarding the customer’s generating facility. The remaining issues continue to be evaluated in the proceeding.

DG and distributed energy storage under the Energy Agreement.  Under the Energy Agreement, the utilities committed to facilitate planning for distributed energy resources through a new Clean Energy Scenario Planning process. Under this process, Locational Value Maps were developed in 2009 to identify areas where DG and distributed energy storage would provide utility system benefits and can be reasonably accommodated.

The utilities also agreed to power utility-owned DG using sustainable biofuels or other renewable technologies and fuels, and to support either customer-owned or utility-owned distributed energy storage. The utilities are currently planning distributed energy storage research, development and demonstration projects for installation in 2011-2012.

The parties to the Energy Agreement support reconsideration of the PUC’s restrictions on utility-owned DG where it is proven that utility ownership and dispatch clearly benefits grid reliability and ratepayer interests, and the equipment is competitively procured. The parties also support HECO’s dispatchable standby generation units upon showing reasonable ratepayer benefits.

The utilities may contract with third parties to aggregate fleets of DG or standby generators for utility dispatch or under PPAs, or may undertake such aggregation themselves if no third parties respond to a solicitation for such services.

The Energy Agreement also provides that to the degree that transmission and distribution automation and other smart grid technology investments are needed to facilitate distributed energy resource utilization, those investments should be recoverable through a Clean Energy Infrastructure Surcharge (which was replaced by the Renewable Energy Infrastructure Program Surcharge) and later placed in rate base in the next rate case proceeding.

 

Environmental mattersThe HECO, HELCO and MECO 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 EPA. The 2004federal Environmental Protection Agency (EPA). Hawaii State Legislature passed legislation thatlaw 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.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 HECO’s steam generating facilities on Oahu.

 

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See “Environmental regulation” in Note 3 of HEI’s “Notes to Consolidated Financial Statements.” There can be no assurance that a significant environmental liability will not be incurred by the electric utilities or that the related costs will be recoverable through rates.

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 HECO and its subsidiaries 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 electric utilities or that the related costs will be recoverable through rates. See “Environmental regulation” in Note 3 of HEI’s “Notes to 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 electric utility’s future competitive position, results of operations, financial condition and financial condition.liquidity.

 

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

 

Property, plant and equipmentProperty, 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 i nin the future) are included in regulatory liabilities.

 

HECO and its subsidiaries 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 HECO’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 “Major projects” in Note 3 of HEI’s “Notes to Consolidated Financial Statements” concerning costs of major projects that have not yet been approved for inclusion in the applicable utility’s rate base.

 

67



Regulatory assets and liabilitiesThe electric 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 HECO and its subsidiaries 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, 2010,2012, the consolidated regulatory liabilities and regulatory assets of the utilities amounted to $297$322 million and $478$865 million, respectively, compared to $288$315 million and $427$669 million as of December 31, 2009,2011, respectively. Regulatory liabilities and regulatory assets are itemized in Note 3 of HEI’s “Notes to 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, 20102012 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 HECO and its subsidiaries’ operations currently satisfy the criteria for regulatory accounting. If events or circumstances should change so that those criteria are no longer satisfied, the

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electric utilities expect that the regulatory assets would be charged to expense and the regulatory liabilities would be credited to income or refunded to ratepayers immediately. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations, financial condition and financial positionliquidity may result if regulatory assets have to be charged to expense or if regulatory liabilities are required to be refunded to ratepayers immediately.

 

RevenuesElectric 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.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, 2010,2012, revenues applicable to energy consumed, but not yet billed to customers, amounted to $104$134 million and the RBA revenues recognized in 2012 amounted to $56 million.

 

Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order. As of December 31, 2010, HECO and its subsidiaries had recognized $4 million of such revenues with respect to interim orders. Also, theThe rate schedules of the electric 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 electric 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 positioncondition and cash flowsliquidity may result if the utilitiesECACs or PPACs were to lose their ECACs.lost.

 

Consolidation of variable interest entities.  A business enterprise must evaluate whether it should consolidate a VIE.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 HECO (oror its subsidiaries as applicable) may be found to meet the definition of a primary beneficiary of a VIE (the IPP) which finding may result in the consolidation of the IPP in HECO’s consolidated financial statements. The consolidation of IPPs could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of ass etsassets 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 HEI’s “Notes to Consolidated Financial Statements.”

 

Additional information concerning HECO is incorporated herein by reference to page 3 of HECO Exhibit 99.2.

68



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 20102012 with assets of $4.8$5.0 billion and net income of $58$59 million, compared to assets of $4.9 billion as of December 31, 20092011 and net income of $22$60 million in 2009. The weak national economic environment and declines in the national housing market in 2009 and 2008 impacted securities in ASB’s investment portfolio. The rating agencies downgraded the ratings on a significant number of mortgage-related securities in 2009, including several mortgage-related securities held in ASB’s portfolio. During 2009, ASB sold its private issue mortgage-related securities portfolio to reduce its credit risk and improve the prospects for consistent future earnings. The sales resulted in a net charge of $19 million ($32 million pretax) in the fourth quarter of 2009. ASB also improved its interest rate risk by selling substantially all of its salable fixed rate residential loan production during 2009 and more than 75% of its fixed rate residential loan production in the first nine months of 2010 into the secondary market. A portion of the excess liquidity was used to pay off other borrowings that were maturing. Also in 2009, ASB recorded a net charge of $9 million ($15 million pretax) for other-than-temporary impairment (OTTI) in the value of s ecurities and a higher provision for loan losses than in 2010 and 2008.2011.

 

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.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 after the completion of its performance improvement project.

 

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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 weak global, national and local economic environments have resulted in a persistent, low level of interest rates weak loan demand, and excess liquidity in the financial system. In addition, expectations are increasing that interestsystem have impacted the new loan production rates will rise rapidly once there are strong signs that the economic recovery is taking hold. ASB’s decisionand made it challenging to sell substantial fixed rate mortgage production in 2009 and 2010, weak loan demand, and challenges in findingfind investments with adequate risk-adjusted returns, which resulted in declining loan balances and an increase in ASB’s liquidity position, which had 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.

 

Although ASB’s loan quality improved in 2010, there are still signs2012 as a result of stabilized or increasing property values, more financial stressflexibility of borrowers, and overall general economic improvement in the Hawaii and mainland markets.state of Hawaii. The slowdown in the economy, both nationally and locally, hashad resulted in ASB experiencing higher levels of loan delinquencies and losses, which were concentrated in the vacantresidential land portfolio and on the neighbor islands. As a result,The residential land portfolio has declined, which has enabled ASB to release some loan loss reserves on that portfolio. Although ASB’s provision for loan losses had increaseddecreased in 2009 and remained2012 compared to 2011, it is still at a highan elevated level in 2010, followingcompared to several years of historically low loan losses and loan loss allowances. While a mildgradual recovery beganwas experienced in 20102012 as the global economic recovery began to take hold, many challenges remain and the outlook for the Hawaii economy is for a slow, steady recovery. Consumers and businesses are expected to recover slowly in 20112013 as gradual improvement in measures such as job growth, unemployment and real personal income are expected. Contin uedContinued financial stress on ASB’s customers may result in higher levels of loan delinquencies and losses.

 

69



Results of operations.

 

(dollars in millions)

 

2010

 

% change

 

2009

 

% change

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

283

 

3

 

$

275

 

(23

)

$

359

 

Net interest income

 

190

 

(6

)

201

 

(3

)

207

 

Operating income

 

93

 

192

 

32

 

18

 

27

 

Net income

 

58

 

169

 

22

 

22

 

18

 

Return on average common equity (1)

 

11.6

%

156

 

4.5

%

43

 

3.2

%

Earning assets

 

 

 

 

 

 

 

 

 

 

 

Average balance (1)

 

$

4,492

 

(6

)

$

4,804

 

(16

)

$

5,722

 

Weighted-average yield

 

4.68

%

(8

)

5.10

%

(7

)

5.46

%

Costing liabilities

 

 

 

 

 

 

 

 

 

 

 

Average balance (1)

 

$

3,445

 

(9

)

$

3,801

 

(20

)

$

4,754

 

Weighted-average rate

 

0.59

%

(49

)

1.15

%

(48

)

2.22

%

Net interest margin (2)

 

4.23

%

1

 

4.19

%

16

 

3.62

%

·2012 vs. 2011

 

(in millions)

 

2012

 

2011

 

Increase
(decrease)

 

Primary reason(s) for significant change

 

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 equity 1

 

11.7

%

12.0

%

(0.3)%

 

 

 

70



(1)·2011 vs. 2010

(in millions)

 

2011

 

2010

 

Increase
(decrease)

 

Primary reason(s) for significant change

 

Interest income

 

$199

 

$210

 

$(11)

 

Decrease largely due to lower yields on earning assets. ASB’s 2011 average loan portfolio balance was $27 million higher than the 2010 average loan portfolio balance as the average commercial markets and home equity lines of credit loan balances increased by $106 million and $98 million, respectively. ASB targeted these loan types because of their shorter duration and variable rates. Offsetting these loan portfolio increases was a decrease in the average residential loan portfolio balance of $181 million due to lower production and ASB’s decision to sell a portion of the residential loan production. The average investment and mortgage-related securities portfolio balance increased by $71 million as ASB purchased securities with its excess liquidity.

 

Noninterest income

 

65

 

73

 

(8)

 

Lower fee income on deposits as a result of new overdraft fee legislation.

 

Revenues

 

264

 

283

 

(19)

 

 

 

 

Interest expense

 

 

14

 

 

20

 

 

(6)

 

Lower funding costs as a result of the low interest rate environment. Average deposit balances for 2011 increased by $29 million compared to 2010 balances due to an increase in core deposits of $199 million, partly offset by a decrease in term certificates of $171 million. The other borrowings average balance decreased by $18 million due to lower retail repurchase agreements.

 

 

 

 

 

 

 

 

 

 

 

Provision for loan losses

 

15

 

21

 

(6)

 

Decrease primarily due to lower loan loss reserves for the commercial markets portfolio as a result of lower historical loss ratios in 2011 and lower loan loss reserves for the residential land portfolio due to the contraction of the portfolio. ASB’s nonaccrual and renegotiated loans represented 3.1% and 2.8% of total outstanding loans as of December 31, 2011 and 2010, respectively.

 

 

 

 

 

 

 

 

 

 

 

Noninterest expense

 

143

 

149

 

(6)

 

Lower data processing expense due to lower service bureau expenses with the system conversion in mid-2010.

 

Expenses

 

172

 

190

 

(18)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

92

 

93

 

(1)

 

Lower net interest income and noninterest income, partially offset by lower provision for loan losses and noninterest expenses.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

60

 

58

 

2

 

Lower operating income, partly offset by lower taxes primarily due to additional low income housing credits and tax-free income from municipal bonds and bank-owned life insurance.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Return on average common equity 1

 

12.0

%

11.6

%

0.4%

 

 

 

1          Calculated using the average daily balances.

(2)Defined as net interest income as a percentage of average earning assets.

·Net interest income before provision for loan losses for 2010 decreased by $11.5 million, or 5.7%, when compared to 2009 due to lower balances and yields on earning assets, partly offset by lower funding costs. ASB’s average interest earning assets and loan portfolio balances decreased by $312 million and $347 million, respectively, primarily due to the sale of substantial residential loan production in 2009 and 2010. The average

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commercial market and residential land loan portfolio balances decreased by $42 million and $31 million, respectively, due to repayments in the portfolios. The average home equity line of credit portfolio balance increased by $74 million due to promotional campaigns in the first half of 2010. The average investment and mortgage-related securities portfolio balance decreased by $61 million due to the sale of private-issue mortgage-related securities portfolio in the fourth quarter of 2009. The other investments average balance increased by $97 million due to an increase in liquidity as a result of ASB’s fixed rate mortgage production sales. Average deposit balances for 2010 decreased by $116 million compared to 2009 due to an outflow of time certificates of $372 million as ASB did not aggressively price its time certificate products, partly offset by a $256 million increase in the average core deposit balan ce as ASB introduced new core deposit products. The other borrowings average balance decreased by $160 million primarily due to the payoff of maturing amounts. Net interest margin increased from 4.19% in 2009 to 4.23% in 2010 due to lower funding costs as a result of the outflow of higher costing term certificates and a shift in deposit mix.

During 2010, ASB recorded a provision for loan losses of $20.9 million, or $11.1 million lower than the provision for loan losses in 2009, primarily due to a $10 million provision for loan loss in 2009 on a commercial loan that subsequently sold and lower level of nonperforming loans. ASB’s nonaccrual and renegotiated loans represented 2.8%, 2.3% and 0.7% of total loans outstanding as of December 31, 2010, 2009 and 2008, respectively.

Net charge-offs for 2010 totaled $21.9 million compared to $26.1 million in 2009. The decrease in net charge-offs was due to a $10 million partial charge-off of a commercial loan in 2009. ASB experienced an increase in net charge-offs of 1-4 family and residential land loans in 2010.

Noninterest income for 2010 of $72.6 million was $42.7 million higher than noninterest income for 2009. Excluding the losses on sale of private-issue mortgage-related securities and OTTI charges in 2009, noninterest income for 2010 was $4.9 million lower than 2009 due to lower deposit fees as a result of new overdraft fee legislation and lower gain on sale of loans.

Noninterest expense for 2010 of $148.9 million was $18.5 million lower than 2009 operating expenses primarily due to lower compensation, occupancy, data processing, services and equipment expenses as a result of ASB’s performance improvement project, which reduced ASB’s cost structure through improved processes and procedures, and improved the efficiency of ASB. In May 2010, ASB completed the conversion to the Fiserv Inc. banking platform system, which reduced service bureau expenses by approximately $0.5 million per month beginning in June 2010. ASB incurred conversion costs totaling approximately $4.4 million in 2010 to complete the project.

·Net interest income before provision for loan losses for 2009 decreased by $5.7 million, or 2.8%, when compared to 2008 due to lower balances and yields of earning assets, partly offset by lower funding costs. ASB’s average interest earning assets decreased by $918 million primarily due to the balance sheet restructure in June 2008 and ASB’s sales of the residential loans it produced in 2009. Net interest margin increased from 3.62% in 2008 to 4.19% in 2009 due to the balance sheet restructure, which removed lower-spread net assets (investment and mortgage-related securities and other borrowings) and lowered funding costs as a result of the outflow of higher costing term certificates, a shift in deposit mix and the paydown of other borrowings. The decrease in the average loan portfolio balance was due to a decrease in the average 1-4 family residential loan portfolio of $315 million as ASB sold substantially all of its salable residential loan production in the current low interest rate environment. Offsetting the decrease in the residential loan portfolio were increases in the average balances of the home equity line of credit and commercial markets portfolios of $66 million and $39 million, respectively. The average investment and mortgage-related securities portfolio balances decreased by $797 million due to the balance sheet restructure in June 2008 and the sale of the private-issue mortgage-related securities portfolio in the fourth quarter of 2009. The other investments average balance increased by $114 million due to an increase in liquidity as a result of ASB’s fixed rate mortgage production sales throughout 2009, weak loan demand, and challenges in finding investments with adequate risk-adjusted returns. A verage deposit balances for 2009 decreased by $140 million compared to 2008 as ASB experienced an outflow of term certificates of $337 million, partly offset by an inflow in core deposits of $197 million. The decrease in other borrowings average balance was due to the early extinguishment of other

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borrowings in the balance sheet restructure in 2008 and the paydown of maturing other borrowings in 2009 with excess liquidity.

During 2009, ASB recorded a provision for loan losses of $32 million, or $21.7 million higher than in 2008, primarily due to a $10 million provision for loan loss on a commercial loan that was subsequently sold and a higher level of nonperforming residential 1-4 family, residential lot and consumer loans and increases in the historical loss ratios for these loan types.

Net charge-offs for 2009 totaled $26.1 million compared to $4.7 million in 2008. The increase from 2008 to 2009 in net charge-offs was primarily due to the $10 million partial charge-off of a commercial loan that was subsequently sold and higher residential 1-4 family, residential lot and home equity lines of credit charge-offs. In the fourth quarter of 2009, ASB recorded charge-offs of $7.2 million relating to residential 1-4 family, residential lot and home equity lines of credit loans, which had specific allowance for loan losses allocated to them in prior periods. ASB took a partial charge-off on these loans for the amount of the specific allowance for loan losses.

Noninterest income for 2009 of $29.9 million was $16.2 million lower than noninterest income for 2008. Excluding losses on sale of securities and OTTI charges, noninterest income for 2009 was $6.1 million higher than 2008, primarily due to higher gains on sale of loans and deposit account fees. 2008 noninterest income included insurance recoveries on legal and litigation matters of $4.3 million and a $1.9 million gain on sale of stock in membership organizations.

Noninterest expense for 2009 decreased by $48.6 million when compared to 2008, primarily due to losses on the early extinguishment of certain borrowings from the balance sheet restructuring in 2008. Excluding the losses from the balance sheet restructuring, noninterest expense for 2009 decreased by $8.7 million primarily due to lower consulting and contract services, compensation and equipment expenses, partly offset by higher data processing expenses and an FDIC special assessment of $2.3 million. In 2008, ASB began a performance improvement project to increase revenues, reduce ASB’s cost structure through improved processes and procedures and improve the efficiency of ASB. The performance improvement project includes changes to bank operating processing, reorganization of personnel and review of bank real estate. For example, in the second quarter of 2009, ASB signed an agreem ent with Fiserv Inc. to use its technology to consolidate ASB’s disparate manual processes using a single, integrated approach. Included in 2009 noninterest expenses were the following charges related to ASB’s performance improvement project: (1) real estate transaction losses and expenses of $3.9 million; (2) professional services costs of $2.5 million; (3) severance of $1.7 million; (4) Fiserv (service bureau) conversion costs of $1.7 million; (5) prepayment penalty on early extinguishment of debt of $0.7 million; and (6) technology software write-off of $0.2 million.

 

See Note 4 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of guarantees and further information about ASB.

 

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Table of Contents

 

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 2010, 20092012, 2011 and 2008.2010.

 

 

2010

 

2009

 

 

2012

 

 

2011

 

($ in thousands)

 

Average
balance

 

Interest

 

Average
rate (%)

 

Average
balance

 

Interest

 

Average
rate (%)

 

(dollars in thousands)

 

Average
balance

 

 


Interest

 

 

Yield/
rate (%)

 

 

Average
balance

 


Interest

 

 

Yield/
rate (%)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other investments (1)

 

$

334,270

 

$

621

 

0.19

 

$

237,770

 

$

329

 

0.14

 

Investment and mortgage-related securities

 

566,126

 

14,468

 

2.56

 

627,365

 

26,648

 

4.25

 

Loans receivable (2)

 

3,591,794

 

195,192

 

5.43

 

3,938,575

 

217,838

 

5.53

 

Total interest-earning assets (3)

 

4,492,190

 

210,281

 

4.68

 

4,803,710

 

244,815

 

5.10

 

Other investments 1

 

$

203,751

 

 

$

269

 

 

0.13

 

 

$

233,909

 

$

342

 

 

0.15

 

Available-for-sale investment and mortgage-related securities

 

623,438

 

 

14,368

 

 

2.30

 

 

637,123

 

14,763

 

 

2.32

 

Loans

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family 2

 

1,894,603

 

 

99,056

 

 

5.23

 

 

2,016,224

 

109,908

 

 

5.45

 

Commercial real estate

 

402,410

 

 

18,387

 

 

4.57

 

 

351,832

 

17,911

 

 

5.09

 

Home equity line of credit

 

585,797

 

 

16,106

 

 

2.75

 

 

474,029

 

13,935

 

 

2.94

 

Residential land

 

34,744

 

 

2,097

 

 

6.04

 

 

53,904

 

2,979

 

 

5.53

 

Commercial loans

 

714,679

 

 

30,925

 

 

4.33

 

 

637,182

 

31,432

 

 

4.93

 

Consumer loans

 

101,933

 

 

9,486

 

 

9.31

 

 

85,356

 

8,320

 

 

9.75

 

Total loans 3

 

3,734,166

 

 

176,057

 

 

4.71

 

 

3,618,527

 

184,485

 

 

5.10

 

Total interest-earning assets 4

 

4,561,355

 

 

190,694

 

 

4.18

 

 

4,489,559

 

199,590

 

 

4.45

 

Allowance for loan losses

 

(39,135

)

 

 

 

 

(42,121

)

 

 

 

 

 

(39,323

)

 

 

 

 

 

 

 

(39,263

)

 

 

 

 

 

 

Non-interest-earning assets

 

415,986

 

 

 

 

 

352,398

 

 

 

 

 

 

431,680

 

 

 

 

 

 

 

 

423,183

 

 

 

 

 

 

 

Total assets

 

$

4,869,041

 

 

 

 

 

$

5,113,987

 

 

 

 

 

Total Assets

 

$

4,953,712

 

 

 

 

 

 

 

 

$

4,873,479

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Shareholder’s Equity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest-bearing demand and savings deposits

 

$

2,410,118

 

3,475

 

0.14

 

$

2,234,259

 

6,676

 

0.30

 

Savings

 

$

1,727,754

 

 

1,128

 

 

0.07

 

 

$

1,672,033

 

1,756

 

 

0.11

 

Interest-bearing checking

 

612,629

 

 

111

 

 

0.02

 

 

593,891

 

184

 

 

0.03

 

Money market

 

202,539

 

 

319

 

 

0.16

 

 

250,682

 

650

 

 

0.26

 

Time certificates

 

768,991

 

11,221

 

1.46

 

1,140,997

 

27,370

 

2.40

 

 

517,752

 

 

4,865

 

 

0.94

 

 

598,360

 

6,393

 

 

1.07

 

Total interest-bearing deposits

 

3,179,109

 

14,696

 

0.46

 

3,375,256

 

34,046

 

1.01

 

 

3,060,674

 

 

6,423

 

 

0.21

 

 

3,114,966

 

8,983

 

 

0.29

 

Other borrowings

 

266,149

 

5,653

 

2.12

 

425,947

 

9,497

 

2.23

 

Advances from Federal Home Loan Bank

 

50,014

 

 

2,176

 

 

4.35

 

 

64,466

 

2,553

 

 

3.96

 

Securities sold under agreements to repurchase

 

172,683

 

 

2,693

 

 

1.56

 

 

182,655

 

2,933

 

 

1.61

 

Total interest-bearing liabilities

 

3,445,258

 

20,349

 

0.59

 

3,801,203

 

43,543

 

1.15

 

 

3,283,371

 

 

11,292

 

 

0.34

 

 

3,362,087

 

14,469

 

 

0.43

 

Non-interest bearing liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deposits

 

824,039

 

 

 

 

 

743,982

 

 

 

 

 

 

1,060,121

 

 

 

 

 

 

 

 

916,957

 

 

 

 

 

 

Other

 

96,510

 

 

 

 

 

89,248

 

 

 

 

 

 

108,161

 

 

 

 

 

 

 

 

95,363

 

 

 

 

 

 

Shareholder’s equity

 

503,234

 

 

 

 

 

479,554

 

 

 

 

 

 

502,059

 

 

 

 

 

 

 

 

499,072

 

 

 

 

 

 

 

Total Liabilities and Shareholder’s Equity

 

$

4,869,041

 

 

 

 

 

$

5,113,987

 

 

 

 

 

 

$

4,953,712

 

 

 

 

 

 

 

 

$

4,873,479

 

 

 

 

 

 

 

Net interest income

 

 

 

$

189,932

 

 

 

 

 

$

201,272

 

 

 

 

 

 

 

$

179,402

 

 

 

 

 

 

 

 

$

185,121

 

 

 

 

Net interest margin (%) (4)

 

 

 

 

 

4.23

 

 

 

 

 

4.19

 

Net interest margin (%) 5

 

 

 

 

 

 

 

3.93

 

 

 

 

 

 

 

 

4.12

 

 

 

 

2008

 

 

 

 

 

 

 

($ in thousands)

 

Average
balance

 

Interest

 

Average
rate (%)

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

Other investments (1)

 

$

123,819

 

$

1,542

 

1.25

 

 

 

 

 

 

 

Investment and mortgage-related securities

 

1,424,015

 

63,666

 

4.47

 

 

 

 

 

 

 

Loans receivable (2)

 

4,173,802

 

247,210

 

5.92

 

 

 

 

 

 

 

Total interest-earning assets (3)

 

5,721,636

 

312,418

 

5.46

 

 

 

 

 

 

 

Allowance for loan losses

 

(30,829

)

 

 

 

 

 

 

 

 

 

 

Non-interest-earning assets

 

415,822

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

6,106,629

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Shareholder’s Equity:

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest-bearing demand and savings deposits

 

$

2,094,396

 

11,953

 

0.57

 

 

 

 

 

 

 

Time certificates

 

1,478,427

 

49,530

 

3.35

 

 

 

 

 

 

 

Total interest-bearing deposits

 

3,572,823

 

61,483

 

1.72

 

 

 

 

 

 

 

Other borrowings

 

1,180,844

 

43,941

 

3.72

 

 

 

 

 

 

 

Total interest-bearing liabilities

 

4,753,667

 

105,424

 

2.22

 

 

 

 

 

 

 

Non-interest bearing liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Deposits

 

686,461

 

 

 

 

 

 

 

 

 

 

 

Other

 

104,539

 

 

 

 

 

 

 

 

 

 

 

Shareholder’s equity

 

561,962

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Shareholder’s Equity

 

$

6,106,629

 

 

 

 

 

 

 

 

 

 

 

Net interest income

 

 

 

$

206,994

 

 

 

 

 

 

 

 

 

Net interest margin (%) (4)

 

 

 

 

 

3.62

 

 

 

 

 

 

 

72



 

 

2010

 

 

 

 

 

 

 

 

 

(dollars in thousands)

 

Average
balance

 

 

Interest

 

 

Yield/
rate (%)

 

 

 

 

 

 

 

 

 

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other investments 1

 

$  334,270

 

 

$      621

 

 

0.19

 

 

 

 

 

 

 

 

 

 

Available-for-sale investment and mortgage-related securities

 

566,126

 

 

14,468

 

 

2.56

 

 

 

 

 

 

 

 

 

 

Loans

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family 2

 

2,197,582

 

 

124,101

 

 

5.65

 

 

 

 

 

 

 

 

 

 

Commercial real estate

 

324,324

 

 

16,642

 

 

5.13

 

 

 

 

 

 

 

 

 

 

Home equity line of credit

 

375,853

 

 

12,568

 

 

3.34

 

 

 

 

 

 

 

 

 

 

Residential land

 

82,895

 

 

4,671

 

 

5.64

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

530,731

 

 

29,626

 

 

5.58

 

 

 

 

 

 

 

 

 

 

Consumer loans

 

80,409

 

 

7,584

 

 

9.43

 

 

 

 

 

 

 

 

 

 

Total loans 3

 

3,591,794

 

 

195,192

 

 

5.43

 

 

 

 

 

 

 

 

 

 

Total interest-earning assets 4

 

4,492,190

 

 

210,281

 

 

4.68

 

 

 

 

 

 

 

 

 

 

Allowance for loan losses

 

(39,135

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-interest-earning assets

 

415,986

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

$4,869,041

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Shareholder’s Equity:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Savings

 

$1,608,650

 

 

2,262

 

 

0.14

 

 

 

 

 

 

 

 

 

 

Interest-bearing checking

 

568,659

 

 

329

 

 

0.06

 

 

 

 

 

 

 

 

 

 

Money market

 

232,809

 

 

884

 

 

0.38

 

 

 

 

 

 

 

 

 

 

Time certificates

 

768,991

 

 

11,221

 

 

1.46

 

 

 

 

 

 

 

 

 

 

Total interest-bearing deposits

 

3,179,109

 

 

14,696

 

 

0.46

 

 

 

 

 

 

 

 

 

 

Advances from Federal Home Loan Bank

 

65,000

 

 

2,566

 

 

3.95

 

 

 

 

 

 

 

 

 

 

Securities sold under agreements to repurchase

 

201,149

 

 

3,087

 

 

1.53

 

 

 

 

 

 

 

 

 

 

Total interest-bearing liabilities

 

3,445,258

 

 

20,349

 

 

0.59

 

 

 

 

 

 

 

 

 

 

Non-interest bearing liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deposits

 

824,039

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

96,510

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Shareholder’s equity

 

503,234

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Liabilities and Shareholder’s Equity

 

$4,869,041

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net interest income

 

 

 

 

$189,932

 

 

 

 

 

 

 

 

 

 

 

 

 

Net interest margin (%) 5

 

 

 

 

 

 

 

4.23

 

 

 

 

 

 

 

 

 

 

(1)1                    Includes federal funds sold, interest bearing deposits and stock in the FHLBFederal Home Loan Bank of Seattle ($98 million as of December 31, 2010).Seattle.

(2)2Includes loans held for sale.

3                    Includes loan fees of $4.9 million, $3.9 million and $6.3 million $6.9 millionfor 2012, 2011 and $4.4 million for 2010, 2009 and 2008, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.

(3)4                    Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.8 million $0.5 million and $0.1 million for 2012, 2011 and nil for 2010, and 2009, respectively.

(4)5                    Defined as net interest income as a percentage of average earning assets.

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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 current interest rate environment iswas impacted by disruptions in the financial markets and these conditions may continue and have a negative impact on ASB’s net interest margin.

Loan originations and mortgage-related securities are ASB’s primary sources of 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 HEI’s “Notes to Consolidated Financial Statements” for the composition of ASB’s loans receivable.

 

The decreaseincrease in the total loan portfolio from $3.6 billion at the end of 2011 to $3.7 billion at the end of 2009 to $3.5 billion at the end of 20102012 was primarily due to ASB’s strategic decision to sell mostgrowth in the commercial real estate and home equity line of the salablecredit loan portfolios, which ASB targeted because of their shorter duration and/or variable rates partly offset by lower residential loans it originated during 2010 ($340 million of loans sold).loan balances.

73



 

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 HEI’s “Notes to Consolidated Financial Statements” for information with respect to nonperforming assets. The level of nonperforming loans reflects the impact of current unemployment levels in Hawaii and the weak economic environment globally, nationally and in Hawaii.

 

Allowance for loan losses.  See “Allowance for loan losses” in Note 4 of HEI’s “Notes to Consolidated Financial Statements” for the tables which sets forth the allocation of ASB’s allowance for loan losses. For 2010 compared to 2009, the increase in2012, the allowance for loan losses for residential 1-4 family and residential land loans wasincreased by $4.1 million due to higher historical loss ratios used to computegrowth in the loan loss reserves, partly offset by lower balances. The decrease in the allowance for loan losses for commercial construction loans for 2010 compared to 2009 was due to lower loan balances. For 2010 compared to 2009, the decrease in the allowance for loan losses for commercial loans was due to lower histor ical loss ratios used to compute the loan loss reserves. The increase in the allowance for loan losses for consumer loans for 2010 compared to 2009 was primarily due to anportfolios (2.6% growth or $96.3 million increase in outstanding balances) and higher impairment reserves for the commercial and commercial real estate loan balances.portfolios. Although overall loan quality improved, a number of commercial borrowers experienced financial stress during the year.

 

Investment and mortgage-related securities.  As of December 31, 2010,2012, ASB’s investment portfolio consisted of 47%62% mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA), 26% federal agency obligations and 12% municipal bonds. As of December 31, 2011, ASB’s investment portfolio consisted of 55% mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) or Government National Mortgage Association (GNMA), 47%35% federal agency obligations and 6%10% municipal bonds. As of December 31, 2009, ASB’s investment portfolio consisted of 75% mortgage-related securities issued by FNMA, FHLMC or GNMA and 24% federal agency obligations and 1% municipal bonds.

Principal and interest on mortgage-related securities issued by FNMA, FHLMC and GNMA are guaranteed by the issuer and, in the securities carry implied AAA ratings.

case of GNMA, backed by the full faith and credit of the United States.

The unrealized gains on ASB’s investment in federal agency mortgage-backed securities were primarily caused by lower interest rates. The low interest rate environment coupled with tighter spreads on all mortgage collateralized securities caused the market value of the securities held to increase above 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, 20102012, 2011 and 2009,2010, ASB did not have any private-issue mortgage-related securities. At December 31, 2008, the PMRS portfolio had $59 million of unrealized losses, due to multiple factors primarily related to deterioration in the residential housing market and spread widening for all credit sensitive sectors of the market. Increasing foreclosures coupled with recessionary employment pressures and declining housing prices had depressed the values of all private-issue mortgage collateralized securities as risks for this sector had increased. Changes in credit rating for issues originated in 2006 and 2007 had dramatically depressed

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Table of Contents

valuations in this sector of the portfolio. In 2008, ASB recorded an OTTI charge of $7.8 million on two PMRS. In the fourth quarter of 2009, ASB sold its PMRS portfolio and had no OTTI as of December 31, 2009.

 

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, 2010,2012, ASB’s costing liabilities consisted of 94%96% deposits and 6%4% other borrowings. As of December 31, 2009,2011, ASB’s costing liabilities consisted of 93%95% deposits and 7%5% other borrowings. See Note 4 of HEI’s “Notes to Consolidated Financial Statements&# 148;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.instruments, respectively. In addition, changes in credit spreads also impact the fair values of those instruments.

Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) could reduce the market value of available-for-sale investment and mortgage-related securities and reduce shareholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities (such as those that occurred in the fourth quarter of 2009 and in the 2008 balance sheet restructure) or an OTTI in the value of the securities. As of December 31, 20102012 and December 31, 2009,2011, ASB had unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI of $4$11 million and $5$10 million, respectively. See &# 147;Quantitative“Quantitative and qualitative disclosures about market risk.”

74



 

Legislation and regulation.  ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (OTS), whose regulatory functions are to be transferred to the Office of the Comptroller of the Currency (OCC) as described below, 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 HEI’s “Notes to 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 and ASB, has changed and will undergo substantial changescontinue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. The Dodd-Frank Act increases regulation and oversight of the financial services industry and imposes restrictions on the ability of firms within the industry to conduct business consistent with historical practices. Most importantlyImportantly for HEI and ASB, under the Dodd-Frank Act, will abolish their historical federal financial institution regulator,on July 21, 2011, all of the OTS, effective one year fromfunctions of the enactment date (subjectOffice of Thrift Supervision (OTS) transferred to extension by not more than an additional six months)the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI, as a thrift holding company, will movemoved to the Federal Reserve,FRB, and supervision and regulation of ASB, as a federally chartered savings bank, will movemoved to the OCC. While the laws and regulations applicable to HEI and ASB willdid not generally change—the Home Owners Loan Act and regulations issued thereunder will still apply—change, the applicable laws and regulations will beare being interpreted, and new and amended regulations willmay be adopted, by the Federal ReserveFRB and the OCC. HEI will for the first time be subject to minimum consolidated capital requirements, and ASB may be required to be supervised through ASHI, its intermediate holding company. The Dodd-Frank Act requires regulators, at a minimum, to apply to bank and thrift holding companies leverage and risk-based capital standards that are at least as strict as those in effect at the insured depository institution level on the date the Act became effective, although there will be a phase-in period for meeting these standards. In addition, HEI will continue to be required to serve as a source of strength t oto 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.

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Table of Contents

More stringent affiliate transaction rules willnow apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards arewere raised with respect to the ability of ASB to merge with or acquire another institution. WhileIn reviewing a potential merger or acquisition, the Dodd-Frank Act requiresapproving federal agency will need to consider the minimum reserve ratio for the Deposit Insurance Fundextent to be increased from 1.15% to 1.35% by 2020, the FDIC is required to offset the effect of this increase for depository institutions with total consolidated assets of less than $10 billion. Based onwhich the proposed changestransaction will result in “greater or more concentrated risks to the assessment base and rates, ASB anticipates a reduction in its annual FDIC assessment by approximately $2 million. ASB may be affected by the provisionstability of the Dodd-Frank Act that repeals, effective in July 2011 (unless extended), the prohibition on p ayments of interest by banksU.S. banking or savings associations on demand deposit accounts for businesses.

financial system.”

The Dodd-Frank Act establishes a Consumer Financial Protection Bureau (Bureau) to be housed inestablished the Federal Reserve to take sole responsibility (subject to limited oversight by the new Financial Stability Oversight Council) for rulemaking under the principal federal consumer financial protection laws, such as the Truth in Lending Act, Real Estate Settlement Procedures Act, Equal Credit Opportunity Act, Truth in Savings Act, Fair Debt Collection Practices Act and several other consumer protection laws, but enforcement of these laws and rules will be by the OCC in the case of ASB because itBureau. It has less than $10 billion in assets. The Bureau will have broad power in that it will have authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures includingand the use of new model formsforms. On December 21, 2012, the Bureau issued the Remittance Rule (an amendment to Regulation E) which closes for comment on January 30, 2013. For 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.  On January 10, 2013, the Bureau issued the Ability-to-Repay rule which closes for comment on February 25, 2013. For mortgages, among other things, (i) potential borrowers have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer has 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 adopt. be lower.

ASB may also be subje ctsubject 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 only allows federal law to preempt a state consumer financial law on a “case by case” basis in the consumer financial protection areaonly 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

75



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. Regulations are required to be adopted under these provisions of the Dodd-Frank Act within 18 months after the date that is to be specified by the Secretary of the Treasury for the transfer of consumer protection power to the Bureau. ASB cannot predict at this time what effect these new rules may ultimately have on its mortgage origination practices, its ability to originate mortgage loans or the costs it will incur in complying with these requirements.

The Dodd-Frank Act will affect financial regulation more generally as well, although many of these regulatory changes may not impact ASB or the Company directly, either because they are limited in application to larger entities or because they relate to activities in which ASB is not substantially engaged. For example, the Dodd-Frank Act establishes a Financial Stability Oversight Council that would, among other things, designate certain nonbank financial companies that it considers to be of systemic risk to be supervised by the Federal Reserve, as well as monitor the financial markets for trends affecting systemic risk and coordinate the regulatory activities of the federal bank regulators. It also would establish a mechanism for the FDIC to resolve systemically important companies that may fail. The ability of companies to engage in derivatives transactions and hedge for their own account li kely will be impacted by provisions in the Dodd-Frank Act that require such transactions to be moved to exchanges and for capital and margin to be held against them, as well as by the so-called “Volcker rule,” which will limit the ability of financial institutions to invest for their own account once the rule becomes effective (but with exceptions important to ASB, such as for purchases of U.S. government or agency obligations).

The “Durbin Amendment” to the Dodd-Frank Act requiresrequired the Federal ReserveFRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. The Federal Reserve has proposedIn June 2011, the FRB issued a cap onfinal 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 card issuers canan issuer may receive to 12for an electronic debit transaction is 21-24 cents, per transaction.depending on certain components. For 2012, ASB currently earnshad earned an average of 52 cents per transaction. As specified in the Dodd-Frank Act, these regulations will exempt banks like ASB, that, along with their affiliates, have less than $10 billion in assets. However, market pressures could very well push the impact downcause all banks to all banks.

observe this limitation.

Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until a year or more after its enactment, when implementing regulations are issued and effective. Thus, management cannot predict the ultimate impact of the Dodd-Frank Act, as amended, on the Company or ASB at this time. Nor can management predict the impact or substance of other future federal or state legislation or regulation, or the application thereof.

 

Credit CARD ActProposed Capital RulesOn May 22, 2009, President Obama signedThe FRB, OCC and FDIC issued three notices of proposed rulemaking (NPR) that would revise and replace the Credit Card Accountability Responsibilitycurrent capital rules. The proposed rules are intended to help ensure banks maintain strong capital positions,  which would enable them to continue lending to creditworthy households and businesses even after unforeseen losses and during severe economic downturns.

The first NPR, titled Regulatory Capital Rules: Regulatory Capital, Implementation of Basel III, Minimum Regulatory Capital Ratios, Capital Adequacy, and Transition Provisions (Basel III NPR), applies to all depository institutions, bank holding companies with total consolidated assets of $500 million or more, and savings and loan holding companies and revises the risk-based and leverage capital requirements consistent with agreements reached by the Basel Committee on Banking Supervision (Basel III). The Basel III NPR would increase the quantity and quality of capital required, revise the definition of capital to improve the ability of regulatory capital instruments to absorb losses, establish limitations on capital distributions and certain discretionary bonus payments if additional specified amounts of common equity tier 1 capital are not met, and introduce a supplementary leverage ratio for internationally active banking organizations. The Basel III NPR would also revise the prompt corrective action framework by incorporating new regulatory capital minimums and updating the definition of tangible common equity.

The second NPR, titled Regulatory Capital Rules: Standardized Approach for Risk-weighted Assets; Market Discipline and Disclosure ActRequirements (Standardized Approach NPR), proposes to revise and harmonize the rules for calculating risk-weighted assets to enhance risk sensitivity and address weaknesses identified over the past several years. The Standardized Approach NPR would incorporate aspects of 2009 into law. Among other things, it requiresthe Basel II standardized framework such as methods for determining risk-weighted assets for residential mortgages, securitization exposures and counterparty credit risk. The Standardized Approach NPR would apply to the same set of institutions as the Basel III NPR, but also introduces disclosure requirements for U.S. banking organizations with $50 billion or more in assets.

The third NPR, Regulatory Capital Rules: Advanced Approaches Risk-based Capital Rule: Market Risk Capital Rule (Advanced Approaches NPR), would apply to banking organizations that consumers receive a reasonable amount of timeare subject to makethe banking agencies’ advanced approaches rule, or to their credit card payments, prohibits payment allocation methods thatmarket risk rule, and revises the advanced approaches risk-based capital rules to be consistent with Basel III and the Dodd-Frank Act. Generally, the advanced approaches rules would apply to institutions with $250 billion or more in consolidated assets or $10 billion or more in foreign exposure, and the market risk rule would apply to savings and loan holding companies with significant trading activity.

 

Proposed Capital Requirements

Proposal effective dates

1/1/13

1/1/14

1/1/15

1/1/16

1/1/17

1/1/18

1/1/19

Capital conservation buffer

 

 

 

0.625%

1.25%

1.875%

2.50%

Common equity ratio + conservation buffer

3.50%

4.00%

4.50%

5.125%

5.75%

6.375%

7.00%

Tier 1 capital ratio + conservation buffer

4.50%

5.50%

6.00%

6.625%

7.25%

7.875%

8.50%

Total capital ratio + conservation buffer

8.00%

8.00%

8.00%

8.625%

9.25%

9.875%

10.50%

Countercyclical capital buffer – not applicable to ASB

0.625%

1.25%

1.875%

2.50%

The proposed rules allow for a transition period to meet the proposed capital requirement levels. ASB is reviewing the proposed rules and the impact to its capital ratios. Based on a preliminary assessment,

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unfairly maximize interest charges, prohibits issuers from raisingmanagement believes ASB and HEI can satisfy the interest rate on an existing credit card balance in certain circumstances, and prohibits issuers from charging over-limit fees unless the cardholder agreedproposed capital rules that would be applicable to allow the issuer to complete over-limit transactions and restricts the manner in which the issuer may assess over-limit fees. The major provisions of the Act were effective February 22, 2010.

New overdraft rules.  On November 12, 2009, the Board of Governors of the Federal Reserve System announced that it amended Regulation E (which implements the Electronic Fund Transfer Act) to limit the ability of a financial institution to assess an overdraft fee for paying automated teller machine or one-time debit card transactions that overdraw a consumer’s account, unless the consumer affirmatively consents, or opts in, to the institution’s payment of overdrafts for those transactions. These new rules applied on July 1, 2010 for new accounts and August 15, 2010 for existing accounts. In 2009, these types of overdraft fees totaled approximately $15 millio n pretax. The amendment had a negative impact on ASB’s noninterest income of approximately $4.4 million pretax for the second half of 2010.them, if adopted.

 

FHLB of Seattle stock.  As of December 31, 2010,2012, ASB’s investment in stock of the FHLB of Seattle of $97.8$96.0 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.levels, and ASB’s investment is substantially in excess of that requirement. The FHLB of Seattle reported net income of $23.9 million for nine months ended September 30, 2010 compared to a net loss of $144$49.6 million for the nine months ended September 30, 2009.2012 compared to net income of $70.7 million for the nine months ended September 30, 2011. The FHLB of Seattle reported retained earnings of $77$207 million as of September 30, 20102012 and was in compliance with all of its regulatory capital requirements. In October 2010, the FHLB of Seattle entered into a Stipulation and Consent to the Issuance of a Consent Order with the Federal Housing Finance Agency (Finance Agency), which requires the FHLB of Seattle to take certain actions related to its business and operations. The Consents provide that, following a stabilization period and once the FHLB of Seattle reaches and maintains certain thresholds, it may redeem or repurchase capital stock and begin paying dividends. ASB does not believe that the Consents will affect the FHLB of Seattle’s ability to meet ASB’s liquidity and funding needs. ASB received cash dividends on its $98 million ofThe FHLB of Seattle did not pay any cash dividends in 2010, 2011 or 2012.

In September 2012, the 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 $2 million of excess stock from ASB in September and December of $0.9 million in 2008, nil in 2009 and nil in 2010.2012.

 

Commitments and contingencies. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

 

Recentaccountingpronouncements.See “Recent “Recentaccountingpronouncementsandinterpretations”inNote1ofHEI’s “Notes “NotestoConsolidatedFinancialStatements.”

 

Liquidity and capital resources.

December 31

 

2010

 

% change

 

2009

 

% change

 

 

2012

 

% change

 

2011

 

% change

 

(dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

4,797

 

(3

)

$

4,941

 

(9

)

 

$5,042

 

3

 

$4,910

 

2

 

Available-for-sale investment and mortgage-related securities

 

678

 

57

 

433

 

(34

)

 

671

 

8

 

624

 

(8)

 

Loans receivable, net

 

3,498

 

(5

)

3,670

 

(13

)

Loans receivable held for investment, net

 

3,737

 

3

 

3,643

 

4

 

Deposit liabilities

 

3,975

 

(2

)

4,059

 

(3

)

 

4,230

 

4

 

4,070

 

2

 

Other bank borrowings

 

237

 

(20

)

298

 

(56

)

 

196

 

(16)

 

233

 

(2)

 

 

As of December 31, 2010,2012, ASB was one of Hawaii’s largest financial institutions based on assets of $4.8$5.0 billion and deposits of $4.0$4.2 billion.

In July 2010, Moody’s affirmed ASB’s counterparty credit rating of A3 and changed ASB’s outlook to “stable” from “negative” based on ASB’s better than expected asset quality and earnings performance in the last several periods. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3 and in July 2010 maintained the rating following its annual review of ASB. 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. Such ratings are not recommendations to buy, sell or hold any HEI or HECO 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.

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, 20102012 were $83$160 million lowerhigher than December 31, 2009.2011. ASB’s principal sources of borrowings are advances from the FHLB and securities sold

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under agreements to repurchase from broker/dealers. As of December 31, 2010,2012, FHLB borrowings totaled approximately $65$50 million, representing 1.4%1.0% 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, 2010,2012, ASB’s unused FHLB borrowing capacity was approximately $1.3$0.9 billion. As of December 31, 2010,2012, securities sold under agreements to repurchase totaled $172$146 million, representing 3.6%2.9% 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, 2010,2012, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2$1.5 billion. There are no commitments to lend additional funds to borrowers whose loans are impaired. There are no commitments to lend additional funds to borrowers whose loan terms have been modified in trouble debt restructurings as of December 31, 2012. 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, 20102012 and 2009,2011, ASB had $58.9$64.9 million and $65.3$66.8 million of loans on nonaccrual status, respectively, or 1.7% and 1.8% of net loans outstanding, respectively. As of December 31, 20102012 and 2009,2011, ASB had $4.3$6.1 million and $4.0$7.3 million, respectively, of real estate acquired in settlement of loans.

 

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In 2010,2012, operating activities provided cash of $113$50 million. Net cash of $128$163 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 net decreases in loans held for investment, repayments of investment and mortgage-related securities and proceeds from the sale of mortgage-related securities and real estate. Financing activities usedprovided net cash of $206$77 million due to a net decreasesincrease in deposits, partly offset by a decrease in other borrowings and deposits and 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, 2010,2012, ASB was well-capitalized (see “Capital“Regulation—Capital requirements” below for ASB’s capital ratios).

For a discussion of ASB dividends, see “Common stock equity” in Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

 

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.

 

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

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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 environmentVolatility in U.S. capital markets may negatively impact the fair values of investment and mortgage-related securities held by ASB. As of December 31, 2010,2012, the fair value and carrying value of the investment and mortgage-related securities held by ASB were $0.7 billion. ASB’s strategic sales of its private-issue mortgage-related securities in the fourth quarter of 2009 and substantially all of its salable residential loan production during 2009 and more than 75% of its residential loan production in 2010 helped to reduce its exposure to credit risk and interest rate risk.

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

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levels of interest rates weak loan demand, and excess liquidity in the financial system have made it challenging to find investments with adequate risk-adjusted returns resulting in declining loan balances and an increase in ASB’s liquidity position, withhad 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. S eeSee “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 securedcollateralized 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.

 

RegulationASB is subject to examination and comprehensive regulation by the Department of Treasury, OTSOCC 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 OTS.OCC.

 

Capital requirements.  The OTS,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, 2010,2012, ASB was in compliance with OTSOCC minimum regulatory capital requirements and was “well-capitalized” within the meaning of OTSOCC prompt corrective action regulations and FDIC capital regulations, as follows:

·           ASB met applicable minimum regulatory capital requirements (noted in parentheses) as of December 31, 20102012 with a tangible capital ratio of 9.2%9.1% (1.5%), a core capital ratio of 9.2%9.1% (4.0%) and a total risk-based capital ratio of 13.9%12.8% (8.0%).

·           ASB met the capital requirements to be generally considered “well-capitalized” (noted in parentheses) as of December 31, 20102012 with a leverage ratio of 9.2%9.1% (5.0%), a Tier-1 risk-based capital ratio of 12.8%11.7% (6.0%) and a total risk-based capital ratio of 13.9%12.8% (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

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operations, deterioration in collateral values or the inability to dispose of real estate owned (such as 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 OTS.OCC. In conducting its examinations, the OTSOCC 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 OTSOCC 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 “mem orandum“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 OTS’sOCC’s report of its safety and soundness examination or the component and overall CAMELS rating to any person

79



or organization not officially connected with the institution as an officer, director, employee, attorney, or auditor, except as provided by regulation. The OTSOCC 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, 2010,2012, 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. Savings associationsInstitutions 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 o ror inability to comply with those restrictions could effectively result in the required divestiture of ASB. As of December 31, 2010,2012, approximately 80%76% of ASB’s assets were qualified thrift investments.

 

Unitary Savingssavings and Loan Holding Companyloan holding company.  The GrammGramm-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 newly authorized financial holding companies permitted under the Gramm Act. There have been legislative proposals in the past which would operate to eliminate the

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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 HEI’s “Notes to 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 market participantsthird party pricing service and are based on observable inputs, including historical trading levels or sector yields, using market-based valuation techniques. The pricesprice of these securities may be influenced by factors such asis generally based on observable inputs, which include market liquidity, corporate credit considerations of the underlying collateral, the levels of interest rates, expectations of

80



prepayments and defaults, limited investor base, market sector concerns and overall market psychology. Adverse changesTo 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 anythe market place. The third party price selected will be based on the value that best reflects the data and observable characteristics of these factors may result in losses, and such losses could be material. the security.As of December 31, 2010,2012, ASB had investment and mortgage-related securities issued by FHLMC, GNMA and FNMA valued at $0.6 billion.

 

Allowance for loan losses.See Note 1 of HEI’s “Notes to Consolidated Financial Statements” and the discussion above under “Earning assets, costing liabilities and other factors.” As of December 31, 2010,2012, ASB’s allowance for loan losses was $40.6$42.0 million and ASB had $58.9$64.9 million of loans on nonaccrual status, compared to $41.7$37.9 million and $65.3$66.8 million at December 31, 2009,2011, respectively. In 2010,2012, ASB recorded a provision for loan losses of $20.9$12.9 million.

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, 2010,2012, 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 delinq uentdelinquent 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 toto 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 $0.5$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 losse s.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 affecteffect on the Company’s results of operations, financial positioncondition and cash flows.liquidity.

 

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HECO:

The information required by this item is set forth in HECO’s MD&A, incorporated herein by reference to page 3 of HECO Exhibit 99.2.

ITEM 7A.       QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEI:HEI

and HECO (in the case of HECO, only the information related to HECO and its subsidiaries):

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, 2010.

2012.

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.

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 Company is exposed to some commodity price risk primarily related to the fuel supply and IPP contracts of the electric utilities. The Company’s commodity price risk is substantially mitigated so long as the electric utilities have their current ECACs in their rate schedules. The Company currently has no hedges against its commodity price risk. The Company currently has no 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, and 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 electric 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.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 HEI’s “Notes to 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-

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specificscenario-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

82



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: t hethe 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).

ASB’s net portfolioConsistent with OCC guidelines, the market value (NPV) ratio is a measure of theor economic capitalization of ASB. The NPV ratioASB is the ratio of the net portfoliomeasured as economic value of ASB to the present value of expected net cash flows from existing assets. Net portfolio valueequity (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. The NPV ratio is calculated by ASB pursuant to guidelines established by the OTS in Thrift Bulletin 13a and The OTS Net Portfolio Value Model Manual. Key assumptions used in the calculation of ASB’s NPV ratioEVE include the prepayment behavior of loans and investments, the possible distribution of future interest rates, pricing spreads for as setsassets and liabilities in the alternate scenarios and the rate and balance behavior of deposit accounts with indeterminate maturities. Typically, if the value of ASB’s assets grows relative to the value of its liabilities, the NPV ratio will increase. Conversely, if the value of ASB’s liabilities grows relative to the value of its assets, the NPV ratio will decrease. The NPV ratioEVE 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.

points (bp) up to + 300 bp. The NPV ratio sensitivity measurechange in EVE is measured as the change in EVE in a given rate scenario from the NPV ratio calculated in the base case toand expressed as a percentage. To gain further insight into the NPV ratio calculatedIRR profile, additional analysis is periodically performed in the alternate scenarios including rate scenarios. The sensitivity measure alone is not necessarily indicativeshifts of the interest-rate risk of an institution, as institutions with high levels of capital may be able to support a high sensitivity measure. This measure is evaluatedgreater magnitude, yield curve twists and changes in conjunction with the NPV ratio calculated in each scenario.

key balance sheet drivers.

ASB’s interest-rate risk sensitivity measures as of December 31, 20102012 and 20092011 constitute “forward-looking statements” and were as follows:

 

 

 

2010

 

2009

 

December 31
Change in interest rates

 

Change
in NII

 

NPV
ratio

 

NPV ratio
sensitivity*

 

Change
in NII

 

NPV
ratio

 

NPV ratio
sensitivity*

 

(basis points)

 

Gradual change

 

Instantaneous change

 

Gradual change

 

Instantaneous change

 

+300

 

(1.3

)%

12.04

%

(196

)

(0.3

)%

10.92

%

(245

)

+200

 

(1.3

)

12.84

 

(116

)

(0.3

)

11.86

 

(151

)

+100

 

(0.8

)

13.52

 

(48

)

(0.2

)

12.72

 

(65

)

Base

 

 

14.00

 

 

 

13.37

 

 

-100

 

(0.6

)

14.04

 

4

 

(0.9

)

13.53

 

16

 


*Change from base case in basis points (bp).

December 31

 

2012

 

2011

 

Change in interest rates

 

Change in NII

 

Change in EVE

 

Change in NII

 

Change in EVE

 

(basis points)

 

Gradual change

 

Instantaneous change

 

Gradual change

 

Instantaneous change

 

+300

 

1.6

%

 

(9.4

)%

 

0.5

%

 

(7.4)

%

 

+200

 

0.5

 

 

(4.9

)

 

(0.3

)

 

(3.8

)

 

+100

 

0.1

 

 

(1.9

)

 

(0.4

)

 

(1.5

)

 

Base

 

 

 

 

 

 

 

 

 

-100

 

(0.2

)

 

(1.7

)

 

(0.4

)

 

(3.5

)

 

 

Management believes that ASB’s interest rate risk position as of December 31, 20102012 represents a reasonable level of risk. UnderThe NII profile under the rising interest rate scenarios theis asset sensitive for all rate increases as of December 31, 2010 NII profile was more liability sensitive2012 compared to December 31, 20092011 due primarily to changes in assumption about the asset mix.

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Tablerepricing of Contents

certain commercial loans.

ASB’s base NPV ratioEVE was $767 million as of December 31, 2010 increased2012 compared to $848 million as of December 31, 2011 due to changes in discounting spreads for certain retail loans and changes in mix for core deposits.

The change in EVE was more sensitive in the rising scenarios as of December 31, 2012 compared to December 31, 20092011 due to the higher relative value ofshift in the mortgageinvestment portfolio towards a longer duration mix, and the decreasechanges in size and change inthe mix of the balance sheet.

ASB’s NPV ratio sensitivity as of December 31, 2010 was less sensitive in the rising rate scenarios compared to December 31, 2009 as the asset mix shifted from longer duration mortgages to shorter durationretail loans and investments.

core deposits.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity NPV ratio, and NPV ratio sensitivity analysesthe 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

83



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, 2010,2012, 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 (pension and other postretirement benefits)”benefits” in “Management’s discussion and analysis of financial condition and results of operations”HEI’s MD&A and Note 9 of HEI’s “Notes to Consolidated Financial Statements”) and the possible effect of interest rates on the electric utilities’ allowed rates of return (see  47;Electric“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 Medium-Termprivately-placed Senior Notes, is at fixed rates. Therefore, the estimated fair value of such debt is lower than the amount outstandingrates (see Note 15 of HEI’s “Notes to Consolidated Financial Statements”). See Note 6 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of the use of forward starting swaps to manage some of the interest rate risk associated with HEI’s planned issuancefair value of long-term debt, in the future.net-other than bank).

 

HECO:Other risks relating to HECO

 

TheAdditional information required by this itemItem 7A is set forth in HECO’s Quantitative and Qualitative Disclosures about Market Risk, incorporated herein by reference to pagepages 3 and 4 of HECO Exhibit 99.2.

 

ITEM 8.          FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

HEI:

 

Index to Consolidated Financial Statements

Page

Page

ReportsReport of Independent Registered Public Accounting FirmsFirm

9385

Consolidated Financial Statements

9586

 

9284



Table of Contents

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 sheetsheets as of December 31, 20102012 and 2011 and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for each of the year thenthree years in the period ended December 31, 2012 present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and its subsidiaries (the “Company”) at December 31, 2010,2012 and 2011, and the results of their operations and their cash flows for each of the year thenthree years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010,2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s m anagementmanagement is responsible for these financial statements, 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 and on the Company’s internal control over financial reporting based on our integrated audit.audits.  We conducted our auditaudits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the auditaudits 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 auditaudits of the financial statements included examining, on a test basis, evidence supporting the amounts an dand 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 auditaudits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit providesaudits provide a reasonable basis for our opinion.opinions.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of January 1, 2010.

 

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) prov ideprovide 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 18, 201119, 2013

 

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Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Hawaiian Electric Industries, Inc.:

We have audited the accompanying consolidated balance sheet of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2009, and the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2009, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Honolulu, Hawaii
February 19, 2010

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Table of Contents

Consolidated Statements of Income

Hawaiian Electric Industries, Inc. and Subsidiaries

 

Years ended December 31

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric utility

 

$

2,382,366

 

$

2,035,009

 

$

2,860,350

 

$

3,109,439

$

2,978,690

$

2,382,366

 

Bank

 

282,693

 

274,719

 

358,553

 

 

265,539

 

264,407

 

282,693

 

Other

 

(77

)

(138

)

17

 

 

17

 

(762)

 

(77)

 

 

2,664,982

 

2,309,590

 

3,218,920

 

Total revenues

 

3,374,995

 

3,242,335

 

2,664,982

 

Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric utility

 

2,203,978

 

1,865,338

 

2,668,991

 

 

2,896,427

 

2,763,556

 

2,203,978

 

Bank

 

190,105

 

242,955

 

331,601

 

 

177,106

 

172,806

 

190,105

 

Other

 

14,688

 

13,633

 

14,171

 

 

17,266

 

16,277

 

14,688

 

 

2,408,771

 

2,121,926

 

3,014,763

 

Total expenses

 

3,090,799

 

2,952,639

 

2,408,771

 

Operating income (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electric utility

 

178,388

 

169,671

 

191,359

 

 

213,012

 

215,134

 

178,388

 

Bank

 

92,588

 

31,764

 

26,952

 

 

88,433

 

91,601

 

92,588

 

Other

 

(14,765

)

(13,771

)

(14,154

)

 

(17,249)

 

(17,039)

 

(14,765)

 

 

256,211

 

187,664

 

204,157

 

Interest expense — other than on deposit liabilities and other bank borrowings

 

(81,538

)

(76,330

)

(76,142

)

Total operating income

 

284,196

 

289,696

 

256,211

 

Interest expense – other than on deposit liabilities and other bank borrowings

 

(78,151)

 

(82,106)

 

(81,538)

 

Allowance for borrowed funds used during construction

 

2,558

 

5,268

 

3,741

 

 

4,355

 

2,498

 

2,558

 

Allowance for equity funds used during construction

 

6,016

 

12,222

 

9,390

 

 

7,007

 

5,964

 

6,016

 

Income before income taxes

 

183,247

 

128,824

 

141,146

 

 

217,407

 

216,052

 

183,247

 

Income taxes

 

67,822

 

43,923

 

48,978

 

 

76,859

 

75,932

 

67,822

 

Net income

 

115,425

 

84,901

 

92,168

 

 

140,548

 

140,120

 

115,425

 

Preferred stock dividends of subsidiaries

 

1,890

 

1,890

 

1,890

 

 

1,890

 

1,890

 

1,890

 

Net income for common stock

 

$

113,535

 

$

83,011

 

$

90,278

 

$

138,658

$

138,230

$

113,535

 

Basic earnings per common share

 

$

1.22

 

$

0.91

 

$

1.07

 

$

1.43

$

1.45

$

1.22

 

Diluted earnings per common share

 

$

1.21

 

$

0.91

 

$

1.07

 

$

1.42

$

1.44

$

1.21

 

Dividends per common share

 

$

1.24

 

$

1.24

 

$

1.24

 

$

1.24

$

1.24

$

1.24

 

Weighted-average number of common shares outstanding

 

93,421

 

91,396

 

84,631

 

 

96,908

 

95,510

 

93,421

 

Dilutive effect of share-based compensation

 

272

 

120

 

89

 

 

430

 

310

 

272

 

Adjusted weighted-average shares

 

93,693

 

91,516

 

84,720

 

 

97,338

 

95,820

 

93,693

 

 

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

 

9586



Consolidated Statements of Comprehensive Income

Hawaiian Electric Industries, Inc. and Subsidiaries

Years ended December 31

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

$

138,658

$

138,230

$

113,535

 

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 ($631), ($4,343) and $789 for 2012, 2011 and 2010, respectively

 

956

 

6,578

 

(1,196)

 

Less: reclassification adjustment for net realized gains included in net income, net of taxes of $53, $148 and nil for 2012, 2011 and 2010, respectively

 

(81)

 

(224)

 

 

Derivatives qualified as cash flow hedges:

 

 

 

 

 

 

 

Net unrealized holding losses arising during the period, net of tax benefits of nil, $4 and $745 for 2012, 2011 and 2010, respectively

 

 

(8)

 

(1,169)

 

Less: reclassification adjustment to net income, net of tax benefits of $150, $115 and nil for 2012, 2011 and 2010, respectively

 

236

 

181

 

 

Retirement benefit plans:

 

 

 

 

 

 

 

Prior service credit arising during the period, net of taxes of nil, $4,422 and $3,001 for 2012, 2011 and 2010, respectively

 

 

6,943

 

4,712

 

Net losses arising during the period, net of tax benefits of $63,303, $83,147 and $28,431 for 2012, 2011 and 2010, respectively

 

(99,159)

 

(130,191)

 

(44,626)

 

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 $9,764, $5,976 and $2,566 for 2012, 2011 and 2010, respectively

 

15,291

 

9,364

 

4,030

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,299, $64,134 and $21,336 for 2012, 2011 and 2010, respectively

 

75,471

 

100,692

 

33,499

 

Other comprehensive loss, net of tax benefits

 

(7,286)

 

(6,665)

 

(4,750)

 

Comprehensive income attributable to Hawaiian Electric Industries, Inc.

$

131,372

$

131,565

$

108,785

 

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

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Table of Contents

Consolidated Balance Sheets

Hawaiian Electric Industries, Inc. and Subsidiaries

 

December 31

 

 

 

2010

 

 

 

2009

 

 

 

 

2012

 

 

 

2011

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

$

330,651

 

 

 

$

503,922

 

 

 

$

219,662

 

 

$

270,265

 

Accounts receivable and unbilled revenues, net

 

 

 

266,996

 

 

 

241,116

 

 

 

 

362,823

 

 

 

344,322

 

Available-for-sale investment and mortgage-related securities

 

 

 

678,152

 

 

 

432,881

 

 

 

 

671,358

 

 

 

624,331

 

Investment in stock of Federal Home Loan Bank of Seattle

 

 

 

97,764

 

 

 

97,764

 

 

 

 

96,022

 

 

 

97,764

 

Loans receivable held for investment, net

 

 

 

3,489,880

 

 

 

3,645,578

 

 

 

 

3,737,233

 

 

 

3,642,818

 

Loans held for sale, at lower of cost or fair value

 

 

 

7,849

 

 

 

24,915

 

 

 

 

26,005

 

 

 

9,601

 

Property, plant and equipment, net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Land

 

$

66,002

 

 

 

$

67,381

 

 

 

 

$      70,799

 

 

 

$     66,152

 

 

 

Plant and equipment

 

5,034,211

 

 

 

4,832,740

 

 

 

 

5,492,963

 

 

 

5,177,453

 

 

 

Construction in progress

 

103,303

 

 

 

133,972

 

 

 

 

156,353

 

 

 

140,717

 

 

 

 

5,203,516

 

 

 

5,034,093

 

 

 

 

5,720,115

 

 

 

5,384,322

 

 

 

Less — accumulated depreciation

 

(2,037,598

)

3,165,918

 

(1,945,482

)

3,088,611

 

Less – accumulated depreciation

 

(2,125,286)

 

3,594,829

 

(2,049,821)

 

3,334,501

 

Regulatory assets

 

 

 

478,330

 

 

 

426,862

 

 

 

 

864,596

 

 

 

669,389

 

Other

 

 

 

487,614

 

 

 

381,163

 

 

 

 

494,414

 

 

 

519,296

 

Goodwill

 

 

 

82,190

 

 

 

82,190

 

 

 

 

82,190

 

 

 

82,190

 

Total assets

 

 

 

$

9,085,344

 

 

 

$

8,925,002

 

 

 

$

10,149,132

 

 

$

9,594,477

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts payable

 

 

 

$

202,446

 

 

 

$

159,044

 

 

 

$

212,379

 

 

$

216,176

 

Interest and dividends payable

 

 

 

27,814

 

 

 

27,950

 

 

 

 

26,258

 

 

 

25,041

 

Deposit liabilities

 

 

 

3,975,372

 

 

 

4,058,760

 

 

 

 

4,229,916

 

 

 

4,070,032

 

Short-term borrowings—other than bank

 

 

 

24,923

 

 

 

41,989

 

 

 

 

83,693

 

 

 

68,821

 

Other bank borrowings

 

 

 

237,319

 

 

 

297,628

 

 

 

 

195,926

 

 

 

233,229

 

Long-term debt, net—other than bank

 

 

 

1,364,942

 

 

 

1,364,815

 

 

 

 

1,422,872

 

 

 

1,340,070

 

Deferred income taxes

 

 

 

278,958

 

 

 

188,875

 

 

 

 

439,329

 

 

 

354,051

 

Regulatory liabilities

 

 

 

296,797

 

 

 

288,214

 

 

 

 

322,074

 

 

 

315,466

 

Contributions in aid of construction

 

 

 

335,364

 

 

 

321,544

 

 

 

 

405,520

 

 

 

356,203

 

Retirement benefits liability

 

 

 

656,394

 

 

 

530,407

 

Other

 

 

 

823,479

 

 

 

700,242

 

 

 

 

526,613

 

 

 

521,982

 

Total liabilities

 

 

 

7,567,414

 

 

 

7,449,061

 

 

 

 

8,520,974

 

 

 

8,031,478

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred stock of subsidiaries - not subject to mandatory redemption

 

 

 

34,293

 

 

 

34,293

 

 

 

 

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: 94,690,932 shares and 92,520,638 shares in 2010 and 2009, respectively

 

 

 

1,314,199

 

 

 

1,265,157

 

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 97,928,403 shares and 96,038,328 shares in 2012 and 2011, respectively

 

 

 

1,403,484

 

 

 

1,349,446

 

Retained earnings

 

 

 

181,910

 

 

 

184,213

 

 

 

 

216,804

 

 

 

198,397

 

Accumulated other comprehensive income (loss), net of taxes

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net unrealized gains on securities

 

$

3,532

 

 

 

$

4,728

 

 

 

 

$  10,761

 

 

 

$   9,886

 

 

 

Unrealized losses on derivatives

 

(1,169

)

 

 

 

 

 

 

(760)

 

 

 

(996)

 

 

 

Retirement benefit plans

 

(14,835

)

(12,472

)

(12,450

)

(7,722

)

 

(36,424)

 

(26,423)

 

(28,027)

 

(19,137)

 

Total shareholders’ equity

 

 

 

1,483,637

 

 

 

1,441,648

 

 

 

 

1,593,865

 

 

 

1,528,706

 

Total liabilities and shareholders’ equity

 

 

 

$

9,085,344

 

 

 

$

8,925,002

 

 

 

$

10,149,132

 

 

$

9,594,477

 

 

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

 

9688



Table of Contents

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, 2007

 

83,432

 

1,072,101

 

225,168

 

(21,842

)

1,275,427

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

 

 

90,278

 

 

90,278

 

Net unrealized losses on securities:

 

 

 

 

 

 

 

 

 

 

 

Net unrealized losses arising during the period, net of tax benefits of $19,892

 

 

 

 

(30,124

)

(30,124

)

Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $9,998

 

 

 

 

15,142

 

15,142

 

Retirement benefit plans:

 

 

 

 

 

 

 

 

 

 

 

Prior service credit arising during the period, net of taxes of $641

 

 

 

 

992

 

992

 

Net losses arising during the period, net of tax benefits of $111,967

 

 

 

 

(175,240

)

(175,240

)

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 $3,696

 

 

 

 

5,801

 

5,801

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $96,975

 

 

 

 

152,256

 

152,256

 

Other comprehensive loss

 

 

 

 

 

 

 

(31,173

)

 

 

Comprehensive income

 

 

 

 

 

 

 

 

 

59,105

 

Issuance of common stock:

Common stock offering

 

5,000

 

115,000

 

 

 

115,000

 

 

Dividend reinvestment and stock purchase plan

 

1,425

 

34,607

 

 

 

34,607

 

 

Retirement savings and other plans

 

659

 

15,267

 

 

 

15,267

 

 

Expenses and other, net

 

 

(5,346

)

 

 

(5,346

)

Common stock dividends ($1.24 per share)

 

 

 

(104,606

)

 

(104,606

)

Balance, December 31, 2008

 

90,516

 

1,231,629

 

210,840

 

(53,015

)

1,389,454

 

Cumulative effect of adoption of a standard on other-than-temporary

 

 

 

 

 

 

 

 

 

 

 

Impairment recognition, net of taxes of $2,497

 

 

 

3,781

 

(3,781

)

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

 

 

83,011

 

 

83,011

 

Net unrealized gains on securities:

 

 

 

 

 

 

 

 

 

 

 

Net unrealized gains on securities arising during the period, net of taxes of $8,543

 

 

 

 

12,938

 

12,938

 

Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $18,882

 

 

 

 

28,596

 

28,596

 

Retirement benefit plans:

 

 

 

 

 

 

 

 

 

 

 

Net transition asset arising during the period, net of taxes of $4,172

 

 

 

 

6,549

 

6,549

 

Prior service credit arising during the period, net of taxes of $921

 

 

 

 

1,446

 

1,446

 

Net gains arising during the period, net of taxes of $41,218

 

 

 

 

64,547

 

64,547

 

Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $6,861

 

 

 

 

10,754

 

10,754

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,251

 

 

 

 

(75,756

)

(75,756

)

Other comprehensive income

 

 

 

 

 

 

 

49,074

 

 

 

Comprehensive income

 

 

 

 

 

 

 

 

 

132,085

 

Issuance of common stock:

Dividend reinvestment and stock purchase plan

 

1,714

 

27,701

 

 

 

27,701

 

 

Retirement savings and other plans

 

291

 

4,771

 

 

 

4,771

 

 

Expenses and other, net

 

 

1,056

 

 

 

1,056

 

Common stock dividends ($1.24 per share)

 

 

 

(113,419

)

 

(113,419

)

Balance, December 31, 2009

 

92,521

 

1,265,157

 

184,213

 

(7,722

)

1,441,648

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

 

 

113,535

 

 

113,535

 

Net unrealized losses on securities:

 

 

 

 

 

 

 

 

 

 

 

Net unrealized losses on securities arising during the period, net of tax benefits of $789

 

 

 

 

(1,196

)

(1,196

)

Unrealized losses on derivatives qualified as cash flow hedges:

 

 

 

 

 

 

 

 

 

 

 

Net unrealized holding losses arising during the period, net of tax benefits of $745

 

 

 

 

 

 

 

(1,169

)

(1,169

)

Retirement benefit plans:

 

 

 

 

 

 

 

 

 

 

 

Prior service credit arising during the period, net of taxes of $3,001

 

 

 

 

4,712

 

4,712

 

Net losses arising during the period, net of tax benefits of $28,431

 

 

 

 

(44,626

)

(44,626

)

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 $2,566

 

 

 

 

4,030

 

4,030

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $21,336

 

 

 

 

33,499

 

33,499

 

Other comprehensive loss

 

 

 

 

 

 

 

(4,750

)

 

 

Comprehensive income

 

 

 

 

 

 

 

 

 

108,785

 

Issuance of common stock:

Dividend reinvestment and stock purchase plan

 

1,685

 

37,296

 

 

 

37,296

 

 

Retirement savings and other plans

 

485

 

8,934

 

 

 

8,934

 

 

Expenses and other, net

 

 

2,812

 

 

 

2,812

 

Common stock dividends ($1.24 per share)

 

 

 

(115,838

)

 

(115,838

)

Balance, December 31, 2010

 

94,691

 

1,314,199

 

181,910

 

(12,472

)

1,483,637

 

 

 

Common stock

 

Retained

 

Accumulated
other
comprehensive

 

 

 

(in thousands, except per share amounts)

 

Shares

 

Amount

 

earnings

 

income (loss)

 

Total

 

Balance, December 31, 2009

 

92,521

$

1,265,157

$

180,970

 

$    (7,722)

$

1,438,405

 

Net income for common stock

 

 

 

113,535

 

 

113,535

 

Other comprehensive loss, net of tax benefits

 

 

 

 

(4,750)

 

(4,750)

 

Issuance of common stock:

 

 

 

 

 

 

 

 

 

 

 

Dividend reinvestment and stock purchase plan

 

1,685

 

37,296

 

 

 

37,296

 

Retirement savings and other plans

 

485

 

8,934

 

 

 

8,934

 

Expenses and other, net

 

 

2,812

 

 

 

2,812

 

Common stock dividends ($1.24 per share)

 

 

 

(115,838)

 

 

(115,838)

 

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

 

 

As of December 31, 2010, HEI2012, Hawaiian Electric Industries, Inc. (HEI) had reserved a total of 18,816,26018,803,821 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 19902011 Nonemployee Director Stock Plan, the ASBAmerican Savings Bank, F.S.B. (ASB) 401(k) Plan and the 2010 Executive Incentive Plan.

 

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

 

9789



Table of Contents

Consolidated Statements of Cash Flows

Hawaiian Electric Industries, Inc. and Subsidiaries

 

Years ended December 31

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

115,425

 

$

84,901

 

$

92,168

 

 

$  140,548

 

$  140,120

 

$  115,425

 

Adjustments to reconcile net income to net cash provided by operating activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation of property, plant and equipment

 

154,523

 

151,282

 

150,977

 

 

150,389

 

148,152

 

154,523

 

Other amortization

 

4,605

 

5,389

 

5,085

 

 

7,958

 

19,318

 

4,605

 

Provision for loan losses

 

20,894

 

32,000

 

10,334

 

 

12,883

 

15,009

 

20,894

 

Gain on pension curtailment

 

 

 

(472

)

Impairment of utility assets

 

40,000

 

9,215

 

 

Loans receivable originated and purchased, held for sale

 

(360,527

)

(443,843

)

(204,457

)

 

(519,622)

 

(267,656)

 

(360,527)

 

Proceeds from sale of loans receivable, held for sale

 

392,406

 

471,194

 

185,291

 

 

513,000

 

273,932

 

392,406

 

Net losses on sale of investment and mortgage-related securities

 

 

32,034

 

17,376

 

Other-than-temporary impairment on available-for-sale mortgage-related securities

 

 

15,444

 

7,764

 

Changes in deferred income taxes

 

97,791

 

12,787

 

5,134

 

Changes in excess tax benefits from share-based payment arrangements

 

45

 

310

 

(405

)

Change in deferred income taxes

 

90,848

 

79,444

 

97,791

 

Change in excess tax benefits from share-based payment arrangements

 

(61)

 

35

 

45

 

Allowance for equity funds used during construction

 

(6,016

)

(12,222

)

(9,390

)

 

(7,007)

 

(5,964)

 

(6,016)

 

Decrease in cash overdraft

 

(141

)

 

 

Change in cash overdraft

 

 

(2,688)

 

(141)

 

Changes in assets and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable and unbilled revenues, net

 

(25,880

)

59,550

 

(6,219

)

Increase in accounts receivable and unbilled revenues, net

 

(18,501)

 

(77,326)

 

(25,880)

 

Decrease (increase) in fuel oil stock

 

(74,044

)

(946

)

14,157

 

 

10,129

 

(18,843)

 

(74,044)

 

Increase (decrease) in accounts, interest and dividends payable

 

43,266

 

3,410

 

(18,715

)

Changes in prepaid and accrued income taxes and utility revenue taxes

 

(5,252

)

(61,977

)

16,466

 

Changes in other assets and liabilities

 

(16,378

)

(64,845

)

(5,280

)

Increase in regulatory assets

 

(72,401)

 

(40,132)

 

(2,936)

 

Increase (decrease) in accounts, interest and dividends payable

 

(39,738)

 

(34,480)

 

22,410

 

Change in prepaid and accrued income taxes and utility revenue taxes

 

21,079

 

73,153

 

(5,252)

 

Contributions to defined benefit pension and other postretirement benefit plans

 

(77,703)

 

(74,961)

 

(31,792)

 

Change in other assets and liabilities

 

(17,259)

 

14,038

 

39,206

 

Net cash provided by operating activities

 

340,717

 

284,468

 

259,814

 

 

234,542

 

250,366

 

340,717

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale investment and mortgage-related securities purchased

 

(714,552

)

(297,864

)

(489,264

)

 

(243,633)

 

(361,876)

 

(714,552)

 

Principal repayments on available-for-sale investment and mortgage-related securities

 

465,437

 

357,233

 

610,521

 

 

191,253

 

389,906

 

465,437

 

Proceeds from sale of available-for-sale investment and mortgage-related securities

 

 

185,134

 

1,311,596

 

 

3,548

 

32,799

 

 

Proceeds from sale of other investments

 

 

 

17

 

Net decrease (increase) in loans held for investment

 

118,892

 

484,960

 

(92,241

)

 

(112,730)

 

(181,080)

 

118,892

 

Proceeds from sale of real estate acquired in settlement of loans

 

5,967

 

1,555

 

 

 

11,336

 

8,020

 

5,967

 

Capital expenditures

 

(182,125

)

(304,761

)

(282,051

)

 

(325,480)

 

(235,116)

 

(182,125)

 

Contributions in aid of construction

 

22,555

 

14,170

 

17,319

 

 

45,982

 

23,534

 

22,555

 

Other

 

5,092

 

1,199

 

1,116

 

 

2,677

 

(2,974)

 

5,092

 

Net cash provided by (used in) investing activities

 

(278,734

)

441,626

 

1,077,013

 

Net cash used in investing activities

 

(427,047)

 

(326,787)

 

(278,734)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net decrease in deposit liabilities

 

(83,388

)

(121,415

)

(167,085

)

Net increase (decrease) in deposit liabilities

 

159,884

 

94,660

 

(83,388)

 

Net increase (decrease) in short-term borrowings with original maturities of three months or less

 

(17,066

)

41,989

 

(91,780

)

 

14,872

 

43,898

 

(17,066)

 

Net decrease in retail repurchase agreements

 

(60,308

)

(3,829

)

(37,142

)

Net increase (decrease) in retail repurchase agreements

 

(37,291)

 

10,910

 

(60,308)

 

Proceeds from other bank borrowings

 

 

310,000

 

2,592,635

 

 

5,000

 

 

 

Repayments of other bank borrowings

 

 

(689,517

)

(3,682,119

)

 

(5,000)

 

(15,000)

 

 

Proceeds from issuance of long-term debt

 

 

153,186

 

19,275

 

 

457,000

 

125,000

 

 

Repayment of long-term debt

 

 

 

(50,000

)

 

(375,500)

 

(150,000)

 

 

Changes in excess tax benefits from share-based payment arrangements

 

(45

)

(310

)

405

 

Change in excess tax benefits from share-based payment arrangements

 

61

 

(35)

 

(45)

 

Net proceeds from issuance of common stock

 

22,706

 

15,329

 

136,443

 

 

23,613

 

15,979

 

22,706

 

Common stock dividends

 

(93,034

)

(96,843

)

(83,604

)

 

(96,202)

 

(106,812)

 

(93,034)

 

Preferred stock dividends of subsidiaries

 

(1,890

)

(1,890

)

(1,890

)

 

(1,890)

 

(1,890)

 

(1,890)

 

Increase (decrease) in cash overdraft

 

 

(9,545

)

1,265

 

Other

 

(2,229

)

(2,762

)

350

 

 

(2,645)

 

(675)

 

(2,229)

 

Net cash used in financing activities

 

(235,254

)

(405,607

)

(1,363,247

)

Net cash provided by (used in) financing activities

 

141,902

 

16,035

 

(235,254)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

(173,271

)

320,487

 

(26,420

)

Net decrease in cash and cash equivalents

 

(50,603)

 

(60,386)

 

(173,271)

 

Cash and cash equivalents, January 1

 

503,922

 

183,435

 

209,855

 

 

270,265

 

330,651

 

503,922

 

Cash and cash equivalents, December 31

 

$

330,651

 

$

503,922

 

$

183,435

 

 

$  219,662

 

$  270,265

 

$  330,651

 

 

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

 

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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’s common stock is traded on the New York Stock Exchange.

 

Basis of presentation.  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.

Consolidation.  The consolidated financial statements include the accounts of HEI and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable interest entities (VIEs) of whichwhen the Company is not the primary beneficiary. Investments in companies over which the Company has 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 Company considers cash on hand, deposits in banks, deposits with the Federal Home Loan Bank (FHLB) of Seattle, federal funds sold (excess funds that American Savings Bank, F.S.B. (ASB)ASB loans to other banks overnight at the federal funds rate), money market accounts, certificates of deposit, short-term commercial paper of non-affiliates, reverse repurchase agreements and liquid investments (with original maturities of three months or less) to be cash and cash equivalents.

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, temporary losses and temporaryother-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 other-than-temporary impairment (OTTI)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 befo rebefore recovery of its amortized cost, the OTTI shallmust 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

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basis and the cash flows expected to

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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 has 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 Company’s 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 other-than-temporary impairment.OTTI. Also see “Variable interest entities”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 property, plant and equipment when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make property, plant or equipment 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 cu stomerscustomers 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 6988 years for production plant, from 25 to 6065 years for transmission and distribution plant and from 75 to 4550 years for general plant. The electric utilities’ composite annual depreciation rate, which includes a component for cost of removal, was 3.1% in 2012, 3.2% in 2011 and 3.5% in 2010, 3.8% in 2009 and 3.8% in 2008.2010.

Leases.  HEI, HECOHawaiian Electric Company, Inc. (HECO) and its subsidiaries 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.

Operating lease expense was $19 million, $14 million and $13 million $16 millionin 2012, 2011 and $16 million in 2010, 2009 and 2008, respectively. Future minimum lease payments are $13$18 million, $12$17 million, $14 million, $11 million, $9 million $7and $29 million and $28 million for 2011, 2012, 2013, 2014, 2015, 2016, 2017 and thereafter, respectively.

Retirement benefits.  Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant. 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 co nsultingconsulting actuary. Under a pension tracking mechanism approved by the Public Utilities Commission of the State of Hawaii (PUC), Hawaiian Electric Company, Inc. (HECO)HECO generally will make contributions to the pension fund at the greater of the minimum level required under the law or net periodic pension cost less pension asset, until its pension asset (existing

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(existing at the time of the PUC decision and determined based on the cumulative fund contributions to the plans in excess of the cumulative net

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periodic pension cost recognized) is reduced to zero, at which time HECO would fund the pension cost as specified in the pension tracking mechanism. Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) will also generally fund the greater of the minimum level required under the law or net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

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 electric 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 recognizes on its balance sheet the funded status of its defined benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.

Environmental expenditures.  The Company is 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 to amortize the long-term debt financing costs of the holding company over the term of the related debt.

HECO and its subsidiaries 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 HECO and its subsidiaries’ 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 HECO and its subsidiaries 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 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.

Federal and stateThe 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 electric utility subsidiaries’ investment tax credits, which are deferred and amortized over the estimated useful lives of the properties to which qualified for the credits.

credits relate, in accordance with Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”

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 written off or an unanticipated tax liability might be incurred.

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The Company uses 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.  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

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similarly, except that common shares for dilutive stock compensation are added to the denominator. The Company 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, EPS was comprised as follows for both unvested restricted stock awards and unrestricted common stock:

 

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

Basic

 

Diluted

 

Basic and
diluted

 

Basic and
diluted

 

 

Basic

 

Diluted

 

Basic

 

Diluted

 

Basic

 

Diluted

 

Distributed earnings

 

$

1.24

 

$

1.24

 

$

1.24

 

$

1.24

 

 

$  1.24

 

$  1.24

 

$  1.24

 

$  1.24

 

$  1.24

 

$  1.24

 

Undistributed earnings (loss)

 

(0.02

)

(0.03

)

(0.33

)

(0.17

)

 

0.19

 

0.18

 

0.21

 

0.20

 

(0.02

)

(0.03

)

 

$

1.22

 

$

1.21

 

$

0.91

 

$

1.07

 

 

$  1.43

 

$  1.42

 

$  1.45

 

$  1.44

 

$  1.22

 

$  1.21

 

 

As of December 31, 20102012 and 2009,2010, the antidilutive effect of stock appreciation rights (SARs) on 450,000102,000 and 480,000450,000 shares of common stock (for which the SARs’ exercise prices were greater than the closing market priceprices of HEI’s common stock), respectively, 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 applies the fair value based method of accounting to account for its stock compensation, including the use of a forfeiture assumption. See Note 10.

Impairment of long-lived assets and long-lived assets to be disposed of.  The Company reviews 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.

Noncontrolling interestsOffsetting assets and liabilities.  In December 2007,2011, the FASB issued Accounting Standards Update (ASU) No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities,” which requires disclosures about financial instruments and derivative instruments that are either offset or subject to an enforceable master netting arrangement or similar agreement to enable financial statement users to understand the effect of those arrangements on the entity’s financial position. The Company believes that the adoption of ASU No 2011-11 will not have a standard thatmaterial impact on its financial statement disclosures.

Reporting of Amounts Reclassified Out of AOCI.  In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires companies to provide information about the recognitionamounts reclassified out of a noncontrolling interest (i.e., a minority interest) as equity in the consolidated financial statements, separate from the parent’s equity, and requires the amount of consolidated net income attributable to the parentAOCI by component and to the noncontrolling interest to be clearly identified and presentedpresent, either on the face of the statement where net income statement. Changesis presented or in the parent’s ownership interestnotes, significant amounts reclassified out of AOCI by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that leave control intact are accounted for as capital transactions (i.e., as increases or decreasesnot required under U.S. GAAP to be reclassified in ownership), a gain or loss will be recognized when a subsidiarytheir entirety to net income, an entity is deconsolidated based on the fair value of the noncontrolling equity investment (not carrying amount), and entities mustrequired to cross-reference to other disclosures required under U.S. GAAP that provide sufficient disclosures that c learly identify and distinguish between the interests of the parent and of the noncontrolling owners.additional detail about those amounts. The Company adoptedwill include the standard prospectively on January 1, 2009, exceptdisclosures required by ASU No. 2013-02 its financial statement for the presentation and disclosure requirements which must be applied retrospectively.

In April 2010, management evaluated the impact of Accounting Standards Update (ASU) 2009-04, “Accounting for Redeemable Equity Instruments,” and the provisions of the utilities’ $34 million of preferred stock that allowed preferred shareholders to potentially control the board if preferred dividends were not paid for four quarters, which could lead to the redemption of the preferred shares. This evaluation resulted in the movement of preferred stock of subsidiaries on the consolidated balance sheet from shareholders’ equity to mezzanine equity and the removal of preferred stock of subsidiaries from the consolidated statement of changes in shareholders’ equity for all prior periods presented, which changes were immaterial to the financial statements. There were no changes to previously reported operating income, net income, earnings per share and cash flows.

Variable interest entities.  In June 2009, the FASB issued a standard that amends the guidance in FASB Accounting Standards CodificationTM (ASC) Topic 810 related to the consolidation of VIEs. The standard eliminates exceptions to consolidating qualifying special-purpose entities, contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the

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characteristics that identify a VIE. The Company adopted this standard in the first quarter of 2010 and the adoption did not impact the Company’s financial condition, results of operations or cash flows.2013.

 

Allowance for Credit Losses.  In July 2010, the FASB issued ASU No. 2010-20, “Disclosures about the Credit Quality of Financing ReceivablesReclassifications and the Allowance for Credit Losses,” which requires the Company to provide a greater level of disaggregated information about the credit quality of the Company’s loans and leases and the Allowance for Loan and Lease Losses (the Allowance). This ASU also requires the Company to disclose additional information related to credit quality indicators, nonaccrual and past due information, and information related to impaired loans and loans modified in a troubled debt restructuring. See Note 4.

Reclassifications.revisions.  Certain reclassifications have been made to prior years’ financial statements to conform to the 20102012 presentation, which did not affect previously reported results of operations.

The Company has revised its electric utilities’ previously issued financial statements to correct an error that resulted in the understatement of franchise taxes, net of tax benefits, that should have been recorded in years

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prior to 2010. The Company determined the cumulative impact for periods prior to 2010 to be a charge to its earnings of $3.2 million. These adjustments were not considered to be material individually or in the aggregate to previously issued financial statements. The table below illustrates the effects of this revision on the Company’s Consolidated Financial Statements for those line items affected (these revisions have no impact on the Company’s Consolidated Statements of Income and Cash Flows for the periods reported):

(dollars in thousands)

 

As previously filed

 

As revised

 

Difference

 

December 31, 2011

 

 

 

 

 

 

 

Consolidated Balance Sheet

 

 

 

 

 

 

 

Other assets

 

517,550

 

519,296

 

1,746

 

Total assets

 

9,592,731

 

9,594,477

 

1,746

 

 

 

 

 

 

 

 

 

Other liabilities

 

516,990

 

521,979

 

4,989

 

Total liabilities

 

8,026,489

 

8,031,478

 

4,989

 

Retained earnings

 

201,640

 

198,397

 

(3,243)

 

Total shareholders’ equity

 

1,531,949

 

1,528,706

 

(3,243)

 

Total liabilities and shareholders’ equity

 

9,592,731

 

9,594,477

 

1,746

 

 

 

 

 

 

 

 

 

Consolidated Statement of Changes in Shareholders’ Equity

 

 

 

 

 

 

 

Retained earnings

 

201,640

 

198,397

 

(3,243)

 

Total shareholders’ equity

 

1,531,949

 

1,528,706

 

(3,243)

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

 

 

Consolidated Statement of Changes in Shareholders’ Equity

 

 

 

 

 

 

 

Retained earnings

 

181,910

 

178,667

 

(3,243)

 

Total shareholders’ equity

 

1,483,637

 

1,480,394

 

(3,243)

 

 

 

 

 

 

 

 

 

December 31, 2009

 

 

 

 

 

 

 

Consolidated Statement of Changes in Shareholders’ Equity

 

 

 

 

 

 

 

Retained earnings

 

184,213

 

180,970

 

(3,243)

 

Total shareholders’ equity

 

1,441,648

 

1,438,405

 

(3,243)

 

Electric utility

 

Accounts receivable.  Accounts receivable are recorded at the invoiced amount. The electric utilities generally assess a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. On a monthly basis, the Company adjusts its 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. As of December 31, 2012 and 2011, the allowance for customer accounts receivable, accrued unbilled revenues and other accounts receivable was $2 million.

Contributions in aid of construction.  The electric 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 PUCPUC. 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 includeincluded revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers.

The rate schedules of the electric 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 ECACsrate schedules also include a provision requiring a quarterly reconciliation ofpurchased power adjustment clauses (PPACs) under which the remaining purchase power expenses are recovered through surcharge mechanisms. The amounts collected through the ECACs.ECACs and PPACs are required to be reconciled quarterly.

Upon the implementation of decoupling (HECO on March 1, 2011, HELCO on April 9, 2012 and MECO on May 4, 2012), the electric 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

 

95



adjustment mechanism (RAM) for certain 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 ROACE exceeds the ROACE allowed in its most recent rate case.

HECO and its subsidiaries’ 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, HECO and its subsidiaries’ revenue tax payments to the taxing authorities in the period are based on the prior years’ revenues.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 2010, 20092012, 2011 and 2008,2010, HECO and its subsidiaries included approximately $211$280 million, $181$264 million and $252$211 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 electric utility would recognize a capital asset and a lease obligation. Currently, none of the PPAs isare 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

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extended period of time, as it was in the case of HELCO’s installation of CT-4 and CT-5, 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 2012, 8.0% in 2011 and 8.1% in 2010, 2009 and 2008, and reflected quarterly compounding.

Bank

 

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 and educational loans held for sale are stated at the lower of cost or estimated marketfair value on an aggregate basis. Generally, the determination of marketfair 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

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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 ref lectedreflected 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.

For commercialCommercial and commercial real estate loans are defined as non-homogeneous loans and ASB utilizes a ten-point risk rating system is used.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

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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 loss.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 securedcollateralized 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 flows areflow method is used to measure impairment. For loans securedcollateralized by real estate that are classified as troubled debt restructured loans, th ethe present value of the expected future cash flows of the loans may also be used to measure impairment. Losses from 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.

For the residential,Residential, consumer and credit scored business loans are considered homogeneous commercial loans, receivablewhich 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 usefor 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 the actual loss experience, ASB considers the following qualitative factors for all loans in estimating the allowance for loan losses:

97



 

·                 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 and changes in the level of any concentrations of credit

·                 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 generally on the cash method. When, in management’s judgment, 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 the State of 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 certain concessions to the borrower that it would not otherwise consider. Modifications may include interest rate reductions, forbearance,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 th ethe 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.

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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 the lower of cost or 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. As of December 31, 20102012 and 2009,2011, ASB had $4.3$6.1 million and $4.0$7.3 million, respectively, of real estate acquired in settlement of loans.

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.”other” (ASC 350).

Goodwill.  At December 201031, 2012 and 2009,2011, the amount of goodwill was $82.2 million, which 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.

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In December 2008,September 2011, ASB recordedadopted FASB ASU 2011-8, “Intangibles-Goodwill and Other (Topic 350): Testing Goodwill for Impairment” (ASU 2011-8), which permits an entity to first assess qualitative factors (Step 0) to determine whether it is more likely than not (that is, a write-offlikelihood of $0.9 millionmore than 50%) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform Step 1 of a two-step goodwill relatedimpairment test. An entity has an unconditional option to bypass the qualitative assessment and proceed directly to performing the first step of the goodwill impairment test. In evaluating whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount under ASU 2011-8, an entity shall assess relevant events and circumstances such as:

1.Macroeconomic conditions such as a deterioration in general economic conditions, limitations on accessing capital, or other developments in equity and credit markets;

2.Industry and market considerations such as a deterioration in the environment in which an entity operates, an increased competitive environment, a change in the market for an entity’s products or services, or a regulatory or political development;

3.Cost factors that have a negative effect on earnings and cash flows;

4.Overall financial performance such as a decline in actual or planned revenues or earnings compared with actual and projected results of relevant prior periods;

5.Other relevant entity-specific events such as changes in management, key personnel, strategy, or customers; contemplation of bankruptcy; or litigation;

6.Events affecting a reporting unit such as a change in the composition or carrying amount of its net assets;

7.If applicable, a sustained decrease in share price (considered in both absolute terms and relative to peers).

If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then the first and second steps of the goodwill impairment test under ASC 350 are unnecessary. ASB performed a Step 0 analysis and considered the following events and circumstances in its analysis:

·Macroeconomic conditions – the national economy has stabilized and the Hawaii economy continues to improve. ASB’s business is primarily in the state of Hawaii which continues to show a stabilization of job growth and modest growth in the economy.

·Interest rate environment – the continued low interest rate environment will put pressure on ASB’s net interest margin. ASB has strategic plans to grow the loan portfolio and credit quality continues to improve.

·Financial performance – ASB’s profitability measures of net interest margin, return on assets, return on equity, efficiency ratio and net charge-offs compare favorably to industry peers.

·Regulation and legislation – the impact of lower noninterest income as a result of changes in fee legislation has been reflected in ASB’s financial results and the Durbin Amendment to the saleDodd-Frank Act does not apply to ASB as the bank is under $10 billion of assets.

Based on its analysis, ASB determined that it was not more likely than not that the business of Bishop Insurance Agency. For the three years ended December 31, 2010, there has been no impairment of goodwill. The fair value of ASB was estimated using a valuation method based on a market approach and discounted cash flows with each method having an equal weighting in determining the fair value of ASB. T he market approach primarily considers publicly traded financial institutions with assets of $3 billion to $8 billion and measures the institutions’ market valuesless than its carrying value. The most recent Step 1 goodwill impairment analysis under ASC 350 was performed as a multiple to (1) net income and (2) book equity. The median market value multiples for net income and book equity are then applied to ASB’s net income and book equity to calculate ASB’s fair value using the market approach. The fair value using the market approach also included a 20% control premium. The discounted cash flow analysis uses ASB’s forecasted cash flows and applies a discount rate to present value the cash flows. The discount rate used in the analysis was 10.4%. As of September 30, 2010 and the estimated fair value of ASB exceeded its book value by approximately 35%. For the three years ended December 31, 2012, there has been no impairment of goodwill.

Amortized intangible assets.

 

December 31

 

2012

 

2011

 

 

2010

 

2009

 

 

Gross

carrying

Accumulated

Valuation

Net
carrying

 

Gross

carrying

Accumulated

Valuation

Net
carrying

 

December 31

 

Gross carrying

 

Accumulated

 

Gross carrying

 

Accumulated

 

(in thousands)

 

amount

 

amortization

 

amount

 

Amortization

 

 

amount

amortization

allowance

amount

 

amount

amortization

allowance

amount

 

Mortgage servicing assets

 

$

18,483

 

$

11,656

 

$

15,205

 

$

10,804

 

 

$25,835

(14,519)

(498)

$10,818

 

$21,171

(12,769)

(175)

$8,227

 

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

 

(in thousands)

 

2010

 

2009

 

2008

 

Valuation allowance, January 1

 

$

201

 

$

268

 

$

189

 

Provision (recovery)

 

(12

)

166

 

278

 

Other-than-temporary impairment

 

(61

)

(233

)

(199

)

Valuation allowance, December 31

 

$

128

 

$

201

 

$

268

 

In 2010, 2009 and 2008, aggregate amortization expenses were $0.9 million, $0.8 million and $0.4 million, respectively.

(in thousands)

 

2012

 

2011

 

2010

 

Valuation allowance, January 1

 

$ 175

 

$128

 

$201

 

Provision (recovery)

 

504

 

121

 

(12

)

Other-than-temporary impairment

 

(181

)

(74

)

(61

)

Valuation allowance, December 31

 

$ 498

 

$175

 

$128

 

 

The estimated aggregate amortization expenses for mortgage servicing assets for 2011, 2012, 2013, 2014, 2015, 2016 and 20152017 are $1.0$1.9 million, $0.8$1.5 million, $0.7$1.3 million, $0.6$1.1 million and $0.5$0.9 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. As of December 31,In 2012, 2011 and 2010, and 2009, the mortgage servicing assets had a net carrying value of $6.7 million and $4.2 million, respectively. In 2010, 2009 and 2008, mortgage servicing assets

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acquired through the sale or securitization of loans held for sale were $3.3$4.8 million, $3.3$2.8 million and $0.6$3.3 million, respectively. Amortization expenses for ASB’s mortgage servicing assets amounted to $1.7 million, $1.1 million and $0.9 million $0.8 millionfor 2012, 2011 and $0.4 million for 2010, 2009 and 2008, 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 in the summary of significant accounting policies, 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. The CompanyEach 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

 

HECO and its wholly-owned operating subsidiaries, HELCO and MECO, 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. HECO, HELCO and MECO 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. HECO also owns the following non-regulated 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) (whose functions are to be transferred to the Office of the Comptroller of the Currency)) and the Federal Deposit Insurance Corporation (FDIC), and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System.

 

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Other

“Other” includes amounts for the holding companies (HEI and 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

 

 

Electric utility

 

Bank   

 

Other   

 

Total   

 

 

 

 

 

 

 

 

 

 

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

 

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

 

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

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

2,382,211

 

$

282,693

 

$

78

 

$

2,664,982

 

 

$2,382,211

 

$  282,693

 

$       78

 

$2,664,982

 

Intersegment revenues (eliminations)

 

155

 

 

(155

)

 

 

155

 

 

(155

)

 

Revenues

 

2,382,366

 

282,693

 

(77

)

2,664,982

 

 

2,382,366

 

282,693

 

(77

)

2,664,982

 

Depreciation and amortization

 

157,432

 

749

 

947

 

159,128

 

 

157,432

 

749

 

947

 

159,128

 

Interest expense

 

61,510

 

20,349

 

20,028

 

101,887

 

 

61,510

 

20,349

 

20,028

 

101,887

 

Income (loss) before income taxes

 

125,452

 

92,512

 

(34,717

)

183,247

 

 

125,452

 

92,512

 

(34,717

)

183,247

 

Income taxes (benefit)

 

46,868

 

34,056

 

(13,102

)

67,822

 

 

46,868

 

34,056

 

(13,102

)

67,822

 

Net income (loss)

 

78,584

 

58,456

 

(21,615

)

115,425

 

 

78,584

 

58,456

 

(21,615

)

115,425

 

Preferred stock dividends of subsidiaries

 

1,995

 

 

(105

)

1,890

 

 

1,995

 

 

(105

)

1,890

 

Net income (loss) for common stock

 

76,589

 

58,456

 

(21,510

)

113,535

 

 

76,589

 

58,456

 

(21,510

)

113,535

 

Capital expenditures

 

174,344

 

7,709

 

72

 

182,125

 

 

174,344

 

7,709

 

72

 

182,125

 

Tangible assets (at December 31, 2010)

 

4,285,680

 

4,707,870

 

2,905

 

8,996,455

 

2009

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

2,034,834

 

$

274,719

 

$

37

 

$

2,309,590

 

Intersegment revenues (eliminations)

 

175

 

 

(175

)

 

Revenues

 

2,035,009

 

274,719

 

(138

)

2,309,590

 

Depreciation and amortization

 

154,578

 

1,309

 

784

 

156,671

 

Interest expense

 

57,944

 

43,543

 

18,386

 

119,873

 

Income (loss) before income taxes

 

129,217

 

31,705

 

(32,098

)

128,824

 

Income taxes (benefit)

 

47,776

 

9,938

 

(13,791

)

43,923

 

Net income (loss)

 

81,441

 

21,767

 

(18,307

)

84,901

 

Preferred stock dividends of subsidiaries

 

1,995

 

 

(105

)

1,890

 

Net income (loss) for common stock

 

79,446

 

21,767

 

(18,202

)

83,011

 

Capital expenditures

 

302,327

 

2,188

 

246

 

304,761

 

Tangible assets (at December 31, 2009)

 

3,978,392

 

4,854,595

 

5,625

 

8,838,612

 

2008

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

2,860,177

 

$

358,553

 

$

190

 

$

3,218,920

 

Intersegment revenues (eliminations)

 

173

 

 

(173

)

 

Revenues

 

2,860,350

 

358,553

 

17

 

3,218,920

 

Depreciation and amortization

 

150,297

 

4,884

 

881

 

156,062

 

Interest expense

 

54,757

 

105,424

 

21,385

 

181,566

 

Income (loss) before income taxes

 

149,733

 

26,791

 

(35,378

)

141,146

 

Income taxes (benefit)

 

55,763

 

8,964

 

(15,749

)

48,978

 

Net income (loss)

 

93,970

 

17,827

 

(19,629

)

92,168

 

Preferred stock dividends of subsidiaries

 

1,995

 

 

(105

)

1,890

 

Net income (loss) for common stock

 

91,975

 

17,827

 

(19,524

)

90,278

 

Capital expenditures

 

278,476

 

3,499

 

76

 

282,051

 

Tangible assets (at December 31, 2008)

 

3,856,109

 

5,353,053

 

1,853

 

9,211,015

 

Assets (at December 31, 2010)

 

4,287,745

 

4,796,759

 

2,905

 

9,087,409

 

 

Intercompany electricity sales of the electric 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 consolidated HECO, 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 electric utility 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.

 

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Table of Contents

3 · Electric utility subsidiary

 

Selected financial information

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income Data

 

Years ended December 31

 

2010

 

2009

 

2008

 

 

2012 

 

2011 

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

2,367,441

 

$

2,026,672

 

$

2,853,639

 

 

$3,101,998

 

$2,973,764

 

$2,367,441

 

Other — nonregulated

 

14,925

 

8,337

 

6,711

 

 

2,382,366

 

2,035,009

 

2,860,350

 

Other – nonregulated

 

7,441

 

4,926

 

14,925

 

Total revenues

 

3,109,439

 

2,978,690

 

2,382,366

 

Expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel oil

 

900,408

 

671,970

 

1,229,193

 

 

1,297,419

 

1,265,126

 

900,408

 

Purchased power

 

548,800

 

499,804

 

689,828

 

 

724,240

 

689,652

 

548,800

 

Other operation

 

251,027

 

248,515

 

243,249

 

 

272,117

 

257,065

 

251,027

 

Maintenance

 

127,487

 

107,531

 

101,624

 

 

122,312

 

121,219

 

127,487

 

Depreciation

 

149,708

 

144,533

 

141,678

 

 

144,498

 

142,975

 

149,708

 

Taxes, other than income taxes

 

222,117

 

191,699

 

261,823

 

 

292,841

 

276,504

 

222,117

 

Other — nonregulated

 

4,431

 

1,286

 

1,596

 

 

2,203,978

 

1,865,338

 

2,668,991

 

Impairment of utility assets

 

40,000

 

9,215

 

 

Other – nonregulated

 

3,000

 

1,800

 

4,431

 

Total expenses

 

2,896,427

 

2,763,556

 

2,203,978

 

Operating income from regulated and nonregulated activities

 

178,388

 

169,671

 

191,359

 

 

213,012

 

215,134

 

178,388

 

Allowance for equity funds used during construction

 

6,016

 

12,222

 

9,390

 

 

7,007

 

5,964

 

6,016

 

Interest expense and other charges

 

(61,510

)

(57,944

)

(54,757

)

 

(62,055

)

(60,031

)

(61,510)

 

Allowance for borrowed funds used during construction

 

2,558

 

5,268

 

3,741

 

 

4,355

 

2,498

 

2,558

 

Income before income taxes

 

125,452

 

129,217

 

149,733

 

 

162,319

 

163,565

 

125,452

 

Income taxes

 

46,868

 

47,776

 

55,763

 

 

61,048

 

61,584

 

46,868

 

Net income

 

78,584

 

81,441

 

93,970

 

 

101,271

 

101,981

 

78,584

 

Preferred stock dividends of subsidiaries

 

915

 

915

 

915

 

 

915

 

915

 

915

 

Net income attributable to HECO

 

77,669

 

80,526

 

93,055

 

 

100,356

 

101,066

 

77,669

 

Preferred stock dividends of HECO

 

1,080

 

1,080

 

1,080

 

 

1,080

 

1,080

 

1,080

 

Net income for common stock

 

$

76,589

 

$

79,446

 

$

91,975

 

 

$    99,276

 

$    99,986

 

$    76,589

 

Consolidated Statements of Comprehensive Income

Years ended December 31

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

$  99,276

 

$  99,986

 

$  76,589

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

Retirement benefit plans:

 

 

 

 

 

 

 

Prior service credit arising during the period, net of taxes of nil, $4,408 and $3,001 for 2012, 2011 and 2010, respectively

 

 

6,921

 

4,712

 

Net losses arising during the period, net of tax benefits of $57,375, $74,346 and $27,408 for 2012, 2011 and 2010, respectively

 

(90,082

)

(116,726

)

(43,031)

 

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 $8,709, $5,332 and $2,387 for 2012, 2011 and 2010, respectively

 

13,673

 

8,372

 

3,747

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,069, $64,134 and $21,336 for 2012, 2011 and 2010, respectively

 

75,471

 

100,692

 

33,499

 

Other comprehensive loss, net of tax benefits

 

(938

)

(741

)

(1,073)

 

Comprehensive income attributable to Hawaiian Electric Company, Inc.

 

$  98,338

 

$  99,245

 

$  75,516

 

 

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Consolidated Balance Sheet Data

 

December 31

 

2010

 

2009

 

 

2012

 

2011

 

(in thousands, except share data)

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

Utility plant, at cost

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment

 

$

4,948,338

 

$

4,748,787

 

 

$  5,415,968

 

$  5,103,541

 

Less accumulated depreciation

 

(1,941,059

)

(1,848,416

)

 

(2,040,789

)

(1,966,894

)

Construction in progress

 

101,562

 

132,980

 

 

151,378

 

138,838

 

Net utility plant

 

3,108,841

 

3,033,351

 

 

3,526,557

 

3,275,485

 

Regulatory assets

 

478,330

 

426,862

 

 

864,596

 

669,389

 

Other

 

698,509

 

518,179

 

 

717,640

 

729,133

 

 

$

4,285,680

 

$

3,978,392

 

Total assets

 

$  5,108,793

 

$  4,674,007

 

Capitalization and liabilities

 

 

 

 

 

 

 

 

 

 

Common stock ($6 2/3 par value, authorized 50,000,000 shares, outstanding 13,830,823 shares and 13,786,959 shares in 2010 and 2009, respectively)

 

$

92,224

 

$

91,931

 

Common stock ($6 2/3 par value, authorized 50,000,000 shares, outstanding 14,665,264 shares and 14,233,723 shares in 2012 and 2011, respectively)

 

$       97,788

 

$       94,911

 

Premium on common stock

 

389,609

 

385,659

 

 

468,045

 

426,921

 

Retained earnings

 

854,856

 

827,036

 

 

907,273

 

881,041

 

Accumulated other comprehensive income, net of income taxes

 

709

 

1,782

 

Accumulated other comprehensive loss, net of tax benefits

 

(970

)

(32

)

Common stock equity

 

1,337,398

 

1,306,408

 

 

1,472,136

 

1,402,841

 

Cumulative preferred stock — not subject to mandatory redemption (authorized 5,000,000 shares, $20 par value (1,114,657 shares outstanding), and 7,000,000 shares, $100 par value (120,000 shares outstanding); dividend rates of 4.25-7.625%)

 

34,293

 

34,293

 

Cumulative preferred stock – not subject to mandatory redemption (authorized 5,000,000 shares, $20 par value (1,114,657 shares outstanding), and 7,000,000 shares, $100 par value (120,000 shares outstanding); dividend rates of 4.25-7.625%)

 

34,293

 

34,293

 

Commitments and contingencies (see below)

 

 

 

 

 

Long-term debt, net

 

1,057,942

 

1,057,815

 

 

1,147,872

 

1,000,570

 

Total capitalization

 

2,429,633

 

2,398,516

 

 

2,654,301

 

2,437,704

 

Current portion of long-term debt

 

 

57,500

 

Taxes accrued

 

251,066

 

230,076

 

Deferred income taxes

 

269,286

 

180,603

 

 

417,611

 

337,863

 

Regulatory liabilities

 

296,797

 

288,214

 

 

322,074

 

315,466

 

Retirement benefits liability

 

620,591

 

495,134

 

Contributions in aid of construction

 

335,364

 

321,544

 

 

405,520

 

356,203

 

Other

 

954,600

 

789,515

 

 

437,630

 

444,061

 

 

$

4,285,680

 

$

3,978,392

 

Total capitalization and liabilities

 

$  5,108,793

 

$  4,674,007

 

 

Regulatory assets and liabilities.  In accordance with ASC Topic 980, “Regulated Operations,” HECO and its subsidiaries’ 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 HECO and its subsidiaries’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the electric utilities expect that the regulatory assets would be charged to expense a ndand the regulatory liabilities would be credited to income or refunded to ratepayers immediately. In the event of unforeseen regulatory actions or other circumstances, management believes that a material adverse effect on the Company’s financial condition, results of operations and financial positionand/or liquidity may result if regulatory assets have to be charged to expense or if regulatory liabilities are required to be refunded to ratepayers immediately.

Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, HECO and its subsidiaries 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, HECO and its subsidiaries include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. Noted

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in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2010,2012, if different.

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Regulatory assets were as follows:

 

December 31

 

2010

 

2009

 

(in thousands)

 

 

 

 

 

Retirement benefit plans (9 years; 5 years remaining for HELCO’s $2 million prepaid pension regulatory asset; 5 years, 4 years remaining for HECO’s $7 million pension tracking mechanism; 5 years remaining for HELCO’s $6 million and MECO’s $3 million pension and OPEB tracking mechanisms; indeterminate for remainder)

 

$

356,591

 

$

303,927

 

Income taxes, net (1 to 36 years)

 

82,615

 

82,046

 

Unamortized expense and premiums on retired debt and equity issuances (5 to 30 years; 1 to 18 years remaining)

 

13,589

 

14,878

 

Vacation earned, but not yet taken (1 year)

 

7,349

 

6,849

 

Postretirement benefits other than pensions (18 years; 2 years remaining)

 

3,579

 

5,369

 

Other (1 to 50 years; 1 to 49 years remaining)

 

14,607

 

13,793

 

 

 

$

478,330

 

$

426,862

 

December 31

 

2012

 

2011

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Retirement benefit plans (balance primarily varies with plans’ funded statuses)

 

$660,835

 

$523,640

 

Income taxes, net (1 to 55 years)

 

84,931

 

83,386

 

Decoupling revenue balancing account (1 to 2 years)

 

66,076

 

20,780

 

Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 2 to 20 years remaining)

 

17,130

 

12,267

 

Vacation earned, but not yet taken (1 year)

 

8,493

 

8,161

 

Postretirement benefits other than pensions (18 years; 1 year remaining)

 

249

 

1,861

 

Other (1 to 50 years; 1 to 47 years remaining)

 

26,882

 

19,294

 

 

 

$864,596

 

$669,389

 

 

Regulatory liabilities were as follows:

 

December 31

 

2010

 

2009

 

 

2012

 

2011

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of removal in excess of salvage value (1 to 60 years)

 

$

277,341

 

$

280,674

 

 

$305,978

 

$294,817

 

Retirement benefit plans (5 years beginning with respective utility’s next rate case; 4 years remaining for HECO’s $4 million regulatory liability; 5 years remaining for HELCO’s $0.8 million and MECO’s $0.4 million regulatory liability)

 

18,617

 

5,193

 

Other (1 to 5 years)

 

839

 

2,347

 

Retirement benefit plans (5 years beginning with respective utility’s next rate case; primarily 5 years remaining)

 

15,563

 

20,000

 

Other (5 years; 1 to 2 years remaining)

 

533

 

649

 

 

$

296,797

 

$

288,214

 

 

$322,074

 

$315,466

 

 

The regulatory asset and liability relating to retirement benefit plans was createdrecorded as a result of pension and OPEB tracking mechanisms adopted by the PUC in interim rate case decisions for HECO, MECO and HELCO in 2007 (see Note 9).

Cumulative preferred stock.  The cumulative preferred stock of HECO and its subsidiaries is redeemable at the option of the respective company at a premium or par, but is not subject to mandatory redemption.

Major customers.  HECO and its subsidiaries received 10%11% ($349 million), or $242 million, $199 million11% ($316 million) and $295 million,10% ($242 million) of their operating revenues from the sale of electricity to various federal government agencies in 2010, 20092012, 2011 and 2008,2010, respectively.

Commitments and contingencies.

Fuel contracts.  HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2014.2016. 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, 2010,2012, the estimated cost of minimum purchases under the fuel supply contracts is $1.0 billion in each of 2011 and 2012 and a total of $0.8$0.9 billion in 2013, and $0.7$0.9 billion in 2014. 2014, $0.4 billion in 2015 and $0.4 billion in 2016. The actual cost of purchases in 20112013 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $1.0$1.3 billion, $0.7$1.3 billion and $1.2$1.0 billion of fuel under contractual agreements in 2010, 20092012, 2011 and 2008,2010, respectively.

On December 2, 2009, HECO and Chevron Products Company (Chevron), a division of Chevron USA, Inc. (Chevron) executed, are parties to an amendment to their existingamended contract for the purchase/sale of low sulfur fuel oil (LSFO). The amendment modified the pricing formula,, which could result in higher prices. The amended agreement terminates on April 30, 2013. On January 28, 2010,A successor agreement between the PUC approvedparties for the amendment onsupply of LSFO commences May 1, 2013 with an interim basis, and allowed HECO to include the costs incurred under the amendment in its ECAC, to the extent such costs are not recovered through HECO’s base rates. HECO is awaiting a final D&O from the PUC.

On May 5, 2010, HECO and Tesoro Hawaii Corporation (Tesoro) executed a second amendment to their existing LSFO supply contract (LSFO contract), subject to PUC approval. The amendment modified the pricing

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formula, which could result in higher prices. It also reduced the minimum fuel volumes HECO is obligated to buy under the LSFO contract and reduced the maximum volumes Tesoro is obligated to sell HECO under the LSFO contract. Theinitial term of the amended agreement runs through April 30, 2013ending December 31, 2016 and may automatically renew for annual terms thereafter unless earlier terminated by either party. On June 7, 2010, The PUC issued an interim approval for the recovery of cost incurred under this contract on December 31, 2012.

HECO submittedand Tesoro Hawaii Corp. (Tesoro) are parties to an applicationamended LSFO supply contract (LSFO contract), which runs through April 30, 2013. A successor agreement between the parties for PUC approvalthe supply of the second amendment, such that the changes in fuel prices under the amendment would be included in HECO’s ECAC.LSFO commences May 1, 2013 with an initial term ending December 31, 2014 and may automatically renew for

 

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annual terms thereafter unless earlier terminated by either party. The utilities pay market-related pricesPUC issued an interim approval for the recovery of cost incurred under this contract on December 31, 2012. On January 8, 2013, Tesoro announced the April 2013 closure of its Kapolei refinery on Oahu. Tesoro stated that it will continue operations as a terminal for imported fuel supplies purchased underwhile its Hawaii assets remain for sale. Tesoro has also stated it will honor all existing contracts.

HECO, MECO and HELCO are parties to amended contracts for the supply of industrial fuel oil and diesel fuels with Chevron and Tesoro, agreements.

HECO and Renewable Energy Group Marketing & Logistics Group LLC (REG) entered into a supply contract datedrespectively, which end December 21, 2009 and expiring in 201231, 2014. Both agreements may be automatically renewed for biodiesel to be consumed in the operationannual terms thereafter unless earlier terminated by either of the Campbell Industrial Park combustion turbine. On June 4, 2010,respective parties.

The energy charge for energy purchased from Kalaeloa Partners, L.P. (Kalaeloa) under HECO’s PPA with Kalaeloa is based, in part, on the PUC approvedprice 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 biodiesel supply contract and allowed HECO to includeparties.

The costs incurred under the costsutilities’ fuel contracts are included in its ECAC,their respective ECACs, to the extent such costs are not recovered through HECO’sthe utilities’ base rates. HECO’s price for biodiesel purchased under this agreement reflects market-related prices for animal fat and other process feedstocks.

 

In January 2011, HELCO signed a 20-year contract with Aina Koa Pono-Ka’u LLC to supply 16 million gallons of biodiesel per year from a biorefinery to be constructed by Aina Koa Pono-Ka’u LLC on the island of Hawaii, with initial consumption at HELCO’s Keahole Power Plant to begin by 2015. The utilities filed an application with the PUC requesting approval of, among other things, the contract and the establishment of a Biofuel Surcharge Provision that will pass through the differential between the cost of the biofuel and the cost of the petroleum fuel that the biofuel is replacing, in the event the cost of the biofuel is higher, over the customer base of the utilities based on KWH usage. The effectiveness of the contract is contingent upon PUC approval of, among other items, the proposed methodology for spreading the cost differential between the price of biodiesel and petroleum diesel being replaced over the customers base of all three utilities and the recovery of the contract costs in the utilities’ respective ECACs to the extent not included in base rates.

Power purchase agreements.  As of December 31, 2010,2012, HECO and its subsidiaries had six firm capacity PPAs for a total of 540545 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion, $0.7 billion and $0.5 billion $0.5 billionfor 2012, 2011 and $0.7 billion for 2010, 2009 and 2008, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term (and as amended) and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 20112013 through 20152017 and a total of $0.7 billion in the period from 20162018 through 2030.2033.

In general, HECO and its subsidiaries 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. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. HECO and its subsidiaries 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 HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

 

The energy charge for energy purchased from Kalaeloa under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for fuel oil under a Facility Fuel Supply Contract (fuel contract) between them. Kalaeloa and Tesoro have negotiated a proposed amendment to the pricing formula in their fuel contract. The amendment could result in higher fuel prices for Kalaeloa. In September 2010, HECO submitted a request for PUC approval to include the costs incurred under the PPA as a result of the amendment in HECO’s ECAC.

Purchase power adjustment clause. The final decision and order (D&O) for the HECO 2009 test year rate casePUC has approved a purchased power adjustment clause (PPAC).clauses (PPACs) for the utilities. Purchased power capacity, O&Moperation and maintenance (O&M) and other non-energy costs previously recovered through base rates will beare now recovered in the PPAC,PPACs, and subject to

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approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPACPPACs outside of a rate case. The PPAC will be adjusted monthly and reconciled quarterly and will implement a provision in the Energy Agreement that called for surcharge recovery of these costs. Purchased energy costs will continue to be recovered through the ECAC to the extent they are not recovered through base rates. Upon approval of the final rates in the HECO 2009 test year rate case, HECO will implement the PPAC.

 

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 HCEI.Hawaii Clean Energy Initiative (HCEI). In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an Energy Agreementagreement 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 substa ntialsubstantial 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.

Among the major provisions of the Energy Agreement are the following: (a) pursuing an overall goal of providing 70% of Hawaii’s electricity and ground transportation energy needs from clean energy sources by 2030; (b) developing a feed-in tariff system with standardized purchase prices for renewable energy; (c) replacing system-wide caps on net energy metering (NEM) with per circuit thresholds that require a further study before a proposed interconnection that would take the circuit over the threshold may proceed; (d) adopting a regulatory rate-making model under which the utilities’ revenues would be decoupled from kilowatthour (KWH) sales; (e) continuing the existing ECACs, subject to periodic review by the PUC; (f) establishing a surcharge to allow the utilities to pass through all reasonably incurred purchased power costs; (g) supporting the dev elopment and use of renewable biofuels; (h) promoting greater use of renewable energy, including wind power and solar energy; (i) providing for the retirement or placement on reserve standby status of older and less efficient fossil fuel fired generating units as new, renewable generation is installed; (j) improving and expanding “load management” and “demand response” programs that allow the utilities to control customer loads to improve grid reliability and cost management; (k) the filing of PUC applications for approval of the installation of Advanced Metering Infrastructure, coupled with time-of-use or dynamic rate options for customers; (l) supporting prudent and cost effective investments in smart grid technologies; (m) delinking prices paid under all new renewable energy contracts from oil prices; and (n) exploring establishment of lifeline rates for low income customers.

Many actions have been taken, and continue to be taken, to further the goals of the HCEI. For example, in May 2010, HECO received PUC approval of its power purchase agreement with Kahuku Wind Power, LLC for the purchase of as-available energy. In October 2010, the PUC approved the implementation of FITs for renewable energy generators, including applicable pricing, other terms and conditions and a standard form contract. In December 2010, the PUC allowed HECO to implement immediately the decoupling mechanism approved in August 2010. The PUC also approved HECO’s proposed Purchase Power Adjustment Clause to recover non-energy purchased power agreement costs and ordered that the existing ECAC continue. In January 2011, the PUC approved the replacement of the present system - -wide caps for NEM, with a 15% per circuit distribution threshold for DG penetration.

Renewable energy projects.  HECO and its subsidiaries continue to negotiate with developers of proposed projects (identified in the Energy Agreement) to integrate power into its grid approximately 1,100 MW from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others. This includes HECO’s commitmentplan to

105



integrate with the assistance of the State, up to 400 MW of wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from wind farmsa large windfarm proposed by developers to be built on the islandsisland of Lanai and/or Molokai. The State and HECO have agreed to work together to ensure the supporting infrastructure needed is in place to reliably accommodate this large increment of wind power, including app ropriate additional storage capacity investments and any required utility system connections or interfaces with the cable and the windLanai.

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farm facilities. In December 2009, the PUC issued a decision and order (D&O) that allowsallowed HECO to defer the costs of studies for thisthe large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the stage 1 studies through the REIP surcharge. A decision from the PUC is pending.

In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $555,000 (split evenly between HECO and MECO) 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 HECO and MECO 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, will be determined at a later date.

A revised draft Request for Proposals (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian Islands has been posted on the HECO website prior to the issuance of a proposed final RFP. In February 2012, the PUC granted HECO’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.

In May 2012, the PUC instituted a proceeding for a competitive bidding process for up to 50 MW of firm renewable geothermal dispatchable energy (Geothermal RFP) on the island of Hawaii, and in July 2012, HELCO filed an application to defer 2012 costs related to the Geothermal RFP. HELCO filed the Proposed Final Geothermal RFP with the PUC in January 2013 and is seeking PUC approval to issue the Geothermal RFP.

 

Interim increases.  As of December 31, 2010,2012, HECO and its subsidiaries had recognized $4$7 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

Major 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 HECO’s consolidated net income. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order include the following:those described below.

In May 2011, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System (CIS) project. The PUC subsequently eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the project cost issues. As part of a settlement agreement with the Consumer Advocate, subject to PUC approval, the parties agreed that the regulatory audits for the CIP CT-1 and CIS projects would be eliminated (see “Subsequent event” below).

Campbell Industrial Park combustion turbine No. 1 and transmission line.  HECO built a 110 MW simple cycle combustion turbine generating unit and added an additional 138 kilovolt (kV) transmission line to transmit power from generating units at Campbell Industrial Park (CIP) to the rest of the Oahu electric grid (collectively, the Project).

In a second interim D&O to HECO’s incurred costs for this project, which was placed in service in 2009, test year rate case issued in February 2010, the PUC granted HECO an increase of $12.7 million in annual revenues to recover $163 million of the costs of the Project. As of December 31, 2010, HECO’s cost estimate for the Project waswere $195 million, (of which $195 million had been incurred, including $9 million of AFUDC).AFUDC. HECO’s current rates reflect recovery of $163 million of project costs. In itsJuly 2011, test year rate case,the PUC allowed HECO is seeking to recover actual projectdefer the portion of costs that are in excess of the $163 million estimateprior PUC approved amounts and related depreciation for HECO’s CIP CT-1 project ($32 million) until completion of an independently conducted regulatory audit. The PUC also approved the accrual of a carrying charge on the cost of the project not yet included in its 2009 test year rate case.rates and the related depreciation expense, from July 1, 2011 until the regulatory audit is completed and allowed the remaining project costs that were not deferred to be included in electric rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is collected in electric rates. Management believes no adjustment to project costs is required as of December 31, 2010.2012.

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East Oahu Transmission Project (EOTP).Project.  HECO had planned a project to construct a partially underground transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied. In October 2007, the PUC approved HECO’s request to expend funds for a revised EOTP in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2) for a revised EOTP using different routes requiring the construction of subtransmission lines, but stated that the issue of recovery of the EOTP costs would be determined in a subsequent rate case, after the project is installed and in service.

Phase 1 was placed in service onin June 29, 2010 and is currently estimated to cost $58 million (as a result of higher costs and the project delays). In its2010. The interim D&O issued in July 2011 in HECO’s 2011 test year rate case HECO is seeking to recoverreflected approximately $16 million of Phase 1 costs.costs and related depreciation expense in determining revenue requirements. In April 2010,that D&O, the PUC ordered that a regulatory audit was to be conducted before the PUC determined the recoverability of the remaining Phase 1 costs.

In March 2012, the PUC approved a settlement agreement reached among HECO, proposedthe Consumer Advocate and the Department of Defense, under which, in lieu of a modificationregulatory audit, HECO would write off $9.5 million of 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 HECO’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.

In October 2010, the PUC approved HECO’s proposed modification request for Phase 2 that usesof the EOTP using smart grid technology and is estimatedtechnology. Phase 2 was placed in service in August 2012. As of December 31, 2012, HECO’s incurred costs for the Modified Phase 2 project amounted to cost $10 million (total cost of $15 million, less $5 million of funding through thereceived in Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009)funding). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion in 2012.

As of December 31, 2010, the accumulated costs recorded for the EOTP amounted to $61 million ($59 million for Phase 1 and $2 million for Phase 2), including (i) $12 million of planning and permitting costs incurred prior to the 2002 denial of the permit, (ii) $25 million of planning, permitting and construction costs incurred after the denial of the permit and (iii) $24 million for AFUDC. Management believes that no adjustment to project costs of EOTP Modified Phase 2 is required as of December 31, 2010.

HELCO generating units. In 1991, HELCO began planning to meet increased forecast demand for electricity. HELCO planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time the units would be converted to a 56 MW (net) dual-train combined-cycle unit. In 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”2012.

 

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After numerous delays due to environmental and other permitting challenges,CT-4 and CT-5 became operational in mid-2004 and the costs of CT-4 and CT-5 (less a previously agreed to $12 million write-off) were included in HELCO’s 2006 test year rate case interim and final rate increases.

On June 22, 2009, ST-7 was placed into service. As of December 31, 2010, HELCO’s cost estimate, and incurred costs, for ST-7 were both $92 million. The costs of ST-7 were included in HELCO’s 2010 test year rate case interim increase.

Management believes that no further adjustment to project costs is required at December 31, 2010.

Customer Information System Project.  In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million (including $18 million for capital and deferred costs) for a new Customer Information System (CIS), provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.

HECO signed a contract with a software company in March 2006 with a transition to the new CIS originally scheduled to occur in February 2008, which transition did not occur. Disputes over the parties’ contractual obligations resulted in litigation, which subsequently was settled. HECO subsequently contracted with a new CIS software vendor and a new system integrator. The CIS Project is proceeding withproject’s new software system became operational in May 2012. In February 2012 and May 2012, the implementationPUC granted HECO’s and MECO’s requests, respectively, to defer CIS project operation and maintenance expenses (limited to $2.3 million per year in 2011 and 2012 for HECO and limited to $0.6 million in 2012 for MECO) that are to be subject to a regulatory audit. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses) until the completion of the new software system. regulatory audit and begin amortization of such costs when the amortization is included in rates. For accounting purposes, the utilities will recognize the equity portion of the carrying charge when it is collected in electric rates.

As of December 31, 2010, HECO’s2012, the utilities’ total deferred and capital cost estimatecosts for the CIS was $57project were $20 million (of which $22(after the write-off of $40 million was recorded)of project costs—see “Subsequent event” below). Management believes no further adjustment to project costs is required as of December 31, 2010.2012.

Environmental regulation.  HECO 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. In recent years, legislative, regulatory and regulatory activitygovernmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act has(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 HECO’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

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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 until June 2013.

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 HECO’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, HECO 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, avoid the reduction in operational flexibility imposed by emissions control equipment, achieve timely compliance with the MATS and provide flexibility for optimizing the combined compliance strategies for MATS and the tightening of the National Ambient Air Quality Standards.

On September 14, 2012, the EPA Administrator signed the final action for the Hawaii Regional Haze Federal Implementation Plan (FIP), which became effective on November 8, 2012. The plan establishes an annual limit for sulfur dioxide emissions from five HELCO steam generating units, with compliance required commencing December 31, 2018. No specific control technologies are required for any HECO or MECO generating units.

Depending upon the final outcome of the legislative and regulatory activity (including under the Clean Water Act with respect to cooling water intake controls andCWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, and the Clean Air Act with respect to hazardous air pollutant emissions, tighteningimplementation of themore stringent National Ambient Air Quality Standards, and the Regional Haze rule), HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs.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 certain generating units earlier than anticipated.

 

HECO, HELCO and MECO, 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. Except as otherwise disclosed herein, the Company believesHECO and its subsidiaries believe the costs of responding to its subsidiaries’such releases identified to date will not have a material adverse effect, individually or in the aggregate, on the Company’s or HECO’s consolidated results of operations, financial condition or cash flows.liquidity.

Honolulu Harbor investigation.  Former Molokai Electric Company generation siteHECO.  In 1989, MECO 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 been involved since 1995performed Brownfield assessments of the Site that identified environmental impacts in a work groupthe subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with several other potentially responsible parties (PRPs) identified by the State ofEPA and the Hawaii Department of Health (DOH), MECO 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 MECO contractor of the Adjacent Parcel identified environmental impacts, including oil companies, in investigating and responding to historical subsurface petroleum contaminationelevated polychlorinated biphenyls (PCBs) in the Honolulu Harbor area. A subset of the PRPs (the Participating Parties) entered into a joint defense agreement and ultimately entered into an Enforceable Agreementsubsurface soils. In cooperation with the DOH and EPA, MECO is further investigating the Site and the Adjacent Parcel to address petroleum contaminationdetermine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, MECO accrued an additional $3.1 million (reserve balance of $3.6 million as of December 31, 2012) for the additional investigation and estimated cleanup costs at the site. T he Participating Parties are fundingSite and the investigative andAdjacent Parcel; however, final costs of remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work. Although the Honolulu Harbor investigation involves four units—Iwilei, Downtown, Kapalama and Sand Island—to date all the investigative and remedial work has focusedwill depend on the Iwilei unit.

The Participating Parties have conducted subsurface investigations, assessments and preliminary oil removal, and anticipate finalizing remedial design work for the Iwilei unit in 2011.

Asresults of continued investigation.December 31, 2010, HECO’s remaining accrual for its estimated share of environmental costs for the Iwilei unit was $1.4 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the Participating Parties has not yet been established and (3) management cannot

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estimate the costs to be incurred (if any) for the sites other than the Iwilei unit (such as its Honolulu power plant located in the Downtown unit), the cost estimate may be subject to significant change and additional material costs may be incurred.

 

Global climate change and greenhouse gas (GHG) emissions reduction.  National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions. Carbon dioxide emissions, including those from the combustion of fossil fuels, comprise the largest percentage of 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 electric utilities are participatingparticipated in a Task Force established under Act 234, which iswas 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

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those to be undertakenbeing implemented under the Energy Agreement. A Task Force consultant prepared a work plan, which was submitted toOn October 19, 2012, the Hawaii Legislature in December 2009. BecauseDOH posted the proposed regulations implementingrequired by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have not yet been developed or promulgated, management cannot predictthe 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. Both the federal and state regulations create certain exclusions for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of Act 234 on the electric utilities and the Company, butproposed regulations; compliance costs could be significant.

In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009 (ACES). Among other things, ACES establishes a declining cap on GHG emissions requiring a 3% emissions reduction by 2012 that increases periodically to 83% by 2050. ACES also establishes a trading and offset scheme for GHG allowances. The trading program combined with the declining cap is known as aSeveral approaches (e.g., “cap and trade” approach to emissions reduction. In September 2009, the U.S. Senate began consideration of the Clean Energy Jobs and American Power Act, which also includes cap and trade provisions. Since then, several other approaches) to GHG emission reduction have been either introduced or discussed in the U.S. Senate;Congress; however, no federal legislation has yet been enacted.

On September 22, 2009, the federal Environmental Protection Agency (EPA)EPA issued theits Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions beginning in 2010.emissions. The utilities’ GHG emissionsutilities have submitted the required reports for 2010 are due on March 31, 2011.and 2011 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Management believesSince then, the EPA will make the same or similar endangerment finding regardinghas also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ g enerating units.generating units.

In addition, the Prevention of Significant Deterioration (PSD) permit program of the CAA applies to designated air pollutants from new or modified stationary sources, such as utility electrical generation units. In June 2010, the EPA issued its “PreventionGHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing facilities. States may need to increase fees to cover the increased level of activity caused by this rule. The GHG Tailoring Rule requires a number of existing HECO, HELCO and MECO facilities that are not currently subject to the Covered Source Permit program, to submit an initial Covered Source Permit application to the DO H within one year. The EPA has stated that the PSD program applies to GHG emissions effective January 2, 2011 because that is the date the federal GHG emission standards for motor vehicles (Tailpipe Rule) take effect. Accordingly, 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. OnIn January 12, 2011, the EPA issued a noticeannounced that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation units that are or will be fired on biofuels. On March 27, 2012, the Federal Register published the EPA’s proposed New Source Performance Standard regulating carbon dioxide emissions from affected new fossil fuel-fired generating units. As proposed, the rule does not apply to non-continental units (i.e., in Hawaii and U.S. Territories) and therefore does not apply to the utilities.

HECO and its subsidiaries 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, committing to burnburning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generationgenerating units, and testing biofuel blends in other HECO and MECO 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’

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

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 cash flowsliquidity of the Company.electric utilities. For example, severe weather could cause significant harm to the Company’selectric utilities’ physical facilities.

 

Given Hawaii’s unique geographic location and its isolated electric grids, physical risks of the type associated with climate change have been considered by the utilities in the planning, design, construction, operation and maintenance of their facilities. To ensure the reliability of each island’s grid, the utilities design and construct their electric generation systems with greater levels of redundancy than is typical for U.S. mainland, interconnected systems. Although a major natural disaster could have severe financial implications, such risks have existed since the Company’s inception and the Company makes a concerted effort to prepare for a fast response in the event of an emergency.

The utilities are undertaking an adaptation survey of their facilities as a step in developing a longer-term strategy for responding to the consequences of global climate change.

BlueEarth Biofuels LLC.  BlueEarth Maui Biodiesel LLC (BlueEarth Maui), a joint venture to pursue biodiesel development, was formed in early 2008 between BlueEarth Biofuels LLC (BlueEarth) and Uluwehiokama Biofuels Corp. (UBC), a non-regulated subsidiary of HECO. UBC invested $400,000 in BlueEarth Maui for a minority ownership interest. MECO began negotiating with BlueEarth Maui for a biodiesel fuel purchase contract, however, negotiations stalled. In October 2008, BlueEarth filed a civil action in federal district court against MECO, HECO and others alleging claims based on the parties’ failure to have reached agreement on the biodiesel supply and related land agreements. The lawsuit seeks damages and equitable relief. Trial ha d been scheduled for April 2012. The project was terminated because the litigation was filed and UBC’s investment in the venture was written off in 2009.

Apollo Energy Corporation/Tawhiri Power LLC.  HELCO purchases energy generated at the Kamao’a wind farm pursuant to the Restated and Amended PPA for As-Available Energy (the RAC) dated October 13, 2004 between HELCO and Apollo Energy Corporation (Apollo), later assigned to Apollo’s affiliate, Tawhiri Power LLC (Tawhiri). The maximum allowed output of the wind farm is 20.5 MW.

In June 2010, HELCO and Tawhiri participated in an arbitration relating to disputes surrounding HELCO’s ownership and possessory interest in the switching station and reimbursement of certain interconnection costs. In December 2010, the arbitration panel issued its final award and order finding in favor of HELCO. Thus, Tawhiri transferred title to the switching station and rights to the land to HELCO and paid HELCO $0.6 million (which included reimbursement of certain interconnection costs, prejudgment interest and HELCO’s attorneys’ fees and costs). Tawhiri’s appeal from the PUC’s decision not to hear the issues presented to the arbitration panel remains pending before the Hawaii Intermediate Court of Appeals.

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. HECO and its subsidiaries’ recognition of AROs have no impact on itstheir earnings. Regulatory assets are established to recognize future recoveriesThe cost of the AROs is recovered over the life of the asset through depreciation rates for accretion and depreciation expenses related to AROs and associated assets. depreciation.

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AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, includin gincluding removal of asbestos and other hazardous materials. In September 2009, HECO recorded an ARO related to removing retired generating units at its Honolulu power plant, including abating asbestos and lead-based paint. The obligation was subsequently increased in June 2010, due to an increase in the estimated costs of the removal

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project. In August 2010, HECO recorded a similar ARO related to removing retired generating units at HECO’s Waiau power plant.

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

 

(in thousands)

 

2010

 

2009

 

 

2012

 

2011

 

 

 

 

 

 

Balance, January 1

 

$

23,746

 

$

286

 

 

$ 50,871

 

$ 48,630

 

Accretion expense

 

2,519

 

21

 

 

1,563

 

2,202

 

Liabilities incurred

 

11,949

 

23,479

 

 

 

256

 

Liabilities settled

 

(725

)

(40

)

 

(4,003

)

(835

)

Revisions in estimated cash flows

 

11,141

 

 

 

 

618

 

Balance, December 31

 

$

48,630

 

$

23,746

 

 

$ 48,431

 

$ 50,871

 

 

Collective bargaining agreements.  As of December 31, 2010,2012, approximately 54%52% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company.electric utilities. On MarchNovember 1, 2008, members of2012, the unionutilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreements with HECO, HELCO and MECO. The agreements cover a three-year term, from November 1, 2007 toagreement that both expire on October 31, 2010, and provide2018. The collective bargaining agreement provides for general non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective January 1, 20093% for 2014, 2015, 2017 and 4.5% effective January 1, 2010.2018, and 3.25% for 2016. (A general 3% non-compounded wage increase has been provided to bargaining unit employees for 2013 under the collective bargaining agreement ratified in March 2011). The agreements had been extended to January 31, 2011. On January 31, 2011, a tentative settlement agreement was reached, subject to ratification byalso includes wage adjustments for certain trades and crafts positions and different wage rates for new bargaining unit office and clerical positions. The new benefit agreement provides for an escalating percentage of employee contributions without caps for medical premiums throughout the utilities’ union members.term of the agreement.

 

118Subsequent event.  On January 28, 2013, HECO, HELCO and MECO signed a settlement agreement with the Consumer Advocate (Agreement), subject to approval by the PUC, to write off $40 million of CIS project costs, in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects. An after-tax charge to net income of $24 million ($18 million for HECO, $3 million for HELCO, and $3 million for MECO) was recorded in the fourth quarter of 2012 for the write-off of the project costs. In accordance with the Agreement, the remaining recoverable costs for CIP CT-1 and CIS of $52 million have been included in rate base as of December 31, 2012.

As part of the Agreement, the parties also agreed that HELCO would withdraw its 2013 test year rate case and will not file a rate case until its next turn in the 3-year cycle, which will be for a 2016 test year, but HELCO will make annual RBA and RAM rate adjustment filings to roll forward the base year information from its prior rate case. Additionally, HECO would delay the filing of its scheduled 2014 test year rate case, until no earlier than January 2, 2014. The parties also agree that starting in 2014, HECO will be allowed to record Revenue Adjustment Mechanism (RAM) revenues starting January 1 of each year through 2016. The cash collection of RAM revenues will remain unchanged, starting June 1 of each year through May 31 of the following year.

In deciding to enter into the Agreement, HECO, HELCO, and MECO took into account a number of considerations, including (1) the significant passage of time since the initial costs for the CIP CT-1 and CIS projects were incurred, (2) the uncertain timing and significant resources that would be required by the PUC, HECO and other parties to conduct a fair and meaningful regulatory audit of project costs for CIP CT-1 and CIS, (3) the additional carrying charges that would be accrued to the project cost for both CIP CT-1 and CIS, (4) resolving the regulatory audits, (5) the need to allow the PUC, the Consumer Advocate, HECO, HELCO and MECO to focus their resources on the numerous priorities they face in improving customer service and transforming the electric utility industry in Hawaii from one based on oil-fired generation to one based on energy efficiency and Hawaii’s indigenous renewable energy resources, and (6) the concern for the current high electric bills due to the high fuel costs.

Management cannot predict or provide any assurances concerning the approval or timing of approval of the Agreement by the PUC.

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4 ·  Bank subsidiary

 

Selected financial information

American Savings Bank, F.S.B. and Subsidiaries

 

Consolidated Statements of Income Data

Years ended December 31

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

Interest income

 

 

 

 

 

 

 

Interest and fees on loans

 

$176,057

 

$184,485

 

$195,192

 

Interest on investment and mortgage-related securities

 

13,822

 

14,568

 

14,946

 

Total interest income

 

189,879

 

199,053

 

210,138

 

Interest expense

 

 

 

 

 

 

 

Interest on deposit liabilities

 

6,423

 

8,983

 

14,696

 

Interest on other borrowings

 

4,869

 

5,486

 

5,653

 

Total interest expense

 

11,292

 

14,469

 

20,349

 

Net interest income

 

178,587

 

184,584

 

189,789

 

Provision for loan losses

 

12,883

 

15,009

 

20,894

 

Net interest income after provision for loan losses

 

165,704

 

169,575

 

168,895

 

Noninterest income

 

 

 

 

 

 

 

Fees from other financial services

 

31,361

 

28,881

 

27,280

 

Fee income on deposit liabilities

 

17,775

 

18,026

 

26,369

 

Fee income on other financial products

 

6,577

 

6,704

 

6,487

 

Gain on sale of loans

 

14,628

 

5,028

 

6,338

 

Net gains on sale of securities

 

134

 

371

 

 

Other income, net

 

5,185

 

6,344

 

6,081

 

Total noninterest income

 

75,660

 

65,354

 

72,555

 

Noninterest expense

 

 

 

 

 

 

 

Compensation and employee benefits

 

75,979

 

71,137

 

71,476

 

Occupancy

 

17,179

 

17,154

 

16,548

 

Data processing

 

10,098

 

8,155

 

13,213

 

Services

 

9,866

 

7,396

 

6,594

 

Equipment

 

7,105

 

6,903

 

6,620

 

Office supplies, printing and postage

 

3,870

 

3,934

 

3,928

 

Marketing

 

3,260

 

3,001

 

2,418

 

Communication

 

1,809

 

1,764

 

2,221

 

Other expense

 

23,177

 

23,949

 

25,920

 

Total noninterest expense

 

152,343

 

143,393

 

148,938

 

Income before income taxes

 

89,021

 

91,536

 

92,512

 

Income taxes

 

30,384

 

31,693

 

34,056

 

Net income

 

$58,637

 

$  59,843

 

$  58,456

 

 

Years ended December 31

 

2010

 

2009

 

2008

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest and dividend income

 

 

 

 

 

 

 

Interest and fees on loans

 

$

195,192

 

$

217,838

 

$

247,210

 

Interest and dividends on investment and mortgage-related securities

 

14,946

 

26,977

 

65,208

 

 

 

210,138

 

244,815

 

312,418

 

Interest expense

 

 

 

 

 

 

 

Interest on deposit liabilities

 

14,696

 

34,046

 

61,483

 

Interest on other borrowings

 

5,653

 

9,497

 

43,941

 

 

 

20,349

 

43,543

 

105,424

 

Net interest income

 

189,789

 

201,272

 

206,994

 

Provision for loan losses

 

20,894

 

32,000

 

10,334

 

Net interest income after provision for loan losses

 

168,895

 

169,272

 

196,660

 

Noninterest income

 

 

 

 

 

 

 

Fee income on deposit liabilities

 

26,369

 

30,713

 

28,332

 

Fees from other financial services

 

27,280

 

25,267

 

24,846

 

Fee income on other financial products

 

6,487

 

5,833

 

6,683

 

Net losses on sale of securities

 

 

(32,034

)

(17,376

)

Net losses on available-for-sale securities (includes $32,167 and $7,764 of other-than-temporary impairment losses, net of $16,723 and nil of non-credit losses recognized in other comprehensive income, for 2009 and 2008, respectively)

 

 

(15,444

)

(7,764

)

Other income

 

12,419

 

15,569

 

11,414

 

 

 

72,555

 

29,904

 

46,135

 

Noninterest expense

 

 

 

 

 

 

 

Compensation and employee benefits

 

71,476

 

73,990

 

77,858

 

Occupancy

 

16,548

 

22,057

 

21,890

 

Data processing

 

13,213

 

14,382

 

10,678

 

Services

 

6,594

 

11,189

 

16,706

 

Equipment

 

6,620

 

8,849

 

12,544

 

Office supplies, printing and postage

 

3,928

 

3,758

 

4,243

 

Marketing

 

2,418

 

2,134

 

4,007

 

Communication

 

2,221

 

2,446

 

3,241

 

Loss on early extinguishment of debt

 

 

760

 

39,843

 

Other expense

 

25,920

 

27,906

 

24,994

 

 

 

148,938

 

167,471

 

216,004

 

Income before income taxes

 

92,512

 

31,705

 

26,791

 

Income taxes

 

34,056

 

9,938

 

8,964

 

Net income

 

$

58,456

 

$

21,767

 

$

17,827

 

Consolidated Statements of Comprehensive Income

Years ended December 31

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

Net income

 

$58,637

 

$  59,843

 

$  58,456

 

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 ($631), ($4,343) and $789, for 2012, 2011 and 2010, respectively

 

956

 

6,578

 

(1,196

)

Less: reclassification adjustment for net realized gains included in net income, net of taxes of $53, $148 and nil for 2012, 2011 and 2010, respectively

 

(81

)

(224

)

 

Retirement benefit plans:

 

 

 

 

 

 

 

Net gains (losses) arising during the period, net of (taxes) benefits of $5,240, $6,577 and ($3,007) for 2012, 2011 and 2010, respectively

 

(7,936

)

(9,960

)

4,554

 

Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of (taxes) benefits of $684, $346 and ($13) for 2012, 2011 and 2010, respectively

 

1,036

 

523

 

(20

)

Other comprehensive income (loss), net of taxes

 

(6,025

)

(3,083

)

3,338

 

Comprehensive income

 

$ 52,612

 

$  56,760

 

$  61,794

 

 

119111



Table of Contents

Consolidated Balance Sheet Data

 

December 31

 

2010

 

2009

 

 

2012

 

2011

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

204,397

 

$

425,896

 

 

$   184,430

 

$   219,678

 

Federal funds sold

 

1,721

 

1,479

 

Available-for-sale investment and mortgage-related securities

 

678,152

 

432,881

 

 

671,358

 

624,331

 

Investment in stock of Federal Home Loan Bank of Seattle

 

97,764

 

97,764

 

 

96,022

 

97,764

 

Loans receivable held for investment

 

3,779,218

 

3,680,724

 

Allowance for loan losses

 

(41,985

)

(37,906

)

Loans receivable held for investment, net

 

3,489,880

 

3,645,578

 

 

3,737,233

 

3,642,818

 

Loans held for sale, at lower of cost or fair value

 

7,849

 

24,915

 

 

26,005

 

9,601

 

Other

 

234,806

 

230,282

 

 

244,435

 

233,592

 

Goodwill

 

82,190

 

82,190

 

 

82,190

 

82,190

 

 

$

4,796,759

 

$

4,940,985

 

Total assets

 

$5,041,673

 

$4,909,974

 

Liabilities and shareholder’s equity

 

 

 

 

 

 

 

 

 

 

Deposit liabilities—noninterest-bearing

 

$

865,642

 

$

808,474

 

Deposit liabilities—interest-bearing

 

3,109,730

 

3,250,286

 

Deposit liabilities–noninterest-bearing

 

$1,164,308

 

$  993,828

 

Deposit liabilities–interest-bearing

 

3,065,608

 

3,076,204

 

Other borrowings

 

237,319

 

297,628

 

 

195,926

 

233,229

 

Other

 

90,683

 

92,129

 

 

117,752

 

118,078

 

 

4,303,374

 

4,448,517

 

Total liabilities

 

4,543,594

 

4,421,339

 

Commitments and contingencies (see “Litigation” below)

 

 

 

 

 

Common stock

 

330,562

 

329,439

 

 

333,712

 

331,880

 

Retained earnings

 

169,111

 

172,655

 

 

179,763

 

166,126

 

Accumulated other comprehensive loss, net of tax benefits

 

(6,288

)

(9,626

)

 

(15,396

)

(9,371

)

Total shareholder’s equity

 

498,079

 

488,635

 

Total liabilities and shareholder’s equity

 

$5,041,673

 

$4,909,974

 

Other assets

 

 

 

 

 

Bank-owned life insurance

 

$125,726

 

$121,470

 

Premises and equipment, net

 

62,458

 

52,940

 

Prepaid expenses

 

13,199

 

15,297

 

Accrued interest receivable

 

13,228

 

14,190

 

Mortgage-servicing rights

 

10,818

 

8,227

 

Real estate acquired in settlement of loans, net

 

6,050

 

7,260

 

Other

 

12,956

 

14,208

 

 

493,385

 

492,468

 

 

$244,435

 

$233,592

 

Other liabilities

 

 

 

 

 

Accrued expenses

 

$17,103

 

$21,216

 

Federal and state income taxes payable

 

35,408

 

35,002

 

Cashier’s checks

 

23,478

 

22,802

 

Advance payments by borrowers

 

9,685

 

10,100

 

Other

 

32,078

 

28,958

 

 

$

4,796,759

 

$

4,940,985

 

 

$117,752

 

$118,078

 

 

Other assets

December 31

 

2010

 

2009

 

(in thousands)

 

 

 

 

 

Bank-owned life insurance

 

$

117,565

 

$

113,433

 

Premises and equipment, net

 

56,495

 

54,428

 

Prepaid expenses

 

18,608

 

24,353

 

Accrued interest receivable

 

14,887

 

15,247

 

Mortgage-servicing rights

 

6,699

 

4,200

 

Real estate acquired in settlement of loans, net

 

4,292

 

3,959

 

Other

 

16,260

 

14,662

 

 

 

$

234,806

 

$

230,282

 

Other liabilities

December 31

 

2010

 

2009

 

(in thousands)

 

 

 

 

 

Accrued expenses

 

$

16,426

 

$

17,270

 

Federal and state income taxes payable

 

28,372

 

19,141

 

Cashier’s checks

 

22,396

 

26,877

 

Advance payments by borrowers

 

10,216

 

10,989

 

Other

 

13,273

 

17,852

 

 

 

$

90,683

 

$

92,129

 

Balance sheet restructure.  In 2008, ASB completed a restructuring of its balance sheet through the sale of mortgage-related securities and agency notes and the early extinguishment of certain borrowings to strengthen future profitability ratios and enhance future net interest margin, while remaining “well-capitalized” and without significantly impacting future net income and interest rate risk. On June 25, 2008, ASB completed a series of transactions which resulted in the sales to various broker/dealers of available-for-sale agency and private-issue mortgage-related securities and agency notes with a weighted average yield of 4.33% for approximately $1.3 billion. ASB used the proceeds from the sales of these mortgage-related securities and agency notes to retire debt with a weighted average cost of 4.70%, comprised of approximately $0.9 billion of FHLB advances and $0.3 billion of securities sold under agreements to repurchase. These transactions resulted in a charge to net income of $35.6 million in the second quarter of 2008. The $35.6 million was

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Table of Contents

comprised of:  (1) realized losses on the sale of mortgage-related securities and agency notes of $19.3 million included in “Noninterest income-Net losses on sale of securities,” (2) fees associated with the early retirement of other bank borrowings of $39.8 million included in “Noninterest expense-Loss on early extinguishment of debt” and (3) income taxes of $23.5 million included in “Income taxes.” Although the sales of the mortgage-related securities and agency notes resulted in realized losses in the second quarter of 2008, a portion of the losses on these available-for-sale securities had been previously recognized as unrealized losses in ASB’s equity as a result of mark-to-market charges to other comprehensive income in earlier periods.

As a result of this balance sheet restructuring, ASB freed up capital and paid a dividend of approximately $55 million to HEI in 2008. HEI used the dividend to repay commercial paper and for other corporate purposes.

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.

In the past, ASB owned private-issue mortgage-related securities (PMRS). To further improve its credit risk profile and reduce the potential volatility of future earnings, and in light of the improvement in the fixed-income securities markets, ASB sold the PMRS held in its investment portfolio in the fourth quarter of 2009. Sales of the available-for-sale PMRS were made to various broker/dealers. The PMRS sold were backed by mortgages throughout the mainland U.S. The sales resulted in an after-tax charge to net income of $19 million ($32 million pretax included in “Noninterest income-Net losses on sale of securities”) in the fourth quarter of 2009, which amount had been previously recognized as a reduction to equity as a result of mark-to-market charges to other comprehensive income in earlier periods. A portion of the proceeds from the sales were used to prepay $40 million of advances from FHLB with a weighted average rate of 2.64% and a weighted average maturity of approximately 0.8 years. ASB incurred an after-tax loss of $0.4 million ($0.7 million pretax) related to this early extinguishment of debt. Over time, ASB used the remaining proceeds from the sale of the PMRS to pay down high cost liabilities (maturing certificates of deposit and wholesale borrowings), to fund loan growth and to reinvest in securities with low credit risk and high liquidity, such as government or agency notes and mortgage-related securities.

As of December 31, 2010,2012, ASB’s investment portfolio distribution was 47%62% mortgage-related securities issued by FNMA, FHLMC or GNMA, 47%26% federal agency obligations and 6%12% 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.

Prices for investments and mortgage-related securities are provided by an independent market participantsthird party pricing service and 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 of theseto benchmark securities may be influenced by factors such aswhich 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 liquidity, corporate 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. Adverse changes in any of these factors may result in additional losses.

 

 

 

 

Gross

 

Gross

 

Estimated

 

Gross unrealized losses

 

December 31, 2010

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal agency obligations

 

$

317,945

 

$

171

 

$

(2,220

)

$

315,896

 

$

205,316

 

$

(2,220

)

$

 

$

 

Mortgage-related securities- FNMA, FHLMC and GNMA

 

310,711

 

9,570

 

(311

)

319,970

 

30,986

 

(311

)

 

 

Municipal bonds

 

43,632

 

7

 

(1,353

)

42,286

 

41,479

 

(1,353

)

 

 

 

 

$

672,288

 

$

9,748

 

$

(3,884

)

$

678,152

 

$

277,781

 

$

(3,884

)

$

 

$

 

 

121112



Table

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.

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 Contentstheir 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

 

December 31, 2009

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal agency obligations

 

$

104,091

 

$

109

 

$

(156

)

$

104,044

 

$

54,834

 

$

(156

)

$

 

$

 

Mortgage-related securities- FNMA, FHLMC and GNMA

 

319,642

 

7,967

 

(88

)

327,521

 

15,352

 

(88

)

 

 

Municipal bonds

 

1,300

 

16

 

 

1,316

 

 

 

 

 

 

 

$

425,033

 

$

8,092

 

$

(244

)

$

432,881

 

$

70,186

 

$

(244

)

$

 

$

 

December 31, 2012

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

)

$  –

 

$  –

 

December 31, 2011

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Available-for-sale

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal agency obligations

 

$218,342

 

$  2,393

 

$  (8

)

$220,727

 

$  19,992

 

$  (8

)

$  –

 

$  –

 

Mortgage-related securities-FNMA, FHLMC and GNMA

 

334,183

 

10,699

 

(17

)

344,865

 

11,994

 

(17

)

 

 

Municipal bonds

 

55,393

 

3,346

 

 

58,739

 

 

 

 

 

 

 

$607,918

 

$16,438

 

$(25

)

$624,331

 

$31,986

 

$(25

)

$  –

 

$  –

 

 

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 following table details the contractual maturities of available-for-sale securities. securities were as follows:

 

 

Amortized

 

Fair

 

(in thousands)

 

Cost

 

value

 

 

 

 

 

 

 

Due in one year or less

 

$  28,120

 

$  28,283

 

Due after one year through five years

 

102,549

 

104,453

 

Due after five years through ten years

 

89,666

 

94,895

 

Due after ten years

 

25,982

 

26,344

 

 

 

246,317

 

253,975

 

Mortgage-related securities-FNMA,FHLMC and GNMA

 

407,175

 

417,383

 

Total available-for-sale securities

 

$653,492

 

$671,358

 

All positions with variable maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity.

 

 

Amortized

 

Fair

 

(in thousands)

 

Cost

 

value

 

 

 

 

 

 

 

Due in one year or less

 

$

20,800

 

$

20,834

 

Due after one year through five years

 

274,338

 

272,730

 

Due after five years through ten years

 

55,955

 

54,581

 

Due after ten years

 

10,484

 

10,037

 

 

 

361,577

 

358,182

 

Mortgage-related securities-FNMA,FHLMC and GNMA

 

310,711

 

319,970

 

Total available-for-sale securities

 

$

672,288

 

$

678,152

 

Actual maturities will likely differ from these contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

In 2008,2012, 2011 and 2010, proceeds from sales of available-for-sale investmentmortgage-related securities was $75were $3.5 million, $30.7 million and nil, resulting in gross realized gains of $0.1 million, $0.4 million and nil, respectively and there were no gross realized losseslosses. In 2011, proceeds from the sale of $0.2 million.municipal bonds were $2.1 million

 

In 2010, 2009 and 2008, proceeds from sales of available-for-sale mortgage-related securities were nil, $185.1 million and $1.2 billion, 113



resulting in gross realized gains of nil, $0.8 million$5,000 and $0.6 million andno gross realized losseslosses. There were no sales of nil, $32.9 millionmunicipal bonds in 2012 and $19.8 million, respectively.

2010.

ASB pledged mortgage-related securities and federal agency obligations with a carryingmarket value of approximately $60.8$98.0 million and $33.5$91.9 million as of December 31, 20102012 and 2009,2011, respectively, as collateral to securefor public funds deposits, automated clearinghouse transactions with Bank of Hawaii, and deposits in ASB’s bankruptcy and treasury, tax, and loan accountsaccount with the Federal Reserve Bank of San Francisco. As of December 31, 20102012 and 2009,2011, mortgage-related securities and federal agency obligations with a carrying value of $204.8$189.3 million and $270.1$219.7 million, respectively, were pledged as collateral for securities sold under agreements to repurchase.

FHLB of Seattle stock.  As of December 31, 20102012 and 2009,2011, 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, 2010,2012, consistent with its accounting policy. ASB did not recognize an OTTI loss for 20102012 based on its evaluation of the underlying investment, (including including:

·the net income and growth in retained earnings recorded by the FHLB of Seattle in the first nine months of 2010;2012;

·compliance with all of its regulatory capital requirements and being classified “adequately capitalized” by the significance ofFederal Housing Finance Agency (Finance Agency);

·being allowed by the decline in net assets of the FHLB of Seattle as comparedFinance Agency to its capital stock amoun tand the length of time this situation has persisted; 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

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required to sell before recovery of its par value). Continued deteriorationvalue.

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 losses.security. Non-credit related impairments are reflected in other comprehensive in come.

The following table reflects cumulative OTTIs for expected losses that have been recognized in earnings. The beginning balance for the nine months ended December 31, 2009 relates to credit losses realized prior to April 1, 2009 on debt securities held by ASB as of March 31, 2009. This beginning balance includes the net impact of non-credit losses that were originally reported as losses prior to March 31, 2009 and were subsequently recharacterized from retained earnings as a result of the adoption of new accounting standards for OTTI recognition effective April 1, 2009. Additions to this balance include new securities in which initial credit impairments have been identified and incremental increases of credit impairments on positions that had already taken similar impairments. The additions to cumulative OTTI occurred in the second and third quarter of 2009. In the four th quarter of 2009, ASB sold its private-issue mortgage-related securities portfolio.income. ASB did not recognize OTTI for 2012, 2011 or 2010.

 

(in thousands)

Twelve months ended
December 31, 2010

Nine months ended
December 31, 2009

Balance, beginning of period

$

$

 1,486

Additions:

Initial credit impairments

4,870

Subsequent credit impairments

10,574

Reductions:

For securities sold

(16,930

)

Balance, end of period

$

$

114



 

Loans receivable.

 

December 31

 

2010

 

2009

 

 

2012  

 

2011  

(in thousands)

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

2,087,813

 

$

2,332,763

 

 

$1,866,450  

 

$1,926,774 

Commercial real estate

 

300,689

 

255,716

 

 

375,677  

 

331,931 

Home equity line of credit

 

416,453

 

326,896

 

 

630,175  

 

535,481 

Residential land

 

65,599

 

96,515

 

 

25,815  

 

45,392 

Commercial construction

 

38,079

 

68,174

 

 

43,988  

 

41,950 

Residential construction

 

5,602

 

16,705

 

 

6,171  

 

3,327 

Total real estate loans

 

2,914,235

 

3,096,769

 

 

2,948,276  

 

2,884,855 

 

 

 

 

 

 

 

 

 

Commercial loans

 

551,683

 

545,622

 

 

721,349  

 

716,427 

Consumer loans

 

80,138

 

64,360

 

 

121,231  

 

93,253 

Total loans

 

3,546,056

 

3,706,751

 

 

3,790,856  

 

3,694,535 

Deferred loan fees, net and unamortized discounts

 

(15,530

)

(19,494

)

 

(11,638) 

 

(13,811)

Allowance for loan losses

 

(40,646

)

(41,679

)

 

(41,985) 

 

(37,906)

Total loans, net

 

$

3,489,880

 

$

3,645,578

 

 

$3,737,233  

 

$3,642,818 

 

As of December 31, 20102012 and 2009,2011, ASB’s commitments to originate loans including the undisbursed portion of loans in process, approximated $77.6$97.9 million and $51.7$95.4 million, respectively. The increase was primarily due to a $12 million increase in residential and home equity line of credit loan commitments and construction loans in process and $14 million increase in commercial real estate commitments and loans in process. Commitments to extend credit are agreements to lend to a customer as long as there is no violation of any condition established in the commitments. Commitments generally have fixed expiration dates or other termination clauses and may require payment of a fee. Since certain of the commitments are expected to

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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, 20102012 and 2009,2011, ASB had commitments to sell residential loans of $21.9$86.6 million and $18.6$44.9 million, respectively. The loans are included in loans receivable as held for sale or represent commitments to make loans at an interest rate set prior to funding (rate lock commitments). Rate lock commitments guarantee a specified interest rate for a loan if ASB’s underwriting standards are met, but do not obligate the potential borrower. Rate lock commitments on loans intended to be sold in the secondary market are derivative instruments, but have not been designated as hedges. Rate lock commitments are carried at fair value and adjustments are recorded in “Other income, net” with an offset on the ASB balance sheet in “Other” liabilities. As of December 31, 20102012 and 2009,2011, ASB had rate lock commitments on outstanding loans totaling $15.1 mill ionnotional amounts of $60.4 million and $13.8$35.8 million, respectively. To offset the impact of changes in market interest rates on the rate lock commitments on loans held for sale, ASB utilizes short-term forward sale contracts. Forward sales contracts are also derivative instruments, but have not been designated as hedges, and thus any changes in fair value are also recorded in ASB “Other income,” with an offset in the ASB balance sheet in “Other” assets or liabilities. As of December 31, 20102012 and 2009,2011, the notional amounts for forward sales contracts were $21.9$86.6 million and $18.6$44.9 million, respectively. Valuation models are applied using current market information to estimate fair value. In 2010, there wasThere were no gainsignificant gains or loss on derivatives. There was a net losslosses on derivatives of $0.2 million in 2009. For 2008, there was a net gain on derivatives of $0.3 million.

2012, 2011 and 2010.

As of December 31, 20102012 and 2009, ASB had commitments to sell education loans of nil and $20.5 million, respectively.

As of December 31, 2010 and 2009,2011, standby, commercial and banker’s acceptance letters of credit totaled $16.3$10.5 million and $19.5$10.8 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, 20102012 and 2009,2011, undrawn consumer lines of credit, including credit cards, totaled $856.7 million$1.0 billion and $801.1 million,$0.9 billion, respectively, and undrawn commercial loans including lines of credit totaled $263.4$376.2 million and $315.1$289.3 million, respectively.

ASB services real estate loans for investors ($0.81.3 billion, $0.6$1.0 billion and $0.3$0.8 billion as of December 31, 2010, 20092012, 2011 and 2008,2010, respectively), which are not included in the accompanying consolidated financial statements.balance sheet

115



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, 20102012 and 2009,2011, ASB had pledged loans with an amortized cost of approximately $1.4$1.0 billion and $1.6$1.1 billion, respectively, as collateral to secure advances from the FHLB of Seattle.

As of December 31, 20102012 and 2009,2011, 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 $60.9$70.9 million and $79.3$62.1 million, respectively. The $18.4$8.8 million decreaseincrease in such loans in 20102012 was attributed to closed linesnew commitments and loans of credit and repayments of $57.5$10.0 million offset by loans and lines of credit to new and existing directors and executive officers, offset by closed lines of $39.1credits and repayments of $1.2 million. As of December 31, 20102012 and 2009, $52.52011, $65.9 million and $65.4$56.4 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 prefer redpreferred 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.

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Table of Contents

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—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, and corporate credit cards. For commercial loans, the portfolio is differentiated by separating Commercial & Industrial (C&I) 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.

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.

 

116



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 adjustmentsQualitative adjustments to historical loss rates or other static sources may be necessary since these rates may not be an accurate guide to assessing losses inherent in the current portfolio. To estimate the level of adjustments, management considers factors including levels and trends in problem loans, volume and term of loans, changes in risk from changes in lending policies and practices, management expertise, economic conditions, industry trends, and the effect of credit concentrations.

Unallocated allowanceASB’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.

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Table of Contents

At December 31, 2010, theThe allowance for loan losses was comprised of the following:

 

 

Residential

Commercial
real

Home
equity line

Residen-
tial

Commercial

Residential

Commer-
cial

Consu-
mer

Unallo-

 

(in thousands)

 

1-4 family

estate

of credit

land

construction

construction

loans

loans

cated

Total

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 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

Allowance for loan losses:

 

 

 

 

 

 

 

 

 

Beginning balance

 

$6,497  

$1,474  

$4,269  

$6,411  

$1,714  

$  7  

$16,015  

$3,325  

$ 934

$  40,646 

Charge-offs

 

(5,528)  

–   

(1,439) 

(4,071) 

–   

–   

(5,335) 

(3,117) 

– 

(19,490)

Recoveries

 

110  

–   

25  

170  

–   

–   

869  

567  

– 

1,741 

Provision

 

5,421  

214  

1,499  

1,285  

174  

(3) 

3,318  

3,031  

70

15,009 

Ending balance

 

$6,500  

$1,688  

$4,354  

$3,795  

$1,888  

$  4  

$14,867  

$3,806  

$1,004

$  37,906 

Ending balance: individually evaluated for impairment

 

$203  

$ –   

$ –   

$2,525  

$–   

$ –   

$976  

$ –   

$ – 

$3,704 

Ending balance: collectively evaluated for impairment

 

$6,297  

$1,688  

$4,354  

$1,270  

$1,888  

$  4  

$13,891  

$3,806  

$1,004

$34,202 

 

 

 

 

 

 

 

 

 

 

 

 

Financing Receivables:

 

 

 

 

 

 

 

 

 

Ending balance

 

$1,926,774  

$331,931  

$535,481  

$45,392  

$41,950  

$3,327  

$716,427  

$93,253  

$ – 

$3,694,535 

Ending balance: individually evaluated for impairment

 

$26,012  

$13,397  

$1,450  

$39,364  

$ –   

$ –   

$48,241  

$24  

$ – 

$128,488 

Ending balance: collectively evaluated for impairment

 

$1,900,762  

$318,534  

$534,031  

$6,028  

$41,950  

$3,327  

$668,186  

$93,229  

$ – 

$3,566,047 

 

 

 

Residential

 

Commercial
real

 

Home
equity line

 

Residen-
tial

 

Commercial

 

Residen-
tial
construc-

 

Commer-
cial

 

Consu-
mer

 

Unallo-

 

 

 

(in thousands)

 

1-4 family

 

estate

 

of credit

 

land

 

construction

 

tion

 

loans

 

loans

 

cated

 

Total

 

Allowance for loan losses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

5,522

 

$

861

 

$

4,679

 

$

4,252

 

$

3,068

 

$

19

 

$

19,498

 

$

2,590

 

$

1,190

 

$

41,679

 

Charge-offs

 

6,142

 

 

2,517

 

6,487

 

 

 

6,261

 

3,408

 

 

24,815

 

Recoveries

 

744

 

 

63

 

63

 

 

 

1,537

 

481

 

 

2,888

 

Provision

 

6,373

 

$

613

 

2,044

 

8,583

 

(1,354

)

(12

)

1,241

 

$

3,662

 

(256

)

20,894

 

Ending balance

 

$

6,497

 

$

1,474

 

$

4,269

 

$

6,411

 

$

1,714

 

$

7

 

$

16,015

 

$

3,325

 

$

934

 

$

40,646

 

Ending balance: individually evaluated for impairment

 

$

230

 

$

 

$

 

$

1,642

 

$

 

$

 

$

1,588

 

$

 

 

 

$

3,460

 

Ending balance: collectively evaluated for impairment

 

$

6,267

 

$

1,474

 

$

4,269

 

$

4,769

 

$

1,714

 

$

7

 

$

14,427

 

$

3,325

 

$

934

 

$

37,186

 

Ending balance: loans acquired with deteriorated credit quality

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financing Receivables:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ending balance

 

$

2,087,813

 

$

300,689

 

$

416,453

 

$

65,599

 

$

38,079

 

$

5,602

 

$

551,683

 

$

80,138

 

 

 

$

3,546,056

 

Ending balance: individually evaluated for impairment

 

$

34,615

 

$

12,156

 

$

827

 

$

39,631

 

$

 

$

 

$

28,886

 

$

76

 

 

 

$

116,191

 

Ending balance: collectively evaluated for impairment

 

$

2,053,198

 

$

288,533

 

$

415,626

 

$

25,968

 

$

38,079

 

$

5,602

 

$

522,797

 

$

80,062

 

 

 

$

3,429,865

 

Ending balance: loans acquired with deteriorated credit quality

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

$

 

 

 

$

 

117



 

Changes in the allowance for loan losses were as follows:

 

(dollars in thousands)

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for loan losses, January 1

 

$

35,798

 

$

30,211

 

 

$37,906

 

$40,646

 

$41,679

 

 

 

 

 

 

 

 

 

 

 

 

 

Provision for loan losses

 

32,000

 

10,334

 

 

12,883

 

15,009

 

20,894

 

 

 

 

 

 

 

 

 

 

 

 

 

Charge-offs, net of recoveries

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans

 

9,526

 

308

 

 

3,828

 

10,733

 

14,276

 

Other loans

 

16,593

 

4,439

 

 

4,976

 

7,016

 

7,651

 

Net charge-offs

 

26,119

 

4,747

 

 

8,804

 

17,749

 

21,927

 

Allowance for loan losses, December 31

 

$

41,679

 

$

35,798

 

 

$41,985

 

$37,906

 

$40,646

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of net charge-offs to average loans outstanding

 

0.66

%

0.11

%

 

0.24%

 

0.49%

 

0.61%

 

 

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 quality problemstrends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial and CREindustrial, commercial real estate and commercial construction loans.

A dual ten-point risk rating system is used to determine loan gradereflect the probability of default (borrower risk rating) and is based onloss given default (transaction risk rating). The borrower loan risk. The risk rating addresses risk presented by the individual borrower and is a numerical representation of risk 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 issuesquality 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 loan gradenumerical representation of the risk categories are:

1- Substantially risk free

2- Minimal risk

3- Modest risk

4- Better than average risk

5- Average risk

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 at December 31, 2010 was as follows:

 

December 31

 

2012

 

2011

 

(in thousands)

 

Commercial
real estate

 

Commercial
construction

 

Commercial

 

Commercial
real estate

 

Commercial
construction

 

Commercial

 

Grade:

 

 

 

 

 

 

 

 

 

 

 

 

 

Pass

 

$314,182

 

$39,063

 

$638,854

 

$308,843

 

$41,950

 

$650,234

 

Special mention

 

25,437

 

4,925

 

24,511

 

8,594

 

 

14,660

 

Substandard

 

29,308

 

 

53,538

 

11,058

 

 

47,607

 

Doubtful

 

6,750

 

 

4,446

 

3,436

 

 

3,926

 

Loss

 

 

 

 

 

 

 

Total

 

$375,677

 

$43,988

 

$721,349

 

$331,931

 

$41,950

 

$716,427

 

The increase in commercial real estate and commercial 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.

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Table of Contents

(in thousands)

 

Commercial
real estate

 

Commercial
construction

 

Commercial

 

Grade:

 

 

 

 

 

 

 

Pass

 

$

285,624

 

$

38,079

 

$

462,078

 

Special mention

 

526

 

 

44,759

 

Substandard

 

14,539

 

 

44,259

 

Doubtful

 

 

 

556

 

Loss

 

 

 

31

 

Total

 

$

300,689

 

$

38,079

 

$

551,683

 

 

The credit risk profile based on payment activity for loans at December 31, 2010 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

 

 

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, 2012

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

8,245

 

$

3,719

 

$

36,419

 

$

48,383

 

$

2,039,430

 

$

2,087,813

 

$

 

 

$ 6,353

$1,741

$24,054

$32,148

$1,834,302

$1,866,450

$  – 

Commercial real estate

 

 

4

 

 

4

 

300,685

 

300,689

 

 

 

85

– 

6,750

6,835

368,842

375,677

– 

Home equity line of credit

 

1,103

 

227

 

1,659

 

2,989

 

413,464

 

416,453

 

 

 

1,077

142

1,319

2,538

627,637

630,175

– 

Residential land

 

1,543

 

1,218

 

16,060

 

18,821

 

46,778

 

65,599

 

581

 

 

2,851

75

7,788

10,714

15,101

25,815

– 

Commercial construction

 

 

 

 

 

38,079

 

38,079

 

 

 

– 

– 

– 

– 

43,988

43,988

– 

Residential construction

 

 

 

 

 

5,602

 

5,602

 

 

 

– 

– 

– 

– 

6,171

6,171

– 

Commercial loans

 

892

 

1,317

 

3,191

 

5,400

 

546,283

 

551,683

 

64

 

 

3,052

2,814

1,098

6,964

714,385

721,349

131

Consumer loans

 

629

 

410

 

617

 

1,656

 

78,482

 

80,138

 

320

 

 

598

348

424

1,370

119,861

121,231

242

Total loans

 

$

12,412

 

$

6,895

 

$

57,946

 

$

77,253

 

$

3,468,803

 

$

3,546,056

 

$

965

 

 

$14,016

$5,120

$41,433

$60,569

$3,730,287

$3,790,856

$373

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$10,391

$4,583

$28,113

$43,087

$1,883,687

$1,926,774

$    – 

Commercial real estate

 

– 

– 

– 

– 

331,931

331,931

– 

Home equity line of credit

 

1,671

494

1,421

3,586

531,895

535,481

– 

Residential land

 

2,352

575

13,037

15,964

29,428

45,392

205

Commercial construction

 

– 

– 

– 

– 

41,950

41,950

– 

Residential construction

 

– 

– 

– 

– 

3,327

3,327

– 

Commercial loans

 

226

733

1,340

2,299

714,128

716,427

28

Consumer loans

 

553

344

486

1,383

91,870

93,253

308

Total loans

 

$15,193

$6,729

$44,397

$66,319

$3,628,216

$3,694,535

$ 541

 

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

 

December 31

 

2012

2011

 

Nonaccrual loans

 

Accruing loans 90 days or
more past due

 

Trouble debt
restructured loans

 

 

Nonaccrual
loans

Accruing loans
90 days or
more past due

Nonaccrual
loans

Accruing loans
90 days or
more past due

December 31

 

2010

 

2009

 

2010

 

2009

 

2010

 

2009

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

36,420

 

$

31,848

 

$

 

$

 

$

5,150

 

$

1,986

 

Residential 1–4 family

 

$26,721

$  –

$28,298

$  –

Commercial real estate

 

 

344

 

 

 

1,963

 

513

 

 

6,750

3,436

Home equity line of credit

 

1,659

 

2,755

 

 

 

 

 

 

2,349

2,258

Residential land

 

15,479

 

25,164

 

581

 

 

27,689

 

15,665

 

 

8,561

14,535

205

Commercial construction

 

 

 

 

 

 

 

 

Residential construction

 

 

326

 

 

 

 

 

 

Commercial loans

 

4,956

 

4,171

 

64

 

 

4,035

 

2,904

 

 

20,222

131

17,946

28

Consumer loans

 

341

 

715

 

320

 

 

 

 

 

284

242

281

308

Total

 

$

58,855

 

$

65,323

 

$

965

 

$

 

$

38,837

 

$

21,068

 

 

$64,887

$373

$66,754

$541

 

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

 

 

2010

 

2009

 

December 31
(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

 

December 31

 

2012

 

2011

(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

 

$

18,205

 

$

24,692

 

$

 

$

14,609

 

$

278

 

$

2,412

 

$

2,412

 

$

 

$

1,891

 

$

91

 

 

$14,633

$20,247

$   – 

$16,688

$  294

 

$  19,217

$  26,614

$

– 

$  21,385

$

282

Commercial real estate

 

12,156

 

12,156

 

 

14,276

 

979

 

15,212

 

15,212

 

 

14,522

 

882

 

 

2,929

2,929

– 

7,771

237

 

13,397

13,397

– 

13,404

747

Home equity line of credit

 

 

 

 

 

 

 

 

 

 

 

 

581

1,374

– 

632

1

 

711

1,612

– 

954

6

Residential land

 

33,777

 

40,802

 

 

29,914

 

1,499

 

16,552

 

16,552

 

 

7,934

 

589

 

 

7,691

10,624

– 

21,589

1,185

 

30,781

39,136

– 

33,398

1,779

Commercial construction

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

Residential construction

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

Commercial loans

 

22,041

 

22,041

 

 

29,636

 

1,846

 

27,082

 

27,082

 

 

29,908

 

1,412

 

 

4,265

6,994

– 

24,605

986

 

41,680

43,516

– 

40,952

2,912

Consumer loans

 

 

 

 

 

 

 

 

 

 

 

 

21

21

– 

23

– 

 

25

25

– 

16

– 

 

86,179

 

99,691

 

 

88,435

 

4,602

 

61,258

 

61,258

 

 

54,255

 

2,974

 

 

30,120

42,189

– 

71,308

2,703

 

105,811

124,300

– 

110,109

5,726

 

 

 

 

 

 

 

 

 

 

 

 

With an allowance recorded

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

3,917

 

3,917

 

230

 

2,807

 

175

 

 

 

 

 

 

 

4,803

4,803

384

4,204

250

 

3,525

3,525

203

3,527

201

Commercial real estate

 

 

 

 

 

 

 

 

 

 

 

 

3,821

3,840

535

1,295

– 

 

– 

– 

– 

– 

– 

Home equity line of credit

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

26

– 

 

– 

– 

– 

– 

– 

Residential land

 

5,041

 

5,090

 

1,642

 

3,753

 

327

 

 

 

 

 

 

 

9,984

10,364

3,221

7,428

575

 

7,792

7,852

2,525

8,158

603

Commercial construction

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

Residential construction

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

Commercial loans

 

6,845

 

6,845

 

1,588

 

2,796

 

182

 

4,505

 

4,505

 

1,635

 

3,937

 

236

 

 

16,033

16,912

2,659

8,429

23

 

6,561

6,561

976

8,131

737

Consumer loans

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

 

34,641

35,919

6,799

21,382

848

 

17,878

17,938

3,704

19,816

1,541

 

15,803

 

15,852

 

3,460

 

9,356

 

684

 

4,505

 

4,505

 

1,635

 

3,937

 

236

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

22,122

 

28,609

 

230

 

17,416

 

453

 

2,412

 

2,412

 

 

1,891

 

91

 

 

19,436

25,050

384

20,892

544

 

22,742

30,139

203

24,912

483

Commercial real estate

 

12,156

 

12,156

 

 

14,276

 

979

 

15,212

 

15,212

 

 

14,522

 

882

 

 

6,750

6,769

535

9,066

237

 

13,397

13,397

– 

13,404

747

Home equity line of credit

 

 

 

 

 

 

 

 

 

 

 

 

581

1,374

– 

658

1

 

711

1,612

– 

954

6

Residential land

 

38,818

 

45,892

 

1,642

 

33,667

 

1,826

 

16,552

 

16,552

 

 

7,934

 

589

 

 

17,675

20,988

3,221

29,017

1,760

 

38,573

46,988

2,525

41,556

2,382

Commercial construction

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

Residential construction

 

 

 

 

 

 

 

 

 

 

 

 

– 

– 

– 

– 

– 

 

– 

– 

– 

– 

– 

Commercial loans

 

28,886

 

28,886

 

1,588

 

32,432

 

2,028

 

31,587

 

31,587

 

1,635

 

33,845

 

1,648

 

 

20,298

23,906

2,659

33,034

1,009

 

48,241

50,077

976

49,083

3,649

Consumer loans

 

 

 

 

 

 

 

 

 

 

 

 

21

21

– 

23

– 

 

25

25

– 

16

– 

 

$

101,982

 

$

115,543

 

$

3,460

 

$

97,791

 

$

5,286

 

$

65,763

 

$

65,763

 

$

1,635

 

$

58,192

 

$

3,210

 

 

$64,761

$78,108

$6,799

$92,690

$3,551

 

$123,689

$142,238

$

3,704

$129,925

$

7,267

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 handle 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 does not reduce the interest rate on commercial loan TDR modifications. Occasionally, additional collateral and/or guaranties are obtained.

All TDR loans are classified 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

120



impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.

Loan modifications that occurred during 2012 and 2011 were as follows:

 

 

2012

 

2011

 

 

Number of

Outstanding recorded investment

 

Number of

Outstanding recorded investment

 (dollars in thousands)

 

contracts

Pre-modification

Post-modification

 

contracts

Pre-modification

Post-modification

 

 

 

 

 

 

 

 

 

 Troubled debt restructurings

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

Residential 1-4 family

 

35

$ 8,805

$ 8,232

 

42

$11,233

$  9,853

Commercial real estate

 

– 

– 

– 

 

– 

– 

– 

Home equity line of credit

 

– 

– 

– 

 

1

93

93

Residential land

 

26

6,149

5,484

 

46

9,965

9,946

Commercial loans

 

19

2,583

2,583

 

56

35,349

35,349

Consumer loans

 

– 

– 

– 

 

1

25

25

 

 

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 2012 and 2011, and for which the payment default occurred within one year of the modification, were as follows:

 

 

2012

2011

 (dollars in thousands)

 

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

 

– 

– 

– 

Residential land

 

– 

1

528

Commercial loans

 

1

482

4

799

Consumer loans

 

– 

– 

– 

 

 

1

$

482

5

$

1,327

For 2012 the one commercial loan that subsequently defaulted was modified by temporarily lowering the monthly payments and deferring principal payments for a short period of time. For 2011 the residential land loan TDR that subsequently defaulted was modified by extending the maturity date. The four commercial loans that subsequently defaulted were modified by extending the maturity date and deferring principal payments for a short period of time.

 

Deposit liabilities.

 

December 31

 

2012

2011

 

2010

 

2009

 

 

Weighted-average

 

Weighted-average

 

December 31

 

Weighted-average

 

 

 

Weighted-average

 

 

 

(dollars in thousands)

 

stated rate

 

Amount

 

stated rate

 

Amount

 

 

stated rate

Amount

stated rate

Amount 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Savings

 

0.12

%

$

1,623,211

 

0.19

%

$

1,592,739

 

 

0.06

%

$1,758,547

0.07

%

$1,684,875

Other checking

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest-bearing

 

0.05

 

589,228

 

0.09

 

580,737

 

 

0.02

 

641,970

0.02

 

610,542

Noninterest-bearing

 

 

473,297

 

 

427,585

 

 

–  

 

621,806

–  

 

538,214

Commercial checking

 

 

392,345

 

 

380,889

 

 

–  

 

542,502

–  

 

455,614

Money market

 

0.28

 

230,990

 

0.43

 

202,115

 

 

0.13

 

191,398

0.21

 

236,641

Term certificates

 

1.25

 

666,301

 

1.65

 

874,695

 

 

0.86

 

473,693

0.98

 

544,146

 

0.28

%

$

3,975,372

 

0.46

%

$

4,058,760

 

 

0.13

%

$4,229,916

0.18

%

$4,070,032

 

As of December 31, 20102012 and 2009,2011, certificate accounts of $100,000 or more totaled $153$106 million and $208$119 million, respectively.

The approximate amounts of term certificates outstanding as of December 31, 20102012 with scheduled maturities for 20112013 through 20152017 were $436 million in 2011, $72 million in 2012, $43$284 million in 2013, $40$64 million in 2014, $60$70 million in 2015, $26 million in 2016, $20 million in 2017, and $15$10 million thereafter.

 

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

 

(in thousands)

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Term certificates

 

$

11,221

 

$

27,369

 

$

49,530

 

 

$4,865

 

$6,393

 

$11,221

 

Savings

 

2,262

 

4,952

 

8,577

 

 

1,128

 

1,756

 

2,262

 

Money market

 

884

 

886

 

1,793

 

 

319

 

650

 

884

 

Interest-bearing checking

 

329

 

839

 

1,583

 

 

111

 

184

 

329

 

 

$

14,696

 

$

34,046

 

$

61,483

 

 

$6,423

 

$8,983

 

$14,696

 

 

Other borrowings.

 

Securities sold under agreements to repurchase.

 

 

 

 

 

 

 

 

December 31, 2010
Maturity

 

Repurchase liability

 

Weighted-average
interest rate

 

Collateralized by mortgage-related
securities and federal
agency obligations—
fair value plus accrued interest

 

December 31, 2012

 

 

 

 

 

 

 

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

 

$

122,022

 

0.45

%

$

141,733

 

 

$95,642

 

0.15

%

$127,093

 

1 to 29 days

 

 

 

 

 

– 

 

–  

 

– 

 

30 to 90 days

 

 

 

 

 

– 

 

–  

 

– 

 

Over 90 days

 

50,297

 

4.75

 

63,691

 

 

50,284

 

4.75

 

62,748

 

 

$

172,319

 

1.71

%

$

205,424

 

 

$145,926

 

1.74

%

$189,841

 

 

At December 31, 2010,2012, $50 million of securities sold under agreements to repurchase with a rate of 4.75% and maturity date over 90 days is callable quarterly at par until maturity.

The securities underlying the agreements to repurchase are book-entry securities and were delivered by appropriate entry into the counterparties’ accounts at the Federal Reserve System. Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the consolidated balance sheets. The securities underlying the agreements to repurchase continue to be reflected in ASB’s asset accounts.

The following table sets forth informationInformation concerning securities sold under agreements to repurchase, which provided for the repurchase of identical securities:securities, was as follows:

 

(dollars in millions)

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount outstanding as of December 31

 

$

172

 

$

233

 

$

241

 

 

$146

 

$183  

 

$172 

 

Average amount outstanding during the year

 

$

201

 

$

230

 

$

507

 

 

$173

 

$183  

 

$201 

 

Maximum amount outstanding as of any month-end

 

$

238

 

$

241

 

$

817

 

 

$189

 

$186  

 

$238 

 

Weighted-average interest rate as of December 31

 

1.71

%

1.38

%

1.86

%

 

1.74

%

1.56

%

1.71

%

Weighted-average interest rate during the year

 

1.53

%

1.55

%

2.98

%

 

1.56

%

1.61

%

1.53

%

Weighted-average remaining days to maturity as of December 31

 

628

 

544

 

601

 

 

489

 

490  

 

628 

 

 

Advances from Federal Home Loan Bank.

 

December 31, 2010

 

Weighted-average
stated rate

 

Amount

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Due in

 

 

 

 

 

2011

 

2.64

%

$

15,000

 

2012

 

 

 

2013

 

 

 

2014

 

 

 

2015

 

 

 

Thereafter

 

4.28

 

50,000

 

 

 

3.90

%

$

65,000

 

December 31, 2012

 

Weighted-average
stated rate

 

Amount

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Due in

 

 

 

 

 

2013

 

%

$       – 

 

2014

 

– 

 

– 

 

2015

 

– 

 

– 

 

2016

 

– 

 

– 

 

2017

 

4.28

 

50,000

 

Thereafter

 

– 

 

– 

 

 

 

4.28

%

$50,000

 

 

At December 31, 2010,2012, $50 million of fixed rate FHLB advances with a rate of 4.28% is callable quarterly at par until maturity in 2017.

 

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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 cha rges,charges, to be immediately due and payable. Advances from the FHLB of Seattle are securedcollateralized 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, 20102012 and 2009.2011.

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$65.1 million (Capital Maintenance Agreement). As of December 31, 2010,2012, as a result of capital contributions in prior years, HEI’s maximum obligation to contribute additional capital under the Capital Maintenance Agreement hadhas been reduced to approximately $28.3 million. As of December 31, 2010,2012, ASB was in compliance with the minimum capital requirements under OTSOCC regulations.

In 2010,2012, ASB paid cash dividends of $62$45 million to HEI, compared to $50.1cash dividends of $58 million and distributed noncash dividends of $5 million in 2009.2011. The OTS must approve ASB’snoncash dividend was the fair value of assets associated with an ASB office lease assumed by HEI. The FRB and OCC approved the dividends.

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. The federal judge will hold a hearing to give objectors a chance to weigh in before final approval is given. No date has been set for the hearing. As of December 31, 2010,2012, 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.  Under the Federal Deposit Insurance Reform Act of 2005 (the Reform Act), the Federal Deposit Insurance Corporation (FDIC) may set the designated reserve ratio within a range of 1.15% to 1.50%. The Reform Act requires that the FDIC’s Board of Directors adopt a restoration plan when the Deposit Insurance Fund (DIF) reserve ratio falls below 1.15% or is expected to within six months. Financial institution failures have significantly increased the DIF’s loss provisions, resulting in declines in the reserve ratio. As of June 30, 2008, the reserve ratio had fallen 18 basis points since the previous quarter to 1.01%. To restore the reserve ratio to 1.15%, higher assessment rates were required. The FDIC made changes to the assessment system to ensure that riskier institutions will bear a greater share of the proposed increase in assessments. Under the final rules, financial institutions in Risk Category I, the lowest risk group, will have an initial base assessment rate within the range of 12 to 16 basis points of deposits. After applying adjustments for unsecured debt, secured liabilities and brokered deposits, the total base assessment rate for financial institutions in Risk Category I would be within the range of 7 to 24 basis points of deposits. The new assessment rates became effective April 1, 2009. The FDIC also raised the current rates uniformly by seven basis points for the assessment for the quarter beginning January 1, 2009.

In May 2009, the board of directors of the FDIC voted to levy a special assessment on deposit institutions to build the DIF and restore public confidence in the banking system. The special assessment was 5 basis points on each institution’s total assets, minus its Tier 1 core capital, as of June 30, 2009. Based on the FDIC’s formula, ASB’s special assessment was $2.3 million and ASB recorded the charge in June 2009. ASB is classified in Risk Category I and its assessment rate was 13.9 basis points of deposits, or $5.8 million (excluding the special assessment recorded in June 2009), for 2009, compared to an

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assessment rate of 5.3 basis points of deposits, or $1.5 million (net of a one-time assessment credit), for 2008.

In November 2009, the Board of Directors of the FDICFederal 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 will record a charge to earnings for its regular quarterly assessment and offset the prepaid expense until the asset is exhausted. Once the asset is exhausted, ASB will record an accrued expense payable each quarter for the assessment to be paid. If the prepaid assessmen tassessment is not exhausted by December 30, 2014, any remaining amount will be returned to ASB. ASB’s prepaid assessment was approximately $24 million. For the yearsyear ended December 31, 2010, and 2009, ASB’s assessment rate was 14 basis points of deposits, or $5.7 million and $5.8 million, respectively.

million.

In November 2010,February 2011, the FDIC proposed afinalized rules to change to its assessment base from total domestic deposits to average total assets minus average tangible equity, as required in the Dodd-Frank Act. The proposal would also lower the assessment rate schedule since the new base is larger than the current base.Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Assessment rates would bewere 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 will have assessment rates of 30 to 45 basis points. Based onThe new rate schedule was effective April 1, 2011. For the proposed changes to the assessment baseyears ended December 31, 2012 and rates, ASB anticipates a reduction in its annual2011, ASB’s FDIC assessment by approximately $2 million.insurance assessments were $3.0 million and $3.6 million, respectively.

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The FDIC may impose additional special assessments in the future if it is deemed necessary to ensure the DIFDeposit 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. Management cannot predict with certainty the timing or amounts of any additional assessments.

Deposit insurance coverage.  In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) permanently raised the current standard maximum deposit insurance amount to $250,000. Previously, the standard maximum deposit insurance amount of $100,000 had been temporarily raised to $250,000 through December 31, 2013. The Dodd-Frank Act also redefines the assessment base as average total consolidated assets less average tangible equity (previously the assessment base was based on deposits).

5 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, thus, the probable outcome and range of reasonably possible loss are not determinable at this time. Unconsolidated variable interest entities

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.  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 HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by each of HELCO and MECO each in the respective principal amountsamount of $10 million, (iii) making distributions on these trust s ecuritiessecurities 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 HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Taken together, HECO’s obligations under the HECO debentures, the HECO 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 HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with a ccountingaccounting rules on the consolidation of VIEs. Trust III’s balance sheet as of December 31, 20102012 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 20102012 consisted of $3.4 million of interest income received from the 2004 Debentures;

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$3.3 $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 HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO 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 HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.stock.

 

Purchase powerPower purchase agreements.  As of December 31, 2010,2012, HECO and its subsidiaries had six PPAs totaling 540 MW offor 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 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 91%90% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, withpurchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa, Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP)

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and HPOWER.HPower. Purchases from all IPPs for 20102012 totaled $549$724 million with purchases from AES Hawaii, Kalaeloa, HEP and HPOWERHPower totaling $143$146 million, $225$310 million, $57$65 million and $44$65 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

An enterprise with an interest in a VIE or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

HECO reviewed its significant PPAs and determined in 2004 that the IPPs at that time had no contractual obligation to provide such information. In March 2004, HECO and its subsidiaries sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of accounting standards for VIEs to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (e.g., HP OWER),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 HECO to determine the applicability of accounting standards for VIEs.

Since 2004, HECO 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 2010,2012, HECO and its subsidiaries sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa providedlater 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 theits PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as HELCO and MECO do not have variable interests in the entities because the PPAs do not require them to absorb any variabil ityvariability of the entities.

If the requested information is ultimately received from the otherremaining IPPs, a possible outcome of future analysisanalyses of such information is the consolidation of one or more of such IPPs in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’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. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.

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Kalaeloa Partners, L.P.  In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO 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 HECO 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 HECO 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, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO 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, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO could potentially absorb is the fact that HECO’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 HECO absorbs fuel price variability for the rema iningremaining term of the PPA, the PPA does not currently expose HECO 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 HECO’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates. As of December 31, 2012, HECO’s accounts payable to Kalaeloa amounted to $23 million.

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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 a portion of the $150 million of medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to better forecast its future interest expense. The FSS terminate in January and June 2011 and entitleentitled 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 arewere designated and accounted for as cash flow hedges and havehad a negative fair value of $2.8 million as of December 31, 2010 (recorded in “Other” liabilities on the consolidated balance sheet)liabilities). Changes in fair value arewere recognized (1) in other comprehensive income to the extent that t hey arethey were considered effective, and (2) in net income for any portion considered ineffective. The balance in accumulated other comprehensive income/(loss) (AOCI) at the dates of the anticipated medium-term note issuances will be accreted/amortized into interest expense over the lives of the new notes based on the effective interest method. For 2010, the ineffective portion of the change in fair value, or $0.8 million ($0.5 million, net of tax benefits), was recorded as a derivative loss in “Interest expense—other than on deposit liabilities and other bank borrowings” and the effectivefor any portion or $2.0 million ($1.2 million, net of tax benefits), was recorded as a net loss in AOCI. Of the $1.2 million net loss in AOCI, a net $0.2 million is expected to be reclassified to earnings during the next 12 months.

considered ineffective.

In January 2011, HEI settled the FSS with notional amountsfor payments totaling $50$5.2 million, of which $3.3 million was the ineffective portion ($0.8 million and $2.5 million recognized in 2010 and 2011, respectively) and $1.9 million being amortized to interest expense over five years beginning March 24, 2011 (the date that HEI issued $125 million of Senior Notes via a negative fair value of $1.3 million as of December 31, 2010 for a payment of $1.0 million.private placement).

 

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7 · Short-term borrowings

 

As of December 31, 20102012 and December 31, 2009,2011, HEI had $25$84 million and $42$69 million of outstanding commercial paper, respectively, with a weighted-average interest rate of 0.9% and 0.6%0.8%, respectively, and HECO had no commercial paper outstanding.

As of December 31, 2010,2012, HEI and HECO each maintained a syndicated credit facilities which totaledfacility of $125 million and $175 million, respectively. As of December 31, 2009, HEI borrowed under its facility in August 2012 and HECO maintained syndicated credit facilities which totaled $100 million and $175 million, respectively.repaid such borrowings in the same month. HEI had no borrowings under its facility during 20102011 and 2009. HECO had no borrowings under its facilitiesfacility during 2010. HECO drew on its facility in June2012 and July 2009; all such borrowings were repaid in August 2009.2011. None of the facilities are collateralized.

Credit agreements.

HEI.  Effective May 7, 2010,December 5, 2011, HEI entered into a revolving noncollateralized credit agreement establishing a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on May 7, 2013, withand a syndicate of eight financial institutions.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 225150 basis pointspoints; 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 10050 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 4025 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change. The agreement does not con taincontain 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 does containcontains customary conditions which must be met in order to draw on it, including compliance with its covenants.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, 2012, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of December 31, 2012, as calculated under the agreement), or if HEI no longer owns HECO.

HEI’s $125 million creditThe 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. HEI’s $100 million syndicated credit facility expiring March 31, 2011 was terminated concurrently with the effectiveness of this new syndicated credit facility.

 

HECOEffective May 7, 2010,December 5, 2011, HECO entered into a revolving noncollateralized credit agreement establishing a line of credit facility of $175 million, with a letter of credit sub-facility expiring on May 6, 2011, withand a syndicate of eight financial institutions.institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of HECO’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”,

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as defined in the agreement, plus 225150 basis pointspoints; 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 10050 basis points per annum, as defined in the agreement. Annual fees on the undrawn commitments are 4025 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term ratings change (such as when S&P lowered its long-term ratings for HECO, HELCO and MECO in November&nbs p;2010).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 does containcontains customary conditions that must be met in order to draw on it,the credit facility, including compliance with several covenants. The agreement’s termination date was extendedcovenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to May 7, 2013 after having received PUC approval.pay dividends to, or to repay borrowings from, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio of 42% for HELCO and 43% for MECO as of December 31, 2012, as calculated under the agreement)). In addition to customary defaults, HECO’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 HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 55% as of December 31, 2012, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

HECO’s $175 millionThe credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes. HECO’s $175 million syndicated credit facility expiring March 31, 2011 was terminated concurrently with the effectiveness of this new syndicated credit facility.

 

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8 · Long-term debt

 

8 · Long-term debt

December 31

 

2010

 

2009

 

 

2012

 

2011

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6.50% Junior Subordinated Deferrable Interest Debentures, Series 2004, due 2034 (see Note 5)

 

$

51,546

 

$

51,546

 

 

$

51,546

 

$

51,546

 

 

 

 

 

 

 

 

 

 

 

Obligations to the State of Hawaii for the repayment of special purpose revenue bonds issued on behalf of electric utility subsidiaries

 

 

 

 

 

 

 

 

 

 

4.75-4.95%, due 2012-2025

 

118,500

 

118,500

 

 

61,000

 

118,500

 

5.00-5.50%, due 2014-2032

 

203,400

 

203,400

 

 

63,400

 

203,400

 

5.65-5.75%, due 2018-2027

 

216,000

 

216,000

 

 

100,000

 

216,000

 

6.15-6.20%, due 2020-2029

 

55,000

 

55,000

 

 

 

55,000

 

4.60-4.65%, due 2026-2037

 

265,000

 

265,000

 

 

265,000

 

265,000

 

6.50%, due 2039

 

150,000

 

150,000

 

 

150,000

 

150,000

 

 

1,007,900

 

1,007,900

 

 

639,400

 

1,007,900

 

Less unamortized discount

 

(1,504

)

(1,631

)

 

(74

)

(1,376

)

 

1,006,396

 

1,006,269

 

 

639,326

 

1,006,524

 

 

 

 

 

 

 

 

 

 

 

HEI medium-term notes 4.23-6.141%, due 2011

 

150,000

 

150,000

 

HEI medium-term note 7.13%, due 2012

 

7,000

 

7,000

 

 

 

7,000

 

HEI medium-term note 5.25%, due 2013

 

50,000

 

50,000

 

 

50,000

 

50,000

 

HEI medium-term note 6.51%, due 2014

 

100,000

 

100,000

 

 

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

 

HECO, HELCO and MECO senior notes 3.79%, due 2018

 

50,000

 

 

HECO and MECO senior notes 4.03%, due 2020

 

82,000

 

 

HECO, HELCO and MECO senior notes 4.55%, due 2023

 

100,000

 

 

HECO senior note 4.72%, due 2029

 

35,000

 

 

HECO senior note 4.53%, due 2032

 

40,000

 

 

HECO senior note 5.39%, due 2042

 

150,000

 

 

 

$

1,364,942

 

$

1,364,815

 

 

$

1,422,872

 

$

1,340,070

 

 

As of December 31, 2010,2012, the aggregate principal payments required on long-term debt for 20112013 through 20152017 are $150 million in 2011, $65 million in 2012, $50 million in 2013, $111 million in 2014, nil in 2015, $75 million in 2016 and nil in 2015.2017.

9 127· Retirement benefits



The HEI medium-term notes and Note Agreement for the HEI 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 Note Agreement for the HEI senior notes also contains 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. For example, 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, 2012, as calculated under the agreement) or “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of December 31, 2012, as calculated under the agreement). The Note Agreement also requires that HEI offer to prepay the Notes upon a change of control or certain dispositions of assets (as defined in the Note Agreement).

The electric 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 HECO, and each of HELCO and MECO, of certain financial ratios generally consistent with those in HECO’s existing amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million.

9 · Retirement benefits

Defined benefit plans. Substantially all of the employees of HEI and the electric utilities participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (HEI/HECO 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/HECO 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/HECO Pension Plan, benefits for utility union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions.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 Directors’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.

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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 electric 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 (HECO Benefits Plan). Health benefitsEligibility of employees and dependents are also provided to dependents of eligible retired employees. The contribution for health benefits paid by the participating employers is based on eligibility to retire at termination, the retirees’ yearsretirement date and the date of hire. The

128



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 retirement dates. Generally,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 for these benefits if, upon retirement from active employment, they areto receive postretirement benefits. Employees may be eligible to receive benefits from the HEI/HECO Pension Plan.Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.

In the third quarter of 2009, the Company amended theThe executive lifedeath benefit plan was frozen on September 10, 2009 to limit it to current participants and to freeze the executive life benefits at current levels. In November 2010, August 2010benefit levels as of that date. The electric discount was eliminated for management employees and retirees of HECO in August 2009, HELCO in November 2010, and MECO in August 2010, and HECO, respectively, eliminated the electric discount benefit for merit employees and retirees, and the electric discount benefit for bargaining unit employees and retirees was eliminated on January 31, 2011. 2011 per the collective bargaining agreement.

The Company’s cost for OPEB has been adjusted to reflect the plan amendment,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.

Among other provisions, the HECO Benefits Plan provides prescription drug benefits for Medicare-eligible participants who retire after 1998. Retirees who are eligible for the drug benefits are required to pay a portion of the cost each month. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the 2003 Act) expanded Medicare to include for the first time coverage for prescription drugs. The 2003 Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28% of a participant’s drug costs between $250 and $5,000 (indexed for inflation) if the participant wai ves coverage under Medicare Part D.

The continuation of the HECO Benefits Plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. Each participating employer reserves the right to terminate its participation in the planHECO 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 recent 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 U.S. generally accepted accounting principles 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 expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.6 million in 2010)each of 2011 and 2012) determined in accordance with U.S. generally accepted accounting principles 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 electric utilities have reclassified to a regulatory asset charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge/(credit)charge to AOCI of $55$124 million pretax and $(124)$165 million pretax at December 31, 2010for 2012 and 2009,2011, respectively).

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Table of Contents

In the PUC’s 2007, interim decision on HELCO’s 2006 test year rate case, the PUC allowed HELCO to record a regulatory asset in the amount of $12.8 million (representing HELCO’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. HELCO 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 the PUC’s 2007, interim decisions on HECO and MECO’s 2007 test year rate cases (and in its final decision on HECO’s 2005 test year rate case), the PUC did notdeclined to allow HECO and MECO 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, HECO and MECO are required to fund only the minimum level required under the law until their pension assets are reduced to zero, at which time HECO and MECO 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 HECO’s and MECO’s pension assets from rate base does not allow HECO and MECO 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 (or was,(and has been, in the case of MECO) recovered in

129



rates (as NPPC is recorded in excess of contributions). As of December 31, 2010, MECO did not have any remaining pension asset, and2012, HECO’s pension asset had been reduced to $3$2 million.

The OPEB tracking mechanisms generally require the electric 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 electric utilities for 2012, 2011 and 2010 2009 and 2008 was $39 million, $32 million, $34 million and $27$39 million, respectively.

 

137Retirement 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 Hawaiian Electric Industries Retirement Savings Plan (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.

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Table of Contents

 

PensionDefined benefit pension and other postretirement benefit plans information.  The changes in the obligations and assets of the Company’s retirement benefit plans and the changes in AOCI (gross) for 20102012 and 20092011 and the funded status of these plans and amounts related to these plans reflected in the Company’s consolidated balance sheet as of December 31, 20102012 and 20092011 were as follows:

 

 

 

2010

 

2009

 

(in thousands)

 

Pension
benefits

 

Other
benefits

 

Pension
benefits

 

Other
benefits

 

Benefit obligation, January 1

 

$

1,014,287

 

$

170,572

 

$

964,388

 

$

180,656

 

Service cost

 

28,801

 

4,739

 

25,688

 

4,846

 

Interest cost

 

64,527

 

10,378

 

61,988

 

10,981

 

Amendments

 

 

(7,713

)

109

 

(13,198

)

Actuarial (gains) losses

 

121,898

 

11,817

 

14,323

 

(3,907

)

Benefits paid and expenses

 

(54,979

)

(9,461

)

(52,209

)

(8,806

)

Benefit obligation, December 31

 

1,174,534

 

180,332

 

1,014,287

 

170,572

 

Fair value of plan assets, January 1

 

738,971

 

134,608

 

619,134

 

106,415

 

Actual return on plan assets

 

119,446

 

21,271

 

154,942

 

27,386

 

Employer contribution

 

27,803

 

3,989

 

15,883

 

9,471

 

Benefits paid and expenses

 

(53,864

)

(8,751

)

(50,988

)

(8,664

)

Fair value of plan assets, December 31

 

832,356

 

151,117

 

738,971

 

134,608

 

Accrued benefit liability, December 31

 

(342,178

)

(29,215

)

(275,316

)

(35,964

)

AOCI, January 1 (excluding impact of PUC D&Os)

 

302,147

 

14,693

 

400,875

 

52,433

 

Recognized during year — net recognized transition obligation

 

(2

)

 

(2

)

(1,831

)

Recognized during year — prior service (cost)/credit

 

388

 

396

 

387

 

79

 

Recognized during year — net actuarial gains (losses)

 

(7,392

)

14

 

(15,847

)

(401

)

Occurring during year — prior service cost

 

 

(7,714

)

109

 

(2,476

)

Occurring during year — net actuarial losses (gains)

 

71,411

 

1,647

 

(83,375

)

(22,390

)

Other adjustments

 

 

 

 

(10,721

)

 

 

366,552

 

9,036

 

302,147

 

14,693

 

Cumulative impact of PUC D&Os

 

(340,187

)

(10,880

)

(278,582

)

(17,650

)

AOCI, December 31

 

26,365

 

(1,844

)

23,565

 

(2,957

)

Net actuarial loss

 

367,456

 

18,633

 

303,437

 

16,972

 

Prior service gain

 

(907

)

(9,597

)

(1,295

)

(2,279

)

Net transition obligation

 

3

 

 

5

 

 

 

 

366,552

 

9,036

 

302,147

 

14,693

 

Cumulative impact of PUC D&Os

 

(340,187

)

(10,880

)

(278,582

)

(17,650

)

AOCI, December 31

 

26,365

 

(1,844

)

23,565

 

(2,957

)

Income taxes

 

(10,403

)

718

 

(9,309

)

1,151

 

AOCI, net of taxes, December 31

 

$

15,962

 

$

(1,126

)

$

14,256

 

$

(1,806

)

The Company does not expect any plan assets to be returned to the Company during calendar year 2011.

 

 

2012

 

2011

 

(in thousands)

 

Pension
benefits

 

Other
benefits

 

Pension
benefits

 

Other
benefits

 

Benefit obligation, January 1

 

$1,322,430

 

$190,549

 

$1,174,534

 

$180,332

 

Service cost

 

43,221

 

4,211

 

35,016

 

4,409

 

Interest cost

 

67,480

 

9,009

 

64,966

 

9,534

 

Amendments

 

– 

 

– 

 

– 

 

(11,365

)

Actuarial losses (gains)

 

217,205

 

(1,991

)

104,970

 

16,518

 

Benefits paid and expenses

 

(60,032

)

(7,643

)

(57,056

)

(8,879

)

Benefit obligation, December 31

 

1,590,304

 

194,135

 

1,322,430

 

190,549

 

Fair value of plan assets, January 1

 

839,580

 

142,992

 

832,356

 

151,117

 

Actual return (loss) on plan assets

 

115,794

 

18,477

 

(9,713

)

(2,308

)

Employer contributions

 

74,923

 

2,780

 

72,931

 

2,030

 

Benefits paid and expenses

 

(58,983

)

(7,518

)

(55,994

)

(7,847

)

Fair value of plan assets, December 31

 

971,314

 

156,731

 

839,580

 

142,992

 

Accrued benefit liability, December 31

 

(618,990

)

(37,404

)

(482,850

)

(47,557

)

AOCI, January 1 (excluding impact of PUC D&Os)

 

533,537

 

28,684

 

366,552

 

9,036

 

Recognized during year – net recognized transition obligation

 

(1

)

– 

 

(2

)

– 

 

Recognized during year – prior service credit

 

325

 

1,793

 

389

 

1,494

 

Recognized during year – net actuarial losses

 

(25,675

)

(1,498

)

(16,987

)

(234

)

Occurring during year – prior service cost

 

– 

 

– 

 

– 

 

(11,365

)

Occurring during year – net actuarial losses (gains)

 

172,595

 

(10,133

)

183,585

 

29,753

 

 

 

680,781

 

18,846

 

533,537

 

28,684

 

Cumulative impact of PUC D&Os

 

(621,310

)

(18,123

)

(486,710

)

(29,183

)

AOCI, December 31

 

59,471

 

723

 

46,827

 

(499

)

Net actuarial loss

 

680,973

 

36,521

 

534,054

 

48,152

 

Prior service gain

 

(192

)

(17,675

)

(518

)

(19,468

)

Net transition obligation

 

– 

 

– 

 

1

 

– 

 

 

 

680,781

 

18,846

 

533,537

 

28,684

 

Cumulative impact of PUC D&Os

 

(621,310

)

(18,123

)

(486,710

)

(29,183

)

AOCL(AOCI), December 31

 

59,471

 

723

 

46,827

 

(499

)

Income taxes (benefits)

 

(23,489

)

(281

)

(18,495

)

194

 

AOCL(AOCI), net of taxes (benefits), December 31

 

$  35,982

 

$  442

 

$  28,332

 

$  (305

)

 

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2010, 20092012, 2011 and 2008.

2010.

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, 20102012 and 2009,2011, had aggregate ABOs of $990$1,383 million and $858$1,182 million, respectively, and plan assets of $758$971 million and $673$840 million, respectively.

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 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 HECO and its subsidiaries. If the Adjusted Funding Target Attainment Percentage falls below 80% in the future, the restrictions on accelerated distribution options may apply again.

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 and restrictions on participant benefit accruals may be placed on the plan. If the plans fallThe HEI Retirement Plan fell below these thresholds then, to avoid adverse consequences, funds in excess of2011 and the minimum required contribution may be contributed tofor 2012 incorporated the plan trust.more conservative assumptions required. Other factors could cause changes to the required contribution levels.  The Company’s current estimate of contributions to the qualified defined benefit plans and all other retirement benefit plans in 2011 is $64 million.

131



 

The Company estimates that the cash funding for the qualified defined benefit pension plans in 2011 and 20122013 will be $60$85 million, and $125 million, respectively, which should fully satisfy the minimum

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Table of Contents

required contributions to those plans, including requirements of the utilitiesutilities’ pension tracking mechanisms and the Plan’s funding policy.

The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2013 is $86 million.

As of December 31, 2010,2012, the benefits expected to be paid under theall retirement benefit plans in 2011, 2012, 2013, 2014, 2015, 2016, 2017 and 20162018 through 20202022 amounted to $66 million, $69 million, $72 million, $75$74 million, $79$77 million, $81 million and $452$460 million, respectively.

The Company has 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 years two to 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 net periodic benefit cost.

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

 

 

Pension benefits

 

Other benefits

 

 

 

 

 

 

Investment policy

 

 

 

 

 

Investment policy

 

 

 

 

 

 

Investment policy

 

 

 

 

 

Investment policy

 

December 31

 

2010

 

2009

 

Target

 

Range

 

2010

 

2009

 

Target

 

Range

 

 

2012

 

2011

 

Target

 

Range

 

2012

 

2011

 

Target

 

Range

 

Asset category

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

71

%

68

%

70

%

65-75%

 

70

%

67

%

70

%

65-75%

 

 

69

%

68

%

70

%

65-75

%

70

%

69

%

70

%

65-75

%

Fixed income

 

29

 

32

 

30

 

25-35%

 

30

 

33

 

30

 

25-35%

 

 

31

 

32

 

30

 

25-35

%

30

 

31

 

30

 

25-35

%

 

100

%

100

%

100

%

 

 

100

%

100

%

100

%

 

 

 

100

%

100

%

100

%

 

 

100

%

100

%

100

%

 

 

 

See Note 15 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

 

 

Pension benefits

 

Other benefits

 

December 31

 

2010

 

2009

 

2008

 

2010

 

2009

 

2008

 

 

2012

2011

2010

2012

2011

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

5.68

%

6.50

%

6.625

%

5.60

%

6.50

%

6.50

%

Benefit obligation
Discount rate

 

4.13

%

5.19

%

5.68

%

4.07

%

4.90

%

5.60

%

Rate of compensation increase

 

3.5

 

3.5

 

3.5

 

NA

 

NA

 

3.5

 

 

3.5

 

3.5

 

3.5

 

NA   

 

NA   

 

NA   

 

Net periodic benefit cost (years ended)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

6.50

 

6.625

 

6.125

 

6.50

 

6.50

 

6.125

 

Net periodic benefit cost (years ended)
Discount rate

 

5.19

 

5.68

 

6.50

 

4.90

 

5.60

 

6.50

 

Expected return on plan assets

 

8.25

 

8.25

 

8.50

 

8.25

 

8.25

 

8.50

 

 

7.75

 

8.00

 

8.25

 

7.75

 

8.00

 

8.25

 

Rate of compensation increase

 

3.5

 

3.5

 

4.2

 

NA

 

3.5

 

4.2

 

 

3.5

 

3.5

 

3.5

 

NA   

 

NA   

 

NA   

 

 

NA  Not applicable

 

The Company based its selection of an assumed discount rate for 2011 net periodic benefit cost2012 NPBC and December 31, 20102011 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, 2010.2011. In selecting the expected rate of return on plan assets of 8%7.75% for 2011 net periodic benefit cost,2012 NPBC, the Company considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the plans’Plans’ asset allocations, industry and corporate surveys and the past performance of the plans’ assets. The matching of bond income to anticipated benefit cash flows was refined for 2010 but the basic methods of selecting the assumed discount rate and expected return on plan assets at December 31, 2010 did not change from December 31 2009.

As of December 31, 2010,2012, the assumed health care trend rates for 20112013 and future years were as follows: medical, 9%8%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. As of December 31, 2009,2011, the assumed health care trend rates for 20102012 and future years were as follows: medical, 10%8.5%, grading down to 5% for 20152019 and thereafter; dental, 5%; and vision, 4%. Medicare Advantage

 

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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 2012 through 2014 and 3% higher in 2015.

The components of net periodic benefit costNPBC were as follows:

 

 

Pension benefits

 

Other benefits

 

 

Pension benefits

 

Other benefits

 

(in thousands)

 

2010

 

2009

 

2008

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

28,801

 

$

25,688

 

$

28,356

 

$

4,739

 

$

4,846

 

$

4,777

 

 

$ 43,221

 

$ 35,016

 

$ 28,801

 

$  4,211

 

$ 4,409

 

$ 4,739

 

Interest cost

 

64,527

 

61,988

 

59,765

 

10,378

 

10,981

 

11,008

 

 

67,480

 

64,966

 

64,527

 

9,009

 

9,534

 

10,378

 

Expected return on plan assets

 

(68,959

)

(57,244

)

(73,172

)

(11,101

)

(8,902

)

(10,970

)

 

(71,183

)

(68,901

)

(68,959

)

(10,336

)

(10,650

)

(11,101

)

Amortization of net transition obligation

 

2

 

2

 

2

 

 

1,831

 

3,138

 

 

1

 

2

 

2

 

– 

 

– 

 

 

Amortization of net prior service cost (gain)

 

(388

)

(387

)

(421

)

(396

)

(79

)

13

 

Amortization of net prior service gain

 

(325

)

(389

)

(388

)

(1,793

)

(1,494

)

(396

)

Amortization of net actuarial loss (gain)

 

7,392

 

15,847

 

6,765

 

(14

)

401

 

 

 

25,675

 

16,987

 

7,392

 

1,498

 

234

 

(14

)

Net periodic benefit cost

 

31,375

 

45,894

 

21,295

 

3,606

 

9,078

 

7,966

 

 

64,869

 

47,681

 

31,375

 

2,589

 

2,033

 

3,606

 

Impact of PUC D&Os

 

10,207

 

(10,570

)

5,859

 

5,400

 

(132

)

1,038

 

 

(15,754

)

(3,516

)

10,207

 

(2,227

)

2,674

 

5,400

 

Net periodic benefit cost (adjusted for impact of PUC D&Os)

 

$

41,582

 

$

35,324

 

$

27,154

 

$

9,006

 

$

8,946

 

$

9,004

 

 

 $ 49,115

 

 $ 44,165

 

 $ 41,582

 

$    362

 

$ 4,707

 

 $ 9,006

 

 

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefit pension plans that will be amortized from AOCI or regulatory assets into net periodic pension benefit cost during 20112013 are $(0.3)$(0.1) million, $17.4$39.3 million and de minimis,nil, respectively. The estimated prior service cost (gain), net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI or regulatory assets into net periodic other than pension benefit cost during 20112013 are $(0.9)$(1.8) million, de minimis$2.1 million and nil, respectively.

The Company recorded pension expense of $35 million, $32 million $27 million and $20$32 million and OPEB expense of $7$1 million, $7$4 million and $7 million in 2010, 20092012, 2011 and 2008,2010, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans and other benefits plans with the exception of the ASB Retirement Plan, had accumulated benefit obligationsABO exceeding plan assets as of December 31, 20102012 and December 31, 2009.

2011.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2010,2012, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.2 million and the PBOaccumulated postretirement benefit obligation (APBO) by $3$5.7 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2$0.3 million and the PBOAPBO by $3$5.8 million.

 

Defined contribution plans information.  The ASB 401(k) Plan is a defined contribution plan, which includes a discretionary employer profit sharing contribution (AmeriShare).

  On January 1, 2008, ASB began providing matching contributionsChanges to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a reduction of 100%benefits provided through the defined benefit plan and the addition of a 50% match by the applicable employer on the first 4%6% of eligible pay contributed by participants to HEI’s retirement savingsemployee deferrals through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan).

For 2012, 2011 and 2010, the Company’s expense for its eligible employees. In addition, a newdefined contribution pension plans under the HEIRSP and the ASB 401(k) Plan was created effective January 1, 2008. On May 7, 2009, the account balances of ASB participants were transferred from HEI’s retirement savings plan to account balances in the newly created ASB 401(k) Plan. $41$4 million, in assets was transferred in-kind between plans. On May 15, 2009, ASB contributed $2.1 million to fund the discretionary employer profit sharing (AmeriShare) portion of the plan for the 2008 plan year. This AmeriShare contribution was allocated pro-rata to accounts of eligible participants based on a flat 4% percent of eligible pay. This 4% contribution percentage was determined at year-end based on ASB’s performance and achievement of financial goals for 2008. On March 17, 2010, ASB contributed $1.9 million to fund AmeriShare for the 2009 plan year. This contribution equaled to 3.6% of eligible pay for eligible participants. ASB has accrued $1.9$3 million and $1.5 million in 2010 and 2009, respectively, for its anticipated Amerishare contributions in early 2011 and 2010, respectively. For 2010 and 2009, ASB’s total expense for its employees participating in the HEI retirement savings plan and the new ASB 401(k) Plan combined was $3.6 million and $3.3$4 million, respectively, and cash contributions were $3.6$4 million and $3.9 million, respectively.for each year.

 

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Table of Contents

10 · Share-based compensation

 

10 · Share-based compensation

TheUnder the 2010 Equity and Incentive Plan (EIP) was approved by shareholders in May 2010 and allows HEI tocan issue an aggregate of 4 million 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. The term “deferred shares” in the EIP was replaced by amendment to the EIP with the term “restricted stock units,” which is the term historically used by the Company to refer to a form

As of award equivalent to deferred shares. Through December 31, 2010, grants2012, there were 3.8 million shares remaining available for future issuance under the EIP consisted of 18,009 restrictedwhich an estimated 2.0 million shares and 77,500could be issued upon the vesting of outstanding restricted stock units.

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), grants and awards of an estimated 1.10.2 million shares of common stock (based on various assumptions, including long-term incentive plan (LTIP)LTIP awards earned at maximum levels and the use of the December 31, 20102012 market price of shares as the price on the exercise/payment dates) were outstanding as of December 31, 20102012 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs), restricted stock units, LTIP performance and other shares and dividend equivalents. 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 NQSOs and SARs outstanding under the SOIP, the exercise price of each NQSO or SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. NQSOs, SARs and related dividend equivalents issued in the form of stock awardedawards 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. NQSOs and SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.

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 stock awards under the SOIP generally become unrestricted four years after the date of grant and are forfeited for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations by reason of death, disability or termination without cause. Restricted shares and restricted stock awards compensation expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted shares and restricted stock awa rds are paid quarterly in cash.

Restricted stock units awarded under the EIP in 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 in cash at the end of the restriction period when the associated restricted stock units vest.

Stock performance awards granted under the 2009-20112010-2012,  2011-2013 and 2010-20122012-2014 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.

 

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Table of Contents

 

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

 

(in millions)

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Share-based compensation expense (1)

 

$

2.7

 

$

1.1

 

$

0.8

 

Share-based compensation expense 1

 

$5.9

 

$3.8

 

$2.7

 

Income tax benefit

 

0.9

 

0.3

 

0.1

 

 

2.0

 

1.3

 

0.9

 

 


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

 

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

 

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

Shares

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

Shares 

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding, January 1

 

374,500

 

$

19.73

 

375,500

 

$

19.73

 

603,800

 

$

19.68

 

 

55,500

 

$20.92

 

215,500

 

$20.76

 

374,500

 

$19.73

 

Granted

 

 

 

 

 

 

 

 

–  

 

–  

 

–  

 

–  

 

–  

 

–  

 

Exercised

 

(157,000

)

18.32

 

 

 

(220,300

)

19.62

 

 

(41,500

)

21.06

 

(160,000

)

20.70

 

(157,000

)

18.32

 

Forfeited

 

 

 

 

 

 

 

 

–  

 

–  

 

–  

 

–  

 

–  

 

–  

 

Expired

 

(2,000

)

20.49

 

(1,000

)

17.61

 

(8,000

)

19.23

 

 

–  

 

–  

 

–  

 

–  

 

(2,000

)

20.49

 

Outstanding, December 31

 

215,500

 

$

20.76

 

374,500

 

$

19.73

 

375,500

 

$

19.73

 

 

14,000

 

$20.49

 

55,500

 

$20.92

 

215,500

 

$20.76

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercisable, December 31

 

215,500

 

$

20.76

 

374,500

 

$

19.73

 

375,500

 

$

19.73

 

 

14,000

 

$20.49

 

55,500

 

$20.92

 

215,500

 

$20.76

 

 


(1)Weighted-average exercise price

 

December 31, 2010

 

Outstanding & Exercisable (Vested)

 

Year of
Grant

 

Range of
exercise prices

 

Number
of options

 

Weighted-average
remaining
contractual life

 

Weighted-average
exercise
price

 

 

 

 

 

 

 

 

 

 

 

2001

 

$

 

17.96

 

16,000

 

0.3

 

$

17.96

 

2002

 

 

21.68

 

82,000

 

1.1

 

21.68

 

2003

 

 

20.49

 

117,500

 

2.0

 

20.49

 

 

 

$

 

17.96 — 21.68

 

215,500

 

1.5

 

$

20.76

 

December 31, 2012

 

Outstanding & Exercisable (Vested)

 

Year of
Grant

 

Exercise price

 

Number
of options

 

 

Weighted-average
remaining
contractual life

 

Weighted-average
exercise
price

 

 

 

 

 

 

 

 

 

 

 

 

2003

 

20.49   

 

14,000 

 

 

0.3   

 

$20.49  

 

 

As of December 31, 2010,2012, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $1.0$0.1 million.

NQSO activity and statistics are summarizedwere as follows:

 

($ in thousands, except prices)

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

 

 

Cash received from exercise

 

$

2,876

 

 

$

4,323

 

Intrinsic value of shares exercised (1)

 

$

1,355

 

 

$

2,235

 

Tax benefit realized for the deduction of exercises

 

$

278

 

 

$

705

 

Dividend equivalent shares distributed under Section 409A

 

 

 

6,125

 

Weighted-average Section 409A distribution price

 

 

 

$

22.38

 

Intrinsic value of shares distributed under Section 409A

 

 

 

$

137

 

Tax benefit realized for Section 409A distributions

 

 

 

$

53

 

(dollars in thousands)

 

2012

 

2011 

 

2010

 

 

 

 

 

 

 

 

 

Cash received from exercise

 

$874

 

$3,312

 

$2,876

 

Intrinsic value of shares exercised 1

 

354

 

1,270

 

1,355

 

Tax benefit realized for the deduction of exercises

 

138

 

181

 

278

 

 


(1)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.

 

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Table of Contents

Stock appreciation rights.  Information about HEI’s SARs is summarized as follows:

 

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

Shares

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

Shares

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding, January 1

 

480,000

 

$

26.13

 

791,000

 

$

26.12

 

857,000

 

$

26.12

 

 

282,000

 

$26.14

 

450,000

 

$26.13

 

480,000

 

$26.13

 

Granted

 

 

 

 

 

 

 

 

–  

 

–  

 

–  

 

–  

 

–  

 

–  

 

Exercised

 

 

 

 

 

(36,000

)

26.05

 

 

(114,000

)

26.17

 

(110,000

)

26.09

 

–  

 

–  

 

Forfeited

 

 

 

(6,000

)

26.18

 

(30,000

)

26.18

 

 

–  

 

–  

 

–  

 

–  

 

–  

 

–  

 

Expired

 

(30,000

)

26.18

 

(305,000

)

26.10

 

 

 

 

(4,000

)

26.18

 

(58,000

)

26.13

 

(30,000

)

26.18

 

Outstanding, December 31

 

450,000

 

$

26.13

 

480,000

 

$

26.13

 

791,000

 

$

26.12

 

 

164,000

 

$26.12

 

282,000

 

$26.14

 

450,000

 

$26.13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercisable, December 31

 

450,000

 

$

26.13

 

480,000

 

$

26.13

 

557,000

 

$

26.10

 

 

164,000

 

$26.12

 

282,000

 

$26.14

 

450,000

 

$26.13

 

 


(1)   Weighted-average exercise price

 

December 31, 2010

 

Outstanding & Exercisable (Vested)

 

December 31, 2012

December 31, 2012

 

Outstanding & Exercisable (Vested)

 

Year of
Grant

 

Range of
exercise prices

 

Number of shares
underlying SARs

 

Weighted-average
remaining
contractual life

 

Weighted-average
exercise price

 

 

Range of
exercise prices

 

Number of shares
underlying SARs

 

Weighted-average
remaining
contractual life

 

Weighted-average
exercise price

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2004

 

$

 

26.02

 

150,000

 

2.1

 

$

26.02

 

 

$     26.02

 

62,000

 

1.3

 

$26.02

 

2005

 

 

26.18

 

300,000

 

2.8

 

26.18

 

 

26.18

 

102,000

 

2.3

 

26.18

 

 

$

 

26.02 —26.18

 

450,000

 

2.6

 

$

26.13

 

 

$26.02 –26.18

 

164,000

 

1.9

 

$26.12

 

135



 

As of December 31, 2010,2012, all SARs outstanding were exercisable and had no aggregate intrinsic value.

SARs activity and statistics are summarizedwere as follows:

 

($ in thousands, except prices)

 

2010

 

2009

 

2008

 

 

 

 

 

 

 

 

 

Shares vested

 

 

228,000

 

129,000

 

Aggregate fair value of vested shares

 

 

$

1,354

 

$

733

 

Intrinsic value of shares exercised (1)

 

 

 

$

127

 

Tax benefit realized for the deduction of exercises

 

 

 

$

49

 

Dividend equivalent shares distributed under Section 409A

 

 

3,143

 

 

Weighted-average Section 409A distribution price

 

 

$

13.64

 

 

Intrinsic value of shares distributed under Section 409A

 

 

$

43

 

 

Tax benefit realized for Section 409A distributions

 

 

$

17

 

 

(dollars in thousands, except prices)

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

Intrinsic value of shares exercised 1

 

$197

 

$64

 

– 

 

Tax benefit realized for the deduction of exercises

 

77

 

25

 

– 

 

 


(1)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.

 

Section 409A.  As a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A), in 2009 and 2008, a total of 3,143 and 6,125 dividend equivalent shares, respectively, for NQSO and SAR grants were distributed to SOIP participants. Section 409A, which amended the federal income tax rules governing deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally, dividend equivalents subject to Section 409A will be paid within 2½ months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement or a t the end of the calendar year. The dividend equivalents associated with the 2005 SAR grants had no intrinsic value at December 31, 2009; thus, no distribution was made in 2010. No further dividend equivalents are intended to be paid in accordance with this Section 409A modified distribution.

143



Table of Contents

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

 

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

 

Shares

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

Shares

 

(1)

 

Shares

 

(1)

 

Shares 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding, January 1

 

129,000

 

$

25.50

 

160,500

 

$

25.51

 

146,000

 

$

25.82

 

 

46,807

 

$24.45

 

89,709

 

$24.64

 

129,000

 

$25.50

 

Granted

 

18,009

(2)

22.21

 

 

 

45,000

(3)

24.71

 

 

 

 

 

 

18,009

(2)

22.21

 

Vested

 

(43,565

)

26.29

 

(3,851

)

24.52

 

(6,170

)

25.44

 

 

(37,802

)

24.99

 

(40,102

)

24.83

 

(43,565

)

26.29

 

Forfeited

 

(13,735

)

24.35

 

(27,649

)

25.67

 

(24,330

)

25.90

 

 

 

 

(2,800

)

24.93

 

(13,735

)

24.35

 

Outstanding, December 31

 

89,709

 

$

24.64

 

129,000

 

$

25.50

 

160,500

 

$

25.51

 

 

9,005

 

$22.21

 

46,807

 

$24.45

 

89,709

 

$24.64

 

 


(1)   Weighted-average grant dategrant-date fair value per share. The grant date fair value of a restricted stock award share wasbased on the closing or average price of HEI common stock on the date of grant.

(2)   Total weighted-average grant-date fair value of $0.4 million.

(3)Total weighted-average grant-date fair value of $1.1 million.

As of December 31, 2010, 18,009 restricted shares were outstanding under the EIP and 71,700 shares of restricted stock were outstanding under the SOIP.

 

For 2010, 20092012, 2011 and 2008,2010, total restricted stock vested had a grant-date fair value of $1.1$0.9 million, $0.1$1.0 million and $0.2$1.1 million, respectively, and the tax benefits realized for the tax deductions related to restricted stock awards were $0.2 million for 2012, $0.2 million for 2011, $0.3 million for 2010, $0.1 million for 2009 and $0.2 million for 2008.

2010.

As of December 31, 2010,2012, there was $0.6$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 2.61.9 years.

 

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

 

 

2010

 

2009

 

 

2012

 

2011

 

2010

 

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 Shares 

 

(1)

 

Shares 

(1)

 

Shares 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding, January 1

 

70,500

 

$

16.99

 

 

 

 

247,286

 

$21.80

 

146,500

 

$19.80

 

70,500

 

$16.99

 

Granted

 

77,500

(2)

22.30

 

70,500

(3)

$

16.99

 

 

98,446

(2)

25.99

 

101,786

(3)

24.68

 

77,500

(4)

22.30

 

Vested

 

(250

)

16.99

 

 

 

 

(25,728

)

24.68

 

 

 

(250

)

16.99

 

Forfeited

 

(1,250

)

16.99

 

 

 

 

(4,910

)

24.92

 

(1,000

)

22.60

 

(1,250

)

16.99

 

Outstanding, December 31

 

146,500

 

$

19.80

 

70,500

 

$

16.99

 

 

315,094

 

$22.82

 

247,286

 

$21.80

 

146,500

 

$19.80

 

 


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

(2)   Total weighted-average grant-date fair value of $1.7$2.6 million.

(3)   Total weighted-average grant-date fair value of $1.2$2.5 million.

(4)Total weighted-average grant-date fair value of $1.7 million.

For 2012 and 2010, total restricted stock units that vested and related dividends had a grant-date fair value of $0.7 million and $6,000, respectively, and the related tax benefits were $0.2 million and $2,000, respectively.

As of December 31, 2010, 77,500 restricted stock units were outstanding under the EIP and 69,000 restricted stock units were outstanding under the SOIP.

As of December 31, 2010,2012, there was $1.8$3.4 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 2.92.5 years.

 

LTIP payable in stock.  The 2009-20112011-2013 LTIP and the 2012-2014 LTIP provide for performance awards under the EIP and the 2010-2012 LTIP provideprovides for performance awards under the SOIP of shares of HEI common stock based on the satisfaction of performance goals considered to be a market condition and service conditions over a three-year performance period.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 boththe 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 2009-2011 LTIP has performance goals based on HEI return on average common equit y (ROACE) and the 2010-2012

136



LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets all based on two-year averages (2011-2012).

144



Table, and the 2011-2013 LTIP and the 2012-2014 LTIP have performance goals related to levels of ContentsHEI consolidated net income, HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets – all based on the applicable three-year averages.

 

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

 

 

2010

 

2009

 

 

2012

 

2011

 

2010

 

Awards

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 Shares

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding, January 1

 

36,198

 

$

14.85

 

 

 

 

197,385

 

$25.94

 

126,782

 

$20.33

 

36,198

 

$14.85

 

Granted

 

97,191

 

22.45

 

36,198

(2)

$

14.85

 

 

81,223

(2)

30.71

 

75,015

(3)

35.46

 

97,191

(4)

22.45

 

Vested

 

 

 

 

 

 

(35,397

)

14.85

 

 

 

 

 

Forfeited

 

(6,607

)

21.53

 

 

 

 

(3,955

)

30.82

 

(4,412

)

29.56

 

(6,607

)

21.53

 

Outstanding, December 31

 

126,782

 

$

20.33

 

36,198

 

$

14.85

 

 

239,256

 

$29.12

 

197,385

 

$25.94

 

126,782

 

$20.33

 

 


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

(2)   Total weighted-average grant-date fair value of $0.5 million.$2.5 million (at target performance levels).

On February 8, 2010, LTIP grants (under the 2010-2012 LTIP) were made payable in 97,191 shares(3)Total weighted-average grant-date fair value of HEI common stock (based on the grant date price of $18.95 and$2.7 million (at target TRS performance levels), with a.

(4)Total weighted-average grant dategrant-date fair value of $2.2 million based on the weighted-average grant date fair value per share of $22.45.(at target performance levels).

 

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:

 

 

2010

 

2009

 

 

2012

 

2011

 

2010

Risk-free interest rate

 

1.30

%

1.30

%

 

0.33%

 

1.25%

 

1.30%

Expected life in years

 

3

 

3

 

 

3

 

3

 

3

Expected volatility

 

27.9

%

23.7

%

 

25.3%

 

27.8%

 

27.9%

Dividend yield

 

6.55

%

4.53

%

Range of expected volatility for Peer Group

 

22.3% to 52.3

%

20.8% to 46.9

%

 

15.5% to 34.5%

 

21.2% to 82.6%

 

22.3% to 52.3%

Grant date fair value (per share)

 

$

22.45

 

$

14.85

 

 

$30.71

 

$35.46

 

$22.45

 

For 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.

As of December 31, 2010,2012, there was $1.5$2.5 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.7 years1 year.

 

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

 

 

2010

 

2009

 

 

2012

 

2011

 

2010

 

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 Shares

 

(1)

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Outstanding, January 1

 

24,131

 

$

16.99

 

 

 

 

182,498

 

$22.63

 

161,310

 

$18.66

 

24,131

 

$16.99

 

Granted

 

160,939

 

18.95

 

24,131

(2)

$

16.99

 

 

125,157

 

26.05

 

113,831

(2)

24.96

 

160,939

(3)

18.95

 

Vested

 

 

 

 

 

 

 

–  

 

– 

 

– 

 

 

– 

 

Cancelled

 

(50,786

)

18.95

 

(81,908

)

18.38

 

 

– 

 

Forfeited

 

(23,760

)

18.90

 

 

 

 

(9,694

)

24.44

 

(10,735

)

20.12

 

(23,760

)

18.90

 

Outstanding, December 31

 

161,310

 

$

18.66

 

24,131

 

$

16.99

 

 

247,175

 

$25.04

 

182,498

 

$22.63

 

161,310

 

$18.66

 

 


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

(2)   Total weighted-average grant-date fair value of $0.4 million.$2.8 million (at target performance levels).

(3)Total weighted-average grant-date fair value of $3.0 million (at target performance levels).

 

On February 8, 2010,137



In 2012, LTIP grants (under the 2010-20122012-2014 LTIP) were made payable in 160,939125,157 shares of HEI common stock (based on the grant date priceprices of $18.95$25.98, $26.75, $27.35, $27.22 and $26.03 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.0$3.3 million based on the weighted-average grant date fair value per share of $18.95.

$26.05.

As of December 31, 2010,2012, there was $2.3$3.0 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.91.4 years.

 

145



Table of Contents

11 · Income taxes

 

The components of income taxes attributable to net income for common stock were as follows:

 

Years ended December 31

 

2010

 

2009

 

2008

 

 

2012 

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

$

(25,446

)

$

25,691

 

$

38,041

 

 

$ (15,411

)

$ (7,638

)

$(25,446

)

Deferred

 

85,268

 

14,161

 

7,045

 

 

82,138

 

73,494

 

85,268

 

Deferred tax credits, net

 

(901

)

(593

)

(1,094

)

 

187

 

 

(901

)

 

58,921

 

39,259

 

43,992

 

 

66,914

 

65,856

 

58,921

 

State

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

(7,392

)

6,930

 

4,409

 

 

(4,654

)

2,437

 

(7,392

)

Deferred

 

13,425

 

(783

)

(815

)

 

8,710

 

5,949

 

13,425

 

Deferred tax credits, net

 

2,868

 

(1,483

)

1,392

 

 

5,889

 

1,690

 

2,868

 

 

8,901

 

4,664

 

4,986

 

 

9,945

 

10,076

 

8,901

 

Total

 

$

67,822

 

$

43,923

 

$

48,978

 

 

$ 76,859

 

$ 75,932

 

$ 67,822

 

 

A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% to the amount provided in the Company’s consolidated statements of income was as follows:

 

Years ended December 31

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount at the federal statutory income tax rate

 

$

64,136

 

$

45,088

 

$

48,740

 

 

$76,092

 

$75,618

 

$64,136

 

Increase (decrease) resulting from:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

State income taxes, net of effect on federal income taxes

 

5,786

 

3,033

 

3,241

 

State income taxes, net of federal income tax benefit

 

6,464

 

6,550

 

5,786

 

Other, net

 

(2,100

)

(4,198

)

(3,003

)

 

(5,697)

 

(6,236)

 

(2,100)

 

Total

 

$

67,822

 

$

43,923

 

$

48,978

 

 

$76,859

 

$75,932

 

$67,822

 

Effective income tax rate

 

37.0

%

34.1

%

35.2

%

 

35.4%

 

35.1%

 

37.0%

 

The 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 effective tax rate decreased from 2010 to 2011 due primarily to additional low income housing credits and tax-free income from municipal bonds and bank-owned life insurance at ASB, and a favorable Internal Revenue Service (IRS) appeals settlement related to foreign losses at HEI in 2011.

138



 

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

 

December 31

 

2010

 

2009

 

 

2012 

 

2011

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred tax assets

 

 

 

 

 

 

 

 

 

 

Cost of removal in excess of salvage value

 

$

107,913

 

$

109,210

 

Contributions in aid of construction and customer advances

 

78,958

 

77,766

 

Allowance for loan losses

 

16,461

 

16,869

 

 

$  17,254

 

$  14,076

 

Retirement benefits (AOCI)

 

9,685

 

8,269

 

Retirement benefits

 

266

 

6,175

 

Other

 

35,878

 

39,533

 

 

34,354

 

33,217

 

 

248,895

 

251,647

 

Total deferred tax assets

 

51,874

 

53,468

 

Deferred tax liabilities

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment

 

375,361

 

336,569

 

Retirement benefits

 

12,164

 

6,367

 

Property, plant and equipment related

 

316,900

 

255,488

 

Goodwill

 

20,130

 

18,233

 

 

23,781

 

22,028

 

Regulatory assets, excluding amounts attributable to property, plant and equipment

 

32,074

 

31,947

 

 

33,071

 

32,343

 

FHLB stock dividend

 

20,552

 

20,552

 

 

20,062

 

20,552

 

Change in accounting method related to repairs

 

46,702

 

 

 

69,514

 

48,566

 

Change in accounting method related to contributions in aid of construction

 

 

8,010

 

Other

 

20,870

 

18,844

 

 

27,875

 

28,542

 

 

527,853

 

440,522

 

Total deferred tax liabilities

 

491,203

 

407,519

 

Net deferred income tax liability

 

$

278,958

 

$

188,875

 

 

$439,329

 

$354,051

 

 

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 will realize substantially all of the benefits of the deferred tax assets. As of December 31, 2012, the valuation allowance for deferred tax benefits is not significant. In 2010, the significant increase in2012, the net deferred income tax liability wascontinued to increase primarily due toas a result of accelerated tax deductions taken for

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bonus depreciation (resulting from the Small Business Jobs Act and the2010 Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act) and the change in accounting method for repairs deductions for tax purposes. In 2010, $2.0 million of deferred tax assets were written off due to the expiration of the capital loss carryforward period for losses on an investment in China, which the IRS maintains is a capital loss while HEI asserts the loss is an ordinary deduction.

.

In 2010, interest income on income tax refunds was reflected in “Revenues—Electric utility” in the amount of $9.7 million, which resulted from the settlement with the IRS of appealed issues for the tax years 1996 to 2006 and was due in large part to a change in the method of allocating overhead costs to self-constructed assets. In 2012, 2011 and 2010, 2009 and 2008,credit adjustments to interest expense (and adjustments to expense) on income taxes was reflected in “Interest expense other than on deposit liabilities and other bank borrowings” in the amount of $(0.9)$1.4 million, $0.7$1.2 million and $0.2$0.9 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the IRS. As of December 31, 20102012 and 2009,2011, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and dividends payable” was $2.7$0.3 million and $3.6$1.5 million, respectively.

As of December 31, 2010,2012, the total amount of liability for uncertain tax positions was $12.2$0.8 million and, of this amount, $1.2$0.2 million, if recognized, would affect the Company’s effective tax rate. Management concluded that no significant changesThe Company’s unrecognized tax benefits are primarily the result of temporary differences relating to the liability for uncertain tax positionsdeductibility of costs incurred to repair generation property. The Company believes that it is reasonably possible that the IRS may issue guidance on the deductibility of these repair costs and this guidance will occur withineliminate much of the next 12 months.

uncertainty in 2013.

The changes in total unrecognized tax benefits were as follows:

 

Years ended December 31

 

2010

 

2009

 

(in millions)

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

 

Unrecognized tax benefits, January 1

 

$

26.5

 

$

27.9

 

 

$ 5.7

 

$ 15.4

 

$ 26.5

 

Additions based on tax positions taken during the year

 

11.0

 

 

 

0.3

 

– 

 

11.0

 

Reductions based on tax positions taken during the year

 

 

 

 

– 

 

(0.6

)

– 

 

Additions for tax positions of prior years

 

2.2

 

0.4

 

 

– 

 

0.1

 

2.2

 

Reductions for tax positions of prior years

 

(18.2

)

(1.8

)

 

(4.1

)

(8.1

)

(18.2

)

Decreases due to tax positions taken

 

 

 

Settlements

 

(6.1

)

 

 

– 

 

– 

 

(6.1

)

Lapses of statute of limitations

 

 

 

 

(1.1

)

(1.1

)

– 

 

Unrecognized tax benefits, December 31

 

$

15.4

 

$

26.5

 

 

$ 0.8

 

$ 5.7

 

$ 15.4

 

 

In addition to the liability for uncertain tax positions, the Company’sThe 2012 reduction in unrecognized tax benefits include $1.4 millionwas 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 relatedwas primarily due to refund claims,the IRS’s issuance of guidance (Revenue Procedure 2011-43,

139



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 did not meettaxpayers could transition and minimize the recognition threshold. Consequently,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 have not been recorded on these claims and no liability for uncertain2011.

The IRS is currently auditing tax positions was requiredyears 2010 to offset these potential benefits.

2011. Tax years 20052007 to 2009 currently2011 remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii. HEI Investments, Inc., which owned leveraged lease investments in other states prior to 2008, is also subject to examination by those state tax authorities for tax years 2005 to 2007.

As of December 31, 2010,2012, the disclosures above present the Company’s accrual for potential tax liabilities and related interest. Based on information currently available, the Company believes this accrual has 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 cash flows.

12 · Cash flowsliquidity.

 

12 · Cash flows

Supplemental disclosures of cash flow information.  In 2010, 2009 and 2008, the Company paid interest to non-affiliates amounting to $95 million, $106 million and $182 million, respectively.

(in millions)

 

2012

 

2011

 

2010

 

Supplemental disclosures of cash flow information

 

 

 

 

 

 

 

Interest paid to non-affiliates

 

$ 84

 

$  97

 

$  95

 

Income taxes paid/(refunded)

 

(14

)

(22

)

6

 

Supplemental disclosures of noncash activities

 

 

 

 

 

 

 

Common stock dividends reinvested in HEI common stock 1

 

24

 

12

 

23

 

Increases in common stock related to director and officer compensatory plans

 

6

 

8

 

4

 

Electric utility property, plant and equipment

 

 

 

 

 

 

 

AFUDC-equity

 

7

 

6

 

6

 

Estimated fair value of noncash contributions in aid of construction

 

10

 

7

 

7

 

Unpaid invoices and other

 

37

 

45

 

21

 

Loans transferred from held for investment to held for sale

 

 

6

 

– 

 

Real estate acquired in settlement of loans

 

11

 

12

 

7

 

 

In 2010, 2009 and 2008, the Company paid income taxes amounting to $6 million, $21 million and $91 million, respectively.

Supplemental disclosures of noncash activities.1  Under the HEI DRIP,The amounts shown represents common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $23 million, $17 million and $21 million in 2010, 2009 and 2008, respectively. HEI satisfied the requirements ofunder the HEI DRIP and thein noncash transactions.

 

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HEIRSP (from April 16, 2009 through September 3, 2009) and the ASB 401(k) Plan (from its inception on May 7, 2009 through September 3, 2009) by acquiring for cash its common shares through open market purchases rather than by issuing additional shares. During all other periods in 2009, and for all of 2008 and 2010, HEI satisfied the requirements of the HEI DRIP, HEIRSP and ASB 401(k) Plan through the issuance of additional shares of common stock.

In each of 2010, 2009 and 2008, other noncash increases in common stock issued under director and officer compensatory plans were $4 million, $2 million and $2 million, respectively.

In 2010, 2009 and 2008, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $6 million, $12 million and $9 million, respectively.

In 2010, 2009 and 2008, the estimated fair value of noncash contributions in aid of construction amounted to $7 million, $12 million and $10 million, respectively.

In 2010, 2009 and 2008, real estate acquired in settlement of loans in noncash transactions amounted to $7 million, $5 million and $1 million, respectively.

13 · Regulatory restrictions on net assets

 

As of December 31, 2010,2012, HECO and its subsidiaries could not transfer approximately $588$637 million of net assets to HEI in the form of dividends, loans or advances without PUC approval.

ASB is required to file a notice withnotify the OTSFRB and OCC prior to making any capital distribution (including dividends) to HEI. Generally, the OTSFRB and OCC may disapprove or deny ASB’s notice of intentionrequest 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 OTS.OCC. As of December 31, 2010,2012, ASB could transfer approximately $132$108 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.

 

14 · Significant group concentrations of credit risk

 

Most of the Company’s business activity is with customers located 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 securedcollateralized 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.

 

140



15 · Fair value measurements

 

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its 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 premi umpremium or discount that could result if the Company 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 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. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications

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related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, andbut have not been considered.considered in making such estimates.

 

The Company groups its 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 shall be 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 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:

Cash and cash equivalents and short-termShort-term borrowings—other than bank.  The carrying amount approximated fair value because of the short maturity of these instruments.

 

Investment and mortgage-related securities.  FairTo determine the fair value wasof 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 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.

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

141



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.

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 value is calculatedvalues were estimated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics.

characteristics and remaining maturity.

For other types of loans, fair value isvalues 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 the Company’s 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 a third-party financial services providerproviders based on the current rates offered for debt of the same or similar remaining maturities.

Forward Starting Swaps.  Fair value was estimated by discounting the expected future cash flows of the swaps, using the contractual terms of the swaps, including the period to maturity, and observable market-based inputs, including forward interest rate curves. Fair value incorporates credit valuation adjustments to appropriately reflect nonperformance risk.

 

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 arewere 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

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estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. The fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

142



 

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

 

 

2010

 

2009

 

 

 

 

Estimated fair value

 

December 31
(in thousands)

 

Carrying or
notional
amount

 

Estimated
fair value

 

Carrying or
notional
amount

 

Estimated
fair value

 

(in thousands)

 

Carrying or
notional
amount

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

Financial assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents, excluding money market accounts

 

$

329,553

 

$

329,553

 

$

501,773

 

$

501,773

 

Money market accounts

 

1,098

 

1,098

 

2,149

 

2,149

 

Money market funds

 

$

10

 

$

 

$

10

 

$

 

$

10

 

Available-for-sale investment and mortgage-related securities

 

678,152

 

678,152

 

432,881

 

432,881

 

 

671,358

 

 

671,358

 

 

671,358

 

Investment in stock of Federal Home Loan Bank of Seattle

 

97,764

 

97,764

 

97,764

 

97,764

 

 

96,022

 

 

96,022

 

 

96,022

 

Loans receivable, net

 

3,497,729

 

3,639,983

 

3,670,493

 

3,760,954

 

 

3,763,238

 

 

 

3,957,752

 

3,957,752

 

Financial liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deposit liabilities

 

3,975,372

 

3,979,027

 

4,058,760

 

4,063,888

 

 

4,229,916

 

 

4,235,527

 

 

4,235,527

 

Short-term borrowings—other than bank

 

24,923

 

24,923

 

41,989

 

41,989

 

 

83,693

 

 

83,693

 

 

83,693

 

Other bank borrowings

 

237,319

 

251,822

 

297,628

 

307,154

 

 

195,926

 

 

212,163

 

 

212,163

 

Long-term debt, net—other than bank

 

1,364,942

 

1,345,770

 

1,364,815

 

1,336,250

 

 

1,422,872

 

 

1,481,004

 

 

1,481,004

 

Forward starting swaps

 

2,762

 

2,762

 

 

 

Off-balance sheet items

 

 

 

 

 

 

 

 

 

HECO-obligated preferred securities of trust subsidiary

 

50,000

 

52,500

 

50,000

 

48,480

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

Financial assets

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

10

 

$

 

$

10

 

$

 

$

10

 

Available-for-sale investment and mortgage-related securities

 

624,331

 

 

624,331

 

 

624,331

 

Investment in stock of Federal Home Loan Bank of Seattle

 

97,764

 

 

97,764

 

 

97,764

 

Loans receivable, net

 

3,652,419

 

 

 

3,886,253

 

3,886,253

 

Financial liabilities

 

 

 

 

 

 

 

 

 

 

 

Deposit liabilities

 

4,070,032

 

 

4,075,6561

 

 

4,075,656

1

Short-term borrowings—other than bank

 

68,821

 

 

68,821

 

 

68,821

 

Other bank borrowings

 

233,229

 

 

250,486

 

 

250,486

 

Long-term debt, net—other than bank

 

1,340,070

 

 

1,400,241

 

 

1,400,241

 

1 Revised (increased by $83.9 million) to correct an error in the estimated fair value disclosure at December 31, 2011.

 

As of December 31, 20102012 and 2009,2011, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.2$1.5 billion and $1.3 billion, respectively, and their estimated fair value on such dates was $0.4were $1.2 million and $0.2$0.3 million, respectively. As of December 31, 20102012 and 2009,2011, loans serviced by ASB for others had notional amounts of $817.7 million$1.3 billion and $577.5$993.3 million and the estimated fair value of the servicing rights for such loans was $8.8$11.9 million and $5.6$9.8 million, respectively.

Bank and “other” segments

 

Fair value measurements on a recurring basis.  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 as has been the case during the recent market disruption.periods. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in p ricingpricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.

 

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Table of Contents

 

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

 

 

Fair value measurements using

 

 

Fair value measurements using

 

 

Quoted prices in

 

Significant other

 

Significant

 

��

Quoted prices in

 

Significant other

 

Significant

 

 

active markets
for identical

 

observable
inputs

 

unobservable
inputs

 

 

active markets
for identical

 

observable
inputs

 

unobservable
inputs

 

(in thousands)

 

assets (Level 1)

 

(Level 2)

 

(Level 3)

 

 

assets (Level 1)

 

(Level 2)

 

(Level 3)

 

December 31, 2010

 

 

 

 

 

 

 

Money market accounts (“other” segment)

 

$

 

$

1,098

 

$

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

Money market funds (“other” segment)

 

$ –

 

$         10

 

$ –

 

Available-for-sale securities (bank segment)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mortgage-related securities-FNMA, FHLMC and GNMA

 

$

 

$

319,970

 

$

 

 

$ –

 

$417,383

 

$ –

 

Federal agency obligations

 

 

315,896

 

 

 

 

171,491

 

 

Municipal bonds

 

 

42,286

 

 

 

 

82,484

 

 

 

$

 

$

678,152

 

$

 

 

$ –

 

$671,358

 

$ –

 

Forward starting swaps (“other” segment)

 

$

 

$

(2,762

)

$

 

December 31, 2009

 

 

 

 

 

 

 

Money market accounts (“other” segment)

 

$

 

$

2,149

 

$

 

December 31, 2011

 

 

 

 

 

 

 

Money market funds (“other” segment)

 

$ –

 

$         10

 

$ –

 

Available-for-sale securities (bank segment)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mortgage-related securities-FNMA, FHLMC and GNMA

 

$

 

$

327,521

 

$

 

 

$ –

 

$344,865

 

$ –

 

Federal agency obligations

 

 

104,044

 

 

 

 

220,727

 

 

Municipal bonds

 

 

1,316

 

 

 

 

58,739

 

 

 

$

 

$

432,881

 

$

 

 

$ –

 

$624,331

 

$ –

 

 

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 U. S. generally accepted accounting principles (GAAP).GAAP. These adjustments to fair value usually result from the write-downswritedowns 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 to loans to reflect specific reserves on loans based on the current appraised value of the collateral securing the loans or unobservable market assumption.assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in val uingvaluing 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 20102012 and 2009,2011, goodwill was not measured at fair value. As of December 31, 2009, there were no adjustments to fair value for assets measured at fair value on a nonrecurring basis in accordance with GAAP.

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 HECO’s ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 3).

Assets measured at fair value on a nonrecurring basis were as follows:

 

 

Fair value measurements using

 

 

 

 

Fair value measurements using

 

 

 

 

Quoted prices in active

 

Significant other

 

Significant

 

 

 

 

Quoted prices in active

 

Significant other

 

Significant

 

 

 

 

markets for identical

 

Observable inputs

 

Unobservable inputs

 

 

 

 

markets for identical

 

Observable inputs

 

Unobservable inputs

 

(in millions)

 

Balance

 

assets (Level 1)

 

(Level 2)

 

(Level 3)

 

 

Balance

 

assets (Level 1)

 

(Level 2)

 

(Level 3)

 

 

 

 

 

 

 

 

 

 

Loans

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

$

35

 

$

 

$

26

 

$

9

 

December 31, 2009

 

17

 

 

14

 

3

 

December 31, 2012

 

$ 21

 

$ –

 

$ –

 

$ 21

 

December 31, 2011

 

34

 

 

 

34

 

 

Specific reserves as of December 31, 2010For 2012 and 2009 were $3.5 million and $1.6 million, respectively, and were included in loans receivable held for investment, net. For 2010 and 2009,2011, there were no adjustments to fair value for ASB’s loans held for sale.

 

151Residential 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 creditThe 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 third party appraisals, which include the appraisers’ assumptions and judgment, the value placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.

144



TableReal estate acquired in settlement of Contentsloans. 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, 2012, the significant unobservable inputs used in the fair value measurement were as follows:

 

($ in thousands)

 

Fair value at December 31, 2012

 

Valuation technique

 

Significant unobservable input

 

Significant
unobservable
input value

Residential loans

 

$16,401

 

Fair value of property or collateral

 

Appraised value

 

13 - 96%

Home equity lines of credit

 

581

 

Fair value of property or collateral

 

Appraised value

 

22 - 80%

 

 

 

 

 

 

 

 

 

Commercial loan

 

14

 

Fair value of property or collateral

 

U.S. government agency guarantee

 

85%

Commercial loan

 

118

 

Fair value of property or collateral

 

Appraised value

 

73%

Commercial loan

 

225

 

Fair value of property or collateral

 

Insurance proceeds

 

60%

Commercial loans

 

1,203

 

Fair value of property or collateral

 

Fair value of business assets

 

9 - 94%

Commercial loan

 

1,961

 

Discounted cash flow

 

Present value of expected future cash flows based on anticipated debt restructuring

 

Paydown of loan – 61%

 

 

 

 

 

 

Discount rate

 

4.5%

Total commercial loans

 

3,521

 

 

 

 

 

 

Real estate acquired in settlement of loans

 

2,529

 

Fair value of property or collateral

 

Appraised value

 

58 – 99%

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

145



Retirement benefit plans

On January 1, 2008, the retirement benefit plans (Plans) adopted new standards for fair value measurements of financial assets and liabilities and for fair value measurements of nonfinancial items that are recognized or disclosed at fair value in the financial statements on a recurring basis.

 

Assets held in various trusts for the retirement benefit plans (Plans) are measured at fair value on a recurring basis (including items that are required to be measured at fair value and items for which the fair value option has been elected) and were as follows:

 

 

 

Pension benefits

 

Other benefits

 

 

 

 

 

Fair value measurements using

 

 

 

Fair value measurements using

 

 

 

December 31,

 

Quoted prices
in active
markets for

identical
assets

 

Significant
other
observable
inputs

 

Significant
unobservable

inputs

 

December 31,

 

Quoted prices
in active
markets for
identical
assets

 

Significant
other
observable
inputs

 

Significant
unobservable

inputs

 

(in millions) 

 

2010

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

2010

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Equity securities

 

$

453

 

$

453

 

$

 

$

 

$

80

 

$

80

 

$

 

$

 

Equity index funds

 

80

 

80

 

 

 

14

 

14

 

 

 

Fixed income securities

 

238

 

55

 

183

 

 

8

 

2

 

6

 

 

Pooled and mutual funds

 

78

 

9

 

69

 

 

49

 

39

 

10

 

 

Total

 

849

 

$

597

 

$

252

 

$

 

151

 

$

135

 

$

16

 

$

 

Receivables and payables, net

 

(17

)

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value of plan assets

 

$

832

 

 

 

 

 

 

 

$

151

 

 

 

 

 

 

 

 

Pension benefits

 

Other benefits

 

 

Pension benefits

 

Other benefits

 

 

 

 

Fair value measurements using

 

 

 

Fair value measurements using

 

 

 

 

Fair value measurements using

 

 

 

Fair value measurements using

 

 

December 31,

 

Quoted prices
in active
markets for
identical
assets

 

Significant
other
observable
inputs

 

Significant
unobservable

inputs

 

December 31,

 

Quoted prices
in active
markets for
identical

assets

 

Significant
other
observable
inputs

 

Significant
unobservable

inputs

 

 

 

 

Quoted prices
in active
markets for
identical
assets

 

Significant
other
observable
inputs

 

Significant
unobserv-
able
inputs

 

 

 

Quoted prices
in active
markets for
identical
assets

 

Significant
other
observable
inputs

 

Significant
unobserv-
able
inputs

 

(in millions)

 

2009

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

2009

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

 

December 31

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

December 31

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

$

405

 

$

384

 

$

 

$

21

 

$

71

 

$

67

 

$

 

$

4

 

 

$513

 

$513

 

$  –

 

$ –

 

$  83

 

$  83

 

$  –

 

$ –

 

Equity index funds

 

70

 

70

 

 

 

46

 

46

 

 

 

 

95

 

95

 

 

 

15

 

15

 

 

 

Fixed income securities

 

241

 

32

 

209

 

 

8

 

1

 

7

 

 

 

338

 

125

 

213

 

 

47

 

41

 

6

 

 

Pooled and mutual funds

 

26

 

 

 

26

 

5

 

 

 

5

 

Other

 

18

 

 

(2

)

20

 

5

 

 

 

5

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

$425

 

$425

 

$  –

 

$ –

 

$  73

 

$  73

 

$  –

 

$ –

 

Equity index funds

 

82

 

82

 

 

 

15

 

15

 

 

 

Fixed income securities

 

283

 

98

 

185

 

 

43

 

37

 

6

 

 

Pooled and mutual funds and other

 

87

 

1

 

86

 

 

13

 

 

13

 

 

Total

 

760

 

$

486

 

$

207

 

$

67

 

135

 

$

114

 

$

7

 

$

14

 

 

877

 

$606

 

$271

 

$ –

 

144

 

$125

 

$19

 

$ –

 

Receivables and payables, net

 

(21

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(37)

 

 

 

 

 

 

 

(1)

 

 

 

 

 

 

 

Fair value of plan assets

 

$

739

 

 

 

 

 

 

 

$

135

 

 

 

 

 

 

 

 

$840

 

 

 

 

 

 

 

$143

 

 

 

 

 

 

 

 

The fair values of the financial instruments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset or liability.  Those judgments are developed by the Company based on the best information available in the circumstances.

In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of ASU No. 2009-12, “Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for which the investment does not have a readily determinable fair value, using net asset value per share or its equivalent as a practical expedient.

The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 20102012 and 2009.

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Table of Contents2011.

 

Equity securities, equity index funds, and U.S. Treasury fixed income securities and public mutual funds (Level 1)ValuedEquity 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, equity securities, pooled securities and mutual funds (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. Equity securities and pooled and mutual funds include commingled equity funds and other closed funds, respectively, that are not open to public investment

146



and are valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses.analyses, using observable inputs.

 

Other (Level 3)The ventureVenture capital and limited partnership interests areinterest is valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.

For 20102012 and 2009,2011, the changes in Level 3 assets were as follows:

 

 

2010

 

2009

 

 

2012

 

2011

 

(in thousands)

 

Pension
 benefits

 

Other

benefits

 

Pension
benefits

 

Other

benefits

 

 

Pension
benefits

 

Other
benefits

 

Pension
benefits

 

Other
benefits

 

Balance, January 1

 

$

67,420

 

$

13,703

 

$

49,641

 

$

12,713

 

 

$217

 

$  7

 

$141

 

$ 5

 

Realized and unrealized gains

 

6,650

 

1,445

 

15,132

 

3,301

 

Realized and unrealized gains (losses)

 

(24)

 

(1)

 

92

 

3

 

Purchases and settlements, net

 

(317

)

(3,854

)

2,647

 

(2,311

)

 

388

 

12

 

(16)

 

(1)

 

Transfer in or out of Level 3

 

(73,612

)

(11,289

)

 

 

Balance, December 31

 

$

141

 

$

5

 

$

67,420

 

$

13,703

 

 

$581

 

$18

 

$217

 

$ 7

 

 

16 · Quarterly information (unaudited)

 

Selected quarterly information was as follows:

 

 

Quarters ended

 

Years ended

 

 

Quarters ended

 

Years ended

 

(in thousands, except per share amounts)

 

March 31

 

June 30

 

Sept. 30

 

Dec. 31

 

December 31

 

 

March 31

 

June 30

 

Sept. 30

 

Dec. 31

 

December 31

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010

 

 

 

 

 

 

 

 

 

 

 

2012

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

619,040

 

$

655,664

 

$

694,541

 

$

695,737

 

$

2,664,982

 

 

$814,860

 

$854,268

 

$867,720

 

$838,147

 

$3,374,995

 

Operating income

 

60,707

 

63,631

 

72,631

 

59,242

 

256,211

 

 

75,816

 

79,406

 

91,702

 

37,272

 

284,196

 

Net income for common stock (1)

 

27,126

 

29,262

 

32,449

 

24,698

 

113,535

 

Basic earnings per common share (2)

 

0.29

 

0.31

 

0.35

 

0.26

 

1.22

 

Diluted earnings per common share (3)

 

0.29

 

0.31

 

0.35

 

0.26

 

1.21

 

Net income for common stock 1

 

38,316

 

38,800

 

47,706

 

13,836

 

138,658

 

Basic earnings per common share 2

 

0.40

 

0.40

 

0.49

 

0.14

 

1.43

 

Diluted earnings per common share 3

 

0.40

 

0.40

 

0.49

 

0.14

 

1.42

 

Dividends per common share

 

0.31

 

0.31

 

0.31

 

0.31

 

1.24

 

 

0.31

 

0.31

 

0.31

 

0.31

 

1.24

 

Market price per common share (4)

 

 

 

 

 

 

 

 

 

 

 

Market price per common share 4

 

 

 

 

 

 

 

 

 

 

 

High

 

23.01

 

24.04

 

24.99

 

23.41

 

24.99

 

 

26.79

 

28.87

 

29.24

 

26.75

 

29.24

 

Low

 

18.63

 

21.07

 

22.04

 

21.77

 

18.63

 

 

24.86

 

24.65

 

26.26

 

23.65

 

23.65

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

 

 

 

2011

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

543,797

 

$

525,901

 

$

620,313

 

$

619,579

 

$

2,309,590

 

 

$710,633

 

$794,319

 

$886,355

 

$851,028

 

$3,242,335

 

Operating income

 

44,658

 

35,055

 

68,639

 

39,312

 

187,664

 

 

63,375

 

63,661

 

94,490

 

68,170

 

289,696

 

Net income for common stock (5)

 

20,395

 

15,479

 

33,483

 

13,654

 

83,011

 

Basic earnings per common share (2)

 

0.23

 

0.17

 

0.37

 

0.15

 

0.91

 

Diluted earnings per common share (3)

 

0.22

 

0.17

 

0.37

 

0.15

 

0.91

 

Net income for common stock 5

 

28,462

 

27,139

 

48,404

 

34,225

 

138,230

 

Basic earnings per common share 2

 

0.30

 

0.28

 

0.50

 

0.36

 

1.45

 

Diluted earnings per common share 3

 

0.30

 

0.28

 

0.50

 

0.36

 

1.44

 

Dividends per common share

 

0.31

 

0.31

 

0.31

 

0.31

 

1.24

 

 

0.31

 

0.31

 

0.31

 

0.31

 

1.24

 

Market price per common share (4)

 

 

 

 

 

 

 

 

 

 

 

Market price per common share 4

 

 

 

 

 

 

 

 

 

 

 

High

 

22.73

 

19.25

 

19.45

 

21.55

 

22.73

 

 

26.40

 

26.38

 

24.95

 

26.79

 

26.79

 

Low

 

12.09

 

13.52

 

16.50

 

16.70

 

12.09

 

 

22.79

 

23.25

 

20.59

 

22.91

 

20.59

 

 


(1)1    TheIn the fourth quarter of 2010 includes $62012, as part of a settlement agreement with the Consumer Advocate, the electric utilities recorded a writedown of $24 million of interest income (net of taxes) atof CIS project costs in lieu of conducting regulatory audits of the utilities due to a federal tax settlementCIP CT-1 and $2 million of taxes for the write-off of a deferred tax asset due to the expiration of a capital loss carryforward period.CIS projects.

(2)2    The quarterly basic earnings per common share are based upon the weighted-average number of shares of common stock outstanding in each quarter.

(3)3    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.

(4)4    Market prices of HEI common stock (symbol HE) shown are as reported on the NYSE Composite Tape for the indicated date.Tape.

(5)5    TheIn the fourth quarter of 2009 includes2011, HECO recorded an adjustment of $6 million to revenues related to the third quarter of 2011, which decreased net income for the fourth quarter of 2011 by $3 million. Also, in the fourth quarter of 2011, HECO recorded an impairment charge of $6 million (net of taxes) relating to a $19.3 million, net of tax benefits, loss on ASB’s sale of its private-issue mortgage-related securities. The first and second quarters of 2009 includes a $3.4 million and a $5.9 million, net of tax benefits, respectively, charge for other-than-temporary impairments of securities owned by ASB.transmission project.

 

153147



Table of Contents

 

HECO:

The information required by this itemItem 8 for HECO is incorporated herein by reference to pages 5 to 47 of HECO Exhibit 99.2.99.2 as noted in Item 15(a)(1).

 

ITEM 9.

CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

                                        CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

HEI and HECO:

None

ITEM 9A.

CONTROLS AND PROCEDURES

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, 2010.2012. Based on their evaluations, as of December 31, 2010,2012, 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 generally accepted accounting principles.

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

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 20102012 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 20102012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 93.85.

 

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 20102012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

154148



Table of Contents

 

HECO:

 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Richard M. Rosenblum, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of December 31, 2010.2012. Based on their evaluations, as of December 31, 2010,2012, 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 HECO in reports HECO 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 HECO management, including HECO’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. HECO’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 generally accepted accounting principles.

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

Management conducted an evaluation of the effectiveness of HECO’s internal control over financial reporting as of December 31, 20102012 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.2012.

 

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended December 31, 20102012 that have materially affected, or are reasonably likely to materially affect, HECO’s internal control over financial reporting.

 

ITEM 9B.       OTHER INFORMATION

 

On February 14, 2013, David M. Kostecki provided HEI notification of his voluntary resignation as Vice President-Finance, Controller and HECO:

Interest of named experts.  HEIChief Accounting Officer, effective on or about March 8, 2013.  Mr. Kostecki has recently received an offer to lead another business operation and HECO have agreedis resigning in order to indemnify and hold KPMG LLP (KPMG) harmless against and from any and all legal costs and expenses incurred by KPMG in successful defensepursue this opportunity.  Mr. Kostecki’s resignation was not the result of any legal action or proceeding that arises as a result of KPMG’s consentdisagreement with the Company on any matter relating to the inclusion of its audit report on HEI’s and HECO’s past financial statements included in this Form 10-K.

155



Table of ContentsCompany’s operations, policies or practices.

 

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 34 of this report.

The remaining information called forrequired by this itemItem 10 for HEI is incorporated herein by reference to the following sections in the HEI 20112013 Proxy Statement:

·                  “Nominees for Class II directors whose terms expire at the 2016 Annual Meeting”

·“Continuing Class III directors whose terms expire at the 2014 Annual Meeting”

·                  “Continuing Class I directors whose terms expire at the 2012 Annual Meeting”

·“Continuing Class II directors whose terms expire at the 2013 Annual Meeting”

·“Class I director who intends to resign at the 2011 Annual Meeting”

·“Class III directors who are not continuing after the expiration of their terms at the 20112015 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)

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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.

 

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 20112013 Proxy Statement.

 

HECO:

 

Executive officers of HECO

The executive officers of HECO are listed below. Messrs. Ignacio and Reinhardt are officers of HECO subsidiaries rather than of HECO, but are deemed to be executive officers of HECO under SEC Rule 3b-7 promulgated under the 1934 Exchange Act. HECO executive officers serve from the date of their initial appointment until the annual meeting of the HECO Board (or applicable HECO 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. HECO executive officers may also hold offices with HECO subsidiaries and other affiliates in connection with their current positions listed below.

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Name

Age

Business experience for last 5 years and prior positions
with HECO and its affiliates

Richard M. Rosenblum

60

HECO President and Chief Executive Officer since 1/09

HECO Director since 2/09

·      Prior to joining the Company: Southern California Edison Company Senior Vice President of Generation and Chief Nuclear Officer, 11/05 until his retirement in 5/08

Robert A. Alm

59

HECO Executive Vice President since 3/09

·      HECO Executive Vice President — Public Affairs, 2/08 to 3/09

·      HECO Senior Vice President — Public Affairs, 7/01 to 2/08

Stephen M. McMenamin

55

HECO Senior Vice President and Chief Information Officer since 9/09

·      Prior to being appointed to his current officer position at HECO, served as a full-time consultant to HECO in an acting chief information officer capacity from 6/09 to 9/09 and as a part-time information services consultant to HECO from 3/09 to 5/09

·      Prior to joining the Company: Borland Software Corp. Vice President, Engineering, 1/06 to 2/09

Tayne S. Y. Sekimura

48

HECO Senior Vice President and Chief Financial Officer since 9/09

·      HECO Senior Vice President, Finance and Administration, 2/08 to 9/09

·      HECO Financial Vice President, 10/04 to 2/08

·      HECO Assistant Financial Vice President, 8/04 to 10/04

·      HECO Director, Corporate & Property Accounting, 2/01 to 8/04

·      HECO Director, Internal Audit, 7/97 to 2/01

·      HECO Capital Budgets Administrator, 5/93 to 7/97

·      HECO Capital Budgets Supervisor, 10/92 to 5/93

·      HECO Auditor (internal), 5/91 to 10/92

Patricia U. Wong

54

HECO Senior Vice President, Corporate Services since 9/09

·      HEI Vice President, Administration and Corporate Secretary, 4/05 to 9/09

·      HEI Vice President, Administration, 1/05 to 4/05

·      HECO Vice President, Corporate Excellence, 3/98 to 1/05

·      HECO Manager, Environmental, 9/96 to 3/98

·      HECO Associate General Counsel, 12/94 to 9/96

·      HECO Corporate Attorney, 5/90 to 12/94

Jay M. Ignacio

51

HELCO President since 3/08

·      HELCO Manager, Distribution and Transmission, 11/96 to 3/08

·      HELCO Superintendent, Construction & Maintenance, 4/94 to 11/96

·      HELCO Electrical Engineer, 4/90 to 4/94

Edward L. Reinhardt

58

MECO President since 5/01

·      MECO Manager, Energy Delivery, 12/99 to 5/01

·      MECO Manager, Engineering, 8/90 to 12/99

·      MECO Senior Electrical Engineer, 11/89 to 8/90

·      MECO Staff Engineer, 5/88 to 11/89

·      MECO Electrical Engineer, 4/86 to 5/88

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HECO Board

The directors of HECO are listed below. HECO directors are elected annually by HEI, as sole common shareholder of HECO. Below is information regarding the business experience and certain other directorships for each HECO director, together with information about legal proceedings in which certain directors were involved and a description of the experience, qualifications, attributes and skills that led to the HECO Board’s conclusion at the time of this Form 10-K that each of the directors should serve on the HECO Board in light of HECO’s current business and structure.

Thomas B. Fargo, age 62, HECO director since 2005

Business experience and other public company directorships since 2006

·Operating Executive Board Member, J.F. Lehman & Company (private equity firm), since 2008

·Owner, Fargo Associates, LLC (defense and homeland/national security consultancy), since 2005

·Chief Executive Officer, Hawaii Superferry, Inc. (interisland ferry), 2008-2009

·President, Trex Enterprises Corporation (defense research and development firm), 2005-2008

·Commander, U.S. Pacific Command, 2002-2005

·Director since 2008 and Audit Committee Member, Northrop Grumman Corporation

·Director, Hawaiian Holdings, Inc., 2005-2008

·Director, HEI (parent company of HECO), since 2005

Skills and qualifications for HECO Board service

·Extensive knowledge of the U.S. military, a major customer of HECO and its subsidiaries.

·Leadership, strategic planning and financial and non-financial risk assessment skills developed over 39 years of leading 9 organizations ranging in size from 130 to 300,000 people and managing budgets up to $8 billion, including as Commander of the U.S. Pacific Command (covering 43 countries).

·Experience with corporate governance, including audit, compensation and governance committees, from service on several public and private company boards.

Peggy Y. Fowler, age 59, HECO director since 2009

HECO Audit Committee Member

Business experience and other public company directorships since 2006

·Co-Chief Executive Officer, Portland General Electric Company (PGE), 2009

·President and Chief Executive Officer, Portland General Electric Company, 2000-2008

·Director, Portland General Electric Company, since 1998

·Director, Umpqua Holdings Corporation, since 2009, and Chair of Budget and Compensation Committees, since 2010

Involvement in certain legal proceedings

·PGE was owned by Enron Corp. from 1997 to 2006. Enron also owned Portland General Holdings, Inc., previously a holding company for the nonregulated business of PGE that became a subsidiary of Enron, holding Enron’s nonregulated businesses in Portland. Enron Corp. filed for bankruptcy in 2001. Ms. Fowler was President of Portland General Holdings from 1999 to 2003, when it also filed for bankruptcy protection. The case was procedurally consolidated with the Enron bankruptcy, but Enron’s bankruptcy reorganization plan did not expressly pertain to Portland General Holdings. The Portland General Holdings bankruptcy case was dismissed in October 2005, after substantially all o f its assets were distributed or placed in segregated accounts.

Skills and qualifications for HECO Board service

·35 years of executive leadership, financial oversight and utility operations experience from serving at PGE in senior officer positions, including Chief Operating Officer, President and Chief Executive Officer.

·Breadth of proven management, leadership, analytical and technical skills, including crisis management, risk assessment, strategic planning and public relations skills, demonstrated especially

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by her leadership of PGE after the 2001 bankruptcy of its parent company, Enron Corp., through its independence from Enron in 2006 and by her recognition as Oregon’s Most Admired CEO in a 2005 Portland Business Journal survey and as Portland’s First Citizen in 2007 by the Portland Metropolitan Association of Realtors, an annual award honoring civic achievement and business leadership.

·Expertise in financial oversight, regulatory compliance and corporate governance matters gained from her experience as President (1997-2000), CEO (2000-2008) and Chair (2001-2004) of PGE, her service as a director for PGE and the Portland Branch of the Federal Reserve Bank of San Francisco, a director and member of the Nominating and Corporate Governance Committee for The Regence Group (BlueCross BlueShield health insurance provider in Idaho, Oregon, Utah and Washington), and a director and chair of the Budget and Compensation Committees and member of the Loan and Investment Committee for Umpqua Holdings Corporation (publicly traded bank holding company based in Portland, Oregon).

Timothy E. Johns, age 54, HECO director since 2005

HECO Audit Committee Chair

Business experience since 2006

·President and Chief Executive Officer, Bishop Museum, since 2007

·Chief Operating Officer, Estate of Samuel Mills Damon, 2000-2007

Skills and qualifications for HECO Board service

·Executive management, leadership and strategic planning skills developed over a 27-year career as a businessperson and lawyer and currently as President and Chief Executive Officer of the Bishop Museum, the largest museum in the Pacific and one of the largest natural history specimen collections in the world.

·Business, regulatory, financial stewardship and legal experience from his prior roles as Chief Operating Officer for the Estate of Samuel Mills Damon (private trust with assets valued at over $900 million in 2004) (2000-2007), Chairperson of the Hawaii State Board of Land and Natural Resources (1999-2000), Director of the Hawaii State Department of Land and Natural Resources (1999-2000) and Vice President and General Counsel at Amfac Property Development Corp. (1994-1998).

·Corporate governance knowledge and familiarity with financial oversight and fiduciary responsibilities from his prior service as a director for The Gas Company LLC (Hawaii gas energy provider) (2003-2005) and his current service as one of five trustees of the Parker Ranch Foundation Trust (charitable trust with assets valued at over $350 million, including operation of the largest ranch in Hawaii, significant real estate developments in Waimea, Hawaii and securities holdings, all to benefit certain health care, educational and charitable organizations in Waimea), as a director and Audit Committee member for Grove Farm Company, Inc. (privately-held community and real estate development firm o perating on the island of Kauai) and on the board of Kualoa Ranch, Inc. (private ranch in Hawaii offering tours and activity packages to the public).

Bert A. Kobayashi, Jr., age 40, HECO director since 2006

Business experience since 2006

·Managing Partner, BlackSand Capital, LLC (real estate investment firm), since 2010

·President and Chief Executive Officer, Kobayashi Group, LLC, 2001-2010, and Partner, since 2001

·Vice President, Nikken Holdings, LLC, since 2003

Skills and qualifications for HECO Board service

·From his work as President and Chief Executive Officer of Kobayashi Group, LLC, a Hawaii-based real estate development firm he co-founded with family members in 2001, extensive experience with planning, financing and leading large projects ranging from large office buildings to a luxury residential high-rise in downtown Honolulu, Hawaii to a country club on the island of Maui, and experience with executive management, marketing and government relations.

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·Organizational governance and financial oversight experience from his current service as a director or trustee for two mutual funds (Pacific Capital Funds of Cash Assets and Hawaiian Tax Free Trusts, both from the Aquila Group of Funds), East-West Center Foundation, Nature Conservancy of Hawaii and GIFT Foundation of Hawaii, which he co-founded.

·Recognized business and community leader in Hawaii, named as “Young Business Leader of the Year” for 2007 by Pacific Business News.

Constance H. Lau, age 58, HECO director since 2006

HECO Chairman of the Board since 2006

Current and prior positions with HECO and its affiliates

·President and Chief Executive Officer and Director, HEI (parent company of HECO), since 2006

·Chairman of the Board, HECO, since 2006

·Chairman of the Board, ASB (affiliate of HECO), since 2006

·Chairman of the Board and Chief Executive Officer, ASB, 2008-2010

·Chairman of the Board, President and Chief Executive Officer, ASB, 2006-2008

·President and Chief Executive Officer and Director, ASB, 2001-2006

·Senior Executive Vice President and Chief Operating Officer and Director, ASB, 1999-2001

·Treasurer, HEI, 1989-1999

·Financial Vice President & Treasurer, HEI Power Corp. (former affiliate of HECO), 1997-1999

·Treasurer, HECO and Assistant Treasurer, HEI, 1987-1989

·Assistant Corporate Counsel, HECO, 1984-1987

Other public company directorships since 2006

·Director since 2004 and Audit Committee Member, Alexander & Baldwin, Inc.

·Director, HEI, 2001-2004 and since 2006

Skills and qualifications for HECO Board service

·Intimate understanding of HECO and its affiliates from serving in various chief executive, chief operating and other executive, finance and legal positions at HEI and its major operating subsidiaries, HECO and ASB, over the last 26 years.

·Familiarity with current management and corporate governance practices from her current service as a director and Audit Committee member for Alexander & Baldwin, Inc. and as a director of AEGIS Insurance Services, Inc.

·Experience with financial oversight and expansive knowledge of the Hawaii business community and the local communities that compose the customer bases of HECO and its subsidiaries from serving as a director for various local industry, business development, educational and nonprofit organizations.

·Utility and banking industry knowledge from serving as a director or task force member of the Hawaii Bankers Association, the American Bankers Association, and the Edison Electric Institute.

A. Maurice Myers, age 70, HECO director 2004-2006 and since 2009

Business experience and other public company directorships since 2006

·Chief Executive Officer and Owner, Myers Equipment Leasing, LLC, since 2010

·Chief Executive Officer and Director, POS Hawaii LLC (provider of point-of-sale business systems for restaurants and retailers), since 2009

·Chief Executive Officer and Director, Wine Country Kitchens LLC (manufacturer of gourmet food products), since 2007

·Chairman, Chief Executive Officer and President, Waste Management, Inc. (waste and environmental services provider), 1999-2004

·Director, HEI (parent company of HECO), since 1991

Skills and qualifications for HECO Board service

·20 years of public company executive and board leadership experience as Chairman, Chief Executive Officer and President of Waste Management, Inc., Chairman, Chief Executive Officer and President of

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Yellow Corporation, President of America West Airlines and Chief Executive Officer and President of Aloha Airgroup, Inc.

·Practiced skills in risk assessment, strategic planning, financial oversight, customer and public relations and marketing exercised in leading successful restructuring efforts at Waste Management, Yellow Corporation and America West Airlines.

·      Diverse business experience and public and private company board experience, including from his prior experience as a director and Compensation Committee Chair for Tesoro Corporation and as a director for BIS Industries Limited and Cheap Tickets.

David M. Nakada, age 59, HECO director since 2005

Business experience since 2006

·Executive Director, Boys & Girls Club of Hawaii, since 1979

Skills and qualifications for HECO Board service

·31 years of executive leadership, strategic planning and financial management experience heading the Boys & Girls Club of Hawaii, a nonprofit dedicated to promoting character and leadership development and other positive behaviors in Hawaii’s youth, and growing it from a $500,000 budget, single-facility operation in 1979 to a $5 million budget operation with clubhouses in 12 locations providing services to 14,000 children in Hawaii.

·In-depth knowledge of the Hawaii community at all levels through his extensive outreach and education efforts throughout the state, providing helpful insight about the customer bases of HECO and its subsidiaries and the state and local regulatory and socioeconomic climate and trends.

·Ability to share proven methods for building trust with customers and other stakeholders.

Alan M. Oshima, age 63, HECO director since 2008

Business experience and other public company directorships since 2006

·Owner and Principal, AMO Consulting LLC, since 2008

·Director, Hawaiian Telcom Communications, Inc., 2008-2010

·Senior Vice President, General Counsel and Secretary, Hawaiian Telcom Communications, Inc., 2005-2008

·Advisor, The Carlyle Group, 2005 (relating to its purchase of Verizon Hawaii, Inc., which is now Hawaiian Telcom Communications, Inc.)

·Founding Partner, Oshima, Chun, Fong and Chung LLP, 1985-2005

Involvement in certain legal proceedings

·Mr. Oshima was Senior Vice President, General Counsel and Secretary of Hawaiian Telcom Communications, Inc. until June 2008, when he transitioned to become Senior Advisor and a Director of Hawaiian Telcom. In December 2008, Hawaiian Telcom and related entities filed a proceeding under Chapter 11 of the federal bankruptcy laws. The proceeding was originally filed in Delaware, then was transferred to the federal bankruptcy court in Hawaii. A Plan of Reorganization was approved by the bankruptcy court in December 2009 and by the Hawaii Public Utilities Commission in September 2010 and was completed in October 2010.  Mr. Oshima was one of two members of the Hawaiian Telcom board of directors appointed to serve on a special independent board committee that oversaw the completion of the Plan of Reorganization.

Skills and qualifications for HECO Board service

·Regulatory and corporate governance expertise from his prior position as Senior Vice President, General Counsel and Secretary at Hawaiian Telcom, in which he served as head of regulatory affairs, including overseeing all legal and regulatory matters before the Hawaii Public Utilities Commission, which also regulates HECO and its subsidiaries.

·Prior to joining Hawaiian Telcom, he practiced law for 29 years in the law firms of Carlsmith, Carlsmith, Wicham and Case (now Carlsmith Ball) and the law firm Oshima, Chun, Fong and Chung LLP (now Morihara, Lau & Fong LLP), which specializes in public utility regulation, environmental and natural

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resource issues, land use procedures, water rights, and real estate acquisition, development and disposition of assets, and was named one of America’s Best Lawyers in public utility law from 1995 to 2005.

Richard M. Rosenblum, age 60, HECO director since 2009

Current and prior positions with HECO

·President and Chief Executive Officer, HECO, since 2009

Other business experience since 2006

·Senior Vice President of Generation and Chief Nuclear Officer, Southern California Edison Company, 2005-2008

Skills and qualifications for HECO Board service

·33 years of experience in all phases of electric utility operations, including 32 years at Southern California Edison Company, one of California’s largest electric utilities, and experience leading renewable energy efforts, including initiating one of the nation’s largest solar photovoltaic projects with a goal of installing 250 megawatts of solar generating capacity over five years on commercial rooftops throughout Southern California.

·Operational leadership, strategic planning, customer relations and financial oversight skills from his career at Southern California Edison Company, including as Senior Vice President of Generation and Chief Nuclear Officer (2005-2008), Senior Vice President of Transmission and Distribution (1998-2005), Vice President of Customer Service and Distribution (1996-1998) and Vice President of Engineering and Technical Services (1993-1995).

Kelvin H. Taketa, age 56, HECO director since 2004

Business experience and other public company directorships since 2006

·President and Chief Executive Officer, Hawaii Community Foundation, since 1998

·Director, HEI (parent company of HECO), since 1993

Skills and qualifications for HECO Board service

·Executive management experience with responsibility for overseeing more than $405 million in charitable assets as President and Chief Executive Officer of the Hawaii Community Foundation.

·Proficiency in risk assessment, strategic planning and organizational leadership as well as marketing and public relations obtained from his current position at the Hawaii Community Foundation and his prior experience as Vice President and Executive Director of the Asia/Pacific Region for The Nature Conservancy and as Founder, Managing Partner and Director of Sunrise Capital Inc.

·Knowledge of corporate and nonprofit governance issues gained from his prior service as a director for Grove Farm Company, Inc., his current service as Vice Chair of the Independent Sector and Director of the Stupski Foundation and through publishing articles and lecturing on governance of tax-exempt organizations.

Barry K. Taniguchi, age 63, HECO director since 2001

HECO Audit Committee Member

Business experience and other public company directorships since 2006

·President and Chief Executive Officer, KTA Super Stores (grocery store chain), since 1989

·President, K. Taniguchi Ltd. (real estate lessor), since 1989

·Director since 2002 and Audit Committee Chair, ASB (affiliate of HECO)

·Director, HEI (parent company of HECO), since 2004

·Director, Hawaii Electric Light Company, Inc. (HECO subsidiary), 1997-2009

·Director, Maui Electric Company, Limited (HECO subsidiary), 2006-2009

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Skills and qualifications for HECO Board service

·Current knowledge of and experience with the business community on the island of Hawaii, which is served by HECO’s subsidiary, HELCO, from serving in his current chief executive officer positions for the last 21 years.

·Specific understanding of the business of HECO subsidiaries HELCO and MECO, for which he served as a director from 1997 to 2009 and 2006 to 2009, respectively.

·Accounting and auditing knowledge and experience gained from obtaining a public accounting certification and working as an auditor and a controller.

·Extensive corporate and nonprofit board and leadership experience, including from his current service on the boards of Chamber of Commerce of Hawaii, Hawaii Community Foundation and as Chair of the Hawaii Island Economic Development Board.

Jeffrey N. Watanabe, age 68, HECO director 1999-2006and since 2008

Business experience and other public company directorships since 2006

·Managing Partner, Watanabe Ing & Komeiji LLP, 1972-2007 (now retired)

·Director since 2003 and Compensation and Corporate Governance Committee Member, Alexander & Baldwin, Inc.

·Director since 1988 and Audit and Executive Committee Member, ASB (HECO affiliate)

·Director since 1987 and Chairman of the Board since 2006, HEI (parent company of HECO)

Skills and qualifications for HECO Board service

·Broad business, legal, corporate governance and leadership experience from serving as Managing Partner of the law firm he founded, advising clients on a variety of business and legal matters for 35 years and serving on a dozen public and private company and nonprofit boards and committees, including his current service on the Compensation and Corporate Governance Committees for Alexander & Baldwin, Inc.

·Specific experience with strategic planning from providing strategic counsel to local business clients and prospective investors from the continental United States and the Asia Pacific region for 25 years of his law practice.

Audit Committee of the HECO Board

HECO has a guarantee with respect to 6.50% cumulative quarterly income preferred securities series 2004 (QUIPS) listed on the New York Stock Exchange (NYSE). Because HEI has common stock listed on the NYSE and HECO is a wholly-owned subsidiary of HEI, HEI is subject to the corporate governance listing standards in Section 303A of the NYSE Listed Company Manual and, by reason of an exemption resulting from HEI’s listing, HECO is not. Accordingly, HECO is exempt from NYSE listing standards 303A.04, 303A.05 and 303A.06, which require listed companies to have nominating/corporate governance, compensation and audit committees.

Although not required by NYSE rules to do so, HECO has established one standing committee, the HECO Audit Committee, and voluntarily endeavors to comply with NYSE and SEC requirements regarding audit committee composition. The current members of the HECO Audit Committee are nonemployee directors Timothy E. Johns (chairperson), Peggy Y. Fowler and Barry K. Taniguchi. All committee members are independent and qualified to serve on the committee pursuant to NYSE and SEC requirements. Mr. Taniguchi is also Chair of the HEI Audit Committee. Each of Timothy E. Johns, Peggy Y. Fowler and Barry K. Taniguchi has been determined by the HECO Board to be an “audit committee financial expert” on the HECO Audit Committee.

The HECO Audit Committee operates and acts under a written charter approved by the HECO Board and available on HEI’s website at www.hei.com. The HECO Audit Committee is responsible for overseeing (1) HECO’s financial reporting processes and internal controls, (2) the performance of HECO’s internal auditor, (3) risk assessment and risk management policies set by management and (4) the Corporate Code of Conduct compliance program for HECO and its subsidiaries. In addition, the committee provides input to the HEI Audit Committee regarding the appointment, compensation and oversight of the independent registered public

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accounting firm that audits HEI’s consolidated financial statements and maintains procedures for receiving and reviewing confidential reports to the HECO Audit Committee of potential accounting and auditing concerns.

In 2010, the HECO Audit Committee held five meetings. At each meeting, the committee held executive sessions without management present with the independent registered public accounting firm that audits HEI’s consolidated financial statements and the internal auditor.

Attendance at HECO Board and Committee meetings

In 2010, there were eight regular meetings of the HECO Board. All HECO directors attended at least 75% of the combined total number of meetings of the HECO Board and HECO Board committee on which they served.

Family relationships; executive officer and director arrangements

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

Code of Conduct

The HEI Board has adopted a Corporate Code of Conduct that applies to all of HEI’s subsidiaries, including HECO, and which includes a code of ethics applicable to, among others, HECO’s 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. HECO elects to disclose the information required by Form 8-K,this Item 5.05, “Amendments10 for HECO is incorporated herein by reference to the Registrant’s Codepages 1 to 8 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

Section 16(a) of the 1934 Exchange Act requires HECO’s executive officers, controller, directors and persons who own more than ten percent of a registered class of HECO’s equity securities to file reports of ownership and changes in ownership with the SEC. Such reporting persons are also required by SEC regulations to furnish HECO with copies of all Section 16(a) forms they file. Based solely on its review of such forms provided to it during 2010, or written representations from some of those persons that no Forms 5 were required from such persons, HECO believes that each of the persons required to comply with Section 16(a) of the 1934 Exchange Act with respect to HECO, including its executive officers, controller, directors and persons who own more than ten percent of a registered class of HECO’s equity securities, complied with the repo rting requirements of Section 16(a) of the 1934 Exchange Act for 2010.

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Table of ContentsExhibit 99.3.

 

ITEM 11.        EXECUTIVE COMPENSATION

HEI:

 

The information required underby this itemItem 11 for HEI is incorporated herein by reference to the information relating to executive and director compensation in the HEI 20112013 Proxy Statement.

 

HECO:

 

As Richard M. Rosenblum was deemed an executive officerThe information required by this Item 11 for HECO is incorporated herein by reference to:

·Pages 8 to 34 of HEIHECO Exhibit 99.3;

·The discussion of “What is HECO’s 2011-2013 long-term incentive plan?” at pages 166-167 of HECO’s Annual Report on Form 10-K for the year ended December 31, 2011; and certain

·Information concerning compensation paid to directors of HECO who are also directors of HEI information required under this item for HECO, in addition to that set forth below, is incorporated herein by reference to the information insection of the HEI 20112013 Proxy Statement relating to the compensation of Mr. Rosenblum and directors of HECO who also serve on the HEI Board.entitled, “Director Compensation.”

 

Compensation Committee Interlocks and Insider Participation

 

HEI:

 

The information required to be reported under this caption is incorporated herein by reference to the “Other Relationships and Related Person Transactions—Compensation Committee Interlocks and Insider Participation” section in the HEI 20112013 Proxy Statement.

 

HECO:

 

The HECO Board does not have a separate compensation committee. Rather, the entire HECO Board serves as HECO’s compensation committee and oversees HECO executive compensation matters. As part of its responsibility to oversee compensation programs at HEI and its subsidiaries, the HEI Compensation Committee assists the HECO Boardinformation required by reviewing and making recommendations regarding HECO executive compensation matters. HECO directors Thomas B. Fargo and A. Maurice Myers, who are also directors of HEI, also serve on the HEI Compensation Committee. Admiral Fargo is the chairperson of the HEI Compensation Committee. HECO director Alan M. Oshima attends meetings of the HEI Compensation Committee as a non-voting representative of the HECO Board.

During the last fiscal year, the following HECO officers, who are also directors of HECO, participated in deliberations of the HECO Board regarding HECO executive compensation matters:

·HECO Chairman of the Board Constance H. Lau, who is also HEI President & Chief Executive Officer and an HEI director and is not compensated by HECO, participated in deliberations of the HEI Compensation Committee in recommending, and of the HECO Board in determining, compensation for HECO’s President & Chief Executive Officer and other HECO named executive officers.

·HECO President and Chief Executive Officer Richard M. Rosenblum, who is also a HECO director, was responsible for evaluating the performance of the other HECO named executive officers and other HECO Vice Presidents based on performance goals and subjective measures, which evaluations were used by the HEI Compensation Committee in recommending, and by the HECO Board in determining, compensation for those officers. Mr. Rosenblum did not participate in the deliberations of the HEI Compensation Committee to recommend or of the HECO Board to determine his own compensation but did participate in deliberations of the HECO Board to determine the compensation of the other HECO named executive officer s.

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HECO Board and HEI Compensation Committee Report

The HECO Board and the HEI Compensation Committee have reviewed and discussed with management the Compensation Discussion and Analysis that follows. Based on such review and discussion, the HEI Compensation Committee recommended, and the HECO Board approved, including the Compensation Discussion and Analysis in this Annual Report on Form 10-K.

SUBMITTED BY THE HECO BOARD OF DIRECTORS

Constance H. Lau, Chairman

Thomas B. Fargo

Peggy Y. Fowler

Timothy E. Johns

Bert A. Kobayashi, Jr.

A. Maurice Myers

David M. Nakada

Alan M. Oshima

Richard M. Rosenblum

Kelvin H. Taketa

Barry K. Taniguchi

Jeffrey N. Watanabe

AND SUBMITTED BY THE COMPENSATION COMMITTEE OF

THE HEI BOARD OF DIRECTORS

Thomas B. Fargo, Chairperson

Don E. Carroll

Victor H. Li

A. Maurice Myers

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Compensation Discussion and Analysis

Who were the named executive officersItem 11 for HECO in 2010?

For 2010, the HECO named executive officers were:

1.Richard M. Rosenblum, HECO President and Chief Executive Officer.

2.Tayne S. Y. Sekimura, HECO Senior Vice President and Chief Financial Officer.

3.Robert A. Alm, HECO Executive Vice President.

4.Stephen M. McMenamin, HECO Senior Vice President and Chief Information Officer.

5.Patricia U. Wong, HECO Senior Vice President, Corporate Services.

Summary of Results

In 2010, HECO and its subsidiaries continued to pursue initiatives to improve fundamental operating and financial performance in order to improve profitability and capital efficiency, grow earnings, reduce risk and be positioned to benefit as economic conditions improve.

The utilities focused on their critical role in achieving the state’s clean energy goals, among the most aggressive in the nation. The utilities invested in reliability and clean energy initiatives and sought to recover their costs and earn a return on their investments in a more timely manner. The utilities made progress on their clean energy efforts on numerous fronts in 2010, including the implementation of feed-in-tariffs (a set of standardized purchased power rates which the utilities will pay for renewable energy) and electric vehicle pilot charging rates, the completion of purchase power agreements with renewable developers and implementation of their biofuel strategies.

The utilities received a number of rate case decisions in 2010. In February, HECO received interim rate relief for its biofueled peaking unit and in August, MECO received interim rate relief in its 2010 test year rate case. In November, HELCO received an interim decision in its 2010 test year rate case. The utilities also received a number of final rate case decisions in 2010, including a final rate decision in December for HECO’s 2009 test year rate case. A new regulatory model, generally referred to as “decoupling,” was approved by the PUC in August 2010 with implementation approved for HECO in December 2010 in connection with its 2009 test year rate case. This “decoupling” business model of delinking revenues from kilowatthour sales in setting electric rates is designed to support Hawaii’s efforts to reduce its dependency on oil by aligning the u tility with the state’s public policy to promote energy efficiency and conservation. This new method of ratemaking will allow the utility to recover its investments and costs in a much more timely manner, and will strengthen the utility’s financial viability so that it may attract the capital needed to support reliability and clean energy investments.

Despite the lagging economic recovery, in 2010 HECO was able to preserve earnings and, at the same time, continue to move forward on key strategic initiatives, positioning it for improved performance and shareholder value creation in the near future while helping to achieve important clean energy goals for the state of Hawaii.

Executive Summary

The following are the major revisions to the executive compensation programs impacting the HECO named executive officers in 2010:

·Total direct compensation (comprising base salary, annual incentives and long-term incentives) for the named executive officers was re-evaluated and correlated to the competitive market median of the designated peer group of companies.

·The 2010-2012 long-term incentive plan awards were denominated 100% in HEI stock (rather than a portion in stock and a portion in cash as done in prior long-term incentive plans), less an amount withheld for taxes, with the number of share units determined at the beginning of the performance period to reward participants for increases in share value and to better align executive incentives with shareholder interests.

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·A new nonqualified deferred compensation plan for HEI and HECO executives was adopted to allow executives to defer certain portions of base salary and incentive compensation and to select a range of investment vehicles (similar to that offered under the utilities’ 401(k) plan). This new plan will be implemented in 2011.

·The HEI stock ownership guidelines were revised in December 2010 to increase the ownership requirements of Mr. Rosenblum (and certain other HEI named executive officers) from one and one-half times to two times his base salary in shares of HEI Common Stock by January 1, 2016.

HECO has eliminated nearly all tax gross-ups for named executive officers. There are no tax gross-ups in the change-in-control agreements given to Mr. Rosenblum and Ms. Wong, the only HECO named executive officers who have change-in-control agreements, and aggregate payments under these agreements are limited to the maximum amount deductible under Section 280G of the Internal Revenue Code.There are no tax gross-ups allowed on club membership initiation or membership fees. Tax gross-ups of death benefits have been restricted to the executives who participated in the applicable plan prior to September 9, 2009 (the date the death benefit plan was frozen).

The primary refinement to HECO’s compensation programs has been to make HECO’s executive compensation more performance-based. The executive compensation program applicable to the HECO named executive officers consists of short-term and long-term components. The short-term components comprise base salary and an annual incentive bonus plan, the latter being performance-based. The long-term incentive compensation is made up of a long-term incentive plan (which is performance-based) and a restricted stock unit grant (which is time vested over four years). The HEI Compensation Committee and HECO Board believe that the current executive compensation program reflects “best practices” and is structured to encourage participants to build long-term value in HECO a nd HEI for the benefit of shareholders and other stakeholders.

Compensation Process

Does the HECO Board have a designated compensation committee?

The HECO Board does not have a separate compensation committee.  Rather, the entire HECO Board serves as HECO’s compensation committee and oversees HECO executive compensation matters.  As part of its responsibility to oversee compensation programs at HEI and its subsidiaries, the HEI Compensation Committee assists the HECO Board by reviewing and making recommendations regarding HECO executive compensation matters.  HECO directors Thomas B. Fargo and A. Maurice Myers, who are also directors of HEI, also serve on the HEI Compensation Committee. Admiral Fargo is the chairperson of the HEI Compensation Committee. HECO director Alan M. Oshima attends meetings of the HEI Compensation Committee as a non-voting representative of the HECO Board.

·HECO Chairman of the Board Constance H. Lau, who is also HEI President & Chief Executive Officer and an HEI director and is not compensated by HECO, participated in deliberations of the HEI Compensation Committee in recommending, and of the HECO Board in determining, compensation for HECO’s President & Chief Executive Officer and other HECO named executive officers.

·HECO President and Chief Executive Officer Richard M. Rosenblum, who is also a HECO director, was responsible for evaluating the performance of the other HECO named executive officers and other HECO Vice Presidents based on performance goals and subjective measures, which evaluations were used by the HEI Compensation Committee in recommending, and by the HECO Board in determining, compensation for those officers. Mr. Rosenblum did not participate in the deliberations of the HEI Compensation Committee to recommend or of the HECO Board to determine his own compensation but did participate in deliberations of the HECO Board to determine the compensation of the other HECO named executive officer s.

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Can the HECO Board and the HEI Compensation Committee modify or terminate executive compensation programs?

The HECO Board and the HEI Compensation Committee reserve the right to amend, suspend or terminate any incentive program or other executive compensation program, or any individual executive’s participation in such programs. The HECO Board and the HEI Compensation Committee can exercise discretion to reduce or increase (except to the extent an award or payout is intended to satisfy the requirements for deductibility under Section 162(m) of the Internal Revenue Code) the size of any award or payout to HECO or subsidiary executives. In 2010, no portion of any bonus or long-term incentive compensation paid to any HECO executive was nondeductible under Section 162(m).

In making compensation determinations, the HECO Board and the HEI Compensation Committee will consider financial, accounting and tax consequences, if appropriate. For instance, the HECO Board and the HEI Compensation Committee may determine that there should not be any incentive payout that would otherwise result solely from a new way of accounting for a financial measure. As another example, the HECO Board and the HEI Compensation Committee will take into account tax deductibility in establishing executive compensation, but reserve the right to award compensation even when not deductible if it is reasonable and appropriate.

How do HECO’s compensation policies and practices relate to HECO’s risk management?

HECO has an Enterprise Risk Management function that is principally responsible for identifying and monitoring risk across HECO and its subsidiaries, and for reporting high risk areas to the HECO Board and the HECO Audit Committee. HECO’s Enterprise Risk Management function is part of HEI’s overall Enterprise Risk Management function that is principally responsible for identifying and monitoring risk across all HEI companies and for reporting high risk areas to the HEI Board and designated board committees.  As a result, all HEI and HECO directors, including those that comprise the HEI Compensation Committee, are apprised of the risks which could have a material adverse effect on HECO. The HECO Board and HEI Compensation Committee have assessed and considered these risks when establishing HECO’s compensation policies and practices and the executive compensation program desc ribed in this Compensation Discussion and Analysis.The HECO Board and the HEI Compensation Committee have concluded that the executive compensation program does not encourage unnecessary or excessive risk-taking.

HECO’s compensation policies and practices are designed to encourage executive management to maximize value for shareholders, while considering its key stakeholders, including customers, employees and regulators, and to discourage decisions that introduce risks that may have a material adverse effect on the Company. The executive compensation program is structured to pay for performance and align the executive officers’ interests with shareholder interests, as well as encourage executives to focus on profitability, efficient use of capital, earnings growth and stock price appreciation in both the short and long terms. Because the executive officers are in a position to directly influence HECO’s performance, compensation for executive officers involves a significant portion of pay that is “at risk” and tied directly to HECO and HEI performance — namely, the annual incentive bonus plan and long-term equity-based incentives.

In structuring the incentive compensation plans and setting the particular goals, targets and metrics for awards under those plans, the HEI Compensation Committee and HECO Board incorporate the following elements and practices to ensure consistent leadership and appropriate and prudent decision-making among the named executive officers in a manner that requires cooperation and execution without taking unnecessary or excessive risks:

·Financial performance objectives of the annual cash incentive program linked to approved budget guidelines and nonfinancial measures aligned with the interests of all of HECO’s stakeholders.

·Alignment of financial and nonfinancial performance in the annual cash incentive programs for HECO named executive officers, other officers and nonexecutive employees.

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·“Clawback” capability through an executive compensation recovery policy to recoup incentive awards paid to executives who are found to be personally responsible for fraud, gross negligence or intentional misconduct that causes a restatement of HECO’s financial statements. (This policy is expected to be modified in 2011 upon the completion of SEC rule-making proceedings relating to when and under what circumstances clawbacks are required.)

·Greater financial opportunities in long-term incentive programs best realized through long-term total shareholder return, earnings growth, profitability and efficient use of capital, which mitigates excessive short-term risk-taking.

·Share ownership guidelines requiring Mr. Rosenblum to hold certain amounts of HEI Common Stock, ensuring that HECO’s chief executive has a significant amount of personal stake tied to the long-term performance of HECO and HEI.

·Pro-rata payouts under the performance-based plans (only when performance is above minimum thresholds), rather than an “all-or-nothing” approach.

·Use of annual grants of long-term equity-based incentives vesting over a period of years to encourage executives to focus on sustaining HECO’s and HEI’s long-term performance.

·Use of a variety of performance metrics, both financial and nonfinancial (e.g., net income, return on average common equity, total shareholder return, safety and customer satisfaction, among others), that correlate to long-term creation of shareholder value and are impacted by management decisions.

·A variable and nonformulaic goal-setting process, where prior performance, market conditions, peer group measures and industry performance are considered relative to future expected performance to assess the reasonableness of the goals.

·Exercise of discretion by the HECO Board and the HEI Compensation Committee in establishing performance goals and metrics, in determining whether these goals have been achieved and in administering all performance-based and equity awards, including the form of the award such as cash or stock.

·Continuous monitoring by the HECO Board and the HEI Compensation Committee through assessment of HECO’s progress toward its goals in juxtaposition to risks faced by the enterprise, through management presentations at quarterly meetings and through periodic written reports.

Compensation Program

What is HECO’s philosophy with respect to its executive compensation programs?

HECO’s compensation philosophy is reflected in the following key design priorities that have been developed with recommendations by the HEI Compensation Committee and govern HECO’s executive compensation decisions:

·Design and structure the compensation elements to incent individual and group performance toward achieving the strategic goals of the Company.

·Balance the cash and equity components to align executive compensation with shareholders’ interests.

·Levelize total compensation at the competitive market median of the relevant peer group of companies in order to promote executive recruitment, retention and motivation.

·Pay for performance.

·Establish metrics using a balanced scorecard that focuses executives on long-term value creation and includes consideration of risk management issues and Company performance against its peers.

·Promote key Company values, including integrity, teamwork and egalitarianism, and avoid pressure to take undue risks.

·Manage costs.

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The compensation programs are designed to support HECO’s business goals and promote both short- and long-term profitable growth of the Company. HECO’s participation in HEI equity plans is used in HECO’s executive compensation programs to align executive compensation with the long-term interests of HEI’s shareholders. Total compensation for each executive varies with HEI’s and HECO’s performance in achieving financial and nonfinancial objectives.

What are the objectives of HECO’s executive compensation programs and what are they designed to reward?

The following are the primary objectives of HECO’s executive compensation programs:

·Encourage and reward performance relative to business plans and strategies that maximize the value HECO delivers to HEI’s shareholders and other key stakeholders, such as customers, employees and regulators.

·Provide compensation and benefits that are designed to incent a high level of business performance and be competitive with peer companies and relevant functional positions to attract, retain and motivate talented executives.

·Emphasize performance-based rewards driven by results within the scope of the executive’s responsibility or the responsibilities of the executive team as a group.

·Provide reward strategies to align with HECO’s specific business needs and talent markets.

·Maintain a culture of integrity, where there is no undue pressure to meet or exceed targets for personal gain or to encourage employees to take undue or inappropriate risks.

What is each element of executive compensation?

HECO’s executive compensation elements comprise —

·Base Salary — provides base level of compensation for the year.

·Annual Incentive — supports a single-year focus with variable pay for performance; vehicle is stable over time, but the metrics may vary; only program for rewarding in-year performance.

·Long-Term Incentives — two components comprising long-term performance-based awards (awarded at end of three-year performance period) and long-term time-vested awards (which vest over four years); these long-term incentives encourage a multi-year focus, rewarding sustained business and stock performance; metrics are stable over time, but vehicles may vary; award size is limited to rewarding demonstrated performance and addressing retention risk.

·Retirement, Pension and Savings — retirement benefits provided to all eligible employees through tax-qualified HEI Retirement Plan provide financial security in recognition of years of service; additional benefits that cannot be paid from HEI Retirement Plan due to Internal Revenue Code limits are provided through the HEI Excess Pay Plan.

Why does HECO choose to pay each element?

·HECO chooses to pay its executives a base salary in order to pay value for value received.  Base salary is targeted to peer group median with individual differences (above and below median) to recognize the individual’s position, responsibilities, experience, performance and contributions.

·HECO provides its executives the opportunity to earn annual cash incentives based on the achievement of goals (i) to build fundamental earnings in a controlled risk manner to support the continued payment of the HEI dividend, (ii) to focus on nonfinancial measures important to HECO’s stakeholders and (iii) to motivate executives and encourage their commitment to HECO’s success. Shareholders and other stakeholders benefit from the achievement of these goals.

·HECO provides long-term incentives to support initiatives aimed at building long-term growth in shareholder value, to increase HECO’s financial and strategic flexibility and to develop HECO’s and HEI’s fundamental value. HECO’s long-term incentive plan rewards executives based on HECO and HEI’s successful financial performance over rolling three-year performance periods. The three-year performance period provides balance with the shorter-term focus of the annual incentive compensation plan. In 2010, HECO paid its executives in a mix of earned long-term incentives paid

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partially in cash, HEI stock and service-based restricted stock units in order to encourage stock ownership and alignment of the interests of executives and shareholders. The 2010-2012 long-term incentive plan awards to all HECO executives will be paid entirely in HEI stock, less an amount withheld for taxes, determined in share units set at the beginning of the performance period, to encourage even greater alignment of executive incentives with shareholder interests. The long-term incentive plan, as constructed, also has a favorable retention impact on the executives.

·HECO provides its executives health and welfare benefits and retirement benefits to encourage good health and retention of its executives, as well as to enable HECO to be competitive with its peers.

How does HECO determine the amount for each element?

HECO uses competitive market peer company comparisons to determine the amount of each element of executive compensation.  Peer companies are companies which, in the aggregate, are similar in business focus, financial scope and valuation, provide similar products and services and are sources for talented employees. Peer companies are selected by the HEI Compensation Committee’s independent compensation consultant and are reviewed and approved by the HEI Compensation Committee and HECO Board. The resulting peer companies are used as a reference in determining appropriate pay levels and mix of pay components.

In early 2010, Frederic W. Cook & Co., Inc. (Fred Cook & Co.) the HEI Compensation Committee’s independent compensation consultant, conducted a peer group selection in which the same utility peer group would apply to HECO and HEI. The resulting primary comparator group includes 15 publicly-traded utilities with annual revenue between $1.5 and $6 billion, approximately one-half to three-times that of HEI.

The following were the HECO peer group companies in 2010:

Allegheny Energy

Alliant Energy

Great Plains Energy

Mirant

Northeast Utilities

NSTAR

NV Energy

OGE Energy

Pinnacle West Capital

PNM Resources

Portland General Electric

Questar

TECO Energy

Vectren

Wisconsin Energy

In November 2010, Fred Cook & Co. further refined the peer group selection using different utility peer groups for HECO (with revenues as the key size measure and market capitalization as a secondary consideration).  The resulting primary comparator group, after refinement, includes 18 publicly-traded utilities with annual revenue within a one-half to two-times range of HECO’s consolidated revenue.  The results of the review revealed that the total direct compensation level (i.e., annual cash compensation plus long-term incentive awards) of Mr. Rosenblum is in the median to 75th percentile range.  Ms. Sekimura’s total direct compensation level is below the 25th percentile, and the total direct compensation for the other named executive officers are between the 25th percentile and median range.

The following are the HECO peer group companies in 2011:

Allegheny Energy

Alliant Energy

Avista

Black Hills

DPL

Great Plains Energy

IDACORP

NorthWestern

NSTAR

NV Energy

OGE Energy

Pinnacle West

PNM Resources

Portland General Electric

TECO Energy

UniSource Energy

Vectren

Westar Energy

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The HECO Board and HEI Compensation Committee have discretion to set compensation at levels that may be higher or lower than peer group target percentiles.

How does each element fit into HECO’s overall compensation objectives?

The HECO Board and HEI Compensation Committee, with the assistance of the independent compensation consultant, review each compensation element to determine whether it fits into HECO’s overall compensation objectives. At least annually, at the request of the HEI Compensation Committee, management prepares and the compensation consultant reviews tally sheets on each executive officer to determine how each executive’s elements of pay, such as base salary, annual incentives, benefits and long-term incentives, compared to executives in functionally comparable positions of peer companies. The HEI Compensation Committee and HECO Board use this information to consider whether any element should be reduced or increased or whether the mix of elements should be changed.

The HECO Board and HEI Compensation Committee also review internal equity among the top executives when developing pay recommendations. The HECO Board and HEI Compensation Committee believe that the comparative compensation among the HECO named executive officers is fair, considering job scope, experience, value to the organization and duties relative to the other HECO named executive officers.

Compensation Elements

What are the base salaries of the HECO named executive officers?

The base salaries for the HECO named executive officers are set forth under the “Salary” column in the 2010 Summary Compensation Table below.

In May 2010, the HECO Board approved base salary increases for the HECO named executive officers as shown in the table below.   These adjustments were considered by the HECO Board and the HEI Compensation Committee to be relatively modest in light of the salary freeze in 2009.  Fred Cook & Co., the HEI Compensation Committee’s independent compensation consultant, has determined that the HECO named executive officer base salaries below are near the median level of the 2010 utility peer group.

Name

 

Base Salary Increase

 

% Base Salary
Increase

 

Base Salary
Effective
May 1, 2010

 

Richard M. Rosenblum

 

$

7,000

 

1.2

%

$

587,000

 

Tayne S. Y. Sekimura

 

$

8,000

 

3.0

%

$

274,000

 

Robert A. Alm

 

$

5,000

 

1.4

%

$

356,600

 

Stephen M. McMenamin

 

$

5,000

 

2.0

%

$

255,000

 

Patricia U. Wong

 

$

3,500

 

1.2

%

$

289,200

 

What was HECO’s 2010 annual incentive plan and were there any payouts to HECO named executive officers under this plan?

HECO’s named executive officers participate in an annual incentive plan known as the Executive Incentive Compensation Plan (EICP). In 2010, the HECO Board and HEI Compensation Committee established the following EICP goals, which focused on four key constituencies of the utility: (i) shareholders, (ii) employees, (iii) customers and (iv) regulators. Mr. Rosenblum had additional financial metrics that were aligned with the goals of HEI. The following table lists the performance metrics, weightings, minimum thresholds and target and maximum goals for each of the HECO named executive officers under the 2010 EICP:

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Name

 

Weight

 

Performance Metric

 

Minimum
Threshold

 

Target Goal

 

Maximum Goal

 

 

 

 

 

 

 

 

 

 

 

Richard M. Rosenblum

 

15%

 

HEI Consolidated Net Income

 

$105 million

 

$115 million

 

$125 million

 

 

15%

 

HEI Return on Average Common Equity

 

7.2%

 

7.9%

 

8.5%

 

 

40%

 

Utility Consolidated Net Income

 

$75 million

 

$80 million

 

$85 million

 

 

10%

 

Utility Consolidated Safety (Total Cases Incident Rate)

 

3.20

 

2.41

 

1.41

 

 

10%

 

Utility Consolidated Customer Satisfaction

 

76.6%

 

78.2%

 

82.0%

 

 

10%

 

Hawaii Clean Energy Initiative (HCEI)

 

Meet minimum project milestones

 

Meet target project milestones

 

Meet maximum project milestones

 

 

 

 

 

 

 

 

 

 

 

Tayne S. Y. Sekimura

Robert A. Alm

Patricia U. Wong

Stephen M. McMenamin

 

40%

 

Utility Consolidated Net Income

 

$75 million

 

$80 million

 

$85 million

 

 

20%

 

HECO Safety (Total Cases Incident Rate)

 

2.70

 

2.40

 

1.41

 

 

20%

 

Utility Consolidated Customer Satisfaction

 

76.6%

 

78.2%

 

82.0%

 

 

10%

 

Hawaii Clean Energy Initiative (HCEI)

 

Meet minimum project milestones

 

Meet target project milestones

 

Meet maximum project milestones

 

 

10%

 

Individual goal

 

Meet minimum project milestones

 

Meet target project milestones

 

Meet maximum project milestones

The following were the award ranges, shown as a percentage of annual base salary, that the HECO Board and HEI Compensation Committee approved in February 2010 for the 2010 EICP:

Name

 

Minimum

 

Target

 

Maximum

 

Richard M. Rosenblum

 

30

%

60

%

120

%

Tayne S. Y. Sekimura

 

15

%

30

%

60

%

Robert A. Alm

 

20

%

40

%

80

%

Stephen M. McMenamin

 

15

%

30

%

60

%

Patricia U. Wong

 

15

%

30

%

60

%

In 2010, HECO met the following annual incentive goals:

·Utility consolidated net income at $76.6 million, which was between the minimum threshold of $75 million and target goal of $80.0 million. Utility consolidated net income is the basic financial measurement of earnings for the year and contributes directly to HEI’s net income, its earnings per share and support of its dividend to shareholders. Net income is a generally accepted accounting principle (GAAP) measure.

·Consolidated Safety and HECO Safety focus on employee safety as measured by the Total Cases Incident Rate (TCIR) for HECO and its subsidiaries and for HECO alone, respectively. TCIR is a standard measure of safety performance, which is determined by the total number of Occupational Safety and Health Administration recordable cases x 200,000 productive hours divided by the total number of productive hours for the year, with the lower the TCIR, the better. The goal was selected because of the importance of safety to every employee. The consolidated TCIR was 2.22, which was between the target goal of 2.41 and the maximum goal of 1.41. The HECO TCIR was 2.01, which was between the target goal of 2.40 and the maximum goal of 1.41.

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·Consolidated customer satisfaction is part of HECO’s balanced scorecard focused externally on customers, and is based on customer surveys conducted by a third party vendor in the performance period. It is an indicator of how satisfied customers are with the utility’s service, reliability and pricing. Utility consolidated customer satisfaction was 77.8%, which was above the minimum level of 76.6% and below the target level of 78.2%.

·The utility met three of five project objectives set as annual goals for Hawaii Clean Energy Initiatives. Specified project milestones were achieved or exceeded for the interisland wind studies, a fuel infrastructure strategic plan and implementation of feed-in-tariff projects. These projects are intended to obtain renewable energy from sources including wind energy, photovoltaics, biomass, geothermal, ocean energy and others, which will help the utilities meet their commitments under the Hawaii Renewable Portfolio Standards law and the Hawaii Clean Energy Initiative, an agreement executed between the state of Hawaii and the utilities in October 2008 to proactively reduce the state’s de pendency on fossil fuels by moving toward a future of increasing renewable energy. In 2010, HECO met minimum project milestones for Hawaii Clean Energy Initiatives.

For Mr. Rosenblum, HEI’s goals of net income and return on average common equity were determined on a consolidated basis and were thus impacted by the results from HEI’s bank and utility operating subsidiaries. In 2010, HEI met its two goals of HEI net income and HEI return on average common equity, each at between minimum and target levels. Discussion of these goals is incorporated herein by reference to the discussion in the HEI 2011 Proxy Statement under “Compensation Discussion and Analysis—What was HEI’s 2010 annual incentive plan and were there any payouts under this plan?”. Thirty percentpage 8 of Mr. Rosenblum’s goals were based on the level of achievement of HEI goals in addition to utility goals, because he is also an HEI named executive officer and in recognition of the utility’s influence on the achievement of HEI’s goals. The goals o f other HECO named executive officers focused solely on utility goals, 10% of which were operational-level goals tied to each executive’s specific area of responsibility and 90% of which were overall goals for corporate performance. For their individual operational goals, Ms. Sekimura achieved her goals at the minimum level and Mr. Alm and Ms. Wong achieved their goals at the target level.

Because of the achievement of the corporate goals (and of the individual goals by Mr. Alm and Mses. Sekimura and Wong) at the levels indicated above and in the materials incorporated by reference herein from the HEI 2011 Proxy Statement, in February 2011, the HECO Board and HEI Compensation Committee approved payment of the following 2010 EICP awards for HECO named executive officers:

Name

 

Payout

 

Richard M. Rosenblum

 

$

282,037

 

Tayne S. Y. Sekimura

 

$

67,222

 

Robert A. Alm

 

$

123,781

 

Stephen M. McMenamin

 

$

58,736

 

Patricia U. Wong

 

$

75,290

 

What was HECO’s 2008-2010 long-term incentive plan and were there any payouts to HECO named executive officers under the plan?Exhibit 99.3.

 

HECO’s three-year performance incentive plan is known as the Long Term Incentive Plan (LTIP) and provides awards measured over rolling three-year performance periods. In 2008, the HECO Board and HEI Compensation Committee approved the following award ranges, shown as a percentage of the salary midpoint (the middle salary level in a salary range for a particular job grade or position), for Ms. Sekimura and Mr. Alm, who were participants in the plan.  At the time the 2008-2010 LTIP was approved, Ms. Wong was serving as HEI Vice President — Administration and Corporate Secretary. Her award range was approved by the HEI Compensation Committee and HEI Board.

Name

 

Minimum

 

Target

 

Maximum

 

Tayne S. Y. Sekimura

 

25

%

37.5

%

75

%

Robert A. Alm

 

25

%

37.5

%

75

%

Patricia U. Wong

 

30

%

60.0

%

120

%

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In addition to the basic long-term incentive plan, the HECO Board and HEI Compensation Committee also approved supplemental long-term incentive award levels for the 2008-2010 period for each of the three above-named HECO named executive officers so that the long-term incentive program would be even more performance-based.  Rather than providing restricted stock awards at the levels given in 2007, the HECO Board and HEI Compensation Committee reduced the restricted stock awards given to the HECO named executive officers and provided an additional supplemental long-term incentive opportunity, using the same goals, metrics and exclusions as in the 2008-2010 long-term incentive plan.  Payment of any awards made under this supplemental 2008-2010 long-term incentive program would be paid in a combination of 50% cash and 50% stock (rather than 60% cash and 40% stock for the basic long-term incentive plan) to promote greater stock ownership and alignment with shareholder interests.  The following are the award levels for these supplemental incentives:

Name

 

Minimum

 

Target

 

Maximum

 

Tayne S. Y. Sekimura

 

6.5

%

10.0

%

20.0

%

Robert A. Alm

 

6.5

%

10.0

%

20.0

%

Patricia U. Wong

 

6.5

%

10.0

%

20.0

%

Messrs. Rosenblum and McMenamin did not participate in the 2008-2010 LTIP or 2008-2010 supplemental LTIP because they became employed at HECO after the start of this performance period.

The following table lists the performance metrics, weightings, minimum thresholds, and target and maximum goals, for the 2008-2010 LTIP and supplemental 2008-2010 LTIP. The executives listed together below share the same goals. During part of this performance period (from January 1, 2008 to September 27, 2009), Ms. Wong served as Vice President — Administration and Corporate Secretary at HEI. On September 28, 2009, Ms. Wong transferred to HECO as its Senior Vice President, Corporate Services.  Her 2008-2010 LTIP and supplemental LTIP awards are based on her HEI and HECO goals and prorated for the period that she served at each respective company.

Name

 

Weight

 

Performance Metric

 

Minimum Threshold

 

Target Goal

 

Maximum Goal

Tayne S. Y. Sekimura Robert A. Alm

 

50%

 

Utility Consolidated Free Cash Flow (1)

 

$(24.1) million

 

$(13.0) million

 

$(1.8) million

Patricia U. Wong (HECO Metrics & Goals)

 

30%

 

Utility Consolidated Return on Average Common Equity (2)

 

90% of consolidated allowed rate of return on equity less 50 basis points

 

95% of consolidated allowed rate of return on equity less 50 basis point

 

100% of consolidated allowed rate of return on equity less 50 basis points

 

 

20%

 

HEI Total Return to Shareholders

 

30th percentile of the Edison Electric Institute Index (3)

 

50th percentile of the Edison Electric Institute Index (3)

 

70th percentile of the Edison Electric Institute Index (3)

Patricia U. Wong (HEI Metrics & Goals)

 

40%

 

HEI Total Return to Shareholders

 

30th percentile of the Edison Electric Institute Index (3)

 

50th percentile of the Edison Electric Institute Index (3)

 

70th percentile of the Edison Electric Institute Index (3)

 

 

15%

 

Utility Consolidated Free Cash Flow (1)

 

$(24.1) million

 

$(13.0) million

 

$(1.8) million

 

 

15%

 

Utility Consolidated Return on Average Common Equity (2)

 

90% of consolidated allowed rate of return on equity less 50 basis points

 

95% of consolidated allowed rate of return on equity less 50 basis points

 

100% of consolidated allowed rate of return on equity less 50 basis points

 

 

15%

 

ASB Net Income

 

$55.277 million

 

$57.053 million

 

$62.025 million

 

 

15%

 

ASB Return on Assets

 

0.789%

 

0.816%

 

0.885%


(1)

The three-year performance measure of Utility Consolidated Free Cash Flow will equal the average of each year’s actual results. Utility Consolidated Free Cash Flow is equal to: Net Cash provided by Operating Activities minus Net Capital Expenditures.

(2)

The performance measure of Utility Consolidated Return on Average Common Equity (ROACE) will be based on the relationship between HECO’s consolidated ratemaking ROACE and its weighted-average consolidated allowed rate of return (to be determined by returns allowed per the most recent interim or final PUC decision in effect) less 50 basis points for each of the three years. The minimum or better must be achieved in at least two of the three years in the performance period.

(3)

The Edison Electric Institute (EEI) is an association of U.S. investor-owned electric companies that are representative of companies that are comparable investment alternatives to HEI. The Institute’s members serve 95% of the ultimate

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customers in the investor-owned segment of the industry and represent approximately 70% of the U.S. electric power industry. The three-year EEI Index measures performance data for U.S. investor-owned electric utilities. The performance of the companies in the index is calculated on a noncapitalized weighted basis so as not to give a disproportionate emphasis to the larger companies. Companies are added to or deleted from the three-year index through acquisitions or merger or other changes in ownership. The EEI uses a company in the index when it has three years of consistent comparable data in comparison to this peer group. HEI uses its ranking in the EEI Index to determine how well it performed in the three-year performance period based on total return to shareholders. In 2010, the following companies were in the three-year EEI Index:

Allegheny Energy

ALLETE

Alliant Energy

Ameren

American Electric Power

Avista

Black Hills

Centerpoint Energy

Central Vermont Public Service

CH Energy Group

CLECO

CMS Energy

Consolidated Edison

Constellation Energy Group

Dominion Resources

DPL

DTE Energy

Duke Energy

Edison International

El Paso Electric

The Empire District Electric

Entergy

Exelon

FirstEnergy

Great Plains Energy

Hawaiian Electric Industries

IDACORP

Integrys Energy Group

MDU Resources Group

MGE Energy

Nextera Energy

NiSource

Northeast Utilities

NorthWestern Energy

NSTAR

NV Energy

OGE Energy

Otter Tail

Pepco Holdings

PG&E

Pinnacle West Capital

PNM Resources

Portland General Electric

PPL

Progress Energy

Public Service Enterprise Group

Scana

Sempra Energy

Southern

TECO Energy

UIL Holdings

UniSource Energy

Unitil

Vectren

Westar Energy

Wisconsin Energy

Xcel Energy

The above goals were set by the HEI Compensation Committee and approved by the HECO Board in 2008, because they were believed to provide the necessary incentives to align executive compensation with shareholder value. The minimum performance levels reflected what the HEI Compensation Committee and HECO Board believed to be investors’ minimum expectations relative to other investment opportunities and the maximum goal provided greater upside potential for performance stretch goals. Each goal was aligned with HECO’s strategic plan and determined by the HEI Compensation Committee and HECO Board to be sufficiently difficult to be worthy of a bonus.

The utility consolidated annual free cash flow was $3.0 million, which was at the maximum level.  In addition, HEI’s three-year total return to shareholders was 19% and HEI ranked in the 75th percentile of the Edison Electric Institute index, which was above the maximum level for that performance metric. As a result, named executive officers Mses. Sekimura and Wong and Mr. Alm received awards based on achievement of these two metrics at the maximum level, payable 60% in cash and 40% in shares of HEI Common Stock. In addition, Ms. Wong received an award based on performance at a level between the target and maximum levels for ASB’s net income and at the maximum level for ASB’s return on assets. Ms. Wong’s awards were prorated as described above.

Name

 

Total Payout

 

Tayne S. Y. Sekimura

 

$

133,991

 

Robert A. Alm

 

$

159,425

 

Patricia U. Wong

 

$

278,515

 

In addition, the HEI Compensation Committee and HECO Board also approved the following supplemental long-term incentive awards payable 50% in cash and 50% in HEI Common Stock.

Name

 

Total Payout

 

Tayne S. Y. Sekimura

 

$

35,731

 

Robert A. Alm

 

$

42,514

 

Patricia U. Wong

 

$

46,421

 

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What is HECO’s 2009-2011 long-term incentive plan?ITEM 12.       SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

HECO’s 2009-2011 long-term incentive plan was explained at page 64 of its Annual Report on Form 10-K for the fiscal year ended December 31, 2008, which explanation is incorporated by reference.

What is HECO’s 2010-2012 long-term incentive plan?

The HEI Compensation Committee modified the design of the long-term incentive plan for the 2010-2012 performance period (2010-2012 LTIP) from the design of the plan for the 2009-2011 performance period based on Company strategy and recommendations of Fred Cook & Co. after its executive compensation review. The 2010-2012 LTIP generally will be paid 100% in shares of HEI Common Stock plus accrued dividends less applicable taxes with share units determined at the beginning of the performance period, instead of at the time of the payment of the award.  The number of shares was determined based on the participant’s salary at the beginning of the performance period and the fair market value of HEI Common Stock on the date the 2010-2012 LTIP was approved by the HEI Compensation Committee. The HECO Board and HEI Compensation Committee believe that setting a fixed number of shares de termined at the beginning of the performance period, rather than a number of shares determined by the dollar value of the award divided by the market price of the shares at payout, encourages even greater alignment of executive incentives with shareholder interests and will appropriately incentivize and reward executives to improve long-term shareholder value.

The following are the award levels approved by the HECO Board and HEI Compensation Committee for the 2010-2012 LTIP incentives, shown as a percentage of annual base salary:

Name

 

Minimum

 

Target

 

Maximum

 

Richard M. Rosenblum

 

45

%

90

%

180

%

Tayne S. Y. Sekimura

 

20

%

40

%

80

%

Robert A. Alm

 

20

%

40

%

80

%

Stephen M. McMenamin

 

20

%

40

%

80

%

Patricia U. Wong

 

20

%

40

%

80

%

The HEI Compensation Committee and HECO Board also approved the following long-term incentive goals for the 2010-2012 LTIP performance period for each of the participating HECO named executive officers. The executives listed together below share the same goals.

Name

 

Weight

 

Performance Metric

 

Minimum Threshold

 

Target Goal

 

Maximum Goal

Richard M. Rosenblum

 

 

40%

 

HEI Total Return to Shareholders

 

30th percentile of the Edison Electric Institute Index

 

50th percentile of the Edison Electric Institute Index

 

75th percentile of the Edison Electric Institute Index

 

 

30%

 

HEI 2-year Average Consolidated Net Income

 

$172 million

 

$191 million

 

$210 million

 

 

30%

 

Utility Consolidated Return on 2-year Average Common Equity

 

8.5%

 

9.1%

 

10.0%

Tayne S. Y. Sekimura Robert A. Alm Stephen M. McMenamin

 

40%

 

HEI Total Return to Shareholders

 

30th percentile of the Edison Electric Institute Index

 

50th percentile of the Edison Electric Institute Index

 

75th percentile of the Edison Electric Institute Index

Patricia U. Wong

 

60%

 

Utility Consolidated Return on 2-year Average Common Equity

 

8.5%

 

9.1%

 

10.0%

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The HECO Board and HEI Compensation Committee chose the above goals to encourage long-term achievement of HECO earnings and enhancement of shareholder value. Shareholders, customers and employees all benefit when these goals are met.  Total return to shareholders is a performance measure to show the return on stock to an investor. HEI’s total return is compared to that of the EEI Index of investor-owned electric companies. It is a primary measure that reflects value created for HEI shareholders compared to that created by other investor-owned electric companies.

HEI Consolidated Net Income is the GAAP net income presented in HEI’s annual financial statements adjusted for exclusions allowed for the bank and the utility by the HEI Compensation Committee and will be measured at the end of the performance period based on the average net income for 2011 and 2012.

Utility Consolidated Return on 2-year Average Common Equity (ROACE) is the average of the Utility Consolidated ROACE for 2011 and 2012.  Consolidated ROACE is calculated by dividing net income by the average common equity for each year. Average common equity is calculated by adding the common equity at the beginning of the period and common equity at the end of the period and dividing the result by two.

From a historical perspective, payouts are not easy to achieve, nor are they guaranteed, under the HECO LTIP. The utility faces tough external challenges in the 2010-2012 LTIP performance period. Extraordinary leadership on the part of the named executive officers will be needed to achieve the long-term strategic objectives required for incentive payouts. The utility is focused on implementing the Hawaii Clean Energy Initiative. This directs HECO to increase its portfolio of renewable resources, which requires major capital investments over the next several years, and which in turn requires timely filing and regulatory approval in utility rate cases and other important dockets. The HECO Board and HEI Compensation Committee believe that the LTIP targets are challenging and that if HECO is successful in achieving these goals, shareholder value is expected to increase.

How does the HEI Compensation Committee award HEI Common Stock to HECO named executive officers?

The HEI Compensation Committee provides HEI stock awards to HECO named executive officers, subject to HECO Board approval, to strengthen the linkage of executive compensation with improvement in shareholder value and promote executive retention.

Long-term incentive awards

Long-term incentive awards in 2010 through 2012 were or will be paid at least partially in the form of stock as follows:

·For the 2008-2010 performance period, 40% of the long-term incentive awards and 50% of the supplemental long-term incentive awards earned were paid in the form of stock, with the number of shares determined at the time of payout based on the cash value of the award and the market value of the shares on the payout date.

·For the 2009-2011 performance period, 40% of Mr. Rosenblum’s long-term incentive awards earned will be paid in the form of stock plus accrued dividends less an amount withheld for taxes, with the number of shares determined at the beginning of the performance period based on the potential cash value of the awards and the market value of the shares on the date the plan was approved by the HEI Compensation Committee.

·For the 2010-2012 and 2011-2013 performance periods, 100% of the long-term incentive awards earned will be paid in the form of stock plus accrued dividends less an amount withheld for taxes, with the number of shares determined at the beginning of the performance period.

Annual equity awards

HECO named executive officers are eligible to receive annual equity awards as determined by the HEI Compensation Committee and ratified by the HECO Board. The intent of the annual equity awards program is to encourage executive retention by providing for equity compensation based on staying at the Company for a specified period of time.

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In 2010, restricted stock units (RSUs) were granted to the HECO named executive officers. With RSUs, no stock is issued or outstanding until the actual release of the shares at vesting. The restricted stock units awarded in 2010 vest four years after the grant date, except that monthly pro-rata vesting applies upon an executive’s retirement, death or disability. The restricted stock units accrue dividend equivalents until vested. The 2010 grants of RSUs specific to the HECO named executive officers are summarized in the 2010 Grants of Plan-Based Awards and related notes below.

Equity award vesting periods

The unvested value from the long-term incentive plan in restricted stock units is about twice the annual grant values, which the HECO Board and HEI Compensation Committee view as sufficient for retention purposes. The cliff vesting of the restricted stock units granted in 2010 ensures unvested value extends out four years with no pro-rata vesting before the vesting period ends (except when the participant’s termination is due to retirement, death or disability).

The HECO Board and HEI Compensation Committee determine the number of shares awarded in service-vesting stock grants (versus shares that are performance-based) in consultation with its compensation consultant and considering peer practices. The HEI Compensation Committee’s independent compensation consultant Fred Cook & Co. found that the equity grants to the HECO named executive officers are generally competitive with peers.

What retirement benefits do HECO named executive officers have?

HECO provides retirement benefits to all eligible employees, including the HECO named executive officers, through the tax-qualified HEI Retirement Plan as a means of providing financial security in recognition of their years of service. Additional retirement benefits are also provided to certain HECO named executive officers through the nonqualified HEI Excess Pay Plan, which provides the portion of benefits that cannot be paid from the qualified plan due to Internal Revenue Code limits. Retirement benefits under these plans specific to the HECO named executive officers are discussed in further detail in the 2010 Pension Benefits table and related notes below.

Can HECO named executive officers participate in nonqualified deferred compensation plans?

HECO provides named executive officers with the opportunity to participate in deferred compensation plans that allow executives to defer compensation and the resulting tax liability.

·The HEI Executives’ Deferred Compensation Plan is a nonqualified deferred compensation plan that allows an HEI or HECO executive to defer payment of annual and long-term incentive awards and the resulting tax liability.  However, no named executive officer participated in this plan in 2010.

·In December 2010, the HEI Compensation Committee and Board approved a new, nonqualified deferred compensation plan for executives and directors of HEI and HECO.  This new plan will be implemented in 2011 and allows for the deferral of portions of the participants’ cash compensation, with certain limitations.  This new 2011 plan permits a broader array of investment opportunities that are substantially similar to those available under the HEI 401(k) Plan.  There are no matching contributions under this 2011 Deferred Compensation Plan.

Do HECO named executive officers have executive death benefits?

The Executive Death Benefit Plan of HEI and Participating Subsidiaries, which provided death benefits to an executive’s beneficiaries in the event of an executive’s death while employed or after retirement, was closed to new participants, effective September 9, 2009. These death benefits are provided to beneficiaries of HECO named executive officers other than Mr. McMenamin, who is not covered by the plan because he became a HECO executive officer after September 9, 2009. However, the benefits of participants who were employees as of such date were frozen (i.e., the plan was amended to foreclose any increase in death benefits that would occur due to salary increases after September 9, 2009). Under the original terms of the Executive Death Benefit Plan contracts with the participants, as in effect before September 9, 2009, the death benefits were grossed u p for tax purposes.  This treatment was considered appropriate because the executive death

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benefit is a form of life insurance and traditionally life insurance proceeds have been tax-exempt. Death benefits are discussed in further detail in the 2010 Pension Benefits table and related notes below.

Do HECO named executive officers have change-in-control agreements?

Mr. Rosenblum and Ms. Wong are the only HECO named executive officers who are parties to a change-in-control agreement.

Change-in-control agreements can be an appropriate tool to recruit executives as an expected part of the compensation package, to encourage the continued attention of key executives to the performance of their assigned duties without distraction in the event of a potential change in control and to assist in retaining key executives. Change-in-control agreements can also protect against executive flight during a transaction when key executives might, in the absence of the agreement, accept employment with competitors.

Mr. Rosenblum and Ms. Wong were each granted a double trigger change-in-control agreement, which means that he/she receives a severance payment only if there is both a change in control and he/she were to lose his/her job as a result. A change in control means essentially a change in ownership of HEI, a substantial change in the voting power of HEI’s securities or a change in the majority of the composition of the HEI Board following the consummation of a merger, tender offer or similar transaction. Mr. Rosenblum’s agreement also defines a change in control as essentially a change in ownership of HECO. Mr. Rosenblum would receive a cash lump sum severance multiplier of two times the sum of his base salary and annual bonus (determined to be the greater of the current target bonus or the largest actual bonus during the preceding three fiscal years).  Ms. W ong’s multiplier is one times her base salary and annual bonus. The severance benefits are subject to releases of claims by Mr. Rosenblum and Ms. Wong. The change-in control agreements have initial terms of two years and are automatically renewed for an additional year on each anniversary unless 90 days’ notice of nonrenewal is provided by either party, so that the protected period is at least one year upon nonrenewal. The agreements remain in effect for two years following a change in control.

Change-in-control benefits specific to Mr. Rosenblum and Ms. Wong are discussed in further detail in the Potential Payments upon Termination or Change in Control section and related notes below.

What other benefits do HECO named executive officers have?

HECO provides certain limited other compensation to the named executive officers because they are commonly provided to business executives in Hawaii, such as club memberships primarily for the purpose of business entertainment, or are necessary to recruit executives, such as relocation expenses or extra weeks of vacation, or because of legacy programs that have since been discontinued (such as an electricity discount).

In 2010, Messrs. Rosenblum and Alm and Ms. Wong each had a club membership for the primary purpose of business entertainment expected of executives in their positions.

HECO has eliminated all tax gross-up practices where possible, particularly with respect to perquisites. HECO may, from time to time, reimburse for reasonable business-related expenses. Mr. Rosenblum received a signing bonus upon his hire by HECO in 2009, subject to monthly pro-rata reimbursement in the event of a voluntary termination or termination for cause prior to the completion of 36 months of service. As part of his employment offer, Mr. Rosenblum also was extended a special severance agreement so that in the event his employment is terminated without cause on or before the third anniversary of the date of his hire, he will be paid a declining portion of his annual base salary and any target annual bonus amount, depending on his length of service. Such a severance agreement is not uncommon when hiring experienced executives, especially from the mainland United States, who may have difficulty in finding other employment if their job is terminated within months of their hire and relocation. In order to recruit Mr. Rosenblum, an experienced utility executive, HECO also agreed to give Mr. Rosenblum credit of two years age and service for purposes of calculating his retirement benefits under the HEI Excess Pay Plan. Mr. Rosenblum also received ten days of sick leave and four weeks of vacation, which is more than a new employee would usually receive. Mr. McMenamin, who joined HECO in September 2009, was eligible for reimbursement for temporary housing and monthly round-trip airfare to California for 36 months. Mr. McMenamin is eligible for three weeks of vacation, which is more than a new employee would usually receive.

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For further description of the amounts described above see footnote 5 to the 2010 Summary Compensation Table below.

Summary Compensation Table

The following summary compensation table shows the base salary, annual incentive bonus, grant date fair value of stock awards, non-equity incentive compensation, change in pension value and nonqualified deferred compensation earnings and all other compensation and benefits paid or awarded to the HECO named executive officers during 2008, 2009 and 2010 (as applicable). All compensation amounts presented for Mr. Rosenblum are the same amounts that will be presented for him in the HEI 2011 Proxy Statement.

2010 SUMMARY COMPENSATION TABLE

Name and 2010
Principal Positions 

 

Year

 

Salary
($)

 

Bonus
($) (1)

 

Stock
Awards
 ($) (2)

 

Non-Equity
Incentive
Plan

Compen-
sation
($) (3)

 

Change in
Pension Value
and Nonqualified
Deferred
Compensation
Earnings ($) (4)

 

All Other
Compen-
sation
($) (5)

 

Total ($)

 

Richard M. Rosenblum *

President and Chief Executive Officer

 

2010
2009

 

584,667
580,000

 


250,000

 

786,620
348,916

 

282,037
322,289

 

279,777
435,513

 

26,335
149,881

 

1,959,436
2,086,599

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tayne S. Y. Sekimura

Senior Vice President and Chief Financial Officer

 

2010
2009
2008

 

271,334
262,667
248,667

 



35,000

 

204,667
25,478
24,705

 

236,944
68,953
64,809

 

263,699
118,328
35,289

 



13,129

 

976,644
475,426
421,599

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Robert A. Alm

Executive Vice President

 

2010
2009
2008

 

354,933
340,833
294,133

 



 100,000

 

286,658
33,970
24,705

 

325,720
112,765
79,005

 

288,234
184,754
80,100

 



16,353

 

1,255,545
672,322
594,296

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stephen M. McMenamin **

Senior Vice President and Chief Information Officer

 

2010
2009

 

253,333
62,500

 


 

152,591

 

58,736

 

62,032
34,103

 

44,775
267,852

 

571,467
364,455

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Patricia U. Wong ***

Senior Vice President, Corporate Services

 

2010

 

288,033

 

 

213,134

 

400,226

 

332,812

 

 

1,234,205

 


*Richard M. Rosenblum joined HECO as President and Chief Executive Officer on January 1, 2009.

**Stephen M. McMenamin joined HECO as Senior Vice President and Chief Information Officer on September 28, 2009, and was a consultant to HECO prior to that time. Compensation for his consulting services in 2009 is included in “All Other Compensation” for 2009 for Mr. McMenamin and was described in footnote 6 to the 2009 Summary Compensation Table in HECO’s Form 10-K for 2009.

***Patricia U. Wong rejoined HECO as Senior Vice President-Corporate Services on September 28, 2009.

(1)Represents bonuses paid in cash that were not awarded under a non-equity incentive plan.  Bonuses awarded under non-equity incentive plans are reported under “Non-Equity Incentive Plan Compensation.” Mr. Rosenblum received a signing bonus of $250,000 upon his hiring in 2009. In 2008, Ms. Sekimura and Mr. Alm received bonuses of $35,000 and $100,000, respectively, for the success of their work on the Hawaii Clean Energy Initiative agreement.

(2)These amounts represent the aggregate grant date fair value of grant awards computed in accordance with FASB ASC Topic 718. Stock awards include restricted stock units and performance awards under the 2010-2012 LTIP. The grant date fair value of the restricted stock units was: Mr. Rosenblum $226,000, Ms. Sekimura $90,400, Mr. Alm $135,600, Mr. McMenamin $45,200 and Ms. Wong $90,400. The grant date fair values of the performance awards reported above are based upon the probable outcome of the performance conditions as of the grant date, which is assumed to be the target level. The target value of the performance awards was: Mr. Rosenblum $560,620; Ms. Sekimura $114,267; Mr. Alm $151,058; Mr. M cMenamin $107,391 and Ms. Wong $122,734.  Assuming achievement of the highest level of performance conditions, the maximum value of the performance awards is:  Mr. Rosenblum $1,121,263, Ms. Sekimura $228,557, Mr. Alm $302,093, Mr. McMenamin $214,804 and Ms. Wong $245,468. For a discussion of the assumptions underlying the amounts set out for restricted stock units and performance shares, see Note 10 to HEI’s Consolidated Financial Statements.

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(3)The following 2010 annual incentive awards to the HECO named executive officers were approved by the HEI Compensation Committee and HECO Board and paid in February 2011 to: Mr. Rosenblum $282,037, Ms. Sekimura $67,222, Mr. Alm $123,781, Mr. McMenamin $58,736 and Ms. Wong $75,290. LTIP awards are generally determined in the first quarter of each year for the three-year cycle ending on December 31 of the previous calendar year. The following 2008-2010 LTIP and supplemental LTIP awards to the HECO named executive officers were approved by the HEI Compensation Committee and HECO Board and paid in February 2011 to: Ms. Sekimura $169,722, Mr. Alm $201,939 and Ms. Wong $324,936. These LTIP awards were paid 60% in cash and 40% in shares (or 50% in cash and 50% in shares for the supplemental LTIP awards) of HEI Common Stock (based on the market price of the stock on the date of the approval of the award).

(4)These amounts represent the change in pension and executive death benefit values from December 31, 2009 to December 31, 2010, December 31, 2008 to December 31, 2009 and December 31, 2007 to December 31, 2008, respectively. No HECO named executive officer currently participates in the HEI Nonqualified Deferred Compensation Plan. For a further discussion of these plans, see the 2010 Pension Benefits table and related notes below.

(5)The following table summarizes the components of “All Other Compensation” paid with respect to 2010:

Perquisites and Other Personal Benefits

Name

 

Temporary
Housing
($)

 

Travel Expense
Reimbursements
($)

 

Other
($)

 

Total
All Other
Compensation
($)

 

Richard M. Rosenblum

 

 

 

26,335

 

26,335

 

Tayne S.Y. Sekimura

 

 

 

 

 

Robert A. Alm

 

 

 

 

 

Stephen M. McMenamin

 

13,740

 

26,131

 

4,904

 

44,775

 

Patricia U. Wong

 

 

 

 

 

·Mr. Rosenblum received a club membership and was granted four weeks of vacation.

·The total value of perquisites and other personal benefits provided by or paid by HECO was less than $10,000 for Ms. Sekimura, Mr. Alm, and Ms. Wong and the value of such perquisites and other personal benefits is not included in the table above.

·Mr. McMenamin was paid $39,871 in travel and temporary housing reimbursements, including reimbursement of (i) temporary housing expenses incurred in 2009 but reimbursed in 2010 and (ii) monthly round-trip airfare to California in accordance with his offer letter, which provides for reimbursement of airfare for one round trip per month to California for the 36 months following his date of hire. Mr. McMenamin was also eligible for three weeks of vacation.

Additional narrative disclosure about salary, bonus, stock awards, non-equity incentive plan compensation, change in pension value, nonqualified deferred compensation, and other compensation can be found in the Compensation Discussion and Analysis above.

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Grants of Plan-Based Awards

The following table relates to awards to the HECO named executive officers in 2010 under the annual EICP tied to performance in 2010 and under the LTIP tied to performance over the 2010-2012 period. Also shown are the RSUs granted under the 1987 Stock Option and Incentive Plan in 2010.

2010 GRANTS OF PLAN-BASED AWARDS

 

 

 

 

Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards (1)

 

Estimated Future Payouts
Under Equity Incentive Plan
Awards (2)

 

All Other
Stock
Awards:

Number
of Shares
of Stock

 

Grant Date
Fair Value
of Stock

 

Name 

 

Grant
Date

 

Threshold ($)

 

Target
($)

 

Maximum
($)

 

Threshold (#)

 

Target
(#)

 

Maximum
(#)

 

or Units
(#) (3)

 

Awards
($) (4)

 

Richard M. Rosenblum

 

2/11/10 EICP
2/8/10 LTIP
5/11/10 RSU

 

176,900

 

353,800

 

707,600

 


13,777

 


27,553

 


55,107

 



10,000

 


560,620
226,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tayne S. Y. Sekimura

 

2/11/10 EICP
2/8/10 LTIP
5/11/10 RSU

 

40,600

 

81,100

 

162,200

 


2,808

 


5,616

 


11,233

 



4,000

 


114,267
90,400

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Robert A. Alm

 

2/11/10 EICP

 

71,500

 

143,000

 

286,000

 

 

 

 

 

 

 

 

2/8/10 LTIP

 

 

 

 

 

 

 

3,712

 

7,424

 

14,847

 

 

151,058

 

 

 

5/11/10 RSU

 

 

 

 

 

 

 

6,000

 

135,600

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stephen M. McMenamin

 

2/11/10 EICP

 

38,100

 

76,300

 

152,500

 

 

 

 

 

 

 

2/8/10 LTIP

 

 

 

 

 

 

 

2,639

 

5,278

 

10,557

 

 

107,391

 

 

5/11/10 RSU

 

 

 

 

 

 

 

2,000

 

45,200

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Patricia U. Wong

 

2/11/10 EICP

 

43,600

 

87,200

 

174,300

 

 

 

 

 

 

 

2/8/10 LTIP

 

 

 

 

 

 

 

3,016

 

6,032

 

12,064

 

 

122,734

 

 

5/11/10 RSU

 

 

 

 

 

 

 

4,000

 

90,400

 


EICPExecutive Incentive Compensation Plan (annual incentive)

LTIPLong-Term Incentive Plan (2010-2012 period)

RSU Restricted stock unit

(1) Includes awards under HECO’s 2010 annual EICP based on meeting performance goals at threshold, target and maximum levels. See further discussion of the features of the awards in the Compensation Discussion and Analysis above.

(2)Represents number of shares of stock that would be issued under 2010-2012 LTIP awards payable in HEI Common Stock based upon the achievement of all performance goals at threshold, target and maximum levels and vesting at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the vesting period, except for terminations due to death, disability and retirement, which allow for pro-rata participation based upon completed months of service after a minimum of 12 months of service in the performance period. See further discussion of the features of the awards in the Compensation Discussion and Analysis above.

(3) Represents shares of restricted stock units awarded in 2010 that will be issued as unrestricted stock four years after the date of the grant if the awardee has remained with the Company until that time. The awards are forfeited for terminations of employment during the vesting period, except for terminations due to death, disability and retirement, which allow for pro-rata vesting. The primary purpose of the RSUs is retention and there are no conditions to vesting other than the four-year cliff vesting period. Dividend equivalent rights are accrued quarterly and are paid in cash at the end of the restriction period when the RS Us vest.

(4)Grant date fair value for shares under the 2010-2012 LTIP is estimated in accordance with the fair-value based measurement of accounting as described in FASB ASC Topic 718 based on the probable outcome of the performance conditions as of the grant date. For a discussion of the assumptions and methodologies used to calculate the amounts reported, see the discussion of performance awards contained in Note 10 (Share-based compensation) to HEI’s Consolidated Financial Statements. Grant date fair value for RSUs is based on the average of the high and low sales prices of HEI Common Stock on the New York Stock Exchange on the date of the grant of the award.

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Outstanding Equity Awards at Fiscal Year-End

OUTSTANDING EQUITY AWARDS AT 2010 FISCAL YEAR-END

 

 

Option Awards

 

Stock Awards

 

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Incentive

 

 

 

 

 

 

 

 

 

Equity Incentive Plan Awards

 

 

 

 

 

Number of
Securities
Underlying
Unexercised
Options

 

Plan
Awards:
Number of
Securities
Underlying

 

 

 

Option

 

Shares or Units of Stock
That Have

Not Vested (1)

 

Number of
Unearned
Shares, Units,
or

Other Rights

 

Market or
Payout Value
of Unearned
 Shares,

Units, or

 

Name 

 

Grant
Year

 

Exer-
ciseable
(#)

 

Unexer-ciseable
(#)

 

Unexercised
Unearned
Options (#)

 

Option
Exercise
Price ($)

 

Expira-
tion
Date

 

Number
(#)

 

Market
Value
($) (2)

 

That Have
Not Vested
(#) (3)

 

Other Rights
That Have Not
Vested ($) (2)

 

Richard M. Rosenblum

 

2009

 

 

 

 

 

 

11,000

 

250,690

 

6,147

 

140,090

 

 

2010

 

 

 

 

 

 

10,000

 

227,900

 

27,553

 

627,933

 

 

Total

 

 

 

 

 

 

21,000

 

478,590

 

33,700

 

768,023

 

Tayne S. Y. Sekimura

 

2005

 

6,000

 

 

 

26.18

 

4/07/15

 

 

 

 

 

 

2007

 

 

 

 

 

 

500

 

11,395

 

 

 

 

2008

 

 

 

 

 

 

1,000

 

22,790

 

 

 

 

2009

 

 

 

 

 

 

1,500

 

34,185

 

 

 

 

2010

 

 

 

 

 

 

4,000

 

91,160

 

5,616

 

127,989

 

 

Total

 

6,000

 

 

 

 

 

7,000

 

159,530

 

5,616

 

127,989

 

Robert A. Alm

 

2003

 

12,000

 

 

 

20.49

 

4/21/13

 

 

 

 

 

 

2003 DE

 

287

 

 

 

 

4/21/13

 

 

 

 

 

 

2005

 

12,000

 

 

 

26.18

 

4/07/15

 

 

 

 

 

 

2007

 

 

 

 

 

 

1,000

 

22,790

 

 

 

 

2008

 

 

 

 

 

 

1,000

 

22,790

 

 

 

 

2009

 

 

 

 

 

 

2,000

 

45,580

 

 

 

 

2010

 

 

 

 

 

 

6,000

 

136,740

 

7,424

 

169,193

 

 

Total

 

24,287

 

 

 

 

 

10,000

 

227,900

 

7,424

 

169,193

 

Stephen M. McMenamin

 

2010

 

 

 

 

 

 

2,000

 

45,580

 

5,278

 

120,286

 

 

Total

 

 

 

 

 

 

2,000

 

45,580

 

5,278

 

120,286

 

Patricia U. Wong

 

2003

 

2,000

 

 

 

20.49

 

4/21/13

 

 

 

 

 

 

2003 DE

 

48

 

 

 

 

4/21/13

 

 

 

 

 

 

2005

 

24,000

 

 

 

26.18

 

4/07/15

 

 

 

 

 

 

2007

 

 

 

 

 

 

3,000

 

68,370

 

 

 

 

2008

 

 

 

 

 

 

1,500

 

34,185

 

 

 

 

2009

 

 

 

 

 

 

2,500

 

56,975

 

2,355

 

53,670

 

 

2010

 

 

 

 

 

 

4,000

 

91,160

 

6,032

 

137,469

 

 

Total

 

26,048

 

 

 

 

 

11,000

 

250,690

 

8,387

 

191,139

 


DE Dividend equivalents

All information presented has been adjusted for the 2-for-1 stock split in June 2004.

(1)The 2007 and 2008 restricted stock awards become unrestricted on April 12, 2011 and April 15, 2012, respectively. The 2009 and 2010 RSUs become unrestricted on February 20, 2013 and May 11, 2014.

(2)Market value is based upon the closing price of HEI Common Stock on the New York Stock Exchange of $22.79 as of December 31, 2010.

(3)Represents shares of stock that would be issued under the 2009-2011 LTIP and 2010-2012 LTIP based upon the achievement of performance goals at the threshold level for the 2009-2011 plan and at the target level for the 2010-2012 plan at the end of the three-year performance periods.

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Option Exercises and Stock Vested

2010 OPTION EXERCISES AND STOCK VESTED

 

 

Option Awards

 

Stock Awards

 

Name 

 

Number of
Shares Acquired on
Exercise (#)

 

Value
Realized on
Exercise ($)

 

Number of Shares
Acquired on
Vesting (#)

 

Value Realized on
Vesting ($)

 

Richard M. Rosenblum

 

 

 

 

 

Tayne S. Y. Sekimura

 

 

 

 

 

Robert A. Alm

 

 

 

 

 

Stephen M. McMenamin

 

 

 

 

 

Patricia U. Wong

 

 

 

3,000

(1)

69,495

 


(1)Represents the vesting on May 13, 2010 of restricted stock issued on April 13, 2006.

Pension Benefits

The table below shows the present value as of December 31, 2010 of accumulated benefits for each of the HECO named executive officers and the number of years of service credited to each such executive under the applicable pension plan and executive death benefit plan, determined using the interest rate, mortality rate, and other assumptions set out below, which are consistent with those used in HEI’s financial statements (see Note 9 to HEI’s Consolidated Financial Statements):

2010 PENSION BENEFITS

Name 

 

Plan Name

 

Number of
Years Credited
Service (#)

 

Present Value of
Accumulated
Benefit ($) (4)

 

Payments During
the Last Fiscal
Year ($)

 

Richard M. Rosenblum

 

HEI Retirement Plan (1)

 

2.0

 

133,097

 

 

 

 

HEI Excess Pay Plan (2)

 

4.0

 

436,498

 

 

 

 

HEI Executive Death Benefit (3)

 

 

145,695

 

 

Tayne S. Y. Sekimura

 

HEI Retirement Plan (1)

 

19.6

 

755,190

 

 

 

 

HEI Excess Pay Plan (2)

 

19.6

 

65,921

 

 

 

 

HEI Executive Death Benefit (3)

 

 

71,372

 

 

Robert A. Alm

 

HEI Retirement Plan (1)

 

9.5

 

647,710

 

 

 

 

HEI Excess Pay Plan (2)

 

9.5

 

239,399

 

 

 

 

HEI Executive Death Benefit (3)

 

 

208,211

 

 

Stephen M. McMenamin

 

HEI Retirement Plan (1)

 

1.3

 

93,195

 

 

 

 

HEI Excess Pay Plan (2)

 

1.3

 

2,940

 

 

Patricia U. Wong

 

HEI Retirement Plan (1)

 

20.6

 

1,084,085

 

 

 

 

HEI Excess Pay Plan (2)

 

20.6

 

205,195

 

 

 

 

HEI Executive Death Benefit (3)

 

 

117,130

 

 


(1) Normal retirement benefits under the HEI Retirement Plan are calculated based on a formula of 2.04% x Credited Service (maximum 67%) x Final Average Pay (average monthly base salary for highest thirty-six consecutive months out of the last ten years). Credited service is generally the same as the years of service with HECO or other participating companies (HEI, MECO and HELCO). Additional credited service of up to eight months is used to calculate benefits for participants who retire at age 55 or later with respect to unused sick leave from the current year and prior two years. Credited service is also granted to disabled participants who are vested at the time of disability for the period of disability. The normal form of benefit is a joint and 50 % survivor annuity for married participants and a single life annuity for unmarried participants. Other actuarially equivalent optional forms of benefit are also available. Participants who qualify to receive benefits immediately upon termination may also elect a single sum distribution of up to $50,000 with the remaining benefit payable as an annuity. At early retirement, the single sum distribution option is not actuarially equivalent to the other forms of benefit. Retirement benefits are increased by an amount equal to approximately 1.4% of the initial benefit every twelve months following retirement. The plan provides benefits at early retirement (prior to age 65), normal retirement (age 65), deferred retirement (over age 65) and death. Early retirement benefits are available for participants who meet the age and service requirements at ages 50-64. Early retirement benefits are reduced for participants who retire prior to age 60, based on the participant’s age at the early retirement date. The accru ed normal retirement benefit is reduced by an applicable percentage, which ranges from 30% for early retirement at age 50 to 1% at age 59. Accrued or earned benefits are not reduced for eligible employees who retire at age 60 and above. Subject to the collective bargaining process, HEI has amended the HEI Retirement Plan to reduce the early retirement subsidies for benefits accrued after January 31, 2011. The retirement benefits, including the early retirement subsidies, accrued by all participants through January 31, 2011, will remain unchanged. These amendments do not

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apply to participants who had attained age 45 and were fully vested in their retirement benefits as of January 31, 2011. (Generally, a participant becomes fully vested after completing five years of employment with HEI or its subsidiaries.) Under the amended plan, early retirement subsidies are reduced for participants who retire prior to age 62 and are eliminated for participants who retire prior to age 55. For retirements between the ages of 55 and 61, there will be a 3% reduction for each year prior to age 62. For retirements prior to age 55, no subsidy will be available. A participant retiring after age 50 and before age 55 will receive the actuarial equivalent of the age 65 benefit. As of December 31, 2010, Mr. Alm and Ms. Wong are eligible for early retirement benefits under the HEI Retirement Plan. Benefits for Ms. Sekimura are vested and her earliest retirement date is Aug ust 1, 2012, when she will meet the age and service requirements for early retirement under the plan, assuming continued employment. Messrs. Rosenblum and McMenamin are not eligible for early retirement benefits under the HEI Retirement Plan and have no vested interest in the amounts reported above because they have not satisfied the five-year minimum service period that is required before vesting occurs.

(2) Benefits under the HEI Excess Pay Plan are determined using the same formula as the HEI Retirement Plan, but are not subject to the Internal Revenue Code limits on the amount of annual compensation that can be used for calculating benefits under qualified retirement plans ($245,000 in 2010 as indexed for inflation) and on the amount of annual benefits that can be paid from qualified retirement plans (the lesser of $195,000 in 2010 as indexed for inflation, or the participant’s highest average compensation over three consecutive calendar years). Benefits payable under the HEI Excess Pay Plan are reduced by the benefit payable from the HEI Retirement Plan. Early retirement, death benefits and vesting provisions are similar to the HEI Retirement Plan. As of December 31, 2010, all of the HECO named executive officers were participants in the plan. On November 16, 2009, the HEI Board approved an Addendum to the HEI Excess Pay Plan, which granted Mr. Rosenblum an additional two years of service and two years added to his age to be applied in the calculation of his benefit under the HEI Excess Pay Plan. As of December 31, 2010, Mr. Alm and Ms. Wong are eligible for early retirement benefits immediately upon termination of employment. Accrued benefits for Ms. Sekimura are vested under the HEI Excess Pay Plan and her earliest retirement date is August 1, 2012, when she will meet the age and service requirements for early retirement under the plan, assuming continued employment. Mr. Rosenblum and Mr. McMenamin are not eligible for early retirement benefits and have no vested interest in amounts reported above because they have not satisfied the minimum five-year service period that is required before vestin g occurs.

(3)Messrs. Rosenblum and Alm and Mses. Wong and Sekimura are covered by the Executive Death Benefit Plan of HEI and Participating Subsidiaries. The plan provides death benefits equal to two times the executive’s base salary if the executive dies while actively employed or, if disabled, dies prior to age 65, and one times the executive’s base salary if the executive dies following retirement. Death benefits are grossed up by the amount necessary to pay income taxes on the grossed up benefit amount as an equivalent to the exempt status of death benefits paid from a life insurance policy. The Executive Death Benefit Plan of HEI and Participating Subsidiaries was amended effective September 9, 2009 to close participation to new participants and freeze the benefit for existing participants. Under the amendment, death benefits including the grossed up amount payable to the beneficiaries of Messrs. Rosenblum and Alm and Mses. Wong and Sekimura are equal to two times the respective executive’s base salary on September 9, 2009, if they die while actively employed, or, if disabled, die prior to age 65. Mr. McMenamin is not eligible for benefits under the Executive Death Benefit Plan of HEI and Participating Subsidiaries because he became a HECO executive officer after September 9, 2009.

(4)The present value of accumulated benefits for the HECO named executive officers included in the 2010 Pension Benefits table was determined based on the following:

Methodology The benefits are calculated as of December 31, 2010 based on the credited service and pay of the HECO named executive officer as of such date (or the date of benefit freeze, if earlier).

Assumptions

(a)Discount Rate — The discount rate is the interest rate used to discount future benefit payments in order to reflect the time value of money. The discount rates used in the present value calculations are 5.68% for retirement benefits and 5.60% for executive death benefits as of December 31, 2010.

(b)Mortality Table — The RP-2000 Mortality Table (separate male and female rates) projected to the date of determination with Scale AA is used to discount future pension benefit payments in order to reflect the probability of survival to any given future date. For the calculation of the executive death benefit present value, the mortality table rates are multiplied by the death benefit to capture the death benefit payments assumed to occur at all future dates. Mortality is applied post-retirement only.

(c)Retirement Age — Each HECO named executive officer is assumed to remain in active employment until, and assumed to retire at, the earliest age when unreduced pension benefits would be payable, but no earlier than attained age as of December 31, 2010.

(d)Pre-Retirement Decrements — Pre-retirement decrements refer to events that could occur between the measurement date and the retirement age (such as withdrawal, early retirement, and death) that would impact the present value of benefits. No pre-retirement decrements are assumed in the calculation of pension benefit table present values. Decrements are assumed for financial statement purposes.

(e)Unused Sick Leave — Each HECO named executive officer is assumed to have accumulated 1,160 unused sick leave hours at retirement age.

Nonqualified Deferred Compensation

Although HECO named executive officers are eligible to participate in the HEI deferred compensation plans, which are described in the Compensation Discussion and Analysis above, no HECO named executive officer deferred any amount, and no HECO named executive officer had an account balance under those plans during 2010.

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Potential Payments Upon Termination or Change in Control

The tables below reflect the amount of potential payments to each HECO named executive officer in the event of retirement, voluntary termination, termination for cause, termination without cause and qualifying termination following a change in control, assuming termination occurred on December 31, 2010. The amounts listed below are estimates; actual amounts to be paid would depend on the actual date of termination and circumstances existing at that time. Mr. Rosenblum and Ms. Wong are the only HECO named executive officers with a change-in-control agreement.

2010 TERMINATION/CHANGE-IN-CONTROL PAYMENT TABLE

Name/
Benefit Plan or Program

 

Retirement on
12/31/10
($) (1)

 

Voluntary
Termination

on 12/31/10
($) (2)

 

Termination
for Cause on
12/31/10
($) (3)

 

Termination
without Cause
on 12/31/10
($) (4)

 

Qualifying
Termination
after Change in
Control on
12/31/10
($) (5)

 

Richard M. Rosenblum

 

 

 

 

 

 

 

 

 

 

 

Executive Incentive Compensation Plan (6)

 

 

 

 

 

 

Long-Term Incentive Plan (7)

 

 

 

 

 

 

Restricted Stock and Restricted Stock Unit (8)

 

 

 

 

 

 

Special Severance Payment (9)

 

 

 

 

587,000

 

 

Change-in-Control Agreement

 

 

 

 

 

2,491,646

 

TOTAL

 

 

 

 

587,000

 

2,491,646

 

Tayne S. Y. Sekimura

 

 

 

 

 

 

 

 

 

 

 

Executive Incentive Compensation Plan (6)

 

 

 

 

 

 

Long-Term Incentive Plan (7)

 

 

 

 

 

110,929

 

Restricted Stock and Restricted Stock Unit (8)

 

 

 

 

25,995

 

56,263

 

TOTAL

 

 

 

 

25,995

 

167,192

 

Robert A. Alm

 

 

 

 

 

 

 

 

 

 

 

Executive Incentive Compensation Plan (6)

 

 

 

 

 

 

Long-Term Incentive Plan (7)

 

135,596

 

 

 

 

135,596

 

Restricted Stock and Restricted Stock Unit (8)

 

48,429

 

 

 

36,559

 

84,988

 

TOTAL

 

184,025

 

 

 

36,559

 

220,584

 

Stephen M. McMenamin

 

 

 

 

 

 

 

 

 

 

 

Executive Incentive Compensation Plan (6)

 

 

 

 

 

 

Long-Term Incentive Plan (7)

 

 

 

 

 

40,091

 

Restricted Stock and Restricted Stock Unit (8)

 

 

 

 

 

7,122

 

TOTAL

 

 

 

 

 

47,213

 

Patricia U. Wong

 

 

 

 

 

 

 

 

 

 

 

Executive Incentive Compensation Plan (6)

 

 

 

 

 

 

Long-Term Incentive Plan (7)

 

197,383

 

 

 

 

 

Restricted Stock and Restricted Stock Unit (8)

 

45,580

 

 

 

165,366

 

 

Change-in-Control Agreement

 

 

 

 

 

1,121,463

 

TOTAL

 

242,963

 

 

 

165,366

 

1,121,463

 


Note: All stock-based award amounts were valued using the 2010 year-end closing price of HEI Common Stock of $22.79 per share. Other benefits that are available to all employees on a non-discriminatory basis and perquisites aggregating less than $10,000 in value have not been listed.

(1)   Retirement Payments & Benefits.  Only Mr. Alm and Ms. Wong were eligible for early retirement as of December 31, 2010 and accordingly no amounts are shown in this column for any other HECO named executive officer.  Amounts in this column also do not include amounts payable to Mr. Alm and Ms. Wong under the 2010 Executive Incentive Compensation Plan or the 2008-2010 long term incentive plan or supplemental long-term incentive plan because those amounts would have vested without regard to retirement since December 31, 2010 was the end of their performance periods.  In addition to the amounts shown in this column, retired executives are entitled to receive their vested retirement plan benefits under all termination scenarios.  See the 2010 Pension Benefits table above.

(2)   Voluntary Termination Payment & Benefits.  If a HECO named executive officer voluntarily terminates employment, he or she could lose any annual or long-term incentives based upon the Compensation Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time.  Voluntary termination results in the forfeiture of all unvested restricted stock, unvested restricted shares, unvested restricted stock units and participation in incentive plans. Amounts in this column also do not include amounts payable under the 2010 Executive Incentive Compensation Plan or the 2008-2010 long term incentive plan or supplemental long-term incentive plan because those amounts would have vested without regard to voluntary termination since December 31, 2010 was the end of their performance periods.  The executive’s participation in the change-in-control agreement would also end.

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(3)Termination for Cause Payments & Benefits.  If the executive is terminated for cause, he or she could lose any annual or long-term incentives based upon the HEI Compensation Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time. “Cause” generally means a violation of the HEI Corporate Code of Conduct or, for purposes of awards under the 1987 Stock Option and Incentive Plan (under which no new awards may be made) and the 2010 Equity Incentive Plan, has the meaning set forth in those plans.  Termination for cause results in the forfeiture of all vested nonqualified stock options and sto ck appreciation rights and related dividend equivalents, unvested restricted stock, unvested restricted stock units and participation in incentive plans. The executive’s participation in a change-in-control agreement would also end and the executive’s benefit from the nonqualified retirement plans would be forfeited.

(4)Termination without Cause Payments & Benefits.  If the executive is terminated without cause, he or she could lose any annual or long-term incentives based upon the HEI Compensation Committee’s right to amend, suspend or terminate any incentive award or any portion of it at any time. Termination without cause results in the pro rata vesting of restricted stock (based on service to date compared to original vesting period) and forfeiture of unvested restricted stock units. In the case of nonqualified stock options and stock appreciation rights, the executive has one year in which to exercise.

(5)Change-in-Control Payments & Benefits.Of the HECO named executive officers, only Mr. Rosenblum and Ms. Wong have a change-in-control agreement. “Change in control,” as defined under the change-in-control agreements and HEI’s 1987 Stock Option Incentive Plan and 2010 Equity and Incentive Plan, generally means a change in ownership of HEI, a substantial change in the voting power of HEI’s securities or a change in the majority of the composition of the HEI Board following the consummation of a merger, tender offer or similar transaction. Mr. Rosenblum’s change-in-control agreement also defines a change i n control as essentially a change in ownership of HECO. Mr. Rosenblum’s  and Ms. Wong’s change-in-control agreements provide lump sum severance multipliers of two times and one time, respectively, applied to the sum of the executive’s base salary and annual bonus (determined to be the greater of the current target bonus or the largest actual bonus during the preceding three years). In addition, Mr. Rosenblum and Ms. Wong would receive continued life, disability, dental, accident and health insurance benefits for two years and one year, respectively, and a lump sum payment equal to the present value of the additional benefit they would have earned under the applicable retirement and savings plans during the severance period.  Mr. Rosenblum and Ms. Wong would also receive the greater of current target or actual projected short- and long-term incentive bonuses, prorated if termination occurs during the first half of the applicable performance period and the full aggregate value if termination occurs after the end of the first half of the applicable performance period. Any unvested restricted stock and restricted stock units will become vested and free of restrictions upon a change in control. Additional age and service credit is received for the severance period for purposes of determining retiree welfare benefit eligibility. Executives would receive financial, tax planning and outplacement services, capped at 15% of annual base salary. Payment would generally be delayed for six months following termination of employment to the extent required to avoid an additional tax under Section 409A of the Internal Revenue Code. Interest would accrue during the six-month delay period at the prevailing six-month certificate of deposit rate and payments would be set aside during that period in a grantor (“rabbi”) trust. All the foregoing benefit amounts are included in this column but the total severance is lim ited to the maximum amount deductible under Section 280G of the Internal Revenue Code in each case for the named executive officers.

Other benefits are provided to executives, whether or not they have a change-in-control agreement, upon a change in control under the 1987 Stock Option Incentive Plan and 2010 Equity and Incentive Plan. The provisions in these plans and respective plan agreements provide for accelerated vesting or payments to be made to executives upon a change in control.

(6)Executive Incentive Compensation Plan.  Upon death, disability or retirement, executives continue to participate in the annual incentive compensation plan at a pro-rated amount, provided there has been a minimum service of nine months during the annual performance period, with payment to be made at the end of the annual incentive plan cycle if the applicable performance goals are achieved, using the executive’s salary at the time of termination. In termination scenarios other than a change in control, death, disability or retirement, participants who terminate during the plan cycle forfeit any accrued annual incentive award. Annual incentive compensation payments in the event of a change in control are described in footnote 5 above and quantified as part of the Change- in-Control Agreement payment in the table above.

(7)Long-Term Incentive Plan.  Upon death, disability or retirement, executives continue to participate in each on-going long-term incentive plan cycle at a prorated amount, provided there has been a minimum service of twelve months during the three-year performance period, with payment to be made at the end of the three-year cycle if performance goals are achieved, using the executive’s salary at the time of termination. The amounts shown are at target for goals achievable for all applicable plan years, prorated based upon service through December 31, 2010; actual payouts will depend upon performance achieved at the end of the plan cycle. In termination scenarios other than a change in control, participants who terminate during the plan cycle for reasons other than death, disability or retirement forfeit any accrued long-term incentive award. Long-term incentive compensation payments in the event of a change in control are described in footnote 5 above and quantified as part of the Change-in-Control Agreement payment in the table above.

(8)Restricted Stock and Restricted Stock Units.  Restricted stock vests on a prorata basis (based on service to date compared to the original vesting period) upon termination without cause and becomes fully vested upon a change in control for all executives who have restricted stock. For all other termination events, the unvested restricted stock is forfeited. Restricted stock units vest on a prorata basis (based on completed quarters of service over the original vesting period) upon termination due to death, disability and retirement and become fully vested upon a change in control for all executives who have restricted stock units. For all other termination eve nts, the unvested restricted stock units are forfeited. The amount shown is based on the 2010 year-end closing price of vested shares. Restricted stock and restricted stock unit severance payments in the event of a change in control are described in footnote 5 above and have been quantified as part of the Change-in-Control Agreement payment in the table above.

(9)Special Arrangements. As part of his employment offer, Mr. Rosenblum has a special severance agreement where in the event that his employment is terminated without cause on or before the third anniversary of his date of hire (January 1, 2009), he would be paid a declining portion of his annual base salary and any target bonus amount for the Executive Incentive Compensation Plan. If his employment is terminated after his second anniversary in 2011 and on or before his third anniversary of employment, he would receive 6 months of salary and any target annual bonus. After his third year of employment, he would be eligible for severan ce under the terms of HECO’s standard Severance Pay Plan.

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Director compensation

The HECO Board believes that a competitive package is necessary to attract and retain individuals with the experience, skills and qualifications needed for the challenging role of serving as a director on the board of a regulated electric utility. Based on the recommendations of the HEI Compensation Committee, which is responsible for recommending nonemployee director compensation for the boards of HEI and its subsidiary companies, and taking into consideration the recommendations of the HEI Compensation Committee’s independent compensation consultant who periodically reviews directors’ compensation, the HECO Board chooses to compensate nonemployee directors using a mix of cash and HEI Common Stock to allow for an appropriate level of compensation for services, including stock awards that will align the interests of HECO directors with the interests of HEI shareholders.

In 2010, the HEI Compensation Committee asked its independent compensation consultant, Fred Cook & Co., to conduct an evaluation of HECO’s nonemployee director compensation practices. Fred Cook & Co. assessed the structure of HECO’s nonemployee director compensation program and its value compared to competitive market practices of utility peer companies, similar to the assessments used in its executive compensation review. The 2010 analysis took into consideration the duties and scope of responsibilities of directors. The HEI Compensation Committee reviewed the analysis in determining its recommendations to the HECO Board concerning the appropriate nonemployee director compensation, including cash retainers, stock awards and meeting fees. In its meeting on August 9, 2010, the HECO Board approved the HEI Compensation Committee’s recommendations on nonemploy ee director compensation to be effective on January 1, 2011. Although Ms. Lau and Mr. Rosenblum are members of the HECO Board, they did not participate in the determination of nonemployee director compensation. Likewise, no other executive officer participated in the determination of nonemployee director compensation. There were no increases to the standard director retainer or meeting fees paid to directors in 2010.

Only nonemployee directors receive compensation for their service as directors. Nonemployee directors of HECO who are not also nonemployee directors of HEI receive compensation in the form of a cash retainer and an HEI stock grant. Peggy Y. Fowler, Timothy E. Johns, Bert A. Kobayashi, Jr., David M. Nakada and Alan M. Oshima are the nonemployee directors of HECO who are not also directors of HEI. Nonemployee directors of HECO who are also nonemployee directors of HEI received a cash retainer from HECO in 2010. However, starting in 2011, nonemployee directors of HECO who are also nonemployee directors of HEI will not receive any additional compensation for serving on the HECO board.  Thomas B. Fargo, A. Maurice Myers, Kelvin H. Taketa, Barry K. Taniguchi and Jeffrey N. Watanabe are nonemployee directors of HECO who are also nonemployee directors of HEI.

Stock awardsHECO nonemployee directors who are not also on the HEI Board receive annually an award of shares of HEI Common Stock, which is granted for the purpose of further aligning directors’ and shareholders’ interests in improving shareholder value. Stock grants to directors are given on the last business day of June each year. For fiscal year 2010, each of the HECO nonemployee directors who is not also on the HEI board received 1,000 shares of HEI Common Stock on June 30, 2010.

Cash retainers.  The following is the annual cash retainer schedule for nonemployee directors of HECO for 2010 and 2011.  The retainer is paid in quarterly installments in arrears.  For 2011, the amounts become effective on January 1, 2011. Nonemployee directors of HECO who also serve as a member or chairperson of the HECO Audit Committee or as a non-voting HECO Board representative to attend meetings of the HEI Compensation Committee receive additional retainer amounts, as indicated below.

 

 

2010

 

2011

 

HECO Director

 

$

25,000

 

$

40,000

 

HECO Audit Committee Chairman (additional)

 

$

10,000

 

$

10,000

 

HECO Audit Committee Member (additional)

 

$

4,000

 

$

4,000

 

HECO Non-Voting Representative to HEI Compensation Committee (additional)

 

$

4,000

 

$

6,000

 

Further, the HECO Board has approved meeting fees of $750 per meeting payable to a director who is a member of the Audit Committee after attending a minimum of eight Audit Committee meetings during the

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calendar year and $1,500 per meeting payable to the HECO Board’s non-voting representative after attending six meetings of the HEI Compensation Committee.

The boards of HECO subsidiaries HELCO and MECO are composed entirely of officers of HECO and/or its subsidiaries who receive no additional compensation for such service.

Nonemployee directors may elect to participate in the HEI Nonemployee Directors’ Deferred Compensation Plan and the new HEI/HECO Deferred Compensation Plan, both of which allow any nonemployee director to defer compensation from HEI or its participating subsidiaries for service as a director. The new HEI/HECO Deferred Compensation Plan, approved by the HEI Compensation Committee and HEI Board in December 2010, will be implemented in 2011 and allows for the deferral of portions of the participants’ cash compensation, with certain limitations.  No HECO director is currently participating in either plan. Directors, at their election and at their cost, may also participate in the group employee medical, vision and dental plans available to all HECO employees. No HECO director participated in the program during 2010.

Information concerning the compensation paid to directors of HECO who are also directors of HEI, including Messrs. Fargo, Myers, Taketa, Taniguchi and Watanabe, will be set forth in the applicable sections of the HEI 2011 Proxy Statement, which are incorporated herein by reference.

2010 HECO DIRECTOR COMPENSATION TABLE

The following director compensation table shows the compensation paid or granted to nonemployee members of the HECO Board for 2010:

Name

 

Fees
Earned
or Paid in
Cash

($) (1)

 

Stock
Awards
($) (2)

 

Option
Awards
($)

 

Non-Equity
Incentive
Plan

Compen-
sation ($)

 

Change in
Pension Value
and Nonqualified

Deferred
Compensation
Earnings ($)

 

All Other
Compen-
sation ($)

 

Total ($)

 

Thomas B. Fargo

 

28,152

 

*

NA

 

NA

 

NA

 

 

28,152

 

Peggy Y. Fowler

 

29,000

 

22,945

 

NA

 

NA

 

NA

 

 

51,945

 

Timothy E. Johns Chairman Audit Committee

 

32,836

 

22,945

 

NA

 

NA

 

NA

 

 

55,781

 

Bert A. Kobayashi, Jr.

 

25,000

 

22,945

 

NA

 

NA

 

NA

 

 

47,945

 

A. Maurice Myers

 

25,000

 

*

NA

 

NA

 

NA

 

 

25,000

 

David M. Nakada

 

25,000

 

22,945

 

NA

 

NA

 

NA

 

 

47,945

 

Alan M. Oshima

 

28,000

 

22,945

 

NA

 

NA

 

NA

 

 

50,945

 

Anne M. Takabuki (3)

 

14,500

 

 

NA

 

NA

 

NA

 

 

14,500

 

Kelvin H. Taketa

 

25,000

 

*

NA

 

NA

 

NA

 

 

25,000

 

Barry K. Taniguchi

 

29,471

 

*

NA

 

NA

 

NA

 

 

29,471

 

Jeffrey N. Watanabe

 

25,000

 

*

NA

 

NA

 

NA

 

 

25,000

 


NA  Not applicable

(1)   See detail of cash retainers for board and committee service below.

(2) Represents the value of unrestricted HEI Common Stock determined by reference to the average of the high and low sales prices of $22.945 per share on the New York Stock Exchange on June 30, 2010 of 1,000 shares of HEI Common Stock as the annual grant under the 1990 Nonemployee Director Stock Plan. HECO directors do not receive any HEI restricted stock, restricted stock unit or stock option awards.

(3)Ms. Takabuki resigned from the HECO Board effective June 30, 2010.

*Also an HEI director who accordingly received an HEI stock retainer but no additional stock retainer for HECO service. Information concerning the stock retainer available to HECO directors who are also HEI directors is incorporated herein by reference to the information relating to director compensation in the HEI 2011 Proxy Statement.

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Details of cash retainers for HECO Board and committee service are noted below:

Name

 

HECO Board
Retainer ($)

 

HECO Audit
Committee
Retainer ($)

 

Compensation
Committee
Nonvoting Rep.
Retainer ($)

 

Fees Earned
or Paid in
Cash ($)

 

Thomas B. Fargo

 

25,000

 

3,152

 

 

28,152

 

Peggy Y. Fowler

 

25,000

 

4,000

 

 

29,000

 

Timothy E. Johns

 

25,000

 

7,836

 

 

32,836

 

Bert A. Kobayashi, Jr.

 

25,000

 

 

 

25,000

 

A. Maurice Myers

 

25,000

 

 

 

25,000

 

David M. Nakada

 

25,000

 

 

 

25,000

 

Alan M. Oshima

 

25,000

 

 

3,000

 

28,000

 

Anne M. Takabuki*

 

12,500

 

2,000

 

 

14,500

 

Kelvin H. Taketa

 

25,000

 

 

 

25,000

 

Barry K. Taniguchi

 

25,000

 

4,471

 

 

29,471

 

Jeffrey N. Watanabe

 

25,000

 

 

 

25,000

 


* Ms. Takabuki resigned from the HECO Board effective June 30, 2010.

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ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

HEI:

Security Ownership of Certain Beneficial Owners

 

The information required underby this itemItem 12 for HEI is incorporated herein by reference to the “Stock Ownership Information—Security Ownership of Certain Beneficial Owners” and “Stock Ownership Information—Does HEI have stock ownership and retention guidelines for directors and officers and does it have a policy regarding hedging the risk of ownership?” sections in the HEI 20112013 Proxy Statement.

Equity compensation plan information

 

Information as of December 31, 20102012 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)

 

 

(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

 

1,131,174

 

$

20.76

 

3,953,169

 

 

1,351,869

 

$25.00

 

2,041,754

 

Equity compensation plans not approved by shareholders

 

 

 

 

 

 

 

 

Total

 

1,131,174

 

$

20.76

 

3,953,169

 

 

1,351,869

 

$25.00

 

2,041,754

 

 


(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, 2010,2012, including:  (a) 77,500

SOIP

 

EIP

 

TOTAL

 

 

15,197

 

 

15,197

 

Nonqualified stock options plus accrued dividend equivalents

100

 

 

100

 

Stock appreciation rights plus accrued dividend equivalent rights

68,812

 

284,788

 

353,600

 

Restricted stock units plus estimated compounded dividend equivalents (if applicable) *

103,182

 

 

103,182

 

Shares issued in February 2013 under the 2010-2012 LTIP plus compounded dividend equivalents

 

879,790

 

879,790

 

Shares issuable at maximum payouts under the 2011-2013 and 2012-2014 LTIPs, including estimated compounded dividend equivalents

187,291

 

1,164,578

 

1,351,869

 

 

*Under the EIP, RSUs will be counted against the shares that may be issued with respect to restricted stock units grantedauthorized for issuance as four shares for every share issued.  Accordingly, the 284,788 RSU shares in 2010the table are counted as 1,139,152 shares in determining the 2,041,754 shares available for future issuance under the EIP assuming that all service conditions are met; (b) 215,500 shares that may be issued under the SOIP upon exercise of outstanding nonqualified stock options and 26,240 of dividend equivalent shares accrued as of December 31, 2010 for such options; (c) 573,244 shares that may be issued under the SOIP with respect to awards made under the 2009-2011 Long-term Incentive Plan (LTIP) and the 2010-2012 LTIP , assuming that the performance goals for these awards are met at the maximum levels, (d) 69,000 shares issuable with respect to restricted stock units which were granted in 2009 assuming that all service conditions are met and (e)169,690 shares that could have been issued under performance awards granted in 2008 under the 2008-2010 LTIP and the 2008-2010 supplemental LTIP assuming achievement of all goals at the maximum level and calculated using the closing price of HEI Common Stock on December 31, 2010. The number of shares that may be issued under the LTIP awards is included at the maximum level to show the maximum dilution that may result from these awards; however, shares will only be issued under these awards based upon achievement of their performance goals, and it is expected that a lesser number of shares will ultimately be awarded because it is unlikely that all performance goals will be achieved at maximum levels. For example, the actual number of shares issued under the 2008-2010 LTIP and supplemental LTIP awards was 119,045 shares. The number of shares that may be issued upon the exercise of 450,000 stock appreciation rights (SARs) is not included in this column because the number of shares issued upon the exercise of the SARs is based upon the appreciation in stock price from the date of grant to the date of exercise, converted into shares. As of December 31, 2010, the closing price of HEI Common Stock was $22.79, which was less than the weighted-average exercise price of the shares of $26.13, and accordingly such rights had no intrinsic value and no shares may be issued upon their exercise.EIP.

 

(2)              The weighted average exercise price in this column relates only to the 215,000 shares of HEI Common Stock that may be issued upon exercise of outstanding options.14,000 nonqualified stock options and 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, 2012 and shares that may be issued without the payment of additional consideration (including the LTIP and restricted stock unit awards) and the SARS (which had no intrinsic value at December 31, 2010).

 

(3)              This represents the number of shares available as of December 31, 20102012 for future awards, including 3,904,4911,806,110 shares available for future awards under the EIP and 46,678235,644 shares available for future awards under the 19902011 Nonemployee Director Plan. As of May 11, 2010, no new awards may be granted under the SOIP. The shares remaining available for issuance under the 1990 Director Plan may be issued in the form of unrestricted HEI Common Stock.

 

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HECO:

Security Ownership of Certain Beneficial Owners

The information required by this Item 12 for HECO Common Stock.  HEI owns all of HECO’s outstanding Common Stock, which is HECO’s only class of securities generally entitledincorporated herein by reference to vote on matters requiring shareholder approval.

HECO Preferred Stock.  Various seriespages 34 to 35 of HECO Preferred Stock have been issued and are outstanding. Shares of HECO Preferred Stock are not considered voting securities, but upon certain defaults in dividend payments holders of HECO Preferred Stock may have the right to elect a majority of the directors of HECO. HEI owns 100,000 shares of HECO Preferred Stock, or approximately 9% of the 1,114,657 shares of HECO Preferred Stock outstanding. No HECO directors, executive officers or named executive officers (as listed in the 2010 Summary Compensation Table above) own HECO Preferred Stock.Exhibit 99.3.

 

HEI Common Stock.  The table below shows the number of shares of HEI Common Stock beneficially owned by each person who is a current HECO director or served as a HECO director during any part of 2010, each HECO named executive officer (as listed in the 2010 Summary Compensation Table above) and directors and executive officers as a group as of February 8, 2011.

 

 

Amount and Nature of Beneficial Ownership of HEI Common Stock

 

Name of Individual
or Group

 

Sole Voting or
Investment
Power (1)

 

Shared Voting or
Investment Power
(2)

 

Other
Beneficial
Ownership
(3)

 

Stock
Options/
Restricted
Stock Units
(4)

 

Total (5)

 

HECO nonemployee directors

 

 

 

 

 

 

 

 

 

 

 

Thomas B. Fargo

 

14,612

 

 

 

 

14,612

 

Peggy Y. Fowler

 

 

1,934

 

 

 

1,934

 

Timothy E. Johns

 

14,346

 

 

 

 

14,346

 

Bert A. Kobayashi, Jr.

 

10,684

 

 

 

 

10,684

 

A. Maurice Myers

 

39,414

 

 

 

 

39,414

 

David M. Nakada

 

8,539

 

 

 

 

8,539

 

Alan M. Oshima

 

2,121

 

3,551

 

 

 

5,672

 

Anne Takabuki (6)

 

15,642

 

 

 

 

15,642

 

Kelvin H. Taketa

 

23,122

 

 

 

 

23,122

 

Barry K. Taniguchi

 

 

23,727

 

 

 

23,727

 

Jeffrey N. Watanabe

 

33,449

 

 

4

 

 

33,453

 

 

 

 

 

 

 

 

 

 

 

 

 

HECO employee director

 

 

 

 

 

 

 

 

 

 

 

Constance H. Lau

 

226,064

 

 

7,617

 

139,860

 

373,541

 

 

 

 

 

 

 

 

 

 

 

 

 

HECO employee director and Named Executive Officer

 

 

 

 

 

 

 

 

 

 

 

Richard M. Rosenblum

 

700

 

 

 

8,688

 

9,388

 

 

 

 

 

 

 

 

 

 

 

 

 

Other HECO Named Executive Officers

 

 

 

 

 

 

 

 

 

 

 

Robert A. Alm

 

31,121

 

 

1,646

 

15,278

 

48,045

 

Stephen M. McMenamin

 

 

 

 

 

 

Tayne S. Y. Sekimura

 

7,771

 

 

 

 

7,771

 

Patricia U. Wong

 

27,950

 

 

 

4,713

 

32,663

 

 

 

 

 

 

 

 

 

 

 

 

 

All HECO directors and executive officers as a group (18 persons)

 

471,114

 

29,212

 

9,267

 

198,207

 

707,800

 


(1)Includes the following shares held as of February 8, 2011 in the form of stock units in the HEI Common Stock fund pursuant to the HEI Retirement Savings Plan: approximately 83 shares for Ms. Lau, 823 shares for Ms. Sekimura, 933 shares for Mr. Alm, 7,901 shares for Ms. Wong and 17,678 shares for all directors and executive officers as a group. The value of a unit is measured by the closing price of HEI Common Stock on the measurement date. Also includes the following unvested restricted shares over which the holders have sole voting but no investment power until the restrictions lapse: approximately 24,000 shares for Ms. Lau, 1,500 shares for Ms. Sekimura, 2,000 shares for Mr. Alm, 4,500 shares for Ms. Wong and 37,000 shares for all directors and executive officers as a group.

(2)Shares registered in name of the individual and spouse.

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(3)Shares owned by spouse, children or other relatives sharing the home of the director or officer in which the director or officer disclaims personal interest.

(4)Includes the number of shares that the individuals named above had a right to acquire as of or within 60 days after February 8, 2011 pursuant to (i) stock options and related dividend equivalent rights thereon and (ii) restricted stock units upon retirement. These shares are included for purposes of calculating the percentage ownership of each individual named above and all directors and executive officers as a group as described in footnote (5) below, but are not deemed to be outstanding as to any other person. This column does not include any shares subject to stock appreciation rights (SARs) and the related dividend equivalent rights held by Mses. Lau, Sekimura and Wong and Mr. Alm. As of February 8, 2011, these persons held a total of 142,000 S ARs (granted in 2004 and/or 2005) and 1,831 dividend equivalent rights, which have vested as of February 8, 2011 or will vest within 60 days after February 8, 2011. Upon exercise of a SAR, the holder will receive the number of shares of HEI Common Stock that has a total value equivalent to the difference between the exercise price of the SAR and the fair market value of HEI Common Stock on the date of exercise, which is defined in the grant agreement as the average of the high and low sales prices on the NYSE on that date. As of February 8, 2011, the fair market value of HEI Common Stock as defined in the grant agreement was $25.08 per share, which is lower than the exercise price of all of the SARs held by Mses. Lau, Sekimura and Wong and Mr. Alm on February 8, 2011. Thus, as of February 8, 2011, no shares would be issuable under these SARs. If the market value of HEI Common Stock increases to a sufficient level (above $26.02 in the case of SARs granted in 2004 and above $26.18 in the case of SARs granted in 2005), then shares could be issued under these SARs within 60 days after February 8, 2011, but the number of shares that could be acquired in such event cannot be determined because it would depend on the fair market value of HEI Common Stock, as defined in the grant agreement, on the exercise date.

(5)As of February 8, 2011, the directors and executive officers of HECO as a group and each individual named above beneficially owned less than one percent of the record number of outstanding shares of HEI Common Stock as of that date and no shares were pledged as security.

(6)Ms. Takabuki resigned as of June 30, 2010.

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

 

HEI:

 

The information required underby this itemItem 13 for HEI is incorporated herein by reference to the sections relating to related person transactions and director independence in the HEI 20112013 Proxy Statement.

HECO:

Does HECO have a written related person transaction policy?

 

The HEI Board has adopted a written related person transaction policy that is specifically incorporated in HEI’s Corporate Code of Conduct. The Corporate Code of Conduct, including the related person transaction policy, also applies to HECO and its subsidiaries. The related person transaction policy is specific to transactions between the Company and related persons such as executive officers and directors, their immediate family members or entities with which they are affiliated in which the amount involved exceeds $120,000 and in which any related person had or will have a direct or indirect material interest. Under the policy, the HEI Board, acting through the HEI Nominating and Corporate Governance Committee, will approve a related person transaction involving a director or an officer if the HEI Board determines in advance that the transaction is not inconsistent with the best interes ts of HEI and its shareholders and is not in violation of HEI’s Corporate Code of Conduct.

Are there any related person transactions with HECO?

There have been no transactions since January 1, 2010, and there are no currently proposed transactions, in which HECO or any of its subsidiaries was a participant, the amount involved exceeds $120,000, and any related person (as defined ininformation required by this Item 404 of Regulation S-K) had or will have a direct or indirect material interest.

Are HECO directors independent?

HECO has a guarantee with respect to 6.5% cumulative quarterly income preferred securities series 2004 (QUIPS) listed on the New York Stock Exchange (NYSE). Because HEI has common stock listed on NYSE and13 for HECO is a wholly-owned subsidiary of HEI, HEI is subjectincorporated herein by reference to the corporate governance listing standards in Section 303A of the NYSE Listed Company Manual and, by reason of an exemption resulting

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from HEI’s listing, HECO is not. Accordingly, HECO is exempt from NYSE listing standards 303A.01 and 303A.02 regarding director independence.

Although HECO is exempt from NYSE listing standards 303A.01 and 303A.02, HECO voluntarily endeavorspages 36 to comply with these standards for director independence. The HEI Nominating and Corporate Governance Committee assists the HECO Board with its independence determinations.

For a director to be considered independent under NYSE listing standards 303A.01 and 303A.02, the HECO Board must determine that the director does not have any direct or indirect material relationship with HECO or its parent or subsidiaries apart from his or her service as a director. The NYSE listing standards also specify circumstances under which a director may not be considered independent, such as when the director has been an employee of the Company within the last three fiscal years, if the director has had certain relationships with the Company’s external or internal auditor within the last three fiscal years or when the Company has made or received payments for goods or services to entities with which the director or an immediate family member (as defined by NYSE) of the director has specified affiliations and the aggregate amount of such payments in any year within the last thre e fiscal years exceeds the greater of $1 million or 2% of such entity’s consolidated gross revenues for the last fiscal year.

The HEI Nominating and Corporate Governance Committee and the HECO Board considered the information below, which was provided by HECO directors and/or by HEI and its subsidiaries, concerning relationships between (i) HECO or its affiliates and (ii) the director, the director’s immediate family members (as defined by NYSE) or entities with which such directors or immediate family members have certain affiliations. Based on its consideration of the relationships described below and the recommendations of the HEI Nominating and Corporate Governance Committee, the HECO Board determined that all of the nonemployee directors37 of HECO (Messrs. Fargo, Johns, Kobayashi, Myers, Nakada, Oshima, Taketa, Taniguchi and Watanabe and Ms. Fowler) are independent. In addition, the HECO Board determined that Ms. Takabuki, who resigned as a director effective June 30, 2010, was i ndependent during her service on the HECO Board in 2010. The remaining directors of HECO, Ms. Lau and Mr. Rosenblum, are employee directors.Exhibit 99.3.

 

·With respect to Messrs. Johns, Nakada and Taniguchi, the HECO Board considered the amounts paid during the last three fiscal years to purchase electricity from HECO, HELCO or MECO (the sole public utilities providing electricity to the islands of Oahu, Hawaii and Maui, respectively) by entities employing these directors and where their immediate family members are executive officers. None of the amounts paid by any of these entities for electricity (excluding pass-through surcharges for fuel and for Hawaii state revenue taxes) within the last three fiscal years exceeded the NYSE threshold that would automatically result in a director not being independent (i.e., the greater of $1 million or 2% of such entity’s consolidated gross revenues for the last fiscal year). The HECO Board also considered that HECO, HELCO and MECO are the sole source of electric power on the islands of Oahu, Hawaii and Maui, respectively, and that the rates charged by these public utilities for electricity are fixed by state regulatory authority. Since purchasers of electricity from HECO, HELCO and MECO have no choice as to supplier and no ability to negotiate rates or other terms, the HECO Board determined that these relationships do not impair the independence of these directors.

·With respect to Messrs. Johns, Nakada and Taketa, the HECO Board considered the amount of charitable contributions during the last three fiscal years from HEI and its subsidiaries to nonprofit organizations where these directors serve as executive officers. No such donations exceeded $200,000 per entity in any single fiscal year during the last three fiscal years. In determining that none of these relationships affected director independence, the HECO Board considered that Company policy requires that charitable contributions from HEI or its subsidiaries to entities where a director serves as an executive officer, and where the director has a direct or indirect material interest, and the aggregate amount donated by HEI and its subsidiaries to such organization w ould exceed $120,000 in any single fiscal year, be pre-approved by the HEI Nominating and Corporate Governance Committee and ratified by the Board.

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·With respect to Messrs. Johns, Nakada, Taketa, Taniguchi and Watanabe, the HECO Board considered other director or officer positions held by those directors at entities for which another HECO director or officer serves as a director or officer and determined that none of these relationships affected the independence of these directors. None of these relationships resulted in a compensation committee interlock or would automatically preclude an independence finding under the NYSE standards.

·With respect to Mr. Kobayashi, Jr., the HECO Board determined that the service of his father as an ASB director did not impair Mr. Kobayashi, Jr.’s independence as a HECO director.

·With respect to Mr. Watanabe, the HECO Board determined that the preferential rate mortgage loan that Mr. Watanabe had in 2010 from ASB does not impair Mr. Watanabe’s independence as a HECO director.  Effective 1/1/11, Mr. Watanabe no longer has a preferential rate mortgage loan from ASB.

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES GOVERNANCE

HEI:

 

The information required underby this itemItem 14 for HEI is incorporated herein by reference to the relevant information in the Audit Committee Report in the HEI 20112013 Proxy Statement (but no other part of the “Audit Committee Report” is incorporated herein by reference).

HECO:

Principal accountant fees

The table below shows the fees paid or payableinformation required by this Item 14 for HECO is incorporated herein by reference to PricewaterhouseCoopers LLP (HECO’s independent registered public accounting firm) relating to the auditpage 38 of HECO’s 2010 consolidated financial statements and fees for other professional services billed to HECO in 2010 with comparative amounts for 2009 paid to KPMG LLP (HECO’s former principal independent registered public accounting firm):

 

 

2010

 

2009

 

Audit fees (principally consisted of fees associated with the audit of the consolidated financial statements and internal control over financial reporting, quarterly reviews, issuances of letters to underwriters, review of registration statements and issuance of consents)

 

$

902,000

 

$

829,000

 

Audit-related fees (principally consisted of fees associated with the audit of the financial statements of certain employee benefit plans)

 

15,000

 

15,000

 

Tax fees

 

298,000

 

 

All other fees

 

 

 

 

 

$

1,215,000

 

$

844,000

 

Pre-Approval Policies

Pursuant to its charter, the HECO Audit Committee provides input to the HEI Audit Committee regarding pre-approval of all audit and permitted non-audit services of the independent registered public accounting firm engaged to audit HEI’s consolidated financial statements with respect to HECO, such as with respect to the audit of HECO’s consolidated financial statements. The HECO Audit Committee may delegate this responsibility to one or more of its members, provided that such member or members report to the full committee at its next regularly scheduled meeting any such input provided to the HEI Audit Committee. The HECO Audit Committee has delegated such responsibility to its chairperson. With such input, the HEI Audit Committee pre-approved all of the audit and audit-related services reflected in the table above.Exhibit 99.3.

 

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PART IV

 

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial statements

See Item 8 for the financial statements of HEI. The financial statements for HECO are incorporated herein by reference to the pages 5 to 47 of HECO Exhibit 99.2.99.2 indicated below:

 

Page/s in HECO
Exhibit 99.2

 

 

 

 

ReportsReport of Independent Registered Public Accounting FirmsFirm

 

5

 

Consolidated Statements of Income, Years ended December 31, 2010, 20092012, 2011 and 20082010

6

Consolidated Statements of Comprehensive income, Years ended December 31, 2012, 2011 and 2010

 

7

 

Consolidated Balance Sheets, December 31, 20102012 and 20092011

 

8

 

Consolidated Statements of Capitalization, December 31, 20102012 and 20092011

 

9-10

 

Consolidated Statements of Changes in Shareholders’Common Stock Equity, Years ended December 31, 2010, 20092012, 2011 and 20082010

 

11

 

Consolidated Statements of Cash Flows, Years ended December 31, 2010, 20092012, 2011 and 20082010

 

12

 

Notes to Consolidated Financial Statements

 

13-47

 

 

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

 

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

 

 

 

Page/s in Form 10-K

 

 

 

HEI

 

HECO

 

 

 

 

 

 

 

Reports of Independent Registered Public Accounting Firms

 

199-200

 

201-202

 

Schedule I

Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2010 and 2009 and Years ended December 31, 2010, 2009 and 2008

 

203-205

 

NA

 

Schedule II

Valuation and Qualifying Accounts, Years ended December 31, 2010, 2009 and 2008

 

206

 

206

 

NA Not applicable.

 

 

Page/s in Form 10-K

 

 

HEI

 

 

HECO

 

 

 

 

 

 

Report of Independent Registered Public Accounting Firm

 

154

 

155

Schedule I

Condensed Financial Information of Registrant, Hawaiian Electric Industries, Inc. (Parent Company) as of December 31, 2012 and 2011 and Years ended December 31, 2012, 2011 and 2010

 

156-158

 

NA

Schedule II

Valuation and Qualifying Accounts, Years ended December 31, 2012, 2011 and 2010

 

159

 

159

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 (including the notes) included in HEI’s and HECO’s Consolidated Financial Statements.

 

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[PricewaterhouseCoopers LLP letterhead]

 

Report of Independent Registered Public Accounting Firm on

Financial Statement Schedules

 

To the Board of Directors and Shareholders of

Hawaiian Electric Industries, Inc.:

 

Our auditaudits of the consolidated financial statements and of the effectiveness of internal control over financial reporting referred to in our report dated February 18, 2011, which appears19, 2013 appearing in this Annual Report on Form 10-K, also included an audit of the financial statement schedules as of and for the year ended December 31, 2010 listed in Item 15(a)(2) of this Form 10-K.  In our opinion, these financial statement schedules as of and for the year ended December 31, 2010 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

 

 

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 18, 201119, 2013

 

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[PricewaterhouseCoopers LLP letterhead]

 

[KPMG LLP letterhead]

 

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Hawaiian Electric Industries, Inc.:

Under date of February 19, 2010, we reported on the consolidated balance sheet of Hawaiian Electric Industries, Inc. and subsidiaries as of December 31, 2009, and the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2009, which are included in the Company’s annual report on Form 10-K for the year 2010. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedules as listed in the accompanying index under Item 15.(a)(2). These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.

In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Honolulu, Hawaii

February 19, 2010

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[PricewaterhouseCoopers LLP letterhead]

Report of Independent Registered Public Accounting Firm on

Financial Statement Schedule

 

To the Board of Directors and Shareholder of

Hawaiian Electric Company, Inc.:

 

Our audit of the consolidated financial statements of Hawaiian Electric Company, Inc. referred to in our report dated February 18, 201119, 2013 appearing in Exhibit 99.2 to this Annual Report on Form 10-K (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule as of and for the yearthree years ended December 31, 20102012 listed in Item 15(a)(2) of this Form 10-K.  In our opinion, this financial statement schedule as of and for the year ended December 31, 20102012 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

 

 

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 18, 201119, 2013

 

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[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Hawaiian Electric Company, Inc.:

Under date of February 19, 2010, we reported on the consolidated balance sheet and consolidated statement of capitalization of Hawaiian Electric Company, Inc. (a subsidiary of Hawaiian Electric Industries, Inc.) and subsidiaries as of December 31, 2009, and the related consolidated statements of income, changes in common stock equity and cash flows for each of the years in the two-year period ended December 31, 2009. These consolidated financial statements and our report thereon are incorporated by reference in the Company’s annual report on Form 10-K for the year 2010. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedule as listed in the accompanying index under Item 15.(a)(2). The financial statement schedule is the responsibility of the Company’s management. Our respons ibility is to express an opinion on the financial statement schedule based on our audits.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Honolulu, Hawaii

February 19, 2010

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Hawaiian Electric Industries, Inc.

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

HAWAIIAN ELECTRIC INDUSTRIES, INC. (PARENT COMPANY)

CONDENSED BALANCE SHEETS

 

December 31

 

2010

 

2009

 

 

2012

 

2011

 

(dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

1,540

 

$

2,915

 

 

$

18,021

 

$

1,765

 

Accounts receivable

 

1,773

 

1,625

 

 

1,836

 

1,361

 

Property, plant and equipment, net

 

582

 

818

 

 

5,814

 

6,076

 

Deferred income tax assets

 

12,684

 

8,340

 

 

8,517

 

14,208

 

Other assets

 

6,041

 

6,368

 

 

8,390

 

7,661

 

Investments in subsidiaries, at equity

 

1,838,679

 

1,806,353

 

 

1,978,283

 

1,898,911

 

 

$

1,861,299

 

$

1,826,419

 

 

$

2,020,861

 

$

1,929,982

 

 

 

 

 

 

Liabilities and shareholders’ equity

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

Accounts payable

 

$

722

 

$

153

 

 

$

24,086

 

$

3,602

 

Interest payable

 

6,826

 

6,459

 

 

4,781

 

5,270

 

Notes payable to subsidiaries

 

6,777

 

6,205

 

 

7,722

 

7,019

 

Commercial paper

 

24,923

 

41,989

 

 

83,694

 

68,821

 

Long-term debt, net

 

307,000

 

307,000

 

 

275,000

 

282,000

 

Retirement benefits liability

 

28,004

 

26,201

 

Other

 

31,414

 

22,965

 

 

3,709

 

8,363

 

 

377,662

 

384,771

 

 

 

 

 

 

 

426,996

 

401,276

 

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: 94,690,932 shares and 92,520,638 shares

 

1,314,199

 

1,265,157

 

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 97,928,403 shares and 96,038,328 shares

 

1,403,484

 

1,349,446

 

Retained earnings

 

181,910

 

184,213

 

 

216,804

 

198,397

 

Accumulated other comprehensive loss

 

(12,472

)

(7,722

)

 

(26,423

)

(19,137

)

 

1,483,637

 

1,441,648

 

 

1,593,865

 

1,528,706

 

 

$

1,861,299

 

$

1,826,419

 

 

$

2,020,861

 

$

1,929,982

 

 

 

 

 

 

Note to Balance Sheets

 

 

 

 

 

 

 

 

 

 

Long-term debt consisted of :

 

 

 

 

 

 

 

 

 

 

HEI medium-term notes 4.23 and 6.141%, due 2011

 

$

150,000

 

$

150,000

 

HEI medium-term note 7.13%, due 2012

 

7,000

 

7,000

 

HEI medium-term note 7.13%, paid in 2012

 

$

 

$

7,000

 

HEI medium-term note 5.25%, due 2013

 

50,000

 

50,000

 

 

50,000

 

50,000

 

HEI medium-term note 6.51%, due 2014

 

100,000

 

100,000

 

 

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

 

 

$

307,000

 

$

307,000

 

 

$

275,000

 

$

282,000

 

 

The aggregate payments of principal required subsequent to December 31, 20102012 on long-term debt are $150 million in 2011, $7 million in 2012, $50 million in 2013, and $100 million in 2014.

2014, nil in 2015, $75 million in 2016 and nil in 2017.

As of December 31, 2010,2012, HEI has a General Agreement of Indemnity in favor of both SAFECO Insurance Company of America (SAFECO) 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 SAFECO 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.

 

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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

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

204

 

$

400

 

$

499

 

 

$

221

 

$

253

 

$

204

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in income of subsidiaries

 

134,470

 

100,896

 

109,830

 

 

 

 

 

 

 

 

 

134,674

 

101,296

 

110,329

 

Equity in net income of subsidiaries

 

157,883

 

158,722

 

134,470

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating, administrative and general

 

13,336

 

12,675

 

12,652

 

 

16,191

 

15,401

 

13,336

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation of property, plant and equipment

 

320

 

409

 

431

 

 

672

 

227

 

320

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Taxes, other than income taxes

 

314

 

337

 

328

 

 

421

 

409

 

314

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13,970

 

13,421

 

13,411

 

 

17,284

 

16,037

 

13,970

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

120,704

 

87,875

 

96,918

 

 

 

 

 

 

 

 

Interest expense

 

19,961

 

18,517

 

21,727

 

 

16,695

 

22,013

 

19,961

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income before income tax benefits

 

100,743

 

69,358

 

75,191

 

 

124,125

 

120,925

 

100,743

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax benefits

 

12,792

 

13,653

 

15,087

 

 

14,533

 

17,305

 

12,792

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

113,535

 

$

83,011

 

$

90,278

 

 

$

138,658

 

$

138,230

 

$

113,535

 

 

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.

 

204HAWAIIAN 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.

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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,

 

 

Years ended December 31,

(in thousands)

 

2010

 

2009

 

2008

 

 

2012

 

2011

 

2010

 

Cash flows from operating activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

113,535

 

$

83,011

 

$

90,278

 

 

$

138,658

 

$

138,230

 

$

113,535

 

Adjustments to reconcile net income to net cash provided by operating activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in net income

 

(134,470

)

(100,896

)

(109,830

)

 

(157,883

)

(158,722

)

(134,470

)

Common stock dividends/distributions received from subsidiaries

 

110,769

 

105,128

 

122,391

 

 

118,044

 

128,558

 

110,769

 

Depreciation of property, plant and equipment

 

320

 

409

 

431

 

 

672

 

227

 

320

 

Other amortization

 

625

 

373

 

448

 

 

845

 

981

 

625

 

Changes in deferred income taxes

 

(1,432

)

(78

)

(10

)

 

150

 

276

 

(1,432

)

Changes in excess tax benefits from share-based payment arrangements

 

45

 

310

 

(405

)

 

(61

)

35

 

45

 

Changes in assets and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable

 

(148

)

213

 

(304

)

 

(475

)

412

 

(148

)

Increase (decrease) in accounts and interest payable

 

936

 

165

 

(1,159

)

Increase (decrease) in prepaid and accrued income taxes

 

(1,897

)

(2,799

)

6,667

 

Increase in accounts and interest payable

 

19,995

 

1,324

 

936

 

Changes in prepaid and accrued income taxes

 

(4,861

)

3,550

 

(1,897

)

Contribution to defined benefit pension and other postretirement benefit plans

 

(1,628

)

(1,785

)

(724

)

Changes in other assets and liabilities

 

3,657

 

3,655

 

5,003

 

 

13,662

 

5,183

 

4,381

 

Net cash provided by operating activities

 

91,940

 

89,491

 

113,510

 

 

127,118

 

118,269

 

91,940

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net decrease (increase) in notes receivable from subsidiaries

 

 

10,464

 

(41,550

)

Capital expenditures

 

(84

)

(246

)

(76

)

 

(410

)

(110

)

(84

)

Investments in subsidiaries

 

(4,364

)

(61,969

)

(1,555

)

 

(44,000

)

(40,000

)

(4,364

)

Other

 

 

(4,206

)

 

Net cash used in investing activities

 

(4,448

)

(51,751

)

(43,181

)

 

(44,410

)

(44,316

)

(4,448

)

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net decrease in notes payable to subsidiaries with original maturities of three months or less

 

(1,428

)

(2,120

)

(4,544

)

 

(1,797

)

(1,757

)

(1,428

)

Net decrease in short-term borrowings with original maturities of three months or less

 

(17,066

)

41,989

 

(62,990

)

Repayments of short-term borrowings with original maturities greater than three months

 

 

 

(50,000

)

Net increase (decrease) in short-term borrowings with original maturities of three months or less

 

14,873

 

43,897

 

(17,066

)

Proceeds from issuance of long-term debt

 

 

125,000

 

 

Repayment of long-term debt

 

(7,000

)

(150,000

)

 

Changes in excess tax benefits from share-based payment arrangements

 

(45

)

(310

)

405

 

 

61

 

(35

)

(45

)

Net proceeds from issuance of common stock

 

22,706

 

15,329

 

136,443

 

 

23,613

 

15,979

 

22,706

 

Common stock dividends

 

(93,034

)

(96,843

)

(83,604

)

 

(96,202

)

(106,812

)

(93,034

)

Net cash used in financing activities

 

(88,867

)

(41,955

)

(64,290

)

 

(66,452

)

(73,728

)

(88,867

)

Net increase (decrease) in cash and equivalents

 

(1,375

)

(4,215

)

6,039

 

 

16,256

 

225

 

(1,375

)

Cash and cash equivalents, January 1

 

2,915

 

7,130

 

1,091

 

 

1,765

 

1,540

 

2,915

 

Cash and cash equivalents, December 31

 

$

1,540

 

$

2,915

 

$

7,130

 

 

$

18,021

 

$

1,765

 

$

1,540

 

 

Supplemental disclosures of noncash activities:

In 2012, 2011 and 2010, 2009 and 2008, $1.1$1.8 million, $1.3 million and $2.7$1.1 million, respectively, of HEI advances to ASHI were converted to equity 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, $12 million and $23 million $17 millionin 2012, 2011 and $21 million in 2010, 2009 and 2008, respectively. HEI satisfied the requirements of the HEI DRIP, and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) (from April 16, 2009 through September 3, 2009) and the ASB 401(k) Plan (from its inception on May 7, 2009August 18, 2011 through September 3, 2009)January 8, 2012) by acquiring for cash its common shares through open market purchases rather than by issuing additional shares. During all other periods

Note:

HEI’s “Notes to Consolidated Financial Statements” in 2009, and for all of 2008 and 2010,Part II, Item 8 should be read in conjunction with the above HEI satisfied the requirements of the HEI DRIP, HEIRSP and ASB 401(k) Plan through the issuance of additional shares of common stock.(Parent Company) financial statements.

 

205158



Table of Contents

 

Hawaiian Electric Industries, Inc.

and Hawaiian Electric Company, Inc.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Years ended December 31, 2010, 20092012, 2011 and 20082010

 

Col. A

 

Col. B

 

Col. C

 

Col. D

 

Col. E

 

 

 

Balance

 

Additions

 

 

 

 

 

(in thousands)
Description

 

at begin-
ning of
period

 

Charged to
costs and
expenses

 

Charged
to other
accounts

 

Deductions

 

Balance at
end of
period

 

2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for uncollectible accounts — electric utility

 

$

3,822

 

$

(1,296

)

$

1,910

(a)

$

3,158

(b)

$

1,278

 

Allowance for uncollectible interest — bank

 

$

2,947

 

 

$

1,450

 

 

$

4,397

 

Allowance for losses for loans receivable — bank

 

$

41,679

 

$

20,894

 

$

2,888

(a)

$

24,815

(b)

$

40,646

 

2009

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for uncollectible accounts — electric utility

 

$

3,425

 

$

4,704

 

$

8,764

(a)

$

13,071

(b)

$

3,822

 

Allowance for uncollectible interest — bank

 

$

634

 

 

$

2,313

 

 

$

2,947

 

Allowance for losses for loans receivable — bank

 

$

35,798

 

$

32,000

 

$

847

(a)

$

26,966

(b)

$

41,679

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for uncollectible accounts — electric utility

 

$

2,010

 

$

6,627

 

$

2,582

(a)

$

7,794

(b)

$

3,425

 

Allowance for uncollectible interest — bank

 

$

32

 

 

$

602

 

 

$

634

 

Allowance for losses for loans receivable — bank

 

$

30,211

 

$

10,334

 

$

879

(a)

$

5,626

(b)

$

35,798

 

Valuation allowance for deferred tax assets — other

 

$

766

 

$

37

(c)

 

$

803

(d)

$

 

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

 

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

 

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

 

2010

 

 

 

 

 

 

 

 

 

 

 

Allowance for uncollectible accounts – electric utility

 

$3,822

 

$(1,296

)

$1,910

 (a)

$3,158

 (b)

$1,278

 

Allowance for uncollectible interest – bank

 

$2,947

 

 

$1,450

 

 

$4,397

 

Allowance for losses for loans receivable – bank

 

$41,679

 

$20,894

 

$2,888

 (a)

$24,815

 (b)

$40,646

 

 


(a)      Primarily bad debts recovered.

(b)      Bad debts charged off.

(c)Estimated change in the non-deductible executive compensation pursuant to Internal Revenue Code §162(m).

(d)Income tax valuation allowance adjustment.

206159



Table of Contents

 

(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 HECO are listed in the index under the headings “HEI” and “HECO,” respectively, except that the exhibits listed under “HECO” 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

 

Senior Financial

Executive Vice President, Chief Financial Officer and Treasurer of HEI

 

Senior Vice President and

   and Chief Financial Officer of HEI

Chief Financial Officer of HECO

 

(Principal Financial Officer of HEI)

 

(Principal Financial Officer of HECO)

 

 

Date:

February 18, 201119, 2013

Date:

February 18, 201119, 2013

 

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 18, 2011.19, 2013. 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 HECO

 

 

(Chief Executive Officer of HEI)

 

 

 

 

 

 

/s/ Richard M. Rosenblum

 

President and Director of HECO

Richard M. Rosenblum

 

(Chief Executive Officer of HECO)

 

 

 

 

 

 

/s/ James A. Ajello

 

Senior FinancialExecutive Vice President, TreasurerChief Financial Officer

James A. Ajello

 

and Chief Financial OfficerTreasurer of HEI

 

 

(Principal Financial Officer of HEI)

 

 

 

 

 

 

/s/ David M. Kostecki

 

Vice President-Finance, Controller and

David M. Kostecki

 

Chief Accounting Officer

 

 

(Principal Accounting Officer of HEI)

 

207160



Table of ContentsSIGNATURES (continued)

 

Signature

 

Title

 

 

 

 

 

 

/s/ Tayne S. Y. Sekimura

 

Senior Vice President and

Tayne S. Y. Sekimura

 

Chief Financial Officer of HECO

 

 

(Principal Financial Officer of HECO)

 

 

 

 

 

 

/s/ Patsy H. NanbuCathlynn L. Yoshida

 

Controller of HECO

Patsy H. NanbuCathlynn L. Yoshida

 

(Principal Accounting Officer of HECO)

 

 

 

 

 

 

/s/ Don E. Carroll

 

Director of HEIHECO

Don E. Carroll

 

 

 

/s/ Shirley J. Daniel

Director of HEI

Shirley J. Daniel

 

 

 

 

 

 

 

 

/s/ Thomas B. Fargo

 

Director of HEI and HECO

Thomas B. Fargo

 

 

 

 

 

 

 

 

/s/ Peggy Y. Fowler

 

Director of HEI and HECO

Peggy Y. Fowler

 

 

 

 

 

 

 

 

/s/Timothy E. Johns

 

Director of HECO

Timothy E. Johns

/s/ Micah A. Kane

Director of HECO

Micah A. Kane

 

 

 

 

 

 

 

 

/s/ Bert A. Kobayashi, Jr.

 

Director of HECO

Bert A. Kobayashi, Jr.

 

 

 

 

 

 

 

 

/s/ Victor Hao LiA. Maurice Myers

 

Director of HEI

Victor Hao LiA. Maurice Myers

 

 

 

208161



Table of ContentsSIGNATURES (continued)

 

Signature

 

Title

 

 

 

 

 

 

/s/ A. Maurice Myers

Director of HEI and HECO

A. Maurice Myers

 

 

 

/s/ David M. NakadaKeith P. Russell

 

Director of HECOHEI

David M. NakadaKeith P. Russell

 

 

 

/s/ Alan M. Oshima

Director of HECO

Alan M. Oshima

 

 

 

 

 

 

 

 

/s/ James K. Scott

 

Director of HEI

James K. Scott

 

 

 

 

 

 

 

 

/s/ Kelvin H. Taketa

 

Director of HEI and HECO

Kelvin H. Taketa

 

 

 

 

 

 

 

 

/s/ Barry K. Taniguchi

 

Director of HEI and HECO

Barry K. Taniguchi

 

 

 

 

 

 

 

 

/s/ Jeffrey N. Watanabe

 

Chairman of the Board of Directors of HEI

Jeffrey N. Watanabe

 

 and Director of HECO

 

209162



Table of Contents

 

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.
HEI:

 

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 October 31, 2008May 9, 2011 (Exhibit 3(ii) to HEI’s QuarterlyCurrent Report on Form 10-Q for the quarter ended September 30, 2008,8-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. 13 to Registration Statement on Form S-3 of HEI (Registration No. 33-58820) filed on September 26, 1997 in connection with the sale of Medium-Term Notes, Series B, 7.13% due October 1, 2012.

4.4(b)

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.

 

 

 

4.4(c)4.4(b)

 

Pricing Supplement No. 2 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on March 5, 2003 in connection with the sale of Medium-Term Notes, Series D, 5.25% due March 7, 2013.

 

 

 

4.4(d)4.4(c)

 

Pricing Supplement No. 3Master Note Purchase Agreement among HEI and the Purchasers thereto, dated March 24, 2011 (Exhibit 4(a) to Registration StatementHEI’s Current Report on Form S-3 of HEI (Registration8-K dated December 5, 2011, File No. 333-87782) filed on March 15, 2004 in connection with the sale of Medium-Term Notes, Series D, 4.23% due March 15, 2011.1-8503).

 

 

 

4.4(e)

Pricing Supplement No. 4 to Registration Statement on Form S-3 of HEI (Registration No. 333-87782) filed on August 4, 2006 in connection with the sale of Medium-Term Notes, Series D, 6.141% due August 15, 2011.

4.5(a)*4.5

 

Hawaiian Electric Industries Retirement Savings Plan, restatement effective January 1, 2008 (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).2013.

 

 

 

4.5(b)4.6

 

Amendment 2009-1 to the Hawaiian Electric Industries Retirement Savings Plan, executed May 5, 2009 (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-8503).

4.6(a)

Master Trust Agreement dated as of February 1, 2000September 4, 2012 between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1999, File No. 1-8503).

4.6(b)

First Amendment dated as of August 1, 2000 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8503).

4.6(c)

Second Amendment dated as of November 1, 2000 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, File No. 1-8503).

4.6(d)

Third Amendment dated as of April 1, 2001 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99 to HEI’s Current Report on Form 8-K dated June 19, 2001, File No. 1-8503).



Table of Contents

Exhibit no.

Description

4.6(e)

Fourth Amendment dated as of December 31, 2001 to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8503).

4.6(f)

Fifth Amendment dated as of April 1, 2002, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8503).

4.6(g)

Sixth Amendment dated as of January 1, 2002, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.8 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-8503).

4.6(h)

Seventh Amendment dated as of July 1, 2002, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 1-8503).

4.6(i)

Eighth Amendment dated as of September 1, 2003, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99 to HEI’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8503).

4.6(j)

Ninth Amendment dated as of February 2, 2004, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-8503).

4.6(k)

Tenth Amendment dated as of October 3, 2005, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(k) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, File No. 1-8503).

4.6(l)

Eleventh Amendment dated as of November 1, 2006, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(l) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 1-8503).

4.6(m)

Twelfth Amendment dated as of August 1, 2007, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-8503).

4.6(n)

Thirteenth Amendment dated as of October 17, 2008, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(n) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

4.6(o)

Fourteenth Amendment dated as of December 31, 2008, to Trust Agreement (dated as of February 1, 2000) between HEI and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(o) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

4.6(p)

Fifteenth Amendment effective as of January 15, 2010, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee (Exhibit 99.2(o) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-8503).

4.6(q)

Sixteenth Amendment effective as of March 10, 2010, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee (Exhibit 4 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010,September 30, 2012, File No. 1-8503).

 

 

 

*4.6(r)4.6(a)

 

SeventeenthLetter Amendment effective November 28, 2012 to Master Trust Agreement dated as of December 31, 2010, to Trust Agreement (dated as of February 1, 2000)September 4, 2012 between HEI and ASB and Fidelity Management Trust Company, as Trustee.Company.

 

 

 

4.7

 

Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan, as amended and restated (Exhibit 4(a) to Registration Statement on Form S-3, Registration No. 333-158999)333-180413).

 

 

 

*4.8

 

American Savings Bank 401k401(k) Plan, (Exhibit 4 to Registration Statement on Form S-8, Registration No. 333-159000).restatement effective January 1, 2013.

 

 

 

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).



Table of Contents

Exhibit no.

Description

10.3

 

OTS letter regarding release from Part II.B. of the Regulatory Capital Maintenance/Dividend Agreement dated May 26, 1988 (Exhibit 10.3(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 1992, File No. 1-8503).



Exhibit no.

Description

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 10.1810.19 are also management contracts or compensatory plans or arrangements with HECO participants.

 

 

 

*10.4

 

HEI Executive Incentive Compensation Plan amended and restated as of February 23, 2009 (Exhibit 10.4 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).4, 2013.

 

 

 

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, 2010.2010 (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.

 

 

 

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 Agreement Pursuant to the 1987 Stock Option and Incentive Plan of Hawaiian Electric Industries, Inc. (Exhibit 10.2 to HEI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-8503).

10.7(e)

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 and restated as of February 23, 2009 (Exhibit 10.8 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).4, 2013.

 

 

 

10.9

 

HEI Supplemental Executive Retirement Plan amended and restated as of January 1, 2009 (Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8503).

 

 

 

10.9(a)

 

Amendments to the HEI Supplemental Executive Retirement Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.9(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

 

 

 

10.10

 

HEI Excess Pay Plan amended and restated as of January 1, 2009 (Exhibit 10.10 to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

 

 

 

10.10(a)

 

HEI Excess Pay Plan Addendum for Constance H. Lau (Exhibit 10.10(a) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).



Table of Contents

Exhibit no.

Description

10.10(b)

HEI Excess Pay Plan Addendum for Curtis Y. Harada (Exhibit 10.10(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

 

 

 

10.10(c)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.

 

 

 

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).

 



Exhibit no.

Description

*10.13

 

HEI 19902011 Nonemployee Director Stock Plan as amended and restated(Appendix A to HEI’s Proxy Statement for 2011 Annual Meeting of Shareholders filed on May 6, 2008.March 21, 2011, File No. 1-8503).

 

 

 

*10.14

 

Nonemployee Director’s Compensation Schedule effective January 1, 2011.2011 (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, 2010.2010 (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, HECO 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).

 

 

 

10.2010.21

 

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).

 

 

 

10.20(a)10.21(a)

 

Amendments to the American Savings Bank Supplemental Executive Retirement, Disability, and Death Benefit Plan Freezing Benefit Accruals Effective December 31, 2008 (Exhibit 10.19(b) to HEI’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, File No. 1-8503).

 

 

 

10.21

Transition and Consulting Agreement between Timothy K. Schools and ASB dated April 27, 2010 (Exhibit 10.1 to HEI’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-8503).

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).

 

 

 

*11

 

Computation of Earnings per Share of Common Stock.

 

 

 

*1212.1

 

Computation of Ratio of Earnings to Fixed Charges.

 

 

 

*2121.1

 

Subsidiaries of HEI.

 

 

 

*23.1

 

Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers LLP).

 

 

 

*23.2

Consent of Independent Registered Public Accounting Firm (KPMG LLP).



Table of Contents

Exhibit no.

Description

*31.1

 

Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer).

 

 

 

*31.2

 

Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer).



Exhibit no.

Description

 

 

 

*32.1

 

Written Statement of Constance H. Lau (HEI Chief Executive Officer) FurnishedHEI Certification Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2

Written Statement of James A. Ajello (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.1350.

 

 

 

*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.

 

 

 

HECO:

 

 

3(i).1

 

HECO’s Certificate of Amendment of Articles of Incorporation (Exhibit 3.1 to HECO’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 HECO’s Amended Articles of Incorporation (Exhibit 3.1(b) to HECO’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 HECO’s Amended Articles of Incorporation (Exhibit 3(i).4 to HECO’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 HECO’s Amended Articles of Incorporation effective August 6, 2009 (Exhibit 3(i).4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-4955).

 

 

 

3(ii)

 

HECO’s Amended and Restated Bylaws (as last amended August 6, 2010) (Exhibit 3(ii) to HECO’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 HECO, HELCO and MECO (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 HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

 

 

 

4.4

 

HECO Junior Indenture with The Bank of New York, as Trustee, dated as of March 1, 2004 (Exhibit 4(f) to HECO’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 HECO’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 HECO, dated March 18, 2004 (Exhibit 4(g) to HECO’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 HECO dated as of March 1, 2004 (Exhibit 4(l) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

 

 

 

4.8

 

MECO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(h) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).

 

 

 

4.9

 

HELCO Junior Indenture with The Bank of New York, as Trustee, including HECO Subsidiary Guarantee, dated as of March 1, 2004 (Exhibit 4(j) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).



Table of Contents

Exhibit no.

Description

4.10

 

6.500% Junior Subordinated Deferrable Interest Debenture, Series 2004 issued by MECO, dated March 18, 2004 (Exhibit 4(i) to HECO’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 HELCO, dated March 18, 2004 (Exhibit 4(k) to HECO’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, HECO, MECO and HELCO (Exhibit 4(m) to HECO’s Current Report on Form 8-K dated March 16, 2004, File No. 1-4955).



Exhibit no.

Description

4.13

Note Purchase Agreement among HECO and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(a) to HECO’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

4.14

Note Purchase and Guaranty Agreement among HECO, MECO and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(b) to HECO’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

4.15

Note Purchase and Guaranty Agreement among HECO, HELCO and the Purchasers that are parties thereto, dated April 19, 2012 (Exhibit 4(c) to HECO’s Current Report on Form 8-K dated April 19, 2012, File No. 1-4955).

4.16

Note Purchase Agreement among HECO and the Purchasers that are parties thereto, dated September 13, 2012 (Exhibit 4 to HECO’s Current Report on Form 8-K dated September 13, 2012, File No. 1-4955).

 

 

 

10.1(a)

 

Power Purchase Agreement between Kalaeloa Partners, L.P., and HECO dated October 14, 1988 (Exhibit 10(a) to HECO’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 HECO and Kalaeloa Partners, L.P., dated June 15, 1989 (Exhibit 10(c) to HECO’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 HECO, as Lessee, dated February 27, 1989 (Exhibit 10(d) to HECO’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 HECO and Kalaeloa Partners, L.P., dated February 9, 1990 (Exhibit 10.2(c) to HECO’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 HECO and Kalaeloa Partners, L.P., dated December 10, 1991 (Exhibit 10.2(e) to HECO’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 HECO and Kalaeloa Partners, L.P., dated October 1, 1999 (Exhibit 10.1 to HECO’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 HECO and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.3 to HECO’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 HECO and Kalaeloa Partners, L.P., dated October 12, 2004 (Exhibit 10.4 to HECO’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 HECO, entered into on March 25, 1988 (Exhibit 10(a) to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, File No. 1-4955).

 

 

 

10.2(b)

 

Agreement between HECO and AES Barbers Point, Inc., pursuant to letters dated May 10, 1988 and April 20, 1988 (Exhibit 10.4 to HECO’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 HECO (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, File No. 1-4955).

 

 

 

10.2(d)

 

HECO’s Conditional Notice of Acceptance to AES Barbers Point, Inc. dated January 15, 1990 (Exhibit 10.3(c) to HECO’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 HECO (Exhibit 10.2(e) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2003, File No. 1-4955).

 

 

 

10.3(a)

 

Agreement between MECO and Hawaiian Commercial & Sugar Company pursuant to letters dated November 29, 1988 and November 1, 1988 (Exhibit 10.8 to HECO’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 MECO, dated November 30, 1989 (Exhibit 10(e) to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990, File No. 1-4955).

 

 

 

10.3(c)

 

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



Table of Contents

 

Exhibit no.

 

Description

10.3(d)

 

Termination Notice dated December 27, 1999 for Amended and Restated Power Purchase Agreement by and between A&B Hawaii, Inc., through its division, Hawaiian Commercial & Sugar Company, and MECO, dated November 30, 1989, as amended (Exhibit 10.2 to HECO’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 MECO, dated November 30, 1989, as amended (Exhibit 10.4(f) to HECO’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 MECO dated November 30, 1989, as Amended on November 1, 1990.1990 (Exhibit 10.3(f) to HECO’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 HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(a) to HECO’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 HELCO 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 HELCO and Thermal Power Company dated March 24, 1986 (Exhibit 10(b) to HECO’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 HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’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 HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(c) to HECO’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 HELCO and Puna Geothermal Venture dated March 24, 1986, as amended (Exhibit 10.5(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1995, File No. 1-4955).

 

 

 

10.5(a)10.4(f)

 

Fifth Amendment dated February 7, 2011 to the Purchase Power Contract between HECOHELCO and the City and County of HonoluluPuna Geothermal Venture dated March 10,24, 1986, as amended (Exhibit 10.910.4(f) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1989,2011, File No. 1-4955).

 

 

 

10.5(b)10.4(g)

 

Amendment No. 1 toPower Purchase Power ContractAgreement between HECOPuna Geothermal Venture and the City and County of HonoluluHELCO dated March 10, 1986February 7, 2011 (Exhibit 10.6(a)10.4(g) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001,2011, File No. 1-4955).

 

 

 

10.5(c)

Firm Capacity Amendment, dated April 8, 1991, to Purchase Power Contract, dated March 10, 1986, by and between HECO and the City & County of Honolulu (Exhibit 10 to HECO’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, File No. 1-4955).

10.5(d)

Amendment No. 2 to Purchase Power Contract Between HECO and City and County of Honolulu dated March 10, 1986 (Exhibit 10.6(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

10.6(a)10.5(a)

 

Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO 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 HELCO,” which is provided in final form as Exhibit 10.6(b)) (Exhibit 10.7 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

 

 

 

10.6(b)10.5(b)

 

Interconnection Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(a) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

 

 

 

10.6(c)10.5(c)

 

Amendment No. 1, executed on January 14, 1999, to Power Purchase Agreement between Encogen Hawaii, L.P. and HELCO dated October 22, 1997 (Exhibit 10.7(b) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-4955).

 

 

 

10.6(d)10.5(d)

 

Power Purchase Agreement Novation dated November 8, 1999 by and among Encogen Hawaii, L.P., Hamakua Energy Partners and HELCO (Exhibit 10.7(c) to HECO’s Annual Report on Form 10-K for fiscal year ended December 31, 2001, File No. 1-4955).



Table of Contents

Exhibit no.

Description

*10.6(e)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 HELCO dated April 19, 2010.2010 (Exhibit 10.6(e) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).

 

 

 

*10.6(f)10.5(f)

 

Guarantee Agreement between Great Point Power Hamakua Holdings, LLC and HELCO dated June 4, 2010.2010 (Exhibit 10.6(f) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, File No. 1-4955).



Exhibit no.

Description

 

 

 

10.7(a)10.6(a)

 

Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.8 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

 

 

 

10.7(b)10.6(b)

 

First Amendment to Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO entered into as of April 12, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(c) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

 

 

 

10.7(c)10.6(c)

 

Second Amendment to Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO entered into as of December 2, 2009 (confidential treatment has been granted through December 31, 2014 for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.7(c) to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009, File No. 1-4955).

10.7

Low Sulfur Fuel Oil Supply Contract by and between Chevron and HECO dated as of August 24, 2012 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.2 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

 

 

 

10.8(a)

 

Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and HECO, MECO, HELCO, HTB and YB dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit) (Exhibit 10.9 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

 

 

 

10.8(b)

 

Amendment to Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between Chevron and HECO, MECO and HELCO 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 HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

 

 

 

10.9

 

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

 

 

 

10.10(a)

 

Low Sulfur Fuel Oil Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO dated as of November 14, 1997 (confidential treatment has been requested for portions of this exhibit)exhibit, which has been redacted accordingly) (Exhibit 10.11 to HECO’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 Low Sulfur Fuel Oil Supply Contract by and between Tesoro Hawaii Corporation, formerly known as BHP Petroleum Americas Refining Inc., and HECO dated March 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(a) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

 

 

 

10.10(c)

 

Second Amendment to Low Sulfur Fuel Oil Supply Contract By and Between BHP Petroleum Americas Refining Inc. (nka, Tesoro Hawaii Corporation) and HECO entered into as of May 5, 2010 (confidential treatment has been granted through December 31, 2014 for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.4 to Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-4955).

 

 

 

10.11(a)10.11

Low Sulfur Fuel Oil Supply Contract by and between Tesoro and HECO 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 HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).

10.12(a)

 

Inter-Island Industrial Fuel Oil and Diesel Fuel Supply Contract by and between BHP Petroleum Americas Refining Inc. and HECO, MECO and HELCO dated November 14, 1997 (confidential treatment has been requested for portions of this exhibit)exhibit, which has been redacted accordingly) (Exhibit 10.12 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 1997, File No. 1-4955).

 

 

 

10.11(b)10.12(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 HECO, MECO and HELCO dated March 29, 2004 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10(b) to HECO’s Current Report on Form 8-K, dated May 28, 2004, File No. 1-4955).

 

 

 

10.1210.12(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 HECO, MECO and HELCO dated January 31, 2012 (confidential treatment has been requested for portions of this exhibit, which has been redacted accordingly) (Exhibit 10.4 to HECO’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-4955).



Exhibit no.

Description

10.13(a)

 

Contract of private carriage by and between HITI and HELCO dated December 4, 2000 (Exhibit 10.13 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

 

 

 

10.13*10.13(b)

Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and HELCO, dated July 1, 2011.

10.14(a)

 

Contract of private carriage by and between HITI and MECO dated December 4, 2000 (Exhibit 10.14 to HECO’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-4955).

 

 

 

10.14*10.14(b)

Consent to Change of Ownership/Control of Carrier by and between K-Sea Operating Partnership, L.P., and MECO, dated July 1, 2011.

10.15

 

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).



Table of Contents

Exhibit no.

Description

10.1510.16

Stipulated Settlement Agreement between the Hawaiian Electric Companies and the Division of Consumer Advocacy regarding Certain Regulatory Matters (Exhibit 10 to HECO’s Current Report on Form 8-K, dated January 28, 2013, File No. 1-4955).

10.17

 

Credit Agreement, dated as of May 7, 2010, among HECO, 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).

 

 

 

10.18

Amendment No. 1, dated as of December 5, 2011, to the Credit Agreement, dated as of May 7, 2010, among HECO, 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 HECO’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 HECO’s Item 6. Selected Financial Data on page 4 of HECO Exhibit 99.2).

 

 

 

*1212.2

 

Computation of Ratio of Earnings to Fixed Charges.

 

 

 

*2121.2

 

Subsidiaries of HECO.

 

 

 

*31.3

 

Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer).

 

 

 

*31.4

 

Certification Pursuant to 13a-14 of the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer).

 

 

 

*32.332.2

 

Written Statement of Richard M. Rosenblum (HECO Chief Executive Officer) FurnishedHECO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.

*32.4

Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002.1350.

 

 

 

*99.1

 

Reconciliation of electric utility operating income per HEI and HECO Consolidated Statements of Income.

 

 

 

*99.2

 

Forward-Looking Statements, Selected Financial Data, HECO’s MD&A, HECO’s Quantitative and Qualitative Disclosures about Market Risk and HECO’s Consolidated 20102012 Financial Statements (with ReportsReport of Independent Registered Public Accounting FirmsFirm thereon).

*99.3

HECO’s Directors, Executive Officers and Corporate Governance; HECO’s Executive Compensation; HECO’s Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters; HECO’s Certain Relationships and Related Transactions, and Director Independence; and HECO’s Principal Accounting Fees and Services.