10-Q 1 a13-6935_110q.htm 10-Q

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended March 31, 2013

 

OR

 

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

 

Exact Name of Registrant as

 

Commission

 

I.R.S. Employer

Specified in Its Charter

 

File Number

 

Identification No.

HAWAIIAN ELECTRIC INDUSTRIES, INC.

 

1-8503

 

99-0208097

and Principal Subsidiary

 

 

 

 

HAWAIIAN ELECTRIC COMPANY, INC.

 

1-4955

 

99-0040500

 

State of Hawaii

(State or other jurisdiction of incorporation or organization)

 

Hawaiian Electric Industries, Inc. – 1001 Bishop Street, Suite 2900, Honolulu, Hawaii  96813

Hawaiian Electric Company, Inc. – 900 Richards Street, Honolulu, Hawaii  96813

(Address of principal executive offices and zip code)

 

Hawaiian Electric Industries, Inc. (808) 543-5662

Hawaiian Electric Company, Inc. (808) 543-7771

(Registrant’s telephone number, including area code)

 

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

Hawaiian Electric Industries Inc.  Yes x     No o

Hawaiian Electric Company, Inc.  Yes x     No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

Hawaiian Electric Industries Inc.  Yes x     No o

Hawaiian Electric Company, Inc.  Yes x     No o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

Hawaiian Electric Industries Inc.  Yes o    No x

Hawaiian Electric Company, Inc.  Yes o     No x

 

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

 

Hawaiian Electric Industries Inc.

 

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

(Do not check if a smaller reporting company)

Smaller reporting company o

 

Hawaiian Electric Company, Inc.

 

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

(Do not check if a smaller reporting company)

Smaller reporting company o

 

APPLICABLE ONLY TO CORPORATE ISSUERS:

 

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

 

Class of Common Stock

 

Outstanding April 29, 2013

Hawaiian Electric Industries, Inc. (Without Par Value)

 

98,541,357 Shares

Hawaiian Electric Company, Inc. ($6-2/3 Par Value)

 

14,665,264 Shares (not publicly traded)

 

 

 



Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2013

 

INDEX

 

Page No.

 

 

ii

 

Glossary of Terms

iv

 

Forward-Looking Statements

 

 

 

 

 

PART I. FINANCIAL INFORMATION

1

 

Item 1.

Financial Statements

 

 

 

 

 

 

 

Hawaiian Electric Industries, Inc. and Subsidiaries

1

 

 

Consolidated Statements of Income -

three months ended March 31, 2013 and 2012

2

 

 

Consolidated Statements of Comprehensive Income -

three months ended March 31, 2013 and 2012

3

 

 

Consolidated Balance Sheets - March 31, 2013 and December 31, 2012

4

 

 

Consolidated Statements of Changes in Shareholders’ Equity -

three months ended March 31, 2013 and 2012

5

 

 

Consolidated Statements of Cash Flows -

three months ended March 31, 2013 and 2012

6

 

 

Notes to Consolidated Financial Statements

 

 

 

 

 

 

 

Hawaiian Electric Company, Inc. and Subsidiaries

27

 

 

Consolidated Statements of Income -

three months ended March 31, 2013 and 2012

27

 

 

Consolidated Statements of Comprehensive Income -

three months ended March 31, 2013 and 2012

28

 

 

Consolidated Balance Sheets - March 31, 2013 and December 31, 2012

29

 

 

Consolidated Statements of Changes in Common Stock Equity -

three months ended March 31, 2013 and 2012

30

 

 

Consolidated Statements of Cash Flows -

three months ended March 31, 2013 and 2012

31

 

 

Notes to Consolidated Financial Statements

49

 

Item 2.

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

49

 

 

HEI Consolidated

53

 

 

Electric Utilities

61

 

 

Bank

68

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

69

 

Item 4.

Controls and Procedures

 

 

 

 

 

PART II. OTHER INFORMATION

70

 

Item 1.

Legal Proceedings

70

 

Item 1A.

Risk Factors

80

 

Item 5.

Other Information

84

 

Item 6.

Exhibits

85

 

Signatures

 

i



Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended March 31, 2013

 

GLOSSARY OF TERMS

 

Terms

 

Definitions

 

 

 

AFTAP

 

Adjusted Funding Target Attainment Percentage

AFUDC

 

Allowance for funds used during construction

AOCI

 

Accumulated other comprehensive income

ARO

 

Asset retirement obligation

ASB

 

American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc.

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.

CIP CT-1

 

Campbell Industrial Park 110 MW combustion turbine No. 1

Company

 

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.; HEI Properties, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).

Consumer Advocate

 

Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii

DBEDT

 

State of Hawaii Department of Business, Economic Development and Tourism

D&O

 

Decision and order

Dodd-Frank Act

 

Dodd-Frank Wall Street Reform and Consumer Protection Act

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 clauses

EIP

 

2010 Equity and Incentive Plan

EGU

 

Electrical generating unit

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

EPA

 

Environmental Protection Agency -- federal

EPS

 

Earnings per share

EVE

 

Economic value of equity

Exchange Act

 

Securities Exchange Act of 1934

FDIC

 

Federal Deposit Insurance Corporation

federal

 

U.S. Government

FHLB

 

Federal Home Loan Bank

FHLMC

 

Federal Home Loan Mortgage Corporation

FNMA

 

Federal National Mortgage Association

FRB

 

Federal Reserve Board

 

ii



Table of Contents

 

GLOSSARY OF TERMS, continued

 

Terms

 

Definitions

 

 

 

GAAP

 

U.S. generally accepted accounting principles

GHG

 

Greenhouse gas

GNMA

 

Government National Mortgage Association

HCEI

 

Hawaii Clean Energy Initiative

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.

HEI

 

Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., HEI Properties, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.)

HEIRSP

 

Hawaiian Electric Industries Retirement Savings Plan

HELCO

 

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

HPOWER

 

City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant

IPP

 

Independent power producer

Kalaeloa

 

Kalaeloa Partners, L.P.

KW

 

Kilowatt

KWH

 

Kilowatthour

LTIP

 

Long-term incentive plan

MAP-21

 

Moving Ahead for Progress in the 21st Century Act

MECO

 

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

MW

 

Megawatt/s (as applicable)

NII

 

Net interest income

NQSO

 

Nonqualified stock option

O&M

 

Other operation and maintenance

OCC

 

Office of the Comptroller of the Currency

OPEB

 

Postretirement benefits other than pensions

PPA

 

Power purchase agreement

PPAC

 

Purchased power adjustment clause

PUC

 

Public Utilities Commission of the State of Hawaii

RAM

 

Revenue adjustment mechanism

RBA

 

Revenue balancing account

RFP

 

Request for proposal

REIP

 

Renewable Energy Infrastructure Program

RHI

 

Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.

ROACE

 

Return on average common equity

RORB

 

Return on average rate base

RPS

 

Renewable portfolio standard

SAR

 

Stock appreciation right

SEC

 

Securities and Exchange Commission

See

 

Means the referenced material is incorporated by reference

SOIP

 

1987 Stock Option and Incentive Plan, as amended

TDR

 

Troubled debt restructuring

UBC

 

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

VIE

 

Variable interest entity

 

iii



Table of Contents

 

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, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

 

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

 

·            international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB), which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii (including the effects of sequestration), the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal, state and international responses to those conditions, and the potential impacts of global developments (including global economic conditions and uncertainties, unrest, 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 (e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of climate change, such as more severe storms and rising sea levels), including their impact on Company operations and the economy;

 

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

 

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

 

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

 

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

 

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

 

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

 

·            the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement), setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), and the fulfillment by the electric utilities of their commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering (and potential disapproval of actual or proposed) HCEI-related costs; reliance by the Company on outside parties 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 cables, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

 

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

 

·            fuel oil price changes, 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;

 

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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 existing, new and 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 and/or liabilities), the regulation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);

 

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

 

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

 

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

 

·            the ability of the electric utilities to recover increasing costs and earn a reasonable return on capital investments not covered by revenue adjustment mechanisms;

 

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

 

·            changes in accounting principles applicable to HEI, 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-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 (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits); and

 

·            other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or 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.

 

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Table of Contents

 

PART I - FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

 

Three months ended March 31

 

2013

 

2012

 

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

Electric utility

 

$

719,273

 

$

749,610

 

Bank

 

64,756

 

65,252

 

Other

 

35

 

(2

)

Total revenues

 

784,064

 

814,860

 

Expenses

 

 

 

 

 

Electric utility

 

666,320

 

692,356

 

Bank

 

43,005

 

42,340

 

Other

 

4,082

 

4,348

 

Total expenses

 

713,407

 

739,044

 

Operating income (loss)

 

 

 

 

 

Electric utility

 

52,953

 

57,254

 

Bank

 

21,751

 

22,912

 

Other

 

(4,047

)

(4,350

)

Total operating income

 

70,657

 

75,816

 

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

 

(19,788

)

(18,539

)

Allowance for borrowed funds used during construction

 

730

 

870

 

Allowance for equity funds used during construction

 

1,215

 

1,940

 

Income before income taxes

 

52,814

 

60,087

 

Income taxes

 

18,662

 

21,298

 

Net income

 

34,152

 

38,789

 

Preferred stock dividends of subsidiaries

 

473

 

473

 

Net income for common stock

 

$

33,679

 

$

38,316

 

Basic earnings per common share

 

$

0.34

 

$

0.40

 

Diluted earnings per common share

 

$

0.34

 

$

0.40

 

Dividends per common share

 

$

0.31

 

$

0.31

 

Weighted-average number of common shares outstanding

 

98,135

 

96,167

 

Net effect of potentially dilutive shares

 

405

 

394

 

Adjusted weighted-average shares

 

98,540

 

96,561

 

 

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

 

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Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

$

33,679

 

$

38,316

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

Net unrealized losses on securities:

 

 

 

 

 

Net unrealized losses on securities arising during the period, net of tax benefits, of $547 and $149 for the three months ended March 31, 2013 and 2012, respectively

 

(828

)

(226

)

Derivatives qualified as cash flow hedges:

 

 

 

 

 

Less: reclassification adjustment to net income, net of tax benefits of $37 for the three months ended March 31, 2013 and 2012

 

59

 

59

 

Retirement benefit plans:

 

 

 

 

 

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 $3,846 and $2,473 for the three months ended March 31, 2013 and 2012, respectively

 

6,021

 

3,873

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,384 and $2,162 for the three months ended March 31, 2013 and 2012, respectively

 

(5,313

)

(3,395

)

Other comprehensive income (loss), net of taxes

 

(61

)

311

 

Comprehensive income attributable to Hawaiian Electric Industries, Inc.

 

$

33,618

 

$

38,627

 

 

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

 

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Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

 

(dollars in thousands)

 

 

 

March 31, 2013

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

$

262,708

 

 

 

$

219,662

 

Accounts receivable and unbilled revenues, net

 

 

 

348,487

 

 

 

362,823

 

Available-for-sale investment and mortgage-related securities

 

 

 

659,400

 

 

 

671,358

 

Investment in stock of Federal Home Loan Bank of Seattle

 

 

 

95,152

 

 

 

96,022

 

Loans receivable held for investment, net

 

 

 

3,803,002

 

 

 

3,737,233

 

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

 

 

 

5,351

 

 

 

26,005

 

Property, plant and equipment, net of accumulated depreciation of $2,142,040 in 2013 and $2,125,286 in 2012

 

 

 

3,640,308

 

 

 

3,594,829

 

Regulatory assets

 

 

 

874,151

 

 

 

864,596

 

Other

 

 

 

527,820

 

 

 

494,414

 

Goodwill

 

 

 

82,190

 

 

 

82,190

 

Total assets

 

 

 

$

10,298,569

 

 

 

$

10,149,132

 

 

 

 

 

 

 

 

 

 

 

Liabilities and shareholders’ equity

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

Accounts payable

 

 

 

$

253,096

 

 

 

$

212,379

 

Interest and dividends payable

 

 

 

26,358

 

 

 

26,258

 

Deposit liabilities

 

 

 

4,312,620

 

 

 

4,229,916

 

Short-term borrowings—other than bank

 

 

 

133,937

 

 

 

83,693

 

Other bank borrowings

 

 

 

193,233

 

 

 

195,926

 

Long-term debt, net—other than bank

 

 

 

1,422,875

 

 

 

1,422,872

 

Deferred income taxes

 

 

 

459,249

 

 

 

439,329

 

Regulatory liabilities

 

 

 

325,527

 

 

 

322,074

 

Contributions in aid of construction

 

 

 

415,795

 

 

 

405,520

 

Retirement benefits liability

 

 

 

643,104

 

 

 

656,394

 

Other

 

 

 

471,217

 

 

 

526,613

 

Total liabilities

 

 

 

8,657,011

 

 

 

8,520,974

 

 

 

 

 

 

 

 

 

 

 

Preferred stock of subsidiaries - not subject to mandatory redemption

 

 

 

34,293

 

 

 

34,293

 

Commitments and contingencies (Notes 3 and 4)

 

 

 

 

 

 

 

 

 

Shareholders’ equity

 

 

 

 

 

 

 

 

 

Preferred stock, no par value, authorized 10,000,000 shares; issued: none

 

 

 

 

 

 

 

Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 98,471,405 shares in 2013 and 97,928,403 shares in 2012

 

 

 

1,413,700

 

 

 

1,403,484

 

Retained earnings

 

 

 

220,049

 

 

 

216,804

 

Accumulated other comprehensive income (loss), net of taxes

 

 

 

 

 

 

 

 

 

Net unrealized gains on securities

 

$

9,933

 

 

 

$

10,761

 

 

 

Unrealized losses on derivatives

 

(701

)

 

 

(760

)

 

 

Retirement benefit plans

 

(35,716

)

(26,484

)

(36,424

)

(26,423

)

Total shareholders’ equity

 

 

 

1,607,265

 

 

 

1,593,865

 

Total liabilities and shareholders’ equity

 

 

 

$

10,298,569

 

 

 

$

10,149,132

 

 

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

 

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Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Shareholders’ Equity (unaudited)

 

 

 

Common stock

 

Retained

 

Accumulated
other
comprehensive

 

 

 

(in thousands, except per share amounts)

 

Shares

 

Amount

 

Earnings

 

loss

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2012

 

97,928

 

$

1,403,484

 

$

216,804

 

$

(26,423

)

$

1,593,865

 

Net income for common stock

 

 

 

33,679

 

 

33,679

 

Other comprehensive loss, net of tax benefits

 

 

 

 

(61

)

(61

)

Issuance of common stock, net

 

543

 

10,216

 

 

 

10,216

 

Common stock dividends ($0.31 per share)

 

 

 

(30,434

)

 

(30,434

)

Balance, March 31, 2013

 

98,471

 

$

1,413,700

 

$

220,049

 

$

(26,484

)

$

1,607,265

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2011

 

96,038

 

$

1,349,446

 

$

198,397

 

$

(19,137

)

$

1,528,706

 

Net income for common stock

 

 

 

38,316

 

 

38,316

 

Other comprehensive income, net of taxes

 

 

 

 

311

 

311

 

Issuance of common stock, net

 

503

 

13,434

 

 

 

13,434

 

Dividend equivalents paid on equity-classified awards

 

 

 

(95

)

 

(95

)

Common stock dividends ($0.31 per share)

 

 

 

(29,817

)

 

(29,817

)

Balance, March 31, 2012

 

96,541

 

$

1,362,880

 

$

206,801

 

$

(18,826

)

$

1,550,855

 

 

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

 

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Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net income

 

$

34,152

 

$

38,789

 

Adjustments to reconcile net income to net cash provided by (used in) operating activities

 

 

 

 

 

Depreciation of property, plant and equipment

 

39,726

 

37,911

 

Other amortization

 

935

 

1,419

 

Provision for loan losses

 

1,858

 

3,546

 

Loans receivable originated and purchased, held for sale

 

(79,224

)

(89,087

)

Proceeds from sale of loans receivable, held for sale

 

102,254

 

85,252

 

Change in deferred income taxes

 

19,967

 

21,260

 

Change in excess tax benefits from share-based payment arrangements

 

(414

)

(44

)

Allowance for equity funds used during construction

 

(1,215

)

(1,940

)

Changes in assets and liabilities

 

 

 

 

 

Decrease in accounts receivable and unbilled revenues, net

 

14,335

 

37,562

 

Increase in fuel oil stock

 

(29,272

)

(14,458

)

Increase in regulatory assets

 

(17,746

)

(13,948

)

Increase (decrease) in accounts, interest and dividends payable

 

38,148

 

(36,991

)

Change in prepaid and accrued income taxes and utility revenue taxes

 

(50,933

)

(41,126

)

Contributions to defined benefit pension and other postretirement benefit plans

 

(21,476

)

(26,815

)

Change in other assets and liabilities

 

(2,776

)

(17,046

)

Net cash provided by (used in) operating activities

 

48,319

 

(15,716

)

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

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

 

(26,705

)

(53,931

)

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

 

36,504

 

46,355

 

Net increase in loans held for investment

 

(66,934

)

(34,212

)

Proceeds from sale of real estate acquired in settlement of loans

 

3,046

 

3,371

 

Capital expenditures

 

(71,041

)

(65,300

)

Contributions in aid of construction

 

11,710

 

22,855

 

Other

 

869

 

 

Net cash used in investing activities

 

(112,551

)

(80,862

)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Net increase in deposit liabilities

 

82,704

 

55,172

 

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

 

50,244

 

87,467

 

Net decrease in retail repurchase agreements

 

(2,680

)

(379

)

Proceeds from issuance of long-term debt

 

50,000

 

 

Repayment of long-term debt

 

(50,000

)

(57,500

)

Change in excess tax benefits from share-based payment arrangements

 

414

 

44

 

Net proceeds from issuance of common stock

 

4,703

 

5,940

 

Common stock dividends

 

(24,394

)

(23,855

)

Preferred stock dividends of subsidiaries

 

(473

)

(473

)

Other

 

(3,240

)

(3,757

)

Net cash provided by financing activities

 

107,278

 

62,659

 

Net increase (decrease) in cash and cash equivalents

 

43,046

 

(33,919

)

Cash and cash equivalents, beginning of period

 

219,662

 

270,265

 

Cash and cash equivalents, end of period

 

$

262,708

 

$

236,346

 

 

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

 

5



Table of Contents

 

Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1 · Basis of presentation

 

The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto in HEI’s Form 10-K for the year ended December 31, 2012.

 

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of March 31, 2013 and December 31, 2012 and the results of its operations and cash flows for the three months ended March 31, 2013 and 2012. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

 

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Table of Contents

 

2 · Segment financial information

 

(in thousands) 

 

Electric utility

 

Bank

 

Other

 

Total

 

 

 

 

 

 

 

 

 

 

 

Three months ended March 31, 2013

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

719,267

 

$

64,756

 

$

41

 

$

784,064

 

Intersegment revenues (eliminations)

 

6

 

 

(6

)

 

Revenues

 

719,273

 

64,756

 

35

 

784,064

 

Income (loss) before income taxes

 

39,322

 

21,752

 

(8,260

)

52,814

 

Income taxes (benefit)

 

14,394

 

7,597

 

(3,329

)

18,662

 

Net income (loss)

 

24,928

 

14,155

 

(4,931

)

34,152

 

Preferred stock dividends of subsidiaries

 

499

 

 

(26

)

473

 

Net income (loss) for common stock

 

24,429

 

14,155

 

(4,905

)

33,679

 

Assets (at March 31, 2013)

 

5,174,235

 

5,116,385

 

7,949

 

10,298,569

 

 

 

 

 

 

 

 

 

 

 

Three months ended March 31, 2012

 

 

 

 

 

 

 

 

 

Revenues from external customers

 

$

749,574

 

$

65,252

 

$

34

 

$

814,860

 

Intersegment revenues (eliminations)

 

36

 

 

(36

)

 

Revenues

 

749,610

 

65,252

 

(2

)

814,860

 

Income (loss) before income taxes

 

45,207

 

23,464

 

(8,584

)

60,087

 

Income taxes (benefit)

 

17,408

 

7,587

 

(3,697

)

21,298

 

Net income (loss)

 

27,799

 

15,877

 

(4,887

)

38,789

 

Preferred stock dividends of subsidiaries

 

499

 

 

(26

)

473

 

Net income (loss) for common stock

 

27,300

 

15,877

 

(4,861

)

38,316

 

Assets (at December 31, 2012)

 

5,108,793

 

5,041,673

 

(1,334

)

10,149,132

 

 

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.

 

3 · Electric utility subsidiary

 

For consolidated HECO financial information, including its commitments and contingencies, see HECO’s consolidated financial statements beginning on page 27 through Note 10 on page 40.

 

7



Table of Contents

 

4 · Bank subsidiary

Selected financial information

 

American Savings Bank, F.S.B.

Statements of Income Data

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Interest income

 

 

 

 

 

Interest and fees on loans

 

$

42,603

 

$

44,888

 

Interest on investment and mortgage-related securities

 

3,464

 

3,805

 

Total interest income

 

46,067

 

48,693

 

Interest expense

 

 

 

 

 

Interest on deposit liabilities

 

1,312

 

1,779

 

Interest on other borrowings

 

1,164

 

1,261

 

Total interest expense

 

2,476

 

3,040

 

Net interest income

 

43,591

 

45,653

 

Provision for loan losses

 

1,858

 

3,546

 

Net interest income after provision for loan losses

 

41,733

 

42,107

 

Noninterest income

 

 

 

 

 

Fees from other financial services

 

7,643

 

7,337

 

Fee income on deposit liabilities

 

4,314

 

4,278

 

Fee income on other financial products

 

1,794

 

1,549

 

Gain on sale of loans

 

3,346

 

2,035

 

Other income, net

 

1,592

 

1,360

 

Total noninterest income

 

18,689

 

16,559

 

Noninterest expense

 

 

 

 

 

Compensation and employee benefits

 

20,088

 

18,646

 

Occupancy

 

4,123

 

4,225

 

Data processing

 

2,987

 

2,111

 

Services

 

2,103

 

1,783

 

Equipment

 

1,774

 

1,730

 

Other expense

 

7,595

 

6,707

 

Total noninterest expense

 

38,670

 

35,202

 

Income before income taxes

 

21,752

 

23,464

 

Income taxes

 

7,597

 

7,587

 

Net income

 

$

14,155

 

$

15,877

 

 

American Savings Bank, F.S.B.

Statements of Comprehensive Income Data

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

14,155

 

$

15,877

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

Net unrealized losses on securities:

 

 

 

 

 

Net unrealized losses on securities arising during the period, net of tax benefits, of $547and $149 for the three months ended March 31, 2013 and 2012, respectively

 

(828

)

(226

)

Retirement benefit plans:

 

 

 

 

 

Less: amortization of prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $1,424 and $164 for the three months ended March 31, 2013 and 2012, respectively

 

2,157

 

248

 

Other comprehensive income, net of taxes

 

1,329

 

22

 

Comprehensive income

 

$

15,484

 

$

15,899

 

 

8



Table of Contents

 

American Savings Bank, F.S.B.

Balance Sheets Data

 

 

(in thousands)

 

 

 

March 31,
2013

 

 

 

December 31,
2012

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

$

224,870

 

 

 

$

184,430

 

Available-for-sale investment and mortgage-related securities

 

 

 

659,400

 

 

 

671,358

 

Investment in stock of Federal Home Loan Bank of Seattle

 

 

 

95,152

 

 

 

96,022

 

Loans receivable held for investment

 

 

 

3,845,732

 

 

 

3,779,218

 

Allowance for loan losses

 

 

 

(42,730

)

 

 

(41,985

)

Loans receivable held for investment, net

 

 

 

3,803,002

 

 

 

3,737,233

 

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

 

 

 

5,351

 

 

 

26,005

 

Other

 

 

 

246,420

 

 

 

244,435

 

Goodwill

 

 

 

82,190

 

 

 

82,190

 

Total assets

 

 

 

$

5,116,385

 

 

 

$

5,041,673

 

Liabilities and shareholder’s equity

 

 

 

 

 

 

 

 

 

Deposit liabilities—noninterest-bearing

 

 

 

$

1,223,921

 

 

 

$

1,164,308

 

Deposit liabilities—interest-bearing

 

 

 

3,088,699

 

 

 

3,065,608

 

Other borrowings

 

 

 

193,233

 

 

 

195,926

 

Other

 

 

 

106,337

 

 

 

117,752

 

Total liabilities

 

 

 

4,612,190

 

 

 

4,543,594

 

Commitments and contingencies (see “Litigation” below)

 

 

 

 

 

 

 

 

 

Common stock

 

 

 

334,344

 

 

 

333,712

 

Retained earnings

 

 

 

183,918

 

 

 

179,763

 

Accumulated other comprehensive income (loss), net of taxes

 

 

 

 

 

 

 

 

 

Net unrealized gains on securities

 

$

9,933

 

 

 

$

10,761

 

 

 

Retirement benefit plans

 

(24,000

)

(14,067

)

(26,157

)

(15,396

)

Total shareholder’s equity

 

 

 

504,195

 

 

 

498,079

 

Total liabilities and shareholder’s equity

 

 

 

$

5,116,385

 

 

 

$

5,041,673

 

 

 

 

 

 

 

 

 

 

 

Other assets

 

 

 

 

 

 

 

 

 

Bank-owned life insurance

 

 

 

$

126,798

 

 

 

$

125,726

 

Premises and equipment, net

 

 

 

64,217

 

 

 

62,458

 

Prepaid expenses

 

 

 

13,189

 

 

 

13,199

 

Accrued interest receivable

 

 

 

13,773

 

 

 

13,228

 

Mortgage-servicing rights

 

 

 

11,400

 

 

 

10,818

 

Real estate acquired in settlement of loans, net

 

 

 

3,785

 

 

 

6,050

 

Other

 

 

 

13,258

 

 

 

12,956

 

 

 

 

 

$

246,420

 

 

 

$

244,435

 

Other liabilities

 

 

 

 

 

 

 

 

 

Accrued expenses

 

 

 

$

13,723

 

 

 

$

17,103

 

Federal and state income taxes payable

 

 

 

42,205

 

 

 

35,408

 

Cashier’s checks

 

 

 

21,810

 

 

 

23,478

 

Advance payments by borrowers

 

 

 

6,443

 

 

 

9,685

 

Other

 

 

 

22,156

 

 

 

32,078

 

 

 

 

 

$

106,337

 

 

 

$

117,752

 

 

Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.

 

9



Table of Contents

 

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $143 million and $50 million, respectively, as of March 31, 2013 and $146 million and $50 million, respectively, as of December 31, 2012.

 

Securities sold under agreements to repurchase are accounted for as financing transactions and the obligations to repurchase these securities are recorded as liabilities in the balance sheet. All such agreements are subject to master netting arrangements, which provide for conditional right of set-off in case of default by either party; however, ASB presents securities sold under agreements to repurchase on a gross basis in the balance sheet. The following tables present information about the securities sold under agreements to repurchase, including the related collateral received from or pledged to counterparties:

 

(in millions)

 

Gross amount of
recognized liabilities

 

Gross amount offset in
the Balance Sheet

 

Net amount of liabilities presented
in the Balance Sheet

 

Repurchase agreements

 

 

 

 

 

 

 

March 31, 2013

 

$

143

 

$

 

$

143

 

December 31, 2012

 

146

 

 

146

 

 

 

 

Gross amount not offset in the Balance Sheet

 

(in millions)

 

Net amount of liabilities presented
in the Balance Sheet

 

Financial
instruments

 

Cash
collateral
pledged

 

Net amount

 

March 31, 2013

 

 

 

 

 

 

 

 

 

Financial institution

 

$

50

 

$

50

 

$

 

$

 

Commercial account holders

 

93

 

93

 

 

 

Total

 

$

143

 

$

143

 

$

 

$

 

December 31, 2012

 

 

 

 

 

 

 

 

 

Financial institution

 

$

50

 

$

50

 

$

 

$

 

Commercial account holders

 

96

 

96

 

 

 

Total

 

$

146

 

$

146

 

$

 

$

 

 

Investment and mortgage-related securities portfolio.

 

Available-for-sale securities.  The book value (amortized cost), gross unrealized gains and losses, estimated fair value and gross unrealized losses (fair value and amount by duration of time in which positions have been held in a continuous loss position) for securities held in ASB’s “available-for-sale” portfolio by major security type were as follows:

 

 

 

 

 

Gross

 

Gross

 

Estimated

 

Gross unrealized losses

 

 

 

Amortized

 

unrealized

 

unrealized

 

fair

 

Less than 12 months

 

12 months or longer

 

(in thousands)

 

cost

 

gains

 

losses

 

value

 

Fair value

 

Amount

 

Fair value

 

Amount

 

March 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal agency obligations

 

$

165,402

 

$

2,606

 

$

(48

)

$

167,960

 

$

12,025

 

$

(48

)

$

 

$

 

Mortgage-related securities- FNMA, FHLMC and GNMA

 

399,784

 

10,061

 

(506

)

409,339

 

66,595

 

(506

)

 

 

Municipal bonds

 

77,723

 

4,378

 

 

82,101

 

 

 

 

 

 

 

$

642,909

 

$

17,045

 

$

(554

)

$

659,400

 

$

78,620

 

$

(554

)

$

 

$

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

)

$

 

$

 

 

The unrealized losses on ASB’s investments in mortgage-related securities and obligations issued by federal agencies were caused by interest rate movements. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost basis of the investments. Because ASB does

 

10



Table of Contents

 

not intend to sell the securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of their amortized costs basis, which may be at maturity, ASB did not consider these investments to be other-than-temporarily impaired at March 31, 2013.

 

The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.

 

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

 

March 31, 2013

 

Amortized cost

 

Fair value

 

(in thousands)

 

 

 

 

 

Due in one year or less

 

$

68,120

 

$

68,635

 

Due after one year through five years

 

63,839

 

65,258

 

Due after five years through ten years

 

78,211

 

82,977

 

Due after ten years

 

32,955

 

33,191

 

 

 

243,125

 

250,061

 

Mortgage-related securities-FNMA,FHLMC and GNMA

 

399,784

 

409,339

 

Total available-for-sale securities

 

$

642,909

 

$

659,400

 

 

Allowance for loan losses.  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.

 

The allowance for loan losses (balances and changes) and financing receivables were as follows:

 

 

 

 

 

Commercial

 

Home

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

real

 

equity line

 

Residential

 

Commercial

 

Residential

 

Commercial

 

Consumer

 

 

 

 

 

(in thousands)

 

1-4 family

 

estate

 

of credit

 

land

 

construction

 

construction

 

loans

 

loans

 

Unallocated

 

Total

 

Three months ended March 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for loan losses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning balance

 

$

6,068

 

$

2,965

 

$

4,493

 

$

4,275

 

$

2,023

 

$

9

 

$

15,931

 

$

4,019

 

$

2,202

 

$

41,985

 

Charge-offs

 

(210

)

 

(670

)

(227

)

 

 

(426

)

(645

)

 

(2,178

)

Recoveries

 

192

 

 

194

 

137

 

 

 

392

 

150

 

 

1,065

 

Provision

 

(39

)

3,691

 

540

 

(1,442

)

(151

)

3

 

(934

)

131

 

59

 

1,858

 

Ending balance

 

$

6,011

 

$

6,656

 

$

4,557

 

$

2,743

 

$

1,872

 

$

12

 

$

14,963

 

$

3,655

 

$

2,261

 

$

42,730

 

Ending balance: individually evaluated for impairment

 

$

454

 

$

3,169

 

$

 

$

1,943

 

$

 

$

 

$

2,285

 

$

 

$

 

$

7,851

 

Ending balance: collectively evaluated for impairment

 

$

5,557

 

$

3,487

 

$

4,557

 

$

800

 

$

1,872

 

$

12

 

$

12,678

 

$

3,655

 

$

2,261

 

$

34,879

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Financing Receivables:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ending balance

 

$

1,915,207

 

$

391,679

 

$

648,904

 

$

23,894

 

$

40,698

 

$

8,275

 

$

699,918

 

$

127,260

 

$

 

$

3,855,835

 

Ending balance: individually evaluated for impairment

 

$

25,320

 

$

10,662

 

$

1,259

 

$

17,618

 

$

 

$

 

$

19,302

 

$

21

 

$

 

$

74,182

 

Ending balance: collectively evaluated for impairment

 

$

1,889,887

 

$

381,017

 

$

647,645

 

$

6,276

 

$

40,698

 

$

8,275

 

$

680,616

 

$

127,239

 

$

 

$

3,781,653

 

Year ended 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

 

 

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Credit quality.  ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit trends so that appropriate steps can be initiated to manage risk and avoid or minimize future losses. Loans subject to grading include commercial and industrial, commercial real estate and commercial construction loans.

 

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

 

The numerical representation of the risk categories are:

 

1- Substantially risk free

2- Minimal risk

3- Modest risk

4- Better than average risk

5- Average risk

6- Acceptable risk

7- Special mention

8- Substandard

9- Doubtful

10- Loss

 

Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral.

 

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

 

 

 

March 31, 2013

 

December 31, 2012

 

(in thousands)

 

Commercial
real estate

 

Commercial
construction

 

Commercial

 

Commercial
real estate

 

Commercial
construction

 

Commercial

 

Grade:

 

 

 

 

 

 

 

 

 

 

 

 

 

Pass

 

$

310,265

 

$

35,623

 

$

620,811

 

$

314,182

 

$

39,063

 

$

638,854

 

Special mention

 

36,381

 

 

13,601

 

25,437

 

4,925

 

24,511

 

Substandard

 

41,222

 

5,075

 

61,133

 

29,308

 

 

53,538

 

Doubtful

 

3,811

 

 

4,373

 

6,750

 

 

4,446

 

Loss

 

 

 

 

 

 

 

Total

 

$

391,679

 

$

40,698

 

$

699,918

 

$

375,677

 

$

43,988

 

$

721,349

 

 

12



Table of Contents

 

The credit risk profile based on payment activity for loans was as follows:

 

(in thousands)

 

30-59
days
past due

 

60-89
days
past due

 

Greater
than
90 days

 

Total
past due

 

Current

 

Total
financing
receivables

 

Recorded
investment>
90 days and
accruing

 

March 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

5,435

 

$

1,277

 

$

23,292

 

$

30,004

 

$

1,885,203

 

$

1,915,207

 

$

 

Commercial real estate

 

743

 

 

3,811

 

4,554

 

387,125

 

391,679

 

 

Home equity line of credit

 

649

 

371

 

1,323

 

2,343

 

646,561

 

648,904

 

 

Residential land

 

599

 

1,138

 

9,748

 

11,485

 

12,409

 

23,894

 

1,268

 

Commercial construction

 

 

 

 

 

40,698

 

40,698

 

 

Residential construction

 

 

 

 

 

8,275

 

8,275

 

 

Commercial loans

 

3,513

 

400

 

6,370

 

10,283

 

689,635

 

699,918

 

88

 

Consumer loans

 

567

 

250

 

402

 

1,219

 

126,041

 

127,260

 

272

 

Total loans

 

$

11,506

 

$

3,436

 

$

44,946

 

$

59,888

 

$

3,795,947

 

$

3,855,835

 

$

1,628

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

6,353

 

$

1,741

 

$

24,054

 

$

32,148

 

$

1,834,302

 

$

1,866,450

 

$

 

Commercial real estate

 

85

 

 

6,750

 

6,835

 

368,842

 

375,677

 

 

Home equity line of credit

 

1,077

 

142

 

1,319

 

2,538

 

627,637

 

630,175

 

 

Residential land

 

2,851

 

75

 

7,788

 

10,714

 

15,101

 

25,815

 

 

Commercial construction

 

 

 

 

 

43,988

 

43,988

 

 

Residential construction

 

 

 

 

 

6,171

 

6,171

 

 

Commercial loans

 

3,052

 

2,814

 

1,098

 

6,964

 

714,385

 

721,349

 

131

 

Consumer loans

 

598

 

348

 

424

 

1,370

 

119,861

 

121,231

 

242

 

Total loans

 

$

14,016

 

$

5,120

 

$

41,433

 

$

60,569

 

$

3,730,287

 

$

3,790,856

 

$

373

 

 

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

 

 

 

March 31, 2013

 

December 31, 2012

 

(in thousands)

 

Nonaccrual
loans

 

Accruing loans
90 days or
more past due

 

Nonaccrual
loans

 

Accruing loans
90 days or
more past due

 

Real estate loans:

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

25,578

 

$

 

$

26,721

 

$

 

Commercial real estate

 

10,663

 

 

6,750

 

 

Home equity line of credit

 

2,352

 

 

2,349

 

 

Residential land

 

9,249

 

1,268

 

8,561

 

 

Commercial construction

 

 

 

 

 

Residential construction

 

 

 

 

 

Commercial loans

 

19,305

 

88

 

20,222

 

131

 

Consumer loans

 

281

 

272

 

284

 

242

 

Total

 

$

67,428

 

$

1,628

 

$

64,887

 

$

373

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2013

 

December 31, 2012

 

(in thousands)

 

Recorded
investment

 

Unpaid
principal
balance

 

Related
Allowance

 

Average
recorded
investment

 

Interest
income
recognized*

 

Recorded
investment

 

Unpaid
principal
balance

 

Related
allowance

 

Average
recorded
investment

 

Interest
income
recognized*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

With no related allowance recorded

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

14,815

 

$

20,228

 

$

 

$

14,756

 

$

134

 

$

14,633

 

$

20,247

 

$

 

$

16,688

 

$

294

 

Commercial real estate

 

 

 

 

3,207

 

 

2,929

 

2,929

 

 

7,771

 

237

 

Home equity line of credit

 

732

 

1,444

 

 

655

 

 

581

 

1,374

 

 

632

 

1

 

Residential land

 

9,141

 

11,535

 

 

7,833

 

97

 

7,691

 

10,624

 

 

21,589

 

1,185

 

Commercial construction

 

 

 

 

 

 

 

 

 

 

 

Residential construction

 

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

4,573

 

8,175

 

 

4,220

 

 

4,265

 

6,994

 

 

24,605

 

986

 

Consumer loans

 

21

 

21

 

 

21

 

 

21

 

21

 

 

23

 

 

 

 

29,282

 

41,403

 

 

30,692

 

231

 

30,120

 

42,189

 

 

71,308

 

2,703

 

With an allowance recorded

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

5,442

 

5,442

 

454

 

5,008

 

101

 

4,803

 

4,803

 

384

 

4,204

 

250

 

Commercial real estate

 

10,662

 

10,739

 

3,169

 

6,100

 

 

3,821

 

3,840

 

535

 

1,295

 

 

Home equity line of credit

 

 

 

 

 

 

 

 

 

26

 

 

Residential land

 

7,013

 

7,140

 

1,943

 

8,886

 

113

 

9,984

 

10,364

 

3,221

 

7,428

 

575

 

Commercial construction

 

 

 

 

 

 

 

 

 

 

 

Residential construction

 

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

14,729

 

15,775

 

2,285

 

15,221

 

5

 

16,033

 

16,912

 

2,659

 

8,429

 

23

 

Consumer loans

 

 

 

 

 

 

 

 

 

 

 

 

 

37,846

 

39,096

 

7,851

 

35,215

 

219

 

34,641

 

35,919

 

6,799

 

21,382

 

848

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Real estate loans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

20,257

 

25,670

 

454

 

19,764

 

235

 

19,436

 

25,050

 

384

 

20,892

 

544

 

Commercial real estate

 

10,662

 

10,739

 

3,169

 

9,307

 

 

6,750

 

6,769

 

535

 

9,066

 

237

 

Home equity line of credit

 

732

 

1,444

 

 

655

 

 

581

 

1,374

 

 

658

 

1

 

Residential land

 

16,154

 

18,675

 

1,943

 

16,719

 

210

 

17,675

 

20,988

 

3,221

 

29,017

 

1,760

 

Commercial construction

 

 

 

 

 

 

 

 

 

 

 

Residential construction

 

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

19,302

 

23,950

 

2,285

 

19,441

 

5

 

20,298

 

23,906

 

2,659

 

33,034

 

1,009

 

Consumer loans

 

21

 

21

 

 

21

 

 

21

 

21

 

 

23

 

 

 

 

$

67,128

 

$

80,499

 

$

7,851

 

$

65,907

 

$

450

 

$

64,761

 

$

78,108

 

$

6,799

 

$

92,690

 

$

3,551

 

 


*                   Since loan was classified as impaired.

 

Troubled debt restructurings.  A loan modification is deemed to be a troubled debt restructuring (TDR) when ASB grants a concession it would not otherwise consider were it not for the borrower’s financial difficulty.  When a borrower experiencing financial difficulty fails to make a required payment on a loan or is in imminent default, ASB takes a number of steps to improve the collectability of the loan and maximize the likelihood of full repayment. At times, ASB may modify or restructure a loan to help a distressed borrower improve its financial position to eventually be able to fully repay the loan, provided the borrower has demonstrated both the willingness and the ability to fulfill the modified terms. TDR loans are considered an alternative to foreclosure or liquidation with the goal of minimizing losses to ASB and maximizing recovery.

 

ASB may consider various types of concessions in granting a TDR including maturity date extensions, extended amortization of principal, temporary deferral of principal payments, and temporary interest rate reductions. ASB rarely grants principal forgiveness in its TDR modifications. Residential loan modifications generally involve interest rate reduction, extending the amortization period, or capitalizing certain delinquent amounts owed not to exceed the original loan balance. Land loans at origination are typically structured as a three-year term, interest-only monthly payment with a balloon payment due at maturity. Land loan TDR modifications typically involve extending the maturity date up to five years and converting the payments from interest-only to principal and interest monthly, at the same or higher interest rate. Commercial loan modifications generally involve extensions of maturity dates, extending the

 

14



Table of Contents

 

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 impairment amount is an increase to the allowance associated with the modified loan. When available information confirms that specific loans or portions thereof are uncollectible (confirmed losses), these amounts are charged off against the allowance for loan losses.

 

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

 

 

 

Three months ended March 31, 2013

 

Three months ended March 31, 2012

 

 

 

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

 

4

 

$

1,122

 

$

1,063

 

7

 

$

1,413

 

$

1,410

 

Commercial real estate

 

 

 

 

 

 

 

Home equity line of credit

 

4

 

462

 

215

 

 

 

 

Residential land

 

3

 

924

 

868

 

7

 

1,734

 

1,441

 

Commercial loans

 

 

 

 

6

 

160

 

160

 

Consumer loans

 

 

 

 

 

 

 

 

 

11

 

$

2,508

 

$

2,146

 

20

 

$

3,307

 

$

3,011

 

 

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

 

 

 

Three months ended March 31, 2013

 

Three months ended March 31, 2012

 

(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

 

 

 

 

 

Commercial loans

 

 

 

4

 

879

 

Consumer loans

 

 

 

 

 

 

 

 

$

 

4

 

$

879

 

 

For 2012, the four commercial loans that subsequently defaulted were modified by extending the maturity date and deferring principal payments for a short period of time. There are no commitments to lend additional funds to borrowers whose loan terms have been impaired or modified in TDRs as of March 31, 2013.

 

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.

 

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 · Retirement benefits

 

Defined benefit pension and other postretirement benefit plans information.  For the first three months of 2013, the Company contributed $21 million (primarily by the utilities) to its pension and other postretirement benefit plans, compared to $27 million (primarily by the utilities) in the first three months of 2012. The Company’s current estimate of contributions to its pension and other postretirement benefit plans in 2013 is $86 million ($84 million by the utilities, $2 million by HEI and nil by ASB), compared to $78 million ($63 million by the utilities, $2 million by HEI

 

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and $13 million by ASB) in 2012. In addition, the Company expects to pay directly $2 million ($1 million each by the utilities and HEI) of benefits in 2013, compared to $1 million paid in 2012.

 

On July 6, 2012, President Obama signed the Moving Ahead for Progress in the 21st Century Act (MAP-21), which included provisions related to the funding and administration of pension plans. This law does not affect the Company’s accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The Company elected to apply MAP-21 for 2012, which improved the plans’ Adjusted Funding Target Attainment Percentage (AFTAP) for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HEI and HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under ERISA to be less than the net periodic cost for 2013 and 2014; therefore, the Company expects to contribute the net periodic cost for these years. If the AFTAP 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. The HEI Retirement Plan fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

 

The components of net periodic benefit cost for consolidated HEI were as follows:

 

 

 

Pension benefits

 

Other benefits

 

Three months ended March 31

 

2013

 

2012

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

14,089

 

$

10,191

 

$

1,049

 

$

1,096

 

Interest cost

 

16,106

 

16,771

 

1,931

 

2,281

 

Expected return on plan assets

 

(18,085

)

(17,856

)

(2,562

)

(2,621

)

Amortization of prior service gain

 

(24

)

(81

)

(448

)

(448

)

Amortization of net actuarial loss

 

9,819

 

6,423

 

521

 

453

 

Net periodic benefit cost

 

21,905

 

15,448

 

491

 

761

 

Impact of PUC D&Os

 

(7,436

)

(3,857

)

(397

)

(680

)

Net periodic benefit cost (adjusted for impact of PUC D&Os)

 

$

14,469

 

$

11,591

 

$

94

 

$

81

 

 

Consolidated HEI recorded retirement benefits expense of $11 million and $8 million in the first quarters of 2013 and 2012, respectively, and charged the remaining amounts primarily to electric utility plant.

 

The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

 

Defined contribution plans information.  For the first quarters of 2013 and 2012, the Company’s expense for its defined contribution pension plans under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) and the ASB 401(k) Plan was $1.0 million and $0.9 million, respectively, and cash contributions were $2.4 million and $2.2 million, respectively.

 

6 · Share-based compensation

 

Under the 2010 Equity and Incentive Plan (EIP), HEI can 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.

 

As of March 31, 2013, there were 3.6 million shares remaining available for future issuance under the EIP of which an estimated 2.7 million shares could be issued upon the vesting of outstanding restricted stock units and the achievement of performance goals under long-term incentive plans (based on the assumption that long-term incentive plan (LTIP) awards are achieved at maximum levels).

 

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 25,000 shares of common stock (based on the March 31, 2013 market price of shares as the price on the exercise

 

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dates) were outstanding as of March 31, 2013 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs) 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.

 

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

 

Three months ended March 31

 

2013

 

2012

 

(in millions)

 

 

 

 

 

 

 

 

 

 

 

Share-based compensation expense (1)

 

$

1.9

 

$

1.8

 

Income tax benefit

 

0.7

 

0.6

 

 


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

 

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

 

March 31, 2013

 

Outstanding & Exercisable (Vested)

 

Year of
grant

 

Range of
exercise prices

 

Number
of options

 

Weighted-average
remaining
contractual life

 

Weighted-average
exercise price

 

 

 

 

 

 

 

 

 

 

 

2003

 

$

20.49

 

12,000

 

0.1

 

$

20.49

 

 

As of December 31, 2012, NQSOs outstanding totaled 14,000 (representing the same number of underlying shares), with a weighted-average exercise price of $20.49. As of March 31, 2013, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.1 million.

 

NQSO activity and statistics were as follows:

 

Three months ended March 31

 

2013

 

2012

 

(dollars in thousands, except prices)

 

 

 

 

 

 

 

 

 

 

 

Shares exercised

 

2,000

 

12,000

 

Weighted-average exercise price

 

$

20.49

 

$

21.68

 

Cash received from exercise

 

$

41

 

$

260

 

Intrinsic value of shares exercised (1)

 

$

15

 

$

91

 

Tax benefit realized for the deduction of exercises

 

$

6

 

$

36

 

 


(1)                                 Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

 

Stock appreciation rights.  Information about HEI’s SARs was as follows:

 

March 31, 2013

 

Outstanding & Exercisable (Vested)

 

Year of
grant

 

Range of
exercise prices

 

Number of shares
underlying SARs

 

Weighted-average
remaining
contractual life

 

Weighted-average
exercise price

 

 

 

 

 

 

 

 

 

 

 

2004

 

$

26.02

 

62,000

 

1.1

 

$

26.02

 

2005

 

26.18

 

102,000

 

2.0

 

26.18

 

 

 

$

26.02 –26.18

 

164,000

 

1.7

 

$

26.12

 

 

As of December 31, 2012, the shares underlying SARs outstanding totaled 164,000, with a weighted-average exercise price of $26.12. As of March 31, 2013, all SARs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalent rights) of $0.3 million.

 

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

 

 

 

2013

 

2012

 

Three months ended March 31

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

Outstanding, beginning of period

 

9,005

 

$

22.21

 

46,807

 

$

24.45

 

Granted

 

 

 

 

 

Vested

 

 

 

(8,700

)

27.17

 

Forfeited

 

 

 

 

 

Outstanding, end of period

 

9,005

 

$

22.21

 

38,107

 

$

23.83

 

 


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

 

As of March 31, 2013, there was $0.2 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 1.7 years.

 

For the first quarter of 2012, total restricted stock vested had a grant-date fair value of $0.2 million and the tax benefits realized for tax deductions related to restricted stock awards were $0.1 million.

 

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

 

 

 

2013

 

2012

 

Three months ended March 31

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

Outstanding, beginning of period

 

315,094

 

$

22.82

 

247,286

 

$

21.80

 

Granted

 

107,231

(2)

26.89

 

92,512

(3)

25.98

 

Vested

 

(113,212

)

20.30

 

(21,247

)

24.95

 

Forfeited

 

(7,968

)

25.26

 

 

 

Outstanding, end of period

 

301,145

 

$

25.15

 

318,551

 

$

22.80

 

 


(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 $2.9 million.

(3)         Total weighted-average grant-date fair value of $2.4 million.

 

As of March 31, 2013, there was $5.4 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 3 years.

 

For the first quarters of 2013 and 2012, total restricted stock units that vested and related dividends had a grant-date fair value of $3.5 million and $0.6 million, respectively, and the related tax benefits were $1.1 million and $0.2 million, respectively.

 

LTIP payable in stock.  The 2011-2013 LTIP, 2012-2014 LTIP and the 2013-2015 LTIP provide for performance awards under the EIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The potential payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for the LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2011-2013 LTIP, the 2012-2014 LTIP and the 2013-2015 LTIP have performance goals related to levels of HEI consolidated net income, HEI consolidated return on common equity (ROACE), HECO consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on the applicable three-year averages.

 

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

 

 

 

2013

 

2012

 

Three months ended March 31

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

Outstanding, beginning of period

 

239,256

 

$

29.12

 

197,385

 

$

25.94

 

Granted

 

89,533

 

32.69

 

77,482

(2)

30.71

 

Vested

 

(87,753

)

22.45

 

(35,397

)

14.85

 

Forfeited

 

(5,972

)

32.96

 

 

 

Outstanding, end of period

 

235,064

 

$

32.87

 

239,470

 

$

29.12

 

 


(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 $2.4 million.

 

On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 89,533 shares of HEI common stock (based on the grant date price of $26.89 and target TRS performance levels) with a weighted-average grant date fair value of $2.9 million based on the weighted-average grant date fair value per share of $32.69.

 

The following table summarizes the assumptions used to determine the fair value of the LTIP awards linked to TRS and the resulting fair value of LTIP awards granted:

 

 

 

2013

 

2012

 

Risk-free interest rate

 

0.38

%

0.33

%

Expected life in years

 

3

 

3

 

Expected volatility

 

19.4

%

25.3

%

Range of expected volatility for Peer Group

 

12.4% to 25.3

%

15.5% to 34.5

%

Grant date fair value (per share)

 

$

32.69

 

$

30.71

 

 

For the three months ended March 31, 2013 and 2012, total vested LTIP awards linked to TRS and related dividends had a fair value of $2.2 million and $0.6 million, respectively, and the related tax benefits were $0.9 million and $0.2 million, respectively.

 

As of March 31, 2013, there was $4.1 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.8 years.

 

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

 

 

 

2013

 

2012

 

Three months ended March 31

 

Shares

 

(1)

 

Shares

 

(1)

 

 

 

 

 

 

 

 

 

 

 

Outstanding, beginning of period

 

247,175

 

$

25.04

 

182,498

 

$

22.63

 

Granted

 

118,895

 

26.89

 

115,104

(2)

25.98

 

Vested

 

(18,275

)

18.95

 

 

 

Forfeited

 

(5,971

)

25.94

 

 

 

Outstanding, end of period

 

341,824

 

$

26.00

 

297,602

 

$

23.92

 

 


(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 $3 million (at target performance levels).

 

On February 4, 2013, LTIP grants (under the 2013-2015 LTIP) were made payable in 118,895 shares of HEI common stock (based on the grant date price of $26.89 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.2 million based on the weighted-average grant date fair value per share of $26.89.

 

For the three months ended March 31, 2013, total vested LTIP awards linked to other performance conditions and related dividends had a fair value of $0.6 million and the related tax benefits were $0.2 million.

 

As of March 31, 2013, there was $5.4 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 1.8 years.

 

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7 · Earnings per share and shareholders’ equity

 

Earnings per share.  Under the two-class method of computing earnings per share (EPS), EPS was comprised as follows for both participating securities and unrestricted common stock:

 

 

 

2013

 

2012

 

Three months ended March 31

 

Basic and
diluted

 

Basic and
diluted

 

Distributed earnings

 

$

0.31

 

$

0.31

 

Undistributed earnings (loss)

 

0.03

 

0.09

 

 

 

$

0.34

 

$

0.40

 

 

As of March 31, 2013, there were no shares that were antidilutive. As of March 31, 2012 the antidilutive effects of SARs of 210,000 shares of HEI common stock, for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of diluted EPS.

 

Shareholders’ equity.

 

Equity forward transaction.  On March 19, 2013, HEI entered into an equity forward transaction in connection with a public offering of 6.1 million shares of HEI common stock. On March 20, 2013, the underwriters exercised their over-allotment option in full and HEI entered into an equity forward transaction in connection with 0.9 million shares of HEI common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with the Company’s capital investment plans.

 

Pursuant to the terms of these transactions, a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and sold them to a group of underwriters for $26.75 per share, less an underwriting discount equal to $1.00312 per share. Under the terms of the equity forward transactions, to the extent that the transactions are physically settled, HEI would be required to issue and deliver shares of HEI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $25.74688 per share at the time the equity forward transactions were entered into, and the amount of cash to be received by HEI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transactions. The equity forward transactions must be settled fully by March 25, 2015. Except in specified circumstances or events that would require physical settlement, HEI is able to elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to March 25, 2015.

 

The equity forward transactions had no initial fair value since they were entered into at the then market price of the common stock. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled, and at that time HEI will record the proceeds, if any, in equity. HEI concluded that the equity forward transactions were equity instruments based on the accounting guidance in ASC 480 and ASC 815 and that they qualified for an exception from derivative accounting under ASC 815 because the forward sale transactions were indexed to its own stock. HEI anticipates settling the equity forward transactions through physical settlement before March 25, 2015.

 

At March 31, 2013, the equity forward transactions could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $180 million. At March 31, 2013, the equity forward transactions could also have been cash settled, with delivery of cash of approximately $12 million (which amount includes $7 million of underwriting discount) to the forward counterparty, or net share settled with delivery of approximately 440,000 shares of common stock to the forward counterparty.

 

Prior to their settlement, the equity forward transactions will be reflected in HEI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of HEI’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transactions less the number of shares that could be purchased by HEI in the market (based on the average market price during that reporting period)

 

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using the proceeds receivable upon settlement of the equity forward transactions (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transactions are outstanding.

 

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

 

For the three months ended March 31, 2013, the equity forward transactions did not have a material dilutive effect on HEI’s earnings per share.

 

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

 

 

 

Three months ended March 31

 

 

 

 

 

2013

 

2012

 

 

 

(in thousands)

 

Amount reclassified from AOCI

 

Affected line item in the Statement of Income

 

Unrealized gains and losses on securities

 

$

 

$

 

Revenues-bank (net gains on sales of securities)

 

Derivatives qualified as cash flow hedges

 

 

 

 

 

 

 

Interest rate contracts (settled in 2011)

 

59

 

59

 

Interest expense

 

Retirement benefit plan items

 

 

 

 

 

 

 

Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost

 

6,021

 

3,873

 

(See Note 5 for additional details)

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets

 

(5,313

)

(3,395

)

(See Note 5 for additional details)

 

Total reclassifications

 

$

767

 

$

537

 

 

 

 

8 · Commitments and contingencies

 

See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.

 

9 · 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 premium 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. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

 

The Company groups its financial assets measured at fair value in three levels outlined as follows:

 

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Level 1:                Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and is used to measure fair value whenever available.

 

Level 2:                Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

 

Level 3:                Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Deposit liabilities.  The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

 

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Other bank borrowings.  Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

 

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

 

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

 

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

 

 

 

Carrying or
notional

 

Estimated fair value

 

(in thousands)

 

amount

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2013

 

 

 

 

 

 

 

 

 

 

 

Financial assets

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

10

 

$

 

$

10

 

$

 

$

10

 

Available-for-sale investment and mortgage-related securities

 

659,400

 

 

659,400

 

 

659,400

 

Investment in stock of Federal Home Loan Bank of Seattle

 

95,152

 

 

95,152

 

 

95,152

 

Loans receivable, net

 

3,808,353

 

 

 

3,974,112

 

3,974,112

 

Financial liabilities

 

 

 

 

 

 

 

 

 

 

 

Deposit liabilities

 

4,312,620

 

 

4,317,805

 

 

4,317,805

 

Short-term borrowings—other than bank

 

133,937

 

 

133,937

 

 

133,937

 

Other bank borrowings

 

193,233

 

 

208,410

 

 

208,410

 

Long-term debt, net—other than bank

 

1,422,875

 

 

1,529,541

 

 

1,529,541

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

Financial assets

 

 

 

 

 

 

 

 

 

 

 

Money market funds

 

$

10

 

$

 

$

10

 

$

 

$

10

 

Available-for-sale investment and mortgage-related securities

 

671,358

 

 

671,358

 

 

671,358

 

Investment in stock of Federal Home Loan Bank of Seattle

 

96,022

 

 

96,022

 

 

96,022

 

Loans receivable, net

 

3,763,238

 

 

 

3,957,752

 

3,957,752

 

Financial liabilities

 

 

 

 

 

 

 

 

 

 

 

Deposit liabilities

 

4,229,916

 

 

4,235,527

 

 

4,235,527

 

Short-term borrowings—other than bank

 

83,693

 

 

83,693

 

 

83,693

 

Other bank borrowings

 

195,926

 

 

212,163

 

 

212,163

 

Long-term debt, net—other than bank

 

1,422,872

 

 

1,481,004

 

 

1,481,004

 

 

As of March 31, 2013 and December 31, 2012, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.6 billion and $1.5 billion, respectively, and their estimated fair value on such dates were $1.3 million and $1.2 million, respectively. As of March 31, 2013 and December 31, 2012, loans serviced by ASB for others had notional amounts of $1.3 billion and the estimated fair value of the servicing rights for such loans was $13.6 million and $11.9 million, respectively.

 

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

 

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nonperformance risk that market participants would use in pricing 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.

 

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

 

 

 

Fair value measurements using

 

 

 

Quoted prices in

 

Significant other

 

Significant

 

 

 

active markets
for identical

 

observable
 inputs

 

unobservable
inputs

 

(in thousands)

 

assets (Level 1)

 

(Level 2)

 

(Level 3)

 

March 31, 2013

 

 

 

 

 

 

 

Money market funds (“other” segment)

 

$

 

$

10

 

$

 

Available-for-sale securities (bank segment)

 

 

 

 

 

 

 

Mortgage-related securities-FNMA, FHLMC and GNMA

 

$

 

$

409,339

 

$

 

Federal agency obligations

 

 

167,960

 

 

Municipal bonds

 

 

82,101

 

 

 

 

$

 

$

659,400

 

$

 

December 31, 2012

 

 

 

 

 

 

 

Money market funds (“other” segment)

 

$

 

$

10

 

$

 

Available-for-sale securities (bank segment)

 

 

 

 

 

 

 

Mortgage-related securities-FNMA, FHLMC and GNMA

 

$

 

$

417,383

 

$

 

Federal agency obligations

 

 

171,491

 

 

Municipal bonds

 

 

82,484

 

 

 

 

$

 

$

671,358

 

$

 

 

Fair value measurements on a nonrecurring basis.  From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the writedowns of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments based on the current appraised value of the collateral securing the loans or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. During the first quarter of 2013, it was not required that a measurement of the fair value of goodwill be calculated and goodwill was not measured at fair value.

 

Assets measured at fair value on a nonrecurring basis were as follows:

 

 

 

 

 

 

 

 

 

Fair value measurements

 

(in millions) 

 

Balance

 

Level 1

 

Level 2

 

Level 3

 

Loans

 

 

 

 

 

 

 

 

 

March 31, 2013

 

$

21

 

$

 

$

 

$

21

 

December 31, 2012

 

21

 

 

 

21

 

Real estate acquired in settlement of loans

 

 

 

 

 

 

 

 

 

March 31, 2013

 

1

 

 

 

1

 

December 31, 2012

 

3

 

 

 

3

 

 

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

 

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

 

Home equity lines of 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

 

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placed on the assets of the business and cash flows generated by the business entity, and therefore, is classified as a Level 3 measurement.

 

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

 

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

 

($ in thousands)

 

Fair value at
March 31,
2013

 

Valuation technique

 

Significant unobservable input

 

Significant
unobservable
input value

 

Residential loans

 

$

17,331

 

Fair value of property or collateral

 

Appraised value

 

13 - 96%

 

Home equity lines of credit

 

732

 

Fair value of property or collateral

 

Appraised value

 

25 - 85%

 

 

 

 

 

 

 

 

 

 

 

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

 

222

 

Fair value of property or collateral

 

Insurance proceeds

 

60%

 

Commercial loans

 

1,127

 

Fair value of property or collateral

 

Fair value of business assets

 

9 - 93%

 

Commercial loan

 

1,775

 

Discounted cash flow

 

Present value of expected future cash flows based on anticipated debt restructuring

 

Paydown of loan – 59%

 

 

 

 

 

 

 

Discount rate

 

4.5%

 

Total commercial loans

 

3,256

 

 

 

 

 

 

 

Real estate acquired in settlement of loans

 

1,235

 

Fair value of property or collateral

 

Appraised value

 

81 – 99%

 

 

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

 

10 · Cash flows

 

Three months ended March 31

 

2013

 

2012

 

(in millions)

 

 

 

 

 

Supplemental disclosures of cash flow information

 

 

 

 

 

Interest paid to non-affiliates

 

$

21

 

$

22

 

Income taxes paid/(refunded)

 

(3

)

 

Supplemental disclosures of noncash activities

 

 

 

 

 

Common stock dividends reinvested in HEI common stock (1)

 

6

 

6

 

Increases in common stock related to director and officer compensatory plans

 

 

2

 

Additions to electric utility property, plant and equipment - Unpaid invoices and other

 

3

 

3

 

Real estate acquired in settlement of loans

 

1

 

2

 

 


(1)         The amounts shown represent common stock dividends reinvested in HEI common stock under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) in noncash transactions.

 

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11 · Recent accounting pronouncements

 

Obligations resulting from joint and several liability.  In February 2013, the FASB issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.

 

The Company will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.

 

12 · Credit agreement and long-term debt

 

Credit agreement. HEI maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The credit 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.

 

Changes in long-term debt.

 

March 6, 2013 notes.  On March 6, 2013, HEI entered into a First Supplement (the First Supplement) to the Master Note Purchase Agreement dated March 24, 2011 (the Note Agreement). Under the First Supplement, HEI issued $50 million of its unsecured, 3.99% Series 2013A Senior Notes, due March 6, 2023, via a private placement with The Prudential Insurance Company of America, Prudential Arizona Reinsurance Captive Company and The Lincoln National Life Insurance Company.

 

The Note Agreement, as modified by the First Supplement (which includes representations that supersede and supplement the representations in the Note Agreement), contains customary representations and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the Notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s existing amended revolving noncollateralized credit agreement described above and in HEI’s Form 10-K for the year ended December 31, 2012. For example, under the Note Agreement, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less or “Consolidated Net Worth” of at least $975 million.

 

The net proceeds from the issuance of the Notes were used by HEI to refinance $50 million of its unsecured, 5.25% Medium-Term Notes, Series D, which matured on March 7, 2013.

 

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Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

716,197

 

$

747,938

 

Operating expenses

 

 

 

 

 

Fuel oil

 

305,100

 

327,839

 

Purchased power

 

153,364

 

164,789

 

Other operation

 

71,423

 

61,849

 

Maintenance

 

29,702

 

30,038

 

Depreciation

 

38,280

 

36,482

 

Taxes, other than income taxes

 

67,687

 

70,995

 

Income taxes

 

14,095

 

17,365

 

Total operating expenses

 

679,651

 

709,357

 

Operating income

 

36,546

 

38,581

 

Other income

 

 

 

 

 

Allowance for equity funds used during construction

 

1,215

 

1,940

 

Other, net

 

2,312

 

1,309

 

Income tax expense

 

(299

)

(44

)

Total other income

 

3,228

 

3,205

 

Interest and other charges

 

 

 

 

 

Interest on long-term debt

 

14,614

 

14,383

 

Amortization of net bond premium and expense

 

647

 

745

 

Other interest charges (credits)

 

315

 

(271

)

Allowance for borrowed funds used during construction

 

(730

)

(870

)

Total interest and other charges

 

14,846

 

13,987

 

Net income

 

24,928

 

27,799

 

Preferred stock dividends of subsidiaries

 

229

 

229

 

Net income attributable to HECO

 

24,699

 

27,570

 

Preferred stock dividends of HECO

 

270

 

270

 

Net income for common stock

 

$

24,429

 

$

27,300

 

 

HEI owns all of the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.

 

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

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (unaudited)

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Net income for common stock

 

$

24,429

 

$

27,300

 

Other comprehensive income, net of taxes:

 

 

 

 

 

Retirement benefit plans:

 

 

 

 

 

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 $3,395 and $2,212 for the three months ended March 31, 2013 and 2012, respectively

 

5,331

 

3,472

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $3,384 and $2,162 for the three months ended March 31, 2013 and 2012, respectively

 

(5,313

)

(3,395

)

Other comprehensive income, net of taxes

 

18

 

77

 

Comprehensive income attributable to Hawaiian Electric Company, Inc.

 

$

24,447

 

$

27,377

 

 

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

 

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Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

 

(dollars in thousands, except par value)

 

March 31,
2013

 

December 31,
2012

 

Assets

 

 

 

 

 

Utility plant, at cost

 

 

 

 

 

Land

 

$

51,598

 

$

51,568

 

Plant and equipment

 

5,427,933

 

5,364,400

 

Less accumulated depreciation

 

(2,062,810

)

(2,040,789

)

Construction in progress

 

153,669

 

151,378

 

Net utility plant

 

3,570,390

 

3,526,557

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

36,940

 

17,159

 

Customer accounts receivable, net

 

194,457

 

210,779

 

Accrued unbilled revenues, net

 

135,615

 

134,298

 

Other accounts receivable, net

 

5,795

 

28,176

 

Fuel oil stock, at average cost

 

190,691

 

161,419

 

Materials and supplies, at average cost

 

54,430

 

51,085

 

Prepayments and other

 

32,255

 

32,865

 

Regulatory assets

 

61,804

 

51,267

 

Total current assets

 

711,987

 

687,048

 

Other long-term assets

 

 

 

 

 

Regulatory assets

 

812,347

 

813,329

 

Unamortized debt expense

 

10,245

 

10,554

 

Other

 

69,266

 

71,305

 

Total other long-term assets

 

891,858

 

895,188

 

Total assets

 

$

5,174,235

 

$

5,108,793

 

Capitalization and liabilities

 

 

 

 

 

Capitalization

 

 

 

 

 

Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 14,665,264 shares)

 

$

97,788

 

$

97,788

 

Premium on capital stock

 

468,045

 

468,045

 

Retained earnings

 

911,632

 

907,273

 

Accumulated other comprehensive loss, net of income taxes-retirement benefit plans

 

(952

)

(970

)

Common stock equity

 

1,476,513

 

1,472,136

 

Cumulative preferred stock — not subject to mandatory redemption

 

34,293

 

34,293

 

Long-term debt, net

 

1,147,875

 

1,147,872

 

Total capitalization

 

2,658,681

 

2,654,301

 

Commitments and contingencies (Note 5)

 

 

 

 

 

Current liabilities

 

 

 

 

 

Short-term borrowings from nonaffiliates

 

43,052

 

 

Accounts payable

 

228,426

 

186,824

 

Interest and preferred dividends payable

 

21,693

 

21,092

 

Taxes accrued

 

199,350

 

251,066

 

Other

 

67,930

 

62,879

 

Total current liabilities

 

560,451

 

521,861

 

Deferred credits and other liabilities

 

 

 

 

 

Deferred income taxes

 

435,598

 

417,611

 

Regulatory liabilities

 

325,527

 

322,074

 

Unamortized tax credits

 

67,939

 

66,584

 

Retirement benefits liability

 

611,678

 

620,205

 

Other

 

98,566

 

100,637

 

Total deferred credits and other liabilities

 

1,539,308

 

1,527,111

 

Contributions in aid of construction

 

415,795

 

405,520

 

Total capitalization and liabilities

 

$

5,174,235

 

$

5,108,793

 

 

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

 

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Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)

 

 

 

Common stock

 

Premium
on
capital

 

Retained

 

Accumulated
other
comprehensive

 

 

 

(in thousands)

 

Shares

 

Amount

 

stock

 

earnings

 

income (loss)

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2012

 

14,665

 

$

97,788

 

$

468,045

 

$

907,273

 

$

(970

)

$

1,472,136

 

Net income for common stock

 

 

 

 

24,429

 

 

24,429

 

Other comprehensive income, net of taxes

 

 

 

 

 

18

 

18

 

Common stock dividends

 

 

 

 

(20,070

)

 

(20,070

)

Balance, March 31, 2013

 

14,665

 

$

97,788

 

$

468,045

 

$

911,632

 

$

(952

)

$

1,476,513

 

Balance, December 31, 2011

 

14,234

 

$

94,911

 

$

426,921

 

$

881,041

 

$

(32

)

$

1,402,841

 

Net income for common stock

 

 

 

 

27,300

 

 

27,300

 

Other comprehensive income, net of taxes

 

 

 

 

 

77

 

77

 

Common stock dividends

 

 

 

 

(18,261

)

 

(18,261

)

Balance, March 31, 2012

 

14,234

 

$

94,911

 

$

426,921

 

$

890,080

 

$

45

 

$

1,411,957

 

 

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

 

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Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net income

 

$

24,928

 

$

27,799

 

Adjustments to reconcile net income to net cash provided by (used in) operating activities

 

 

 

 

 

Depreciation of property, plant and equipment

 

38,280

 

36,482

 

Other amortization

 

957

 

1,561

 

Change in deferred income taxes

 

17,975

 

20,061

 

Change in tax credits, net

 

1,382

 

1,356

 

Allowance for equity funds used during construction

 

(1,215

)

(1,940

)

Changes in assets and liabilities

 

 

 

 

 

Decrease in accounts receivable

 

38,703

 

25,001

 

Decrease (increase) in accrued unbilled revenues

 

(1,317

)

11,184

 

Increase in fuel oil stock

 

(29,272

)

(14,458

)

Increase in materials and supplies

 

(3,345

)

(3,561

)

Increase in regulatory assets

 

(17,746

)

(13,948

)

Increase (decrease) in accounts payable

 

38,934

 

(33,174

)

Change in prepaid and accrued income taxes and utility revenue taxes

 

(53,666

)

(44,561

)

Contributions to defined benefit pension and other postretirement benefit plans

 

(21,010

)

(26,183

)

Change in other assets and liabilities

 

19,913

 

3,444

 

Net cash provided by (used in) operating activities

 

53,501

 

(10,937

)

Cash flows from investing activities

 

 

 

 

 

Capital expenditures

 

(67,915

)

(63,436

)

Contributions in aid of construction

 

11,710

 

22,855

 

Net cash used in investing activities

 

(56,205

)

(40,581

)

Cash flows from financing activities

 

 

 

 

 

Common stock dividends

 

(20,070

)

(18,261

)

Preferred stock dividends of HECO and subsidiaries

 

(499

)

(499

)

Repayment of long-term debt

 

 

(57,500

)

Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less

 

43,052

 

84,942

 

Other

 

2

 

(120

)

Net cash provided by financing activities

 

22,485

 

8,562

 

Net increase (decrease) in cash and cash equivalents

 

19,781

 

(42,956

)

Cash and cash equivalents, beginning of period

 

17,159

 

48,806

 

Cash and cash equivalents, end of period

 

$

36,940

 

$

5,850

 

 

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

 

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Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1 · Basis of presentation

 

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2012.

 

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of March 31, 2013 and December 31, 2012, the results of their operations and their cash flows for the three months ended March 31, 2013 and 2012. All such adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

 

2 · 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 Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of 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 accounting rules on the consolidation of VIEs. Trust III’s balance sheets as of March 31, 2013 and December 31, 2012 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for the three months ended March 31, 2013 and 2012 each consisted of $0.8 million of interest income received from the 2004 Debentures, $0.8 million of distributions to holders of the Trust Preferred Securities, and $25,000 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

 

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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.

 

Power purchase agreements.  As of March 31, 2013, HECO and its subsidiaries had six PPAs for firm capacity and other PPAs with smaller independent power producers (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 90% of the firm capacity is purchased from AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the quarter ended March 31, 2013 totaled $153 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $23 million, $65 million, $12 million, and $15 million, respectively. Purchases from all IPPs for the quarter ended March 31, 2012 totaled $165 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $35 million, $69 million, $14 million, and $16 million, respectively.

 

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,” and thus excluded from the scope of accounting standards for VIEs. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.

 

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 the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information from two firm capacity producers and other small IPPs who entered into their PPAs prior to December 31, 2003 and have not provided such information, but have been unsuccessful to date as it was not a contractual requirement to provide such information prior to 2004. If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs. 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 the potential recognition of 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.

 

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 remaining 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

 

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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 March 31, 2013, HECO’s accounts payable to Kalaeloa amounted to $24 million.

 

3 · Revenue taxes

 

HECO and its subsidiaries’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period 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 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 the three months ended March 31, 2013 and 2012, HECO and its subsidiaries included approximately $64 million and $67 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

 

4 · Retirement benefits

 

Defined benefit pension and other postretirement benefit plans information.  For the first quarter of 2013, HECO and its subsidiaries contributed $21 million to their pension and other postretirement benefit plans, compared to $26 million in the first quarter of 2012. HECO and its subsidiaries’ current estimate of contributions to their pension and other postretirement benefit plans in 2013 is $84 million, compared to contributions of $63 million in 2012. In addition, HECO and its subsidiaries expect to pay directly $1.0 million of benefits in 2013, compared to $0.5 million paid in 2012.

 

On July 6, 2012, President Obama signed the MAP-21, which included provisions related to the funding and administration of pension plans. This law does not affect the utilities’ accounting for pension benefits; therefore, the net periodic benefit costs disclosed for the plans were not affected. The utilities elected to apply MAP-21 for 2012, which improved the plan’s AFTAP for funding and benefit distribution purposes and thereby reduced the 2012 minimum funding requirement and lifted the restrictions on accelerated distribution options (which restrictions were in effect April 1, 2011 to September 30, 2012) for HECO and its subsidiaries. The effects of MAP-21 are expected to cause the minimum required funding under ERISA to be less than the net periodic cost for 2013 and 2014; therefore, the utilities expect to contribute the net periodic cost for these years as they did for 2012. If the AFTAP 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. The HEI Retirement Plan fell below these thresholds in 2011 and the minimum required contribution for 2012 incorporated the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

 

The components of net periodic benefit cost were as follows:

 

 

 

Pension benefits

 

Other benefits

 

Three months ended March 31

 

2013

 

2012

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

13,603

 

$

9,802

 

$

1,014

 

$

1,048

 

Interest cost

 

14,676

 

15,261

 

1,861

 

2,205

 

Expected return on plan assets

 

(16,090

)

(16,060

)

(2,520

)

(2,579

)

Amortization of net transition obligation

 

 

 

 

(2

)

Amortization of net prior service gain

 

(116

)

(172

)

(451

)

(451

)

Amortization of net actuarial loss

 

8,790

 

5,869

 

504

 

440

 

Net periodic benefit cost

 

20,863

 

14,700

 

408

 

661

 

Impact of PUC D&Os

 

(7,436

)

(3,857

)

(397

)

(680

)

Net periodic benefit cost (adjusted for impact of PUC D&Os)

 

$

13,427

 

$

10,843

 

$

11

 

$

(19

)

 

HECO and its subsidiaries recorded retirement benefits expense of $10 million and $8 million for the first quarters of 2013 and 2012, respectively. The electric utilities charged a portion of the net periodic benefit cost to electric utility plant.

 

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The utilities have implemented pension and OPEB tracking mechanisms under which all of their retirement benefit expenses (except for executive life and nonqualified pension plan expenses) determined in accordance with GAAP are recovered over time. Under the tracking mechanisms, these retirement benefit costs that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

 

Accumulated other comprehensive income.  Reclassifications out of AOCI were as follows:

 

 

 

Three months ended March 31

 

 

 

 

 

2013

 

2012

 

 

 

(in thousands)

 

Amount reclassified from AOCI

 

 

 

Retirement benefit plan items

 

 

 

 

 

 

 

Amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost

 

$

5,331

 

$

3,472

 

(See above)

 

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets

 

(5,313

)

(3,395

)

(See above)

 

Total reclassifications

 

$

18

 

$

77

 

 

 

 

Defined contribution plan information.  For the first quarters of 2013 and 2012, the utilities’ expense for its defined contribution pension plan was $0.2 million and de minimis, respectively.

 

5 · Commitments and contingencies

 

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

 

Renewable energy projects.  HECO and its subsidiaries continue to evaluate opportunities with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, geothermal and others. This includes HECO’s plan to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a large windfarm proposed to be built on the island of Lanai.

 

In December 2009, the PUC allowed HECO to defer the costs of studies for the large wind project for later review of prudence and reasonableness. In April 2013, the PUC approved the recovery of $3.9 million in costs for stage 1 studies for the large wind project over a three-year period, with carrying costs to be accrued over the recovery period at the rate of 1.75% per annum, through the Renewable Energy Infrastructure Program (REIP) Surcharge.

 

In November 2011, 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

 

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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. In February 2013, HELCO issued the Final Geothermal RFP. Bids were received in April 2013 and are being evaluated.

 

Interim increases.  As of March 31, 2013, HECO and its subsidiaries had recognized $3 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.

 

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. However, in March 2012, the PUC eliminated the requirement for a regulatory audit for the EOTP Phase I in connection with an approved settlement of the project cost issues and, in March 2013, the PUC eliminated the requirement for the CIP CT-1 and CIS projects as described below.

 

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

 

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

 

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

 

Campbell Industrial Park combustion turbine No. 1 and transmission line.  HECO’s incurred costs for this project, which was placed in service in 2009, were $195 million, including $9 million of allowance for funds used during construction (AFUDC). In July 2011, the PUC allowed HECO to defer $32 million of costs that were in excess of the prior PUC approved amounts and related depreciation for HECO’s CIP CT-1 project until completion of the contemplated regulatory audit, which was subsequently cancelled pursuant to the 2013 D&O. The PUC also approved the accrual of a carrying charge on the cost of the project not yet included in rates and the related depreciation expense and allowed the remaining project costs that were not deferred to be included in electric rates.

 

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For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is collected in electric rates (expected to begin on June 1, 2013). Effective May 31, 2013, the accrual of a carrying charge will end. The CIP CT-1 deferred costs and depreciation are expected to be recovered in electric rates beginning on June 1, 2013. Management believes no adjustment to project costs is required as of March 31, 2013.

 

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.

 

The CIS project’s new software system became operational in May 2012. In February 2012 and May 2012, the PUC 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) until completion of the contemplated regulatory audit, which was subsequently cancelled pursuant to the 2013 D&O. The PUC also allowed them to accrue AFUDC on project costs (including deferred operation and maintenance expenses). For accounting purposes, the utilities will recognize the equity portion of the carrying charge when it is collected in electric rates (expected to begin on June 1, 2013). Effective May 31, 2013, the accrual of AFUDC will end. As of March 31, 2013, the utilities’ total deferred and capital costs for the CIS project were $20 million (after the write-off of $40 million of project costs pursuant to the 2013 Agreement and 2013 D&O described above). The CIS project costs of $20 million are expected to be recovered in electric rates beginning on June 1, 2013. Management believes no further adjustment to project costs is required as of March 31, 2013.

 

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 governmental activities related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), have increased significantly and management anticipates that such activity will continue.

 

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at HECO’s power plants on the island of Oahu. If adopted as proposed, management believes the proposed regulations would require significant capital and annual other operation and maintenance (O&M) expenditures. On June 11, 2012, the EPA published additional information on the section 316(b) rule making that indicates that the EPA is considering establishing lower cost compliance alternatives in the final rule. The EPA has delayed issuance of the final section 316(b) rule 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 February 6, 2013, the EPA issued a guidance document titled “Next Steps for Area Designations and Implementation of the Sulfur Dioxide National Ambient Air Quality Standard,” which outlines a process that will provide the states additional flexibility and time for their development of one-hour SO2 NAAQS implementation plans. HECO will work with the Hawaii Department of Health (DOH) and the EPA in the rulemaking process for these implementation plans to insure development of cost-effective strategies for NAAQS compliance.

 

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Depending upon the final outcome of the CWA 316(b) regulations and proposed changes to CWA effluent standards, the specifics of the MATS compliance plan, and the implementation of more stringent National Ambient Air Quality Standards, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire or deactivate certain generating units earlier than anticipated.

 

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. HECO and its subsidiaries believe the costs of responding to such releases identified to date will not have a material adverse effect, individually or in the aggregate, on HECO’s consolidated results of operations, financial condition or liquidity.

 

Former Molokai Electric Company generation site.  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 since performed Brownfield assessments of the Site that identified environmental impacts in the subsurface. Although MECO never operated at the Site and operations there had stopped four years before the merger, in discussions with the EPA and the 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 elevated polychlorinated biphenyls (PCBs) in the subsurface soils. In cooperation with the DOH and EPA, MECO is further investigating the Site and the Adjacent Parcel to determine the extent of impacts of PCBs, fuel oils, and other subsurface contaminants. In March 2012, MECO accrued an additional $3.1 million (reserve balance of $3.6 million as of March 31, 2013) for the additional investigation and estimated cleanup costs at the Site and the Adjacent Parcel; however, final costs of remediation will depend on the results of continued investigation.

 

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

 

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities participated in a Task Force established under Act 234, which was charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. On October 19, 2012, the DOH posted the proposed regulations required by Act 234 for public hearing and comment. In general, the proposed regulations would require affected sources that have the potential to emit GHGs in excess of established thresholds to reduce GHG emissions by 25% below 2010 emission levels by 2020. The proposed regulations also assess affected sources an annual fee based on tons per year of GHG emissions, beginning with emissions in calendar year 2012. The proposed DOH GHG rule also tracks the federal 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. HECO submitted comments on the proposed regulations in January 2013. HECO continues to monitor this rulemaking proceeding and will participate in the further development of the regulations.

 

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

 

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The utilities have submitted the required reports for 2010, 2011 and 2012 to the EPA. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Since then, the EPA has also issued rules that begin to address GHG emissions from stationary sources, like the utilities’ generating units.

 

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In June 2010, the EPA issued its GHG Tailoring Rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. In January 2011, the EPA announced 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, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generating 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’ 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 liquidity of the electric utilities. For example, severe weather could cause significant harm to the electric utilities’ physical facilities.

 

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

 

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

 

(in thousands)

 

2013

 

2012

 

Balance, January 1

 

$

48,431

 

$

50,871

 

Accretion expense

 

124

 

451

 

Liabilities incurred

 

 

 

Liabilities settled

 

(642

)

(210

)

Revisions in estimated cash flows

 

 

 

Balance, March 31

 

$

47,913

 

$

51,112

 

 

Collective bargaining agreements.  On November 1, 2012, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement that both expire on October 31, 2018. The collective bargaining agreement provides for general non-compounded wage increases of 3% for 2014, 2015, 2017 and 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 agreement also includes wage adjustments for certain trades and crafts positions and different wage rates for new bargaining unit

 

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office and clerical positions. The new benefit agreement provides for an escalating percentage of employee contributions without caps for medical premiums throughout the term of the agreement. As of April 1, 2013, approximately 52% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities.

 

6 · Cash flows

 

Three months ended March 31

 

2013

 

2012

 

(in millions)

 

 

 

 

 

Supplemental disclosures of cash flow information

 

 

 

 

 

Interest paid

 

$

14

 

$

15

 

Income taxes refunded

 

(26

)

(1

)

Supplemental disclosures of noncash activities

 

 

 

 

 

Additions to electric utility property, plant and equipment - Unpaid invoices and other

 

3

 

3

 

 

7 · 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 electric utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the electric utilities were to sell their entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the electric utilities’ financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

 

The Company 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 is used to measure fair value whenever available.

 

Level 2:                Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that are derived principally from or can be corroborated by observable market data by correlation or other means.

 

Level 3:                Inputs to the valuation methodology are unobservable and significant to the fair value measurement. Level 3 assets and liabilities include financial instruments whose value is determined using discounted cash flow methodologies, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

 

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

 

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

 

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

 

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The estimated fair values of certain of the electric utilities’ financial instruments were as follows:

 

 

 

March 31, 2013

 

December 31, 2012

 

(in thousands)

 

Carrying
amount

 

Estimated
fair value
(Level 2)

 

Carrying
amount

 

Estimated
fair value
(Level 2)

 

 

 

 

 

 

 

 

 

 

 

Financial liabilities

 

 

 

 

 

 

 

 

 

Short-term borrowings - nonaffiliates

 

$

43,052

 

$

43,052

 

$

 

$

 

Long-term debt, net, including amounts due within one year

 

1,147,875

 

1,230,067

 

1,147,872

 

1,181,631

 

 

Fair value measurements on a nonrecurring basis.  From time to time, the utilities may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of the utilities 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 “Asset retirement obligations” in Note 5.

 

8 · Recent accounting pronouncements

 

Obligations resulting from joint and several liability.  In February 2013, the FASB issued Accounting Standards Update (ASU) No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date,” which provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The guidance requires entities to measure these obligations as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires an entity to disclose the nature and amount of the obligation as well as other information. This guidance is effective for all fiscal years, and interim periods within those years, beginning after December 31, 2013.

 

HECO and its subsidiaries will retrospectively adopt ASU No. 2013-04 in the first quarter of 2014 and does not expect it to have a material impact on HECO and its subsidiaries’ results of operations, financial condition or liquidity.

 

9 · Credit agreement

 

HECO maintains an amended revolving noncollateralized credit agreement, which established a line of credit facility of $175 million, with a letter of credit sub-facility, expiring on December 5, 2016, with a syndicate of eight financial institutions. The 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.

 

10 · Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)

 

$

52,953

 

$

57,254

 

Deduct:

 

 

 

 

 

Income taxes on regulated activities

 

(14,095

)

(17,365

)

Revenues from nonregulated activities

 

(3,076

)

(1,672

)

Add:

 

 

 

 

 

Expenses from nonregulated activities

 

764

 

364

 

Operating income from regulated activities after income taxes (per HECO consolidated statements of income)

 

$

36,546

 

$

38,581

 

 

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11 · Consolidating financial information

 

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

 

HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO, (b) under their respective private placement note agreements and the HELCO notes and MECO notes issued thereunder and (c) relating to the trust preferred securities of Trust III (see Note 2 above). HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.

 

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Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended March 31, 2013

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Operating revenues

 

$

505,829

 

106,016

 

104,352

 

 

 

$

716,197

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel oil

 

221,967

 

32,936

 

50,197

 

 

 

305,100

 

Purchased power

 

111,155

 

30,122

 

12,087

 

 

 

153,364

 

Other operation

 

50,111

 

11,064

 

10,248

 

 

 

71,423

 

Maintenance

 

21,652

 

3,806

 

4,244

 

 

 

29,702

 

Depreciation

 

24,707

 

8,547

 

5,026

 

 

 

38,280

 

Taxes, other than income taxes

 

48,085

 

9,686

 

9,916

 

 

 

67,687

 

Income taxes

 

7,311

 

2,714

 

4,070

 

 

 

14,095

 

Total operating expenses

 

484,988

 

98,875

 

95,788

 

 

 

679,651

 

Operating income

 

20,841

 

7,141

 

8,564

 

 

 

36,546

 

Other income (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for equity funds used during construction

 

983

 

138

 

94

 

 

 

1,215

 

Equity in earnings of subsidiaries

 

10,985

 

 

 

 

(10,985

)

 

Other, net

 

2,021

 

142

 

177

 

 

(28

)

2,312

 

Income tax benefits

 

(230

)

(23

)

(46

)

 

 

(299

)

Total other income (loss)

 

13,759

 

257

 

225

 

 

(11,013

)

3,228

 

Interest and other charges

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

9,902

 

2,750

 

1,962

 

 

 

14,614

 

Amortization of net bond premium and expense

 

410

 

117

 

120

 

 

 

647

 

Other interest charges

 

157

 

69

 

117

 

 

(28

)

315

 

Allowance for borrowed funds used during construction

 

(568

)

(92

)

(70

)

 

 

(730

)

Total interest and other charges

 

9,901

 

2,844

 

2,129

 

 

(28

)

14,846

 

Net income

 

24,699

 

4,554

 

6,660

 

 

(10,985

)

24,928

 

Preferred stock dividend of subsidiaries

 

 

134

 

95

 

 

 

229

 

Net income attributable to HECO

 

24,699

 

4,420

 

6,565

 

 

(10,985

)

24,699

 

Preferred stock dividends of HECO

 

270

 

 

 

 

 

270

 

Net income for common stock

 

$

24,429

 

4,420

 

6,565

 

 

(10,985

)

$

24,429

 

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended March 31, 2013

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Net income for common stock

 

$

24,429

 

4,420

 

6,565

 

 

(10,985

)

$

24,429

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

 

 

 

 

 

 

Retirement benefit plans:

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

5,331

 

759

 

657

 

 

(1,416

)

5,331

 

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

 

(5,313

)

(761

)

(656

)

 

1,417

 

(5,313

)

Other comprehensive income (loss), net of taxes

 

18

 

(2

)

1

 

 

1

 

18

 

Comprehensive income attributable to common shareholder

 

$

24,447

 

4,418

 

6,566

 

 

(10,984

)

$

24,447

 

 

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Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended March 31, 2012

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Operating revenues

 

$

530,613

 

112,327

 

104,998

 

 

 

$

747,938

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel oil

 

235,026

 

32,410

 

60,403

 

 

 

327,839

 

Purchased power

 

124,780

 

33,908

 

6,101

 

 

 

164,789

 

Other operation

 

39,948

 

9,015

 

12,886

 

 

 

61,849

 

Maintenance

 

20,836

 

4,249

 

4,953

 

 

 

30,038

 

Depreciation

 

22,571

 

8,436

 

5,475

 

 

 

36,482

 

Taxes, other than income taxes

 

50,553

 

10,463

 

9,979

 

 

 

70,995

 

Income taxes

 

11,963

 

4,223

 

1,179

 

 

 

17,365

 

Total operating expenses

 

505,677

 

102,704

 

100,976

 

 

 

709,357

 

Operating income

 

24,936

 

9,623

 

4,022

 

 

 

38,581

 

Other income (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

Allowance for equity funds used during construction

 

1,581

 

125

 

234

 

 

 

1,940

 

Equity in earnings of subsidiaries

 

8,490

 

 

 

 

(8,490

)

 

Other, net

 

1,094

 

116

 

110

 

(1

)

(10

)

1,309

 

Income tax benefits

 

(30

)

(15

)

1

 

 

 

(44

)

Total other income (loss)

 

11,135

 

226

 

345

 

(1

)

(8,500

)

3,205

 

Interest and other charges

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest on long-term debt

 

9,130

 

2,985

 

2,268

 

 

 

14,383

 

Amortization of net bond premium and expense

 

483

 

137

 

125

 

 

 

745

 

Other interest charges

 

(387

)

33

 

93

 

 

(10

)

(271

)

Allowance for borrowed funds used during construction

 

(725

)

(51

)

(94

)

 

 

(870

)

Total interest and other charges

 

8,501

 

3,104

 

2,392

 

 

(10

)

13,987

 

Net income (loss)

 

27,570

 

6,745

 

1,975

 

(1

)

(8,490

)

27,799

 

Preferred stock dividend of subsidiaries

 

 

134

 

95

 

 

 

229

 

Net income (loss) attributable to HECO

 

27,570

 

6,611

 

1,880

 

(1

)

(8,490

)

27,570

 

Preferred stock dividends of HECO

 

270

 

 

 

 

 

270

 

Net income (loss) for common stock

 

$

27,300

 

6,611

 

1,880

 

(1

)

(8,490

)

$

27,300

 

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Comprehensive Income (Loss) (unaudited)

Three months ended March 31, 2012

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Net income (loss) for common stock

 

$

27,300

 

6,611

 

1,880

 

(1

)

(8,490

)

$

27,300

 

Other comprehensive income (loss), net of taxes:

 

 

 

 

 

 

 

 

 

 

 

 

 

Retirement benefit plans:

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

3,472

 

532

 

473

 

 

(1,005

)

3,472

 

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

 

(3,395

)

(526

)

(467

)

 

993

 

(3,395

)

Other comprehensive income (loss), net of taxes

 

77

 

6

 

6

 

 

(12

)

77

 

Comprehensive income (loss) attributable to common shareholder

 

$

27,377

 

6,617

 

1,886

 

(1

)

(8,502

)

$

27,377

 

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

March 31, 2013

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Utility plant, at cost

 

 

 

 

 

 

 

 

 

 

 

 

 

Land

 

$

43,400

 

5,182

 

3,016

 

 

 

$

51,598

 

Plant and equipment

 

3,377,351

 

1,089,414

 

961,168

 

 

 

5,427,933

 

Less accumulated depreciation

 

(1,198,256

)

(439,184

)

(425,370

)

 

 

(2,062,810

)

Construction in progress

 

123,898

 

17,623

 

12,148

 

 

 

153,669

 

Net utility plant

 

2,346,393

 

673,035

 

550,962

 

 

 

3,570,390

 

Investment in wholly owned subsidiaries, at equity

 

501,871

 

 

 

 

(501,871

)

 

Current assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

32,661

 

2,770

 

1,405

 

104

 

 

36,940

 

Advances to affiliates

 

13,000

 

16,650

 

 

 

(29,650

)

 

Customer accounts receivable, net

 

139,540

 

30,046

 

24,871

 

 

 

194,457

 

Accrued unbilled revenues, net

 

102,307

 

16,484

 

16,824

 

 

 

135,615

 

Other accounts receivable, net

 

13,437

 

861

 

1,341

 

 

(9,844

)

5,795

 

Fuel oil stock, at average cost

 

153,331

 

13,429

 

23,931

 

 

 

190,691

 

Materials and supplies, at average cost

 

33,632

 

5,950

 

14,848

 

 

 

54,430

 

Prepayments and other

 

26,668

 

3,133

 

2,663

 

 

(209

)

32,255

 

Regulatory assets

 

50,315

 

5,412

 

6,077

 

 

 

61,804

 

Total current assets

 

564,891

 

94,735

 

91,960

 

104

 

(39,703

)

711,987

 

Other long-term assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory assets

 

601,447

 

109,547

 

101,353

 

 

 

812,347

 

Unamortized debt expense

 

6,844

 

2,004

 

1,397

 

 

 

10,245

 

Other

 

45,348

 

9,057

 

14,861

 

 

 

69,266

 

Total other long-term assets

 

653,639

 

120,608

 

117,611

 

 

 

891,858

 

Total assets

 

$

4,066,794

 

888,378

 

760,533

 

104

 

(541,574

)

$

5,174,235

 

Capitalization and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock equity

 

$

1,476,513

 

269,716

 

232,051

 

104

 

(501,871

)

$

1,476,513

 

Cumulative preferred stock—not subject to mandatory redemption

 

22,293

 

7,000

 

5,000

 

 

 

34,293

 

Long-term debt, net

 

780,547

 

201,328

 

166,000

 

 

 

1,147,875

 

Total capitalization

 

2,279,353

 

478,044

 

403,051

 

104

 

(501,871

)

2,658,681

 

Current liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of long-term debt

 

43,052

 

 

 

 

 

43,052

 

Short-term borrowings-affiliate

 

16,650

 

 

13,000

 

 

(29,650

)

 

Accounts payable

 

181,266

 

26,534

 

20,626

 

 

 

228,426

 

Interest and preferred dividends payable

 

14,643

 

3,789

 

3,274

 

 

(13

)

21,693

 

Taxes accrued

 

138,681

 

30,586

 

30,292

 

 

(209

)

199,350

 

Other

 

49,186

 

11,989

 

16,586

 

 

(9,831

)

67,930

 

Total current liabilities

 

443,478

 

72,898

 

83,778

 

 

(39,703

)

560,451

 

Deferred credits and other liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income taxes

 

316,153

 

71,233

 

48,212

 

 

 

435,598

 

Regulatory liabilities

 

220,715

 

68,878

 

35,934

 

 

 

325,527

 

Unamortized tax credits

 

41,111

 

13,428

 

13,400

 

 

 

67,939

 

Retirement benefits liability

 

453,573

 

79,421

 

78,684

 

 

 

611,678

 

Other

 

67,362

 

16,937

 

14,267

 

 

 

98,566

 

Total deferred credits and other liabilities

 

1,098,914

 

249,897

 

190,497

 

 

 

1,539,308

 

Contributions in aid of construction

 

245,049

 

87,539

 

83,207

 

 

 

415,795

 

Total capitalization and liabilities

 

$

4,066,794

 

888,378

 

760,533

 

104

 

(541,574

)

$

5,174,235

 

 

44



Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2012

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Utility plant, at cost

 

 

 

 

 

 

 

 

 

 

 

 

 

Land

 

$

43,370

 

5,182

 

3,016

 

 

 

$

51,568

 

Plant and equipment

 

3,325,862

 

1,086,048

 

952,490

 

 

 

5,364,400

 

Less accumulated depreciation

 

(1,185,899

)

(433,531

)

(421,359

)

 

 

(2,040,789

)

Construction in progress

 

130,143

 

12,126

 

9,109

 

 

 

151,378

 

Net utility plant

 

2,313,476

 

669,825

 

543,256

 

 

 

3,526,557

 

Investment in wholly owned subsidiaries, at equity

 

497,939

 

 

 

 

(497,939

)

 

Current assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

8,265

 

5,441

 

3,349

 

104

 

 

17,159

 

Advances to affiliates

 

9,400

 

18,050

 

 

 

(27,450

)

 

Customer accounts receivable, net

 

154,316

 

29,772

 

26,691

 

 

 

210,779

 

Accrued unbilled revenues, net

 

100,600

 

14,393

 

19,305

 

 

 

134,298

 

Other accounts receivable, net

 

33,313

 

1,122

 

3,016

 

 

(9,275

)

28,176

 

Fuel oil stock, at average cost

 

123,176

 

15,485

 

22,758

 

 

 

161,419

 

Materials and supplies, at average cost

 

31,779

 

5,336

 

13,970

 

 

 

51,085

 

Prepayments and other

 

21,708

 

5,146

 

6,011

 

 

 

32,865

 

Regulatory assets

 

42,675

 

4,056

 

4,536

 

 

 

51,267

 

Total current assets

 

525,232

 

98,801

 

99,636

 

104

 

(36,725

)

687,048

 

Other long-term assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory assets

 

601,451

 

109,815

 

102,063

 

 

 

813,329

 

Unamortized debt expense

 

7,042

 

2,066

 

1,446

 

 

 

10,554

 

Other

 

46,586

 

9,871

 

14,848

 

 

 

71,305

 

Total other long-term assets

 

655,079

 

121,752

 

118,357

 

 

 

895,188

 

Total assets

 

$

3,991,726

 

890,378

 

761,249

 

104

 

(534,664

)

$

5,108,793

 

Capitalization and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock equity

 

$

1,472,136

 

268,908

 

228,927

 

104

 

(497,939

)

$

1,472,136

 

Cumulative preferred stock—not subject to mandatory redemption

 

22,293

 

7,000

 

5,000

 

 

 

34,293

 

Long-term debt, net

 

780,546

 

201,326

 

166,000

 

 

 

1,147,872

 

Total capitalization

 

2,274,975

 

477,234

 

399,927

 

104

 

(497,939

)

2,654,301

 

Current liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Current portion of long-term debt

 

 

 

 

 

 

 

Short-term borrowings-affiliate

 

18,050

 

 

9,400

 

 

(27,450

)

 

Accounts payable

 

134,651

 

27,457

 

24,716

 

 

 

186,824

 

Interest and preferred dividends payable

 

14,479

 

4,027

 

2,593

 

 

(7

)

21,092

 

Taxes accrued

 

174,477

 

38,778

 

37,811

 

 

 

251,066

 

Other

 

47,203

 

10,310

 

14,634

 

 

(9,268

)

62,879

 

Total current liabilities

 

388,860

 

80,572

 

89,154

 

 

(36,725

)

521,861

 

Deferred credits and other liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred income taxes

 

302,569

 

68,479

 

46,563

 

 

 

417,611

 

Regulatory liabilities

 

218,437

 

67,359

 

36,278

 

 

 

322,074

 

Unamortized tax credits

 

39,827

 

13,450

 

13,307

 

 

 

66,584

 

Retirement benefits liability

 

459,765

 

80,686

 

79,754

 

 

 

620,205

 

Other

 

68,783

 

17,799

 

14,055

 

 

 

100,637

 

Total deferred credits and other liabilities

 

1,089,381

 

247,773

 

189,957

 

 

 

1,527,111

 

Contributions in aid of construction

 

238,510

 

84,799

 

82,211

 

 

 

405,520

 

Total capitalization and liabilities

 

$

3,991,726

 

890,378

 

761,249

 

104

 

(534,664

)

$

5,108,793

 

 

45



Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2013

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Balance, December 31, 2012

 

$

1,472,136

 

268,908

 

228,927

 

104

 

(497,939

)

$

1,472,136

 

Net income for common stock

 

24,429

 

4,420

 

6,565

 

 

(10,985

)

24,429

 

Other comprehensive income, net of taxes

 

18

 

(2

)

1

 

 

1

 

18

 

Common stock dividends

 

(20,070

)

(3,610

)

(3,442

)

 

7,052

 

(20,070

)

Balance, March 31, 2013

 

$

1,476,513

 

269,716

 

232,051

 

104

 

(501,871

)

$

1,476,513

 

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Three months ended March 31, 2012

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Balance, December 31, 2011

 

$

1,402,841

 

280,468

 

235,568

 

107

 

(516,143

)

$

1,402,841

 

Net income (loss) for common stock

 

27,300

 

6,611

 

1,880

 

(1

)

(8,490

)

27,300

 

Other comprehensive income, net of taxes

 

77

 

6

 

6

 

 

(12

)

77

 

Common stock dividends

 

(18,261

)

(3,284

)

(2,187

)

 

5,471

 

(18,261

)

Balance, March 31, 2012

 

$

1,411,957

 

283,801

 

235,267

 

106

 

(519,174

)

$

1,411,957

 

 

46



Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2013

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

24,699

 

4,554

 

6,660

 

 

(10,985

)

$

24,928

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings of subsidiaries

 

(11,010

)

 

 

 

10,985

 

(25

)

Common stock dividends received from subsidiaries

 

7,052

 

 

 

 

(7,052

)

 

Depreciation of property, plant and equipment

 

24,707

 

8,547

 

5,026

 

 

 

38,280

 

Other amortization

 

(8

)

358

 

607

 

 

 

957

 

Change in deferred income taxes

 

13,572

 

2,755

 

1,648

 

 

 

17,975

 

Change in tax credits, net

 

1,299

 

(17

)

100

 

 

 

1,382

 

Allowance for equity funds used during construction

 

(983

)

(138

)

(94

)

 

 

(1,215

)

Changes in assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable

 

34,652

 

(13

)

3,495

 

 

569

 

38,703

 

Decrease (increase) in accrued unbilled revenues

 

(1,707

)

(2,091

)

2,481

 

 

 

(1,317

)

Decrease (increase) in fuel oil stock

 

(30,155

)

2,056

 

(1,173

)

 

 

(29,272

)

Increase in materials and supplies

 

(1,853

)

(614

)

(878

)

 

 

(3,345

)

Increase in regulatory assets

 

(13,071

)

(2,464

)

(2,211

)

 

 

(17,746

)

Increase (decrease) in accounts payable

 

44,887

 

(903

)

(5,050

)

 

 

38,934

 

Change in prepaid and accrued income and utility revenue taxes

 

(41,093

)

(8,078

)

(4,495

)

 

 

(53,666

)

Contributions to defined benefit pension and other postretirement benefit plans

 

(15,530

)

(2,763

)

(2,717

)

 

 

(21,010

)

Change in other assets and liabilities

 

11,117

 

5,170

 

4,220

 

 

(569

)

19,938

 

Net cash provided by operating activities

 

46,575

 

6,359

 

7,619

 

 

(7,052

)

53,501

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

(47,709

)

(10,118

)

(10,088

)

 

 

(67,915

)

Contributions in aid of construction

 

7,816

 

3,432

 

462

 

 

 

11,710

 

Advances from (to) affiliates

 

(3,600

)

1,400

 

 

 

2,200

 

 

Net cash used in investing activities

 

(43,493

)

(5,286

)

(9,626

)

 

2,200

 

(56,205

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock dividends

 

(20,070

)

(3,610

)

(3,442

)

 

7,052

 

(20,070

)

Preferred stock dividends of HECO and subsidiaries

 

(270

)

(134

)

(95

)

 

 

(499

)

Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less

 

41,652

 

 

3,600

 

 

(2,200

)

43,052

 

Other

 

2

 

 

 

 

 

2

 

Net cash provided by (used in) financing activities

 

21,314

 

(3,744

)

63

 

 

4,852

 

22,485

 

Net increase (decrease) in cash and cash equivalents

 

24,396

 

(2,671

)

(1,944

)

 

 

19,781

 

Cash and cash equivalents, beginning of period

 

8,265

 

5,441

 

3,349

 

104

 

 

17,159

 

Cash and cash equivalents, end of period

 

$

32,661

 

2,770

 

1,405

 

104

 

 

$

36,940

 

 

47



Table of Contents

 

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Three months ended March 31, 2012

 

(in thousands)

 

HECO

 

HELCO

 

MECO

 

Other
subsidiaries

 

Consolidating
adjustments

 

HECO
Consolidated

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

27,570

 

6,745

 

1,975

 

(1

)

(8,490

)

$

27,799

 

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity in earnings of subsidiaries

 

(8,515

)

 

 

 

8,490

 

(25

)

Common stock dividends received from subsidiaries

 

5,471

 

 

 

 

(5,471

)

 

Depreciation of property, plant and equipment

 

22,571

 

8,436

 

5,475

 

 

 

36,482

 

Other amortization

 

485

 

622

 

454

 

 

 

1,561

 

Change in deferred income taxes

 

13,721

 

2,563

 

3,777

 

 

 

20,061

 

Change in tax credits, net

 

1,320

 

36

 

 

 

 

1,356

 

Allowance for equity funds used during construction

 

(1,581

)

(125

)

(234

)

 

 

(1,940

)

Changes in assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable

 

19,978

 

343

 

2,431

 

 

2,249

 

25,001

 

Decrease (increase) in accrued unbilled revenues

 

11,188

 

57

 

(61

)

 

 

11,184

 

Decrease (increase) in fuel oil stock

 

(11,819

)

(2,058

)

(581

)

 

 

(14,458

)

Increase in materials and supplies

 

(2,320

)

(1,128

)

(113

)

 

 

(3,561

)

Increase in regulatory assets

 

(11,612

)

(1,039

)

(1,297

)

 

 

(13,948

)

Increase (decrease) in accounts payable

 

(27,400

)

(2,941

)

(2,833

)

 

 

(33,174

)

Change in prepaid and accrued income and utility revenue taxes

 

(29,011

)

(5,741

)

(9,809

)

 

 

(44,561

)

Contributions to defined benefit pension and other postretirement benefit plans

 

(19,428

)

(3,279

)

(3,476

)

 

 

(26,183

)

Change in other assets and liabilities

 

(2,190

)

2,320

 

5,589

 

(1

)

(2,249

)

3,469

 

Net cash provided by (used in) operating activities

 

(11,572

)

4,811

 

1,297

 

(2

)

(5,471

)

(10,937

)

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

(51,026

)

(6,727

)

(5,683

)

 

 

(63,436

)

Contributions in aid of construction

 

20,748

 

1,579

 

528

 

 

 

22,855

 

Advances from (to) affiliates

 

 

10,250

 

14,500

 

 

(24,750

)

 

Net cash used in investing activities

 

(30,278

)

5,102

 

9,345

 

 

(24,750

)

(40,581

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock dividends

 

(18,261

)

(3,284

)

(2,187

)

 

5,471

 

(18,261

)

Preferred stock dividends of HECO and subsidiaries

 

(270

)

(134

)

(95

)

 

 

(499

)

Repayment of long-term debt

 

(42,580

)

(7,200

)

(7,720

)

 

 

(57,500

)

Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less

 

60,192

 

 

 

 

24,750

 

84,942

 

Other

 

(70

)

(2

)

(48

)

 

 

(120

)

Net cash provided by (used in) financing activities

 

(989

)

(10,620

)

(10,050

)

 

30,221

 

8,562

 

Net increase (decrease) in cash and cash equivalents

 

(42,839

)

(707

)

592

 

(2

)

 

(42,956

)

Cash and cash equivalents, beginning of period

 

44,819

 

3,383

 

496

 

108

 

 

48,806

 

Cash and cash equivalents, end of period

 

$

1,980

 

2,676

 

1,088

 

106

 

 

$

5,850

 

 

48



Table of Contents

 

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and HECO’s Form 10-K for 2012 and should be read in conjunction with the 2012 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI’s and HECO’s Form 10-K for 2012, as well as the quarterly (as of and for the three months ended March 31, 2013) financial statements and notes thereto included in this Form 10-Q.

 

HEI Consolidated

 

RESULTS OF OPERATIONS

 

(in thousands, except per

 

Three months ended
March 31

 

%

 

Primary reason(s) for

 

share amounts)

 

2013

 

2012

 

change

 

significant change*

 

Revenues

 

$

784,064

 

$

814,860

 

(4

)

Decrease for the electric utility and bank segments

 

Operating income

 

70,657

 

75,816

 

(7

)

Decrease for the electric utility and bank segments, partly offset by a reduced operating loss for the “other” segment

 

Net income for common stock

 

33,679

 

38,316

 

(12

)

Lower operating income, higher “interest expense—other than on deposit liabilities and other bank borrowings” and lower AFUDC, partly offset by lower income taxes

 

Basic earnings per common share

 

$

0.34

 

$

0.40

 

(15

)

Lower net income and higher weighted average shares outstanding

 

Weighted-average number of common shares outstanding

 

98,135

 

96,167

 

2

 

Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other plans

 

 


*                 Also, see segment discussions which follow.

 

Notes:  The Company’s effective tax rates (combined federal and state) for the first quarters of 2013 and 2012 were 35%.

 

HEI’s consolidated ROACE was 8.5% for the twelve months ended March 31, 2013 and 9.7% for the twelve months ended March 31, 2012.

 

Dividends.  The payout ratios for the first quarter of 2013 and full year 2012 were 90% and 87%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.

 

Economic conditions.

 

Note:  The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; 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 and continued to grow into 2013, although at a slower pace. State visitor arrivals grew by 7.1% in the first three months of 2013 over 2012. State visitor expenditures also continued to grow, increasing by 7.6% in the first three months of 2013 over 2012. Hotel occupancies and room rates also continued to rise. The outlook for the visitor industry remains positive, albeit with a potential for more moderate growth, with the Hawaii Tourism Authority expecting a 10.0% increase in scheduled nonstop seats to Hawaii for April — June 2013 over the same period in 2012.

 

Hawaii’s unemployment rate was 5.1% in March 2013, lower than the state’s 6.2% rate in March 2012 and the March 2013 national unemployment rate of 7.6%.

 

Hawaii real estate activity as indicated by the home resale market has been mixed in the first quarter of 2013. The median sales price for single family residential homes on Oahu decreased by 2.7%, but closed sales increased

 

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6.9% in the first three months of 2013 as compared to the same period in 2012. Oahu condominiums showed strong momentum with median prices rising 9.7% and closed sales (including 174 presale units for the new Holomua project) increasing 37.1% for first quarter of 2013 as compared to the same period in 2012.

 

Hawaii’s petroleum product prices reflect supply and demand in the Asia-Pacific region and the price of crude oil in international markets. The dramatic reduction in Japan’s nuclear production following the tragic earthquake and tsunami in March 2011 has increased regional demand for energy supplies, including petroleum, and the prices of the utilities’ fuels have accordingly remained at the elevated 2011 level through 2012 and into 2013.

 

The Federal Open Market Committee (FOMC) maintained a highly accommodative stance of monetary policy in their continuing efforts to stimulate the U.S. economy. At its meeting on March 19-20, 2013, the FOMC held the federal funds rate target at 0% to 0.25% and expected to maintain the record low rates for at least as long as the unemployment rate is above 6.5% and the inflation outlook remained under control. The FOMC stated it will continue purchases of Treasury and agency mortgage-backed securities and employ other policy tools as appropriate to support progress toward the FOMC’s statutory mandate of maximum employment and price stability.

 

Overall, Hawaii’s economy is expected to see strengthening growth in 2013 and 2014 with local economic growth supported by continued expansion of the visitor industry and finally signs of recovery in the construction industry.  U.S. budget cuts, continued uncertainty in global economies, heightened tensions with North Korea and avian influenza pose possible risks to local economic growth. Despite economic improvement, the electric utilities’ kilowatt-hour sales declined in 2012. Based on expectations of additional customer renewable self-generation and energy-efficiency installations, the electric utilities’ 2013 and 2014 kilowatt-hour sales are expected to further decline below 2012 levels.

 

Recent tax developments.  The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 contained major tax provisions that impacted the Company through 2012, including the 50% and 100% bonus depreciation provisions for qualified property that resulted in an estimated net increase in federal tax depreciation of $116 million for 2012, primarily attributable to the utilities. In January 2013, the American Taxpayer Relief Act of 2012 was signed into law and provided a one year extension of 50% bonus depreciation, which is estimated to increase the Company’s federal tax depreciation for 2013 by $120 million, primarily attributable to the utilities.

 

The Internal Revenue Service (IRS) issued regulations that provide a general framework for determining whether expenditures are deductible as repairs, effective January 1, 2014. The IRS plans to issue final regulations related to repairs deductions in 2013. In the interim, the IRS has directed its examination teams to discontinue the current examination of these repairs issues and withdraw any proposed adjustments previously made in the examination of tax years prior to 2012. Once final regulations are issued, the Company will review the regulations and will analyze any subsequently issued transitional rules and guidance for their impacts and for the opportunities they present for the current and future years.

 

The IRS recently released a revenue procedure relating to deductions for repairs of generation property, which provides some guidance (that is elective) for taxpayers that own steam or electric generation property. This guidance defines the relevant components of generation property to be used in determining whether such component expenditures should be deducted as repairs or capitalized and depreciated by taxpayers. The revenue procedure also provides an extrapolation methodology that could be used by taxpayers in determining deductions for prior years’ repairs without going back to the specific documentation of those years. The guidance does not provide specific methods for determining the repairs amount. The utilities have begun to evaluate the costs and benefits of adopting this guidance, in order to determine whether and when the election should be made.

 

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.

 

Retirement benefits.  For the first quarter of 2013, the Company’s defined benefit pension and other postretirement benefit plans’ assets generated a gain, after investment management fees, of 6.5%. The market value of these assets

 

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as of March 31, 2013 was $1.2 billion (including $1.1 billion for the utilities) compared to $1.1 billion at December 31, 2012 (including $1.0 billion for the utilities).

 

The Company estimates that the cash funding for its defined benefit pension and other postretirement benefit plans in 2013 will be $86 million ($84 million by the utilities, $2 million by HEI and nil by ASB), which is expected to fully satisfy the minimum required contribution, including requirements of the utilities’ pension and other postretirement benefits tracking mechanisms and the plans’ funding policies.

 

Commitments and contingencies.  See Note 4, “Bank subsidiary,” of HEI’s “Notes to Consolidated Financial Statements” and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”

 

Recent accounting pronouncements.  See Note 11, “Recent accounting pronouncements,” of HEI’s “Notes to Consolidated Financial Statements.”

 

“Other” segment.

 

 

 

Three months ended March 31

 

%

 

 

 

(in thousands)

 

2013

 

2012

 

change

 

Primary reason(s) for significant change

 

Revenues

 

$

35

 

$

(2

)

NM

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating loss

 

(4,047

)

(4,350

)

NM

 

Lower administrative and general expenses

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

(4,905

)

(4,861

)

NM

 

Lower operating loss more than offset by slightly higher interest expense and lower income tax benefits

 

 

NM  Not meaningful.

 

The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; HEI Properties, Inc., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.

 

FINANCIAL CONDITION

 

Liquidity and capital resources.  The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements for the foreseeable future.

 

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

 

(dollars in millions)

 

March 31, 2013

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

Short-term borrowings—other than bank

 

$

134

 

4

%

$

84

 

3

%

Long-term debt, net—other than bank

 

1,423

 

45

 

1,423

 

45

 

Preferred stock of subsidiaries

 

34

 

1

 

34

 

1

 

Common stock equity

 

1,607

 

50

 

1,594

 

51

 

 

 

$

3,198

 

100

%

$

3,135

 

100

%

 

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

 

 

 

Three months ended
March 31, 2013

 

Balance

 

(in millions) 

 

Average balance

 

March 31, 2013

 

December 31, 2012

 

Short-term borrowings(1)

 

 

 

 

 

 

 

Commercial paper

 

$

84

 

$

91

 

$

84

 

Line of credit draws

 

 

 

 

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

 

 

 

125

 

125

 

 


(1)         This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are disclosed below under “Electric utility—Financial Condition—Liquidity and capital resources.” The maximum amount of HEI’s external short-term

 

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borrowings during the first quarter of 2013 was $96 million. At April 29, 2013, HEI had $89 million in outstanding commercial paper and its line of credit facility was undrawn.

 

HEI has a line of credit facility of $125 million (see Note 12 of HEI’s “Notes to Consolidated Financial Statements”). There are customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in the credit agreement, or meet other requirements may result in an event of default. For example, under the agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 19% as of March 31, 2013, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net Worth of $1.7 billion as of March 31, 2013, as calculated under the agreement), or if HEI no longer owns HECO. The commitment fee and interest charges on drawn amounts under the credit agreement are subject to adjustment in the event of a change in HEI’s long-term credit ratings.

 

The Company raised $11 million through the issuance of approximately 0.4 million shares of common stock under the DRIP, the HEIRSP, ASB 401(k) Plan and other plans during the first quarter of 2013.

 

In March 2013, HEI entered into equity forward transactions in which a forward counterparty borrowed 7 million shares of HEI’s common stock from third parties and such borrowed shares were sold pursuant to an HEI registered public offering. At March 31, 2013, the equity forward transactions could have been settled with physical delivery by HEI of 7 million newly-issued shares to the forward counterparty in exchange for cash of $180 million. HEI will not receive any proceeds from the sale of common stock until the equity forward transactions are settled. HEI anticipates physical settlement of the equity forward transactions before March 25, 2015.

 

On March 6, 2013, HEI issued $50 million of 3.99% Senior Notes due March 6, 2023 via a private placement.  HEI used the net proceeds from the issuance of the Senior Notes to refinance $50 million of its 5.25% medium-term notes that matured on March 7, 2013. The 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) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement. For example, see discussion of “Capitalization Ratio” and “Consolidated Net Worth” above.

 

For the first quarter of 2013, net cash provided by operating activities of consolidated HEI was $48 million. Net cash used by investing activities for the same period was $113 million, due to HECO’s consolidated capital expenditures, a net increase in ASB’s loans held for investment and purchases of investment and mortgage-related securities, partly offset by repayments of investment and mortgage-related securities and HECO’s contributions in aid of construction. Net cash provided by financing activities during this period was $107 million as a result of several factors, including net increases in deposit liabilities and short-term borrowings and proceeds from the issuance of common stock under HEI plans, partly offset by the payment of common 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 the first quarter of 2013, HECO and ASB (via ASHI) paid cash dividends to HEI of $20 million and $10 million, respectively.

 

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

 

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 48 to 49, 64 to 67, and 78 to 80 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.

 

Additional factors that may affect future results and financial condition are described on pages iv and v under “Forward-Looking Statements.”

 

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MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

 

In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

 

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s results of operations and financial condition, and currently require management’s most difficult, subjective or complex judgments.

 

For information about these material estimates and critical accounting policies, see pages 49 to 50, 67 to 68, and 80 to 81 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2012 Form 10-K.

 

Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.

 

Electric utility

 

RESULTS OF OPERATIONS

 

Utility strategic progress.  In 2012 and the first quarter of 2013, the utilities continued to make significant progress in implementing their renewable energy strategies and the PUC issued several important regulatory decisions, all of which 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 renewable energy and reliability on a more timely basis.

 

The utilities are committed to achieving or exceeding the State’s Renewable Portfolio Standard goal of 40% renewable energy by 2030 (see “Renewable energy strategy” below). In addition, while it will not take precedence over the utilities’ work to increase their use of renewable energy, the utilities are also working with the State of Hawaii and other entities to examine the possibility of using liquefied natural gas as a cleaner and lower cost fuel to replace, at least in part, the petroleum oil that would otherwise be used for the remaining generation.

 

RegulatoryIn January 2013, the utilities and Consumer Advocate signed a settlement agreement (2013 Agreement), which the PUC approved with clarifications in March 2013 (2013 D&O). See “Major projects” in Note 5 to HECO’s “Notes to Consolidated Financial Statements” and the discussion under “Most recent rate proceedings” below.

 

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 State of Hawaii’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The decoupling model implemented in Hawaii delinks revenues from sales and includes annual revenue adjustments for certain O&M expenses and rate base changes. The decoupling mechanism has three components: (1) a sales decoupling component via a revenue balancing account (RBA), (2) a revenue escalation component via a RAM and (3) an earnings sharing mechanism, which would provide for a reduction of revenues between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case. Decoupling provides for more timely cost recovery and earning on investments. The implementation of decoupling has resulted in an improvement in the utilities’ under-earning situation that has existed over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been well below PUC-allowed returns.

 

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

 

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

2.              managing O&M expenses relative to authorized O&M adjustments; and

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

 

Future earnings growth is also dependent on rate base growth. The utilities’ five-year 2013-2017 forecast reflects net capital expenditures of $2.9 billion and a compounded near-term annual rate base growth rate in the range of 5% to 10%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-

 

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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 (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.

 

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

 

%

 

Return on rate base (RORB)*

 

ROACE**

 

Rate-making ROACE***

 

Twelve months ended March 31, 2013

 

HECO

 

HELCO

 

MECO

 

HECO

 

HELCO

 

MECO

 

HECO

 

HELCO

 

MECO

 

Utility returns

 

7.78

 

6.44

 

7.06

 

6.97

 

5.07

 

7.41

 

9.53

 

6.83

 

8.65

 

PUC-allowed returns

 

8.11

 

8.31

 

7.91

 

10.00

 

10.00

 

10.00

 

10.00

 

10.00

 

10.00

 

Difference

 

(0.33

)

(1.87

)

(0.85

)

(3.03

)

(4.93

)

(2.59

)

(0.47

)

(3.17

)

(1.35

)

 


*

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

**

Recorded net income divided by average common equity.

***

ROACE adjusted to remove items not included by the PUC in establishing rates, such as the write-off of $40 million of CIS project costs, executive bonuses and advertising.

 

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

 

1) the timing of general rate case decisions,

2) the effective date of the RAMs,

3) the 5-year historical average for baseline plant additions, and

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

 

The structural gap in 2014 to 2016 is expected to be 80 to 110 basis points, an improvement of 40 basis points from management’s prior expectations. The improvement is due to the change in the timing of the recognition of the RAM revenues in 2014 to 2016 as defined in the settlement agreement approved by the PUC on March 19, 2013. For 2013, the structural gap remains unchanged at 120 to 150 basis points. Between rate cases, items not covered by the annual RAMs could also have a negative impact on the actual ROACEs achieved by the utilities (primarily investments in software projects, changes in fuel inventory and O&M in excess of indexed escalations). The specific magnitude of the impact will depend on various factors, including the size of software projects, changes in fuel prices and management’s ability to manage costs within the current mechanisms.

 

Management expects the earned ROACE to gradually improve from 2014 to 2016.

 

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 $40 million of CIS project costs pursuant to the 2013 Agreement, 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.

 

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Annual decoupling filings.  On March 28, 2013, HECO, HELCO and MECO submitted their annual decoupling filings for tariffed rates for each respective utility that will be effective from June 1, 2013 through May 31, 2014 unless the filing is modified or suspended by the PUC. Incremental annual changes included in the tariffed rates include: (1) the incremental RAM adjusted revenues (the components of which are shown below), (2) the accrued earnings sharing credits to be refunded, and (3) the amount of the accrued RBA balance as of December 31, 2012 (and associated revenue taxes) to be collected:

 

(in millions)

 

HECO

 

HELCO

 

MECO

 

Annual incremental RAM adjusted revenues

 

 

 

 

 

 

 

O&M

 

$

3.9

 

$

0.9

 

$

1.0

 

Invested capital

 

27.7

 

1.2

 

3.2

 

Total annual incremental RAM adjusted revenues

 

$

31.6

 

$

2.1

 

$

4.2

 

Accrued earnings sharing credits to be refunded

 

$

(2.1

)

$

 

$

 

Accrued RBA balance (and associated revenue taxes) to be collected

 

$

55.4

 

$

4.9

 

$

5.8

 

 

Under the 2011 decoupling tariff order, HECO, HELCO and MECO will accrue and collect 7/12ths of the annual incremental RAM adjusted revenues in one year and the remaining 5/12ths in the following year, provided the RAM rate adjustment remains in effect. The RAM rate adjustment terminates on the effective date of the D&O in a general rate case. However, based on the 2013 Agreement and 2013 D&O, HECO will be allowed to record incremental RAM revenues starting on January 1 of 2014, 2015 and 2016. See “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

 

See “Economic conditions” in the “HEI Consolidated” section above.

 

Results.

 

Three months ended
March 31

 

Increase

 

 

 

2013

 

2012

 

(decrease)

 

(in millions)

 

$

719

 

$

750

 

$

(31

)

Revenues. Decrease largely due to:

 

 

 

 

 

$

(37

)

Lower fuel prices and purchased power, partly offset by:

 

 

 

 

 

3

 

Interim rate increase granted to MECO in its 2012 test year rate case

 

 

 

 

 

1

 

Interim and final rate increases granted to HECO in its 2011 test year rate case

 

 

 

 

 

 

 

 

 

305

 

328

 

(23

)

Fuel oil expense. Decrease largely due to lower fuel prices and lower KWHs generated

 

 

 

 

 

 

 

 

 

153

 

165

 

(12

)

Purchased power expense. Decrease due to lower KWH purchased and lower purchase capacity/non-fuel charges

 

 

 

 

 

 

 

 

 

101

 

92

 

9

 

Other operation and maintenance expenses. Increase largely due to:

 

 

 

 

 

5

 

Higher customer service expenses

 

 

 

 

 

2

 

Reversal of 2011 expenses for the 200 MW RFP and CIS deferral costs in 2012

 

 

 

 

 

2

 

Higher employee benefit costs

 

 

 

 

 

(3

)

Partly offset by a 2012 increase in general liability reserve for an environmental matter

 

 

 

 

 

 

 

 

 

107

 

108

 

(1

)

Other expenses. Decrease largely due to lower taxes other than income taxes due to lower operating revenues, partially offset by higher depreciation due to an increase in plant additions

 

 

 

 

 

 

 

 

 

53

 

57

 

(4

)

Operating income. Decrease from prior year largely due to higher O&M and depreciation expenses, partly offset by interim and final rate increases

 

 

 

 

 

 

 

 

 

24

 

27

 

(3

)

Net income for common stock. Decrease largely due to lower operating income

 

 

 

 

 

 

 

 

 

2,123

 

2,251

 

(128

)

Kilowatthour sales (millions)

 

66.0

 

67.2

 

(1.2

)

Wet-bulb temperature (Oahu average; degrees Fahrenheit)

 

789

 

861

 

(72

)

Cooling degree days (Oahu)

 

$

130.83

 

$

134.37

 

$

(3.54

)

Average fuel oil cost per barrel

 

449,512

 

447,407

 

2,105

 

Customer accounts (end of period)

 

 

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Note:  The electric utilities had effective tax rates for the first quarters of 2013 and 2012 of 37% and 39%, respectively. The 2% decrease in the effective tax rate from the first quarter of 2012 was due to the receipt of nontaxable executive life insurance proceeds and the recognition of research and development credits which became available in 2013 under the American Taxpayer Relief Act of 2012.

 

HECO’s consolidated ROACE was 6.7% for the twelve months ended March 31, 2013 and 7.9% for the twelve months ended March 31, 2012.

 

Other operation and maintenance expenses (excluding expenses covered by surcharges or by third parties) for 2013 are projected to be flat to 1% higher than 2012, as the electric utilities expect to manage expenses to near-2012 levels.

 

Most recent rate proceedingsUnless otherwise agreed or ordered, each electric utility may initiate a PUC proceeding 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 ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

 

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

 

Test year
(dollars in millions)

 

Date
(applied/
implemented)

 

Amount

 

% over
rates in
effect

 

ROACE
(%)

 

RORB
(%)

 

Rate base

 

Common
equity
%

 

Stipulated
agreement
reached with
Consumer
Advocate

 

ROACE
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 (5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Request

 

8/16/12

 

$

19.8

 

4.2

 

10.25

 

8.30

 

$

455

 

57.05

 

 

 

Yes

 

Closed

 

3/27/13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of PUC-approved increases.

 

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(1)         In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 5 of HECO’s “Notes to Consolidated Financial Statements”).

 

(2)         Because the final increase was $7.4 million less in annual revenues, HECO refunded $2.1 million to customers (including interest) in February 2011.

 

(3)         HECO filed a request with the PUC for a general rate increase of $113.5 million, based on a 2011 test year and depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. HECO’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.

 

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

 

(4)         HELCO’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.

 

(5)         HELCO’s request was 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. As a result of the 2013 Agreement and 2013 D&O (described below), the rate case was withdrawn and the docket has been closed.

 

(6)         MECO’s interim increase, effective August 1, 2010, was based on a 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 order instructing MECO and the Consumer Advocate to submit a revised 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 case proceeding. On May 2, 2012, the PUC issued a 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 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.

 

(7)         MECO’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. See discussion below on interim decision and subsequent proposed adjustments to the interim increase.

 

HECO 2011 test year rate case.  In the HECO 2011 test year rate case, the PUC had 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) that were 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.

 

On January 28, 2013, HECO, HELCO, MECO and the Consumer Advocate entered into the 2013 Agreement to, among other things, write-off $40 million of CIS Project costs in lieu of conducting the regulatory audits of the CIP CT-1 and the CIS projects, with the remaining recoverable costs of $52 million to be included in rate base as of December 31, 2012. The parties agreed that HELCO would withdraw its 2013 test year rate case and not file a rate case until its next turn in the rate case cycle, for a 2016 test year, and HECO would delay the filing of its scheduled 2014 test year rate case to no earlier than January 2, 2014. The parties also agreed that starting in 2014, HECO will be allowed to record RAM revenues starting on January 1 of 2014, 2015 and 2016. On March 19, 2013, the PUC issued its 2013 D&O approving the 2013 Agreement, with clarifications. See “Major projects” in Note 5 of HECO’s Consolidated Financial Statements for additional information on the 2013 Agreement and the 2013 D&O and other effects.

 

MECO 2012 test year rate case.  On May 21, 2012, the PUC issued an interim D&O in MECO’s 2012 test year rate case, which became effective June 1, 2012. The D&O authorized MECO to reset its target heat rates by fuel type to 2012 test year levels for the purpose of calculating the energy cost adjustment clause (ECAC) adjustment factor, which will help to ensure MECO’s continuing recovery of its fuel costs. The interim increase is based on MECO’s updated stipulated agreement with the Consumer Advocate filed on May 14, 2012. On July 20, 2012, MECO and the Consumer Advocate filed a stipulated supplement to the stipulated agreement to reduce the test year revenue requirement by $0.1 million in administrative and general expenses and requested that the final D&O for this rate case incorporate the adjustment into the final 2012 test year revenue requirement.

 

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Renewable energy strategy.  The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills as they become less dependent on costly and price-volatile fossil fuel. The utilities’ renewable energy strategy will also allow them to meet Hawaii’s RPS law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. 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 not count toward the RPS after 2014. For 2012, HECO achieved an RPS without DSM energy savings of 13.9%, 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 2015 RPS.

 

Recent developments in the utilities’ renewable energy strategy include the following (also see the projects discussed under “Renewable Energy Projects” in Note 5 of HECO’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 subsequent lowering of MECO’s forecasted peaks, the projected capacity need date on the island of Maui has been deferred. 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 or deactivation of generating units. The scope of both RFPs will be further defined in the the utilities’ IRP, targeted to be filed with the PUC in June 2013. The respective schedules for the HECO and MECO RFPs will be assessed thereafter.

·                  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 to begin within five years of PUC approval. 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 Aina Koa Pono-Ka’u LLC (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 AKP, subject to PUC approval, to supply 16 million gallons of biodiesel per year with initial consumption to begin as early as 2015.

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

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

·                  In May 2012, HECO signed a contract, which was approved by the PUC, with the City and County of Honolulu to purchase an additional 27 MW of capacity and energy from an expanded waste-to-energy HPower facility expected to be placed in service in the second quarter of 2013.

·                  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. Army for construction of a 50 MW utility-owned and operated firm, renewable and dispatchable generation facility at Schofield Barracks on the island of Oahu and expected to be placed in service in 2017.

·                  In September 2012, 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.

 

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·                  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.

·                  In February 2013, HELCO issued the Final Geothermal RFP for up to 50 MW of dispatchable firm power on the island of Hawaii. Bids were received in April 2013 and are being evaluated.

·                  HECO, HELCO and MECO began accepting energy from feed-in tariff projects in 2011. As of March 31, 2013, there were 9 MW, 1 MW and 1 MW of installed feed-in tariff capacity from renewable energy technologies at HECO, HELCO and MECO, respectively.

·                  As of March 31, 2013, there were 105 MW, 24 MW and 27 MW 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 the first quarter of 2013 was more than twice the amount installed in the same quarter of 2012.

·                  In February 2013, HECO issued an “Invitation for Low Cost Renewable Energy Projects on Oahu Through Request for Waiver from Competitive Bidding.” The invitation for waiver projects seeks to lower the cost of electricity for customers in the near term with qualified renewable energy projects on Oahu that can be quickly placed into service at a low cost per kilowatt-hour. HECO will consider requesting a waiver from the PUC Competitive Bidding Framework for projects that meet these goals. Proposals were received in March 2013 and are being evaluated.

 

Commitments and contingencies.  See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

 

Recent accounting pronouncements.  See Note 8, “Recent accounting pronouncements,” of HECO’s “Notes to Consolidated Financial Statements.”

 

FINANCIAL CONDITION

 

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:

 

(dollars in millions)

 

March 31, 2013

 

December 31, 2012

 

Short-term borrowings

 

$

43

 

2

%

$

 

%

Long-term debt, net

 

1,148

 

42

 

1,148

 

43

 

Preferred stock

 

34

 

1

 

34

 

1

 

Common stock equity

 

1,477

 

55

 

1,472

 

56

 

 

 

$

2,702

 

100

%

$

2,654

 

100

%

 

Information about HECO’s short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows:

 

 

 

Average balance

 

Balance

 

(in millions) 

 

Three months ended
March 31, 2013

 

March 31,
2013

 

December 31,
2012

 

Short-term borrowings(1)

 

 

 

 

 

 

 

Commercial paper

 

$

36

 

$

43

 

$

 

Line of credit draws

 

 

 

 

Borrowings from HEI

 

 

 

 

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

 

 

 

175

 

175

 

 


(1)         The maximum amount of HECO’s external short-term borrowings during the first quarter of 2013 was $71 million. At March 31, 2013, HECO had $17 million of short-term borrowings from HELCO, and MECO had $13 million of short-term borrowings from HECO. At April 29, 2013, HECO had $40 million of outstanding commercial paper, no draws under its line of credit facility, no borrowings from HEI and $14 million of short-term borrowings from HELCO. Also, at April 29, 2013, MECO had $19 million of short-term borrowings from HECO. Intercompany borrowings are eliminated in consolidation.

 

HECO has a line of credit facility of $175 million (see Note 9 of HECO’s “Notes to Consolidated Financial Statements”). There are 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

 

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of the subsidiaries to 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 March 31, 2013, 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 March 31, 2013, as calculated under the credit agreement), or if HECO is no longer owned by HEI.

 

Revenue bonds have been issued by the Department of Budget and Finance of the State of Hawaii (DBF) to finance (and refinance) 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 by one of the following bond insurers: Ambac Assurance Corporation; Financial Guaranty Insurance Company, which was placed in a rehabilitation proceeding in the State of New York in June 2012; MBIA Insurance Corporation (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 Standard & Poor’s (S&P’s) and Moody’s Investor Service’s ratings of each of these insurers, which at the time the insured obligations were issued were higher than the ratings of the utilities, are currently either lower than the ratings of the utilities or have been withdrawn.

 

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.

 

Operating activities provided $54 million in net cash during the first quarter of 2013. Investing activities for the same period used net cash of $56 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $22 million, primarily due to the increase in short-term borrowings, partly offset by payment of $21 million of common and preferred dividends.

 

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Table of Contents

 

Bank

 

RESULTS OF OPERATIONS

 

 

 

Three months ended
March 31

 

Increase

 

 

 

(in millions)

 

2013

 

2012

 

(decrease)

 

Primary reason(s) for significant change

 

Interest income

 

$

46

 

$

49

 

$

(3

)

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 the first quarter of 2013 was $108 million higher than for the first quarter of 2012 as the average home equity lines of credit, commercial real estate and consumer loan balances increased by $89 million, $36 million and $28 million, respectively. ASB targeted these loan types because of their shorter duration and/or variable rates. The average residential loan portfolio decreased by $27 million due to higher repayments and loan sales during 2012. 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 increased by $54 million as ASB used its excess liquidity to purchase securities.

 

 

 

 

 

 

 

 

 

 

 

Noninterest income

 

19

 

16

 

3

 

Higher gain on sale of loans as more residential loans were sold in order to manage interest rate risk.

 

Revenues

 

65

 

65

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

2

 

3

 

(1

)

Lower funding costs as a result of the low interest rate environment. Average deposit balances for the first quarter of 2013 increased by $137 million compared to first quarter of 2012 due to an increase in core deposits of $209 million, partly offset by a decrease in term certificates of $72 million. The other borrowings average balance decreased by $40 million due to lower retail repurchase agreements.

 

 

 

 

 

 

 

 

 

 

 

Provision for loan losses

 

2

 

4

 

(2

)

The provision for loan losses benefited from lower net charge-offs and improved credit quality associated with the continued improvement in Hawaii’s economy. However, the provision was impacted by a single commercial real estate loan that was put on nonaccrual status.

 

 

 

 

 

 

 

 

 

 

 

Noninterest expense

 

39

 

35

 

4

 

Higher compensation and benefits expenses due to targeted staffing increases to support increased business volumes, IT and risk management capabilities.

 

Expenses

 

43

 

42

 

1

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

22

 

23

 

(1

)

Lower net interest income and higher noninterest expenses, partially offset by higher noninterest income.

 

Net income

 

14

 

16

 

(2

)

Lower operating income.

 

 

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Details of ASB’s other noninterest income and other noninterest expense were as follows:

 

Three months ended March 31

 

2013

 

2012

 

(in thousands)

 

 

 

 

 

Bank-owned life insurance

 

$

967

 

$

979

 

Other

 

625

 

381

 

Total other income, net

 

$

1,592

 

$

1,360

 

 

 

 

 

 

 

FDIC insurance premium

 

$

840

 

$

853

 

Marketing

 

538

 

550

 

Office supplies, printing and postage

 

873

 

990

 

Communication

 

471

 

436

 

Reversal of interest expense-tax

 

 

(552

)

Other

 

4,873

 

4,430

 

Total other expense

 

$

7,595

 

$

6,707

 

 

See Note 4 of HEI’s “Notes to Consolidated Financial Statements” and “Economic conditions” in the “HEI Consolidated” section above.

 

Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base and lower-risk profile to continue to deliver strong performance compared to industry peers.

 

For the quarter ended March 31, 2013, ASB reported a 1.12% annualized return on assets, net interest margin of 3.78% and a 61% efficiency ratio. For the year ended December 31, 2012, ASB reported a 1.18% return on assets, net interest margin of 3.93% and a 59% efficiency ratio.

 

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Average balance sheet and net interest margin.  The following tables set forth average balances, together with interest earned and accrued, and resulting yields and costs:

 

Three months ended March 31

 

2013

 

2012

 

(dollars in thousands)

 

Average
balance

 

Interest

 

Yield/
rate (%)

 

Average
balance

 

Interest

 

Yield/
rate (%)

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

Other investments (1)

 

$

198,202

 

$

64

 

0.13

 

$

251,615

 

$

97

 

0.15

 

Available-for-sale investment and mortgage-related securities

 

648,693

 

3,619

 

2.23

 

595,072

 

3,879

 

2.61

 

Loans(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

1,882,185

 

23,356

 

4.96

 

1,909,675

 

25,610

 

5.36

 

Commercial real estate

 

421,492

 

4,633

 

4.42

 

385,916

 

4,586

 

4.76

 

Home equity line of credit

 

640,151

 

4,462

 

2.83

 

550,790

 

3,770

 

2.75

 

Residential land

 

25,009

 

256

 

4.09

 

41,868

 

555

 

5.30

 

Commercial loans

 

711,707

 

7,469

 

4.24

 

712,599

 

7,959

 

4.49

 

Consumer loans

 

123,648

 

2,427

 

7.94

 

95,220

 

2,408

 

10.17

 

Total loans (3)

 

3,804,192

 

42,603

 

4.50

 

3,696,068

 

44,888

 

4.87

 

Total interest-earning assets (4)

 

4,651,087

 

46,286

 

4.00

 

4,542,755

 

48,864

 

4.31

 

Allowance for loan losses

 

(42,608

)

 

 

 

 

(38,187

)

 

 

 

 

Non-interest-earning assets

 

434,117

 

 

 

 

 

432,600

 

 

 

 

 

Total assets

 

$

5,042,596

 

 

 

 

 

$

4,937,168

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and shareholder’s equity:

 

 

 

 

 

 

 

 

 

 

 

 

 

Savings

 

$

1,775,477

 

254

 

0.06

 

$

1,698,849

 

310

 

0.07

 

Interest-bearing checking

 

640,190

 

24

 

0.02

 

605,526

 

30

 

0.02

 

Money market

 

195,563

 

63

 

0.13

 

249,685

 

121

 

0.19

 

Time certificates

 

469,798

 

971

 

0.84

 

541,330

 

1,318

 

0.98

 

Total interest-bearing deposits

 

3,081,028

 

1,312

 

0.17

 

3,095,390

 

1,779

 

0.23

 

Advances from Federal Home Loan Bank

 

50,000

 

535

 

4.28

 

50,000

 

541

 

4.28

 

Securities sold under agreements to repurchase

 

147,296

 

629

 

1.71

 

187,326

 

720

 

1.52

 

Total interest-bearing liabilities

 

3,278,324

 

2,476

 

0.30

 

3,332,716

 

3,040

 

0.36

 

Non-interest bearing liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Deposits

 

1,151,572

 

 

 

 

 

1,000,099

 

 

 

 

 

Other

 

110,850

 

 

 

 

 

110,913

 

 

 

 

 

Total liabilities

 

4,540,746

 

 

 

 

 

4,443,728

 

 

 

 

 

Shareholder’s equity

 

501,850

 

 

 

 

 

493,440

 

 

 

 

 

Total liabilities and shareholder’s equity

 

$

5,042,596

 

 

 

 

 

$

4,937,168

 

 

 

 

 

Net interest income

 

 

 

$

43,810

 

 

 

 

 

$

45,824

 

 

 

Net interest margin (%) (5)

 

 

 

 

 

3.78

 

 

 

 

 

4.04

 

 


(1)              Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle.

(2)              Includes loans held for sale.

(3)              Includes loan fees of $1.5 million and $1.1 million for the three months ended March 31, 2013 and 2012, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans, includes nonaccrual loans.

(4)              Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.2 million and $0.2 million for the three months ended March 31, 2013 and 2012, respectively.

(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 interest rate environment has been impacted by disruptions in the financial markets and these conditions have continued to have a negative impact on ASB’s net interest margin.

 

Loan originations and mortgage-related securities are ASB’s primary 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. The composition of ASB’s loan portfolio was as follows:

 

 

 

March 31, 2013

 

December 31, 2012

 

(dollars in thousands)

 

Balance

 

% of total

 

Balance

 

% of total

 

Real estate loans:

 

 

 

 

 

 

 

 

 

Residential 1-4 family

 

$

1,915,207

 

49.7

 

$

1,866,450

 

49.2

 

Commercial real estate

 

391,679

 

10.2

 

375,677

 

9.9

 

Home equity line of credit

 

648,904

 

16.8

 

630,175

 

16.6

 

Residential land

 

23,894

 

0.6

 

25,815

 

0.7

 

Commercial construction

 

40,698

 

1.1

 

43,988

 

1.2

 

Residential construction

 

8,275

 

0.2

 

6,171

 

0.2

 

Total real estate loans, net

 

3,028,657

 

78.6

 

2,948,276

 

77.8

 

 

 

 

 

 

 

 

 

 

 

Commercial loans

 

699,918

 

18.1

 

721,349

 

19.0

 

Consumer loans

 

127,260

 

3.3

 

121,231

 

3.2

 

 

 

3,855,835

 

100.0

 

3,790,856

 

100.0

 

Less: Deferred fees and discounts

 

(10,103

)

 

 

(11,638

)

 

 

Allowance for loan losses

 

(42,730

)

 

 

(41,985

)

 

 

Total loans, net

 

$

3,803,002

 

 

 

$

3,737,233

 

 

 

 

The increase in the total loan portfolio during the first quarter of 2013 was primarily due to an increase in originated ASB’s residential 1-4 family, home equity lines of credit and commercial real estate loan portfolios and is in line with ASB’s target of mid-single digit growth for the year.

 

Loan portfolio risk elements.  See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

 

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

 

 

 

March 31, 2013

 

December 31,2012

 

(dollars in thousands)

 

Balance

 

% of total

 

Balance

 

% of total

 

Federal agency obligations

 

$

167,960

 

26

%

$

171,491

 

26

%

Mortgage-related securities — FNMA, FHLMC and GNMA

 

409,339

 

62

 

417,383

 

62

 

Municipal bonds

 

82,101

 

12

 

82,484

 

12

 

 

 

$

659,400

 

100

%

$

671,358

 

100

%

 

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer and, in the case of GNMA, backed by the full faith and credit of the U.S.

 

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. Advances from the FHLB of Seattle have remained at $50 million from December 31, 2012 to March 31, 2013. As of March 31, 2013 and December 31, 2012, ASB’s costing liabilities consisted of 96% deposits and 4% other borrowings. The weighted average cost of deposits for the first quarter of 2013 was 0.12%, compared to 0.17% for the first quarter of 2012.

 

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

 

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translate into decreases and increases in the fair value of those instruments, respectively. In addition, changes in credit spreads also impact the fair values of those instruments.

 

As of March 31, 2013 and December 31, 2012, 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 $10 million and $11 million, respectively. See “Item 3. Quantitative and qualitative disclosures about market risk.”

 

During the first quarter of 2013, ASB recorded a provision for loan losses of $1.9 million primarily due to charge-offs during the quarter for 1-4 family, residential land, commercial and consumer loans. During the first quarter of 2012, ASB recorded a provision for loan losses of $3.5 million primarily due to charge-offs during the quarter for 1-4 family, residential land, commercial and consumer loans. Continued financial stress on ASB’s customers may result in higher levels of delinquencies and losses.

 

 

 

Three months ended
March 31

 

Year ended
December 31

 

(in thousands)

 

2013

 

2012

 

2012

 

Allowance for loan losses, January 1

 

$

41,985

 

$

37,906

 

$

37,906

 

Provision for loan losses

 

1,858

 

3,546

 

12,883

 

Less: net charge-offs

 

1,113

 

2,618

 

8,804

 

Allowance for loan losses, end of period

 

$

42,730

 

$

38,834

 

$

41,985

 

Ratio of allowance for loan losses, end of period, to end of period loans outstanding

 

1.11

%

1.05

%

1.11

%

Ratio of net charge-offs during the period to average loans outstanding (annualized)

 

0.12

%

0.28

%

0.24

%

 

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

 

Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act).  Regulation of the financial services industry, including regulation of HEI, ASHI and ASB, has changed and will continue to change as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI, ASHI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the Office of Thrift Supervision transferred to the OCC, the FDIC, the Federal Reserve Board (FRB) and the Consumer Financial Protection Bureau (Bureau). Supervision and regulation of HEI and ASHI, as a thrift holding companies, moved to the FRB, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change, the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the FRB, OCC and the Bureau. HEI will 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 to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.

 

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

 

The Dodd-Frank Act established the Bureau. It has authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. On December 21, 2012, the Bureau issued the Remittance Rule (an amendment to Regulation E) which closed 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

 

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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 closed for comment on February 25, 2013. For mortgages, under the proposed Ability-to-Repay rule, among other things, (i) potential borrowers will have to supply financial information, and lenders must verify it, (ii) to qualify for a particular loan, a consumer will have to have sufficient assets or income to pay back the loan, and (iii) lenders will have to determine the consumer’s ability to repay both the principal and the interest over the long term - not just during an introductory period when the rate may be lower.

 

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

 

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

 

The “Durbin Amendment” to the Dodd-Frank Act required the FRB to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. In June 2011, the FRB issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. 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. For the first quarter of 2013, ASB had earned an average of 49 cents per transaction. However, market pressures could cause all banks to observe the limitation.

 

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

 

Proposed Capital Rules.  The FRB, OCC and FDIC issued three notices of proposed rulemaking (NPR) that would revise and replace the current 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 Requirements (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 the Basel II standardized

 

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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 are subject to the banking agencies’ advanced approaches rule, or to their market 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, management believes ASB and HEI can satisfy the proposed capital rules that would be applicable to them, if adopted.

 

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

 

FINANCIAL CONDITION

 

Liquidity and capital resources.

 

(dollars in millions)

 

March 31,
2013

 

December 31,
2012

 

% change

 

Total assets

 

$

5,116

 

$

5,042

 

1

 

Available-for-sale investment and mortgage-related securities

 

659

 

671

 

(2

)

Loans receivable held for investment, net

 

3,803

 

3,737

 

2

 

Deposit liabilities

 

4,313

 

4,230

 

2

 

Other bank borrowings

 

193

 

196

 

(1

)

 

As of March 31, 2013, ASB was one of Hawaii’s largest financial institutions based on assets of $5.1 billion and deposits of $4.3 billion.

 

As of March 31, 2013, ASB’s unused FHLB borrowing capacity was approximately $1.0 billion. As of March 31, 2013, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.6 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

 

For the first quarter of 2013, net cash provided by ASB’s operating activities was $30 million. Net cash used during the same period by ASB’s investing activities was $56 million, primarily due to purchases of investment and mortgage-related securities of $27 million, a net increase in loans receivable of $67 million and additions to premises and equipment of $3 million, partly offset by repayments of investment and mortgage-related securities of $37 million and proceeds from the sale of real estate acquired in settlement of loans of $3 million. Net cash provided in financing activities during this period was $67 million, primarily due to net increases in deposit liabilities of $83 million, partly offset by a net decrease in retail repurchase agreements of $3 million, the payment of $10 million in common stock dividends to HEI (through ASHI) and a net decrease in mortgage escrow deposits of $3 million.

 

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 March 31, 2013, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.1% (5.0%), a Tier-1 risk-based capital ratio of 11.7% (6.0%) and a total risk-based capital ratio of 12.8% (10.0%). FRB approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

 

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s results of operations, financial condition and liquidity. For additional quantitative and qualitative information about the Company’s market risks, see pages 82 to 84, HEI’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2012 Form 10-K and HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 2012 Form 10-K by reference to Exhibit 99.2.

 

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

 

 

 

Change in NII
(gradual change in interest rates)

 

Change in EVE
(instantaneous change in interest rates)

 

Change in interest rates
(basis points)

 

March 31,
2013

 

December 31,
2012

 

March 31,
2013

 

December 31,
2012

 

+300

 

3.1

%

1.6

%

(4.7

)%

(9.4

)%

+200

 

1.5

 

0.5

 

(1.9

)

(4.9

)

+100

 

0.6

 

0.1

 

(0.5

)

(1.9

)

-100

 

(0.2

)

(0.2

)

(3.8

)

(1.7

)

 

Management believes that ASB’s interest rate risk position as of March 31, 2013 represents a reasonable level of risk. Net interest income (NII) sensitivity as of March 31, 2013 was more asset sensitive for increases in rates compared to December 31, 2012 due to changes in the mix of earning assets as more short-term interest earning assets were held as of March 31, 2013 compared to December 31, 2012 and changes in assumptions about the rate sensitivity of certain core deposits.

 

ASB’s base economic value of equity (EVE) increased to $833 million as of March 31, 2013 compared to $767 million as of December 31, 2012 due to changes in the assumptions about the behavior of core deposits.

 

The change in EVE was less sensitive to rising rate scenarios as of March 31, 2013 compared to December 31, 2012 due to growth and changes in the composition of the residential portfolio and changes in the assumptions about the behavior of core deposits.

 

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity and the percentage change in EVE is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

 

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Item 4. Controls and Procedures

 

HEI:

 

Changes in Internal Control over Financial Reporting

 

During the first quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of March 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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 March 31, 2013. Based on their evaluations, as of March 31, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) 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.

 

HECO:

 

Changes in Internal Control over Financial Reporting

 

During the first quarter of 2013, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of March 31, 2013 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

 

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 March 31, 2013. Based on their evaluations, as of March 31, 2013, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) 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.

 

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PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings

 

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Note 4 of HEI’s “Notes to Consolidated Financial Statements” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

 

Item 1A. Risk Factors

 

The following are updated risk factors for HEI, the electric utilities and ASB:

 

Holding Company and Company-Wide Risks.

 

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

 

·                  the provisions of an HEI agreement with the PUC, which could limit the ability of HEI’s principal electric public utility subsidiary, 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 March 31, 2013) upon request of the regulators in order to maintain ASB’s regulatory capital at the level required by regulation;

 

·                  the minimum capital and capital distribution regulations of the OCC that are applicable to ASB;

 

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

 

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

 

The Company is subject to risks associated with the Hawaii economy (in the aggregate and on an individual island basis), volatile U.S. capital markets and changes in the interest rate and credit market environment that have and/or could result in higher retirement benefit plan funding requirements, declines in electric utility KWH sales, declines in ASB’s interest rate margins and investment values, higher delinquencies and charge-offs in ASB’s loan portfolio and restrictions on the ability of HEI or its subsidiaries to borrow money or issue securities.  The two largest components of Hawaii’s economy are tourism and the federal government (including the military). Because the core businesses of HEI’s subsidiaries are providing local public electric utility services (through HECO and its subsidiaries) and banking services (through ASB) in Hawaii, the Company’s operating results are significantly influenced by Hawaii’s economy, which in turn is influenced by economic conditions in the mainland U.S. (particularly California) and Asia (particularly Japan) as a result of the impact of those conditions on tourism, by the impact of interest rates on the construction and real estate industries and by the impact of world conditions (e.g., U.S. presence in Afghanistan) on federal government spending in Hawaii. For example, the turmoil in the financial

 

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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, 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.

 

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 borrowing costs would likely increase with resulting reductions in HEI’s consolidated net income in future periods. Further, if HEI’s or HECO’s commercial paper ratings were to be 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, respectively. Disruptions in the credit markets, a liquidity crisis in the banking industry or increased levels of residential mortgage delinquencies and defaults may result in decreases in the fair value of ASB’s investment securities and an impairment that is other-than-temporary, requiring ASB to write down its investment securities. As of March 31, 2013, 88% of ASB’s investment securities were securities and obligations issued by a federal agency or government sponsored entity that have an implicit guarantee from the U.S. government.

 

HEI and HECO and their subsidiaries may incur higher retirement benefits expenses and have and will likely continue to recognize substantial liabilities for retirement benefitsRetirement 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 postretirement benefits other than pensions (OPEB) tracking mechanisms, have been an allowable expense for rate-making purposes.

 

The Company is subject to the risks associated with the geographic concentration of its businesses and current lack of interconnections that could result in service interruptions at the electric utilities or higher default rates on loans held by ASBThe 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 necessary to maintain higher generation reserve margins than are typical for U.S. mainland utilities to help ensure reliable service. Service interruptions, including in particular extended interruptions that could result from a natural disaster or terrorist activity, could adversely impact the KWH sales of some or all of the electric utility subsidiaries.

 

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Substantially all of ASB’s consumer loan customers are Hawaii residents. A significant portion of the commercial loan customers are located in Hawaii. While a majority of customers are on Oahu, ASB also has customers on the neighbor islands (whose economies have been weaker than Oahu during the recent economic downturn). Substantially all of the real estate underlying ASB’s residential and commercial real estate loans are located in Hawaii. These assets may be subject to a greater risk of default than other comparable assets held by financial institutions with other geographic concentrations in the event of adverse economic, political or business developments or natural disasters affecting Hawaii and the ability of ASB’s customers to make payments of principal and interest on their loans.

 

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

 

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

 

·                  HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration. With the exception of certain identified projects, the utilities are required to use competitive bidding to acquire a future generation resource unless the PUC finds competitive bidding to be unsuitable. The PUC set policies for DG interconnection agreements and standby rates, and established conditions under which electric utilities can provide DG services on customer-owned sites as a regulated service. The results of competitive bidding, competition from IPPs, customer self-generation and the rate at which technological developments facilitating non-utility generation of electricity occur may adversely affect the utilities and the results of their operations.

 

·                 New technological developments, such as the commercial development of energy storage, may render the operations of 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 reputation.  The 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

 

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deductibles 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 $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 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 income or in significant net losses for the affected periods.

 

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

 

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

 

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

 

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

 

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

 

Changes in accounting principles and estimates could affect the reported amounts of the Company’s assets and liabilities or revenues and expenses.  HEI’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the U.S. Changes in accounting principles (including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards), or changes in the Company’s application of existing accounting principles, could materially affect the financial statement presentation

 

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of HEI’s or the electric utilities’ consolidated results of operations and/or financial condition. Further, in preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant change include the amounts reported for investment and mortgage-related securities; property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; electric utility revenues; and allowance for loan losses. 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 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 $874 million as of March 31, 2013) 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 $326 million as of March 31, 2013) 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 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 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’ results of operations, financial condition and liquidity. The PUC has broad discretion over the rates that the electric utilities charge their customers. The electric utilities currently have rate cases pending before the PUC. In addition, as part of the decoupling mechanism that the electric utilities have implemented, each of the electric utilities will file a rate case once every three years. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the items and amounts that may be included in rate base, the returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding could have a material adverse effect on HECO’s consolidated results of operations, financial condition and 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 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, integrated resource plan cost recovery dockets and other proceedings, if and to the extent they exceed the amounts allowed in final orders.

 

Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. For example, HECO’s East Oahu Transmission Project

 

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encountered substantial opposition and consequent delay, increased costs and a subsequent partial write-off of costs in the fourth quarter of 2011. Also, in January 2013, the utilities and the Consumer Advocate signed a settlement agreement to write off $40 million of costs in lieu of conducting PUC-ordered regulatory audits of the CIP CT-1 and the CIS projects.

 

Energy cost adjustment clauses. The rate schedules of each of 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.

 

The Energy Agreement confirms the intent of the parties that the existing ECACs will continue, but subject to periodic review by the PUC. The Energy Agreement also provides that as part of the review, the PUC may examine whether there are renewable energy projects from which the utilities should have, but did not, purchase energy or whether alternative fuel purchase strategies were appropriately used or not used.

 

In the recent rate cases, the PUC has allowed the current ECAC to continue. However, a change in, or the elimination of, the ECAC could have a material adverse effect on the electric utilities.

 

Electric utility operations are significantly influenced by weather conditions.  The electric utilities’ results of operations can be affected by the weather. Weather conditions, particularly temperature and humidity, directly influence the demand for electricity. In addition, severe weather and natural disasters, such as hurricanes, earthquakes, tsunamis and lightning storms, which may become more severe or frequent as a result of global 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 73% of the net energy generated or purchased by the electric utilities in 2012 was generated from the burning of fossil fuel oil, and purchases of power by the electric utilities provided about 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 the 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, inability to comply with regulatory or permit requirements, disruptions in delivery of electricity, operator error and catastrophic events such as earthquakes, tsunamis, hurricanes, fires, explosions, floods or other similar occurrences affecting the electric utilities’ generating facilities or transmission and distribution systems. 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 electric utilities may be adversely affected by new legislation.  Congress, the Hawaii legislature and governmental agencies periodically consider legislation and other initiatives that could have uncertain or negative effects on the electric utilities and their customers. Congress, the Hawaii legislature and governmental agencies have adopted, or are considering adopting, a number of measures that will significantly affect the electric utilities, as described below.

 

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Renewable Portfolio Standards law. In 2009, Hawaii’s RPS law was amended to require electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. Energy savings resulting from energy efficiency programs will not count toward the RPS after 2014. The utilities are committed to achieving these goals and met the 2010 RPS; however, due to the exclusion of energy savings in calculating RPS after 2014 and risks such as potential delays in IPPs being able to deliver contracted renewable energy, it is possible the 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 of $20 for every megawatthour (MWh) that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated, as described in the RPS law and in an RPS framework adopted by the PUC. In addition, the PUC ordered that the utilities will be prohibited from recovering any RPS penalty costs through rates.

 

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

 

Global climate change and greenhouse gas emissions reduction. National and international concern about climate change and the contribution of GHG emissions to climate change have led to action by the state of Hawaii and the EPA and federal legislative and regulatory proposals to reduce GHG emissions.

 

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii.

 

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

 

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

 

On June 3, 2010, the EPA’s final “Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas (GHG) Tailoring Rule” (GHG Tailoring Rule) was published. It creates a new emissions threshold for GHG emissions from new and existing facilities and requires certain facilities to obtain PSD and Title V operating permits. The utilities 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. The foregoing legislation or legislation that now is, or may in the future be, proposed 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 liquidity may be adversely impacted in meeting the commitments and objectives of the HCEI Energy Agreement.  On October 20, 2008, the Governor of the State of Hawaii, the 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 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 energy efficiency and conservation.

 

The far-reaching nature of the Energy Agreement, including the extent of renewable energy commitments, presents risks to the Company. Among such risks are: (1) the dependence on third party suppliers of renewable purchased energy, which if the utilities are unsuccessful in negotiating purchased power agreements with such

 

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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 infrastructure is not installed or does not operate effectively; (4) the likelihood that the utilities may need to make substantial investments in related infrastructure, which could result in increased borrowings and, therefore, materially impact the financial condition and liquidity of the utilities; and (5) the commitment to support a variety of initiatives, which, if approved by the PUC, may have a material impact on the results of operations and financial condition of the utilities depending on their design and implementation. These initiatives include, but are not limited to, removing the system-wide caps on net energy metering (but studying distributed generation interconnections on a per-circuit basis); and developing an Energy Efficiency Portfolio Standard. The implementation of these or other HCEI programs may adversely impact the results of operations, financial condition and liquidity of the 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 paymentsInterest rate risk is a significant risk of ASB’s operations. ASB’s net interest income consists primarily of interest income received on fixed-rate and adjustable-rate loans, mortgage-related securities and investments and interest expense consisting primarily of interest paid on deposits and other borrowings. Interest rate risk arises when earning assets mature or when their interest rates change in a time frame different from that of the costing liabilities. Changes in market interest rates, including changes in the relationship between short-term and long-term market interest rates or between different interest rate indices, can impact ASB’s net interest margin.

 

Although ASB pursues an asset-liability management strategy designed to mitigate its risk from changes in market interest rates, unfavorable movements in interest rates could result in lower net interest income. Residential 1-4 family fixed-rate mortgage loans comprised about 48% of ASB’s loan portfolio as of March 31, 2013 and do not re-price with movements in interest rates. ASB continues to face a challenging interest rate environment. The persistent, low level of interest rates and excess liquidity in the financial system have impacted the new loan production rates and made it challenging to find investments with adequate risk-adjusted returns, which resulted in a negative impact on ASB’s asset yields and net interest margin. The degree to which compression of ASB’s margin will continue when interest rates rise is uncertain.

 

Increases in market interest rates could have an adverse impact on ASB’s cost of funds. Higher market interest rates could lead to higher interest rates paid on deposits and other borrowings. Significant increases in market interest rates, or the perception that an increase may occur, could adversely affect ASB’s ability to originate new loans and grow. An increase in market interest rates, especially a sudden increase, could also adversely affect the ability of ASB’s adjustable-rate borrowers to meet their higher payment obligations. If this occurred, it could cause an increase in nonperforming assets and charge-offs. Conversely, a decrease in interest rates or a mismatching of maturities of interest sensitive financial instruments could result in an acceleration in the prepayment of loans and mortgage-related securities and impact ASB’s ability to reinvest its liquidity in similar yielding assets. Historically low interest rates in 2010, 2011 and 2012 resulted in higher 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;

 

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

 

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

 

·                  changes in ASB’s loan portfolio credit profiles and asset quality, which may increase or decrease the required level of allowance for loan losses;

 

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

 

·                  the impact of 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 OCC and the FDIC, and is subject to reserve requirements established by the Board of Governors of the Federal Reserve System. In addition, the FRB is responsible for regulating ASB’s holding companies, HEI and ASHI. The regulatory authorities have extensive discretion in connection with their supervisory and enforcement activities and examination policies to address not only ASB’s compliance with applicable banking laws and regulations, but also capital adequacy, asset quality, management ability and performance, earnings, liquidity and various other factors.

 

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

 

Recent legislative and regulatory initiatives could have an adverse effect on ASB’s business.  The Dodd-Frank Act, which became law in July 2010, 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 HEI and ASB in substantial and unpredictable ways. A major component of the Dodd-Frank Act is the creation of the Consumer Financial Protection Bureau that has the

 

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responsibility for setting and enforcing clear, consistent rules relating to consumer financial products and services and has the authority to prohibit practices it finds to be unfair, deceptive or abusive. Compliance with any such directives could have adverse effects on ASB’s revenues or operating costs. Failure to comply with laws, regulations or policies could result in sanctions by regulatory agencies, civil money penalties and/or reputation damage, which could have a material adverse effect on ASB’s business, results of operations, financial condition and liquidity.

 

A large percentage of ASB’s loans and securities are collateralized by real estate, and adverse changes in the real estate market and/or general economic or other conditions may result in loan losses and adversely affect the Company’s profitability.  As of March 31, 2013 approximately 79% of ASB’s loan portfolio was comprised of loans primarily collateralized by real estate, most of which was concentrated in the State of Hawaii. ASB’s HELOC (home equity line of credit) portfolio grew by 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 employment conditions, the monetary and fiscal policies of the federal and state government and other significant external events. A deterioration of the economic environment in Hawaii, including a material decline in the real estate market, further declines in home resales, or a material external shock, or any environmental clean-up obligation, may significantly impair the value of ASB’s collateral and ASB’s ability to sell the collateral upon foreclosure. In the event of a default, amounts received upon sale of the collateral may be insufficient to recover outstanding principal and interest. Adverse changes in the economy may also have a negative effect on the ability of borrowers to make timely repayments of their loans. In addition, if poor economic conditions result in decreased demand for real estate loans, ASB’s profits may decrease if alternative investments earn less income than real estate loans.

 

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

 

Generally, both commercial and commercial real estate loans have shorter terms to maturity and earn higher spreads than residential mortgage loans. Only the assets of the business typically secure commercial loans. In such cases, upon default, any collateral repossessed may not be sufficient to repay the outstanding loan balance. In addition, loan collections are dependent on the borrower’s continuing financial stability and, thus, are more likely to be affected by current economic conditions and adverse business developments. ASB has grown its national syndicated lending portfolio where ASB is a participant in credit facilities agented by established and reputable national lenders. Management selectively chooses each deal based on conservative credit criteria to ensure a high quality, well diversified portfolio.

 

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

 

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Item 5. Other Information

 

A.            Ratio of earnings to fixed charges.

 

 

 

Three months ended
March 31

 

Years ended December 31

 

 

 

2013

 

2012

 

2012

 

2011

 

2010

 

2009

 

2008

 

HEI and Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Excluding interest on ASB deposits

 

3.22

 

3.63

 

3.28

 

3.22

 

2.89

 

2.29

 

2.06

 

Including interest on ASB deposits

 

3.11

 

3.44

 

3.14

 

3.03

 

2.64

 

1.95

 

1.71

 

HECO and Subsidiaries

 

3.32

 

3.77

 

3.37

 

3.52

 

2.88

 

2.99

 

3.48

 

 

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

 

B.            Description of HEI’s Common Stock and Preferred Stock.

 

Under our Amended and Restated Articles of Incorporation (Articles), we are authorized to issue 200,000,000 shares of common stock without par value (common stock) and 10,000,000 shares of preferred stock without par value (preferred stock). As of March 19, 2013, 98,467,907 shares of common stock were issued and outstanding and no shares of preferred stock were designated, issued or outstanding.

 

The following is a description of the general terms and provisions of our capital stock and does not purport to be complete and is subject to and qualified in its entirety by reference to the Articles and the Bylaws.

 

Common stock

 

General. The outstanding shares of common stock, other than shares of restricted stock previously issued under HEI’s Stock Option and Incentive Plan of 1987 (as amended and restated) or issued from time to time under HEI’s 2010 Equity and Incentive Plan (as amended and restated) until such restrictions are satisfied, are fully paid and nonassessable. Additional shares of common stock, when issued pursuant to proper authorization, will be fully paid and nonassessable when the consideration for which HEI’s Board of Directors authorizes their issuance has been received by HEI. The holders of common stock have no preemptive rights and there are no applicable conversion, redemption or sinking fund provisions.

 

Common stock is transferable at the Shareholder Services Office of the Company, American Savings Bank Tower, 8th Floor, 1001 Bishop Street, Honolulu, Hawaii 96813, and at the office of Continental Stock Transfer & Trust Company, Co-Transfer Agent and Registrar, 17 Battery Place, New York, New York 10004. Shares of common stock may either be certificated or uncertificated.

 

Dividend Rights and Limitations. Stock and cash dividends may be issued and paid to the holders of common stock as and when declared by our Board of Directors, provided that, after giving effect to the payment of cash dividends, HEI is able to pay its debts as they become due in the usual course of its business and HEI’s total assets are not less than the sum of its total liabilities plus the maximum amount that then would be payable in any liquidation in respect of all outstanding shares having preferential rights in liquidation. All shares of common stock are entitled to participate equally with respect to dividends.

 

HEI is a legal entity separate and distinct from its various subsidiaries. As a holding company with no significant operations of its own, the principal sources of its funds are dividends or other distributions from its operating subsidiaries, borrowings and sales of equity. The ability of certain of HEI’s direct and indirect subsidiaries to pay dividends or make other distributions to HEI, or to make loans or extend credit to or purchase assets from HEI, is subject to contractual, statutory and regulatory restrictions, including without limitation the provisions of an agreement with the PUC (pertaining to HEI’s electric utility subsidiaries) and the minimum capital requirements imposed by law on ASB, as well as restrictions and limitations set forth in debt instruments, preferred stock resolutions and guarantees. HEI does not expect that the regulatory and contractual restrictions applicable to HEI or its direct or indirect subsidiaries will significantly affect HEI’s ability to pay dividends on its common stock. See “Business—HEI Consolidated—Regulation—Restrictions on dividends and other distributions” in HEI’s Annual Report on Form 10-K

 

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for the year ended December 31, 2012 for a more complete description of the ability of certain of HEI’s subsidiaries to pay dividends or make other distributions to HEI.

 

Liquidation Rights. In the event of any liquidation, dissolution, receivership, bankruptcy, disincorporation or winding-up of the affairs of HEI, voluntarily or involuntarily, holders of common stock are entitled to any assets of HEI available for distribution to HEI’s stockholders after the payment in full of any amounts owing to its creditors and any preferential amounts to which holders of any preferred stock may be entitled. All shares of common stock will rank equally in the event of liquidation.

 

Voting Rights. Holders of common stock are entitled to one vote per share, subject to such limitation or loss of right as may be provided in resolutions which may be adopted by the Board of Directors of HEI from time to time creating series of preferred stock or otherwise. The annual meeting of shareholders is held on the date and at the time designated by the Board of Directors, or, if it does not act, by the Chairman of the Board of Directors, or, in the Chairman’s absence or disability, by the President. A shareholder may bring business before the annual meeting only if the shareholder complies with the advance notice and other requirements specified in the Bylaws. A special meeting of shareholders can be called by the Board of Directors, the Chairman of the Board of Directors, the President or upon written demand of shareholders entitled under Hawaii law to make such a demand in the manner prescribed by Hawaii law and in accordance with the advance notice provisions in the Bylaws. At annual and special meetings of stockholders, the presence in person or by proxy of holders of a majority of the outstanding shares of common stock constitutes a quorum, the election of directors requires a plurality of votes cast at a meeting at which a quorum is present and any other action may be approved at a meeting where a quorum is present and due notification of the proposed action has been given if the votes cast in favor of the action exceed the votes cast opposing the action, except (a) as otherwise required by law, (b) as provided in the Articles, (c) as provided in the Bylaws (including with respect to the amendment of certain provisions of the Bylaws) and/or (d) as may be provided in resolutions that may be adopted from time to time creating series of preferred stock or otherwise.

 

Under the current Bylaws, the Board of Directors is to consist of not less than five nor more than eighteen members, with the Board of Directors having the authority to fix the exact number of directors so long as the number is not less than five nor more than eighteen. Nominations for election to the Board of Directors may be made only by or at the direction of the Board of Directors (or a duly authorized committee of the Board of Directors) or by a shareholder who meets the requirements specified in the Bylaws and complies with the advance notice provisions set forth in the Bylaws. So long as there are at least nine directors, one-third (as nearly as possible) of the total number of directors is elected at each annual meeting of stockholders and, under Hawaii law, no holder of common stock is entitled to cumulate votes in an election of directors so long as HEI shall have a class of equity securities registered pursuant to the Exchange Act that is listed on a national securities exchange or traded over-the-counter on the National Market System of the National Association of Securities Dealers, Inc. Automated Quotation System. Under the Bylaws, directors may be removed from office at a special meeting of shareholders properly called for that purpose.

 

Subject to compliance with any applicable advance notice provisions, the Bylaws may be amended by the affirmative vote of a majority of the entire Board of Directors, or at the annual meeting of shareholders or a special meeting of shareholders called for that purpose by the affirmative vote of a majority of shares represented and entitled to vote at such meeting, except that any provision of the Bylaws for which a greater vote is required by the Articles, the Bylaws or by law may itself be amended only by such greater vote. In addition, an amendment to the provisions in the Bylaws relating to (1) matters which may be properly brought before an annual meeting, (2) who may call a special meeting and matters which may be brought before a special meeting, (3) cumulative voting, (4) the number, the manner of fixing the number and the staggered terms of members of the Board of Directors, (5) removal of directors and (6) restricting the amendment of certain provisions of the Bylaws must in each case be approved either (a) by the affirmative vote of 80% of the shares entitled to vote generally with respect to the election of directors voting together as a single class or (b) by the affirmative vote of a majority of the entire Board of Directors plus a concurring vote of a majority of the “continuing directors” (as that term is defined in the Bylaws) voting separately and as a subclass of directors.

 

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The provisions of HEI’s Bylaws referred to in the foregoing two paragraphs, and the statutory provisions referred to below, may have the effect of delaying, deferring or preventing a change in control of HEI.

 

Preferred stock

 

Preferred stock may be authorized by the Board of Directors for issuance in one or more series, without action by stockholders and with such preferences, voting powers, restrictions and qualifications as may be fixed by resolution of the Board of Directors authorizing the issuance of those shares. Under current Hawaii law, all shares of a series of preferred stock must have preferences, limitations and relative rights identical with those of other shares of the same series and, except to the extent otherwise provided in the description of the series, with those of other series in the same class. Under the current Articles, there is no restriction on the repurchase or redemption of shares of preferred stock at a time when there is an arrearage in the payment of dividends or sinking fund installments.

 

If and when authorized by the Board of Directors, preferred stock may be preferred as to dividends or in liquidation, or both, over the common stock. For example, the terms of the preferred stock, if and when authorized, could prohibit dividends on shares of common stock until all dividends and any mandatory redemptions have been paid with respect to shares of preferred stock. In addition, the Board of Directors may, without stockholder approval, issue preferred stock with voting and conversion rights which could adversely affect the voting power or economic rights of the holders of common stock. Issuance of preferred stock by HEI could thus have the effect of delaying, deferring or preventing a change of control of HEI.

 

Restriction on purchases of shares and consequences of substantial holdings under certain Hawaii and federal laws

 

Provisions of Hawaii and federal law, some of which are described below, place restrictions on the acquisition of beneficial ownership of 5% or more of the voting power of HEI. The following does not purport to be a complete enumeration of all of these provisions, nor does it purport to be a complete description of the statutory provisions that are enumerated. Persons contemplating the acquisition of 5% or more of the issued and outstanding shares of HEI’s common stock should consult with their legal and financial advisors concerning statutory and other restrictions on such acquisitions.

 

The Hawaii Control Share Acquisition Act places restrictions on the acquisition of ranges of voting power (starting at 10% and at 10% intervals up to a majority) for the election of directors of HEI unless the acquiring person obtains approval of the acquisition, in the manner specified in the Hawaii Control Share Acquisition Act, by the affirmative vote of the holders of a majority of the voting power of all shares entitled to vote, exclusive of the shares beneficially owned by the acquiring person, and consummates the proposed control share acquisition within 180 days after shareholder approval. If such approval is not obtained, the statute provides that the shares acquired may not be voted for a period of one year from the date of acquisition, the shares will be nontransferable on HEI’s books for one year after acquisition and HEI, during the one-year period, has the right to call the shares for redemption either at the prices at which the shares were acquired or at book value per share as of the last day of the fiscal quarter ended prior to the date of the call for redemption.

 

Under provisions of the Hawaii Business Corporation Act, subject to certain exceptions, HEI may not be a party to a merger or consolidation unless the merger or consolidation is approved by the holders of at least 75% of all of the issued and outstanding voting stock of HEI.

 

Under provisions of Hawaii law regulating public utilities, not more than 25% of the issued and outstanding voting stock of certain public utility corporations, including HECO and its wholly-owned electric utility subsidiaries, may be held, directly or indirectly, by any single foreign corporation or any single nonresident alien, or held by any person, without the prior approval of the PUC. The acquisition of more than 25% of the issued and outstanding voting stock of HEI in one or more transactions might be deemed to result in the holding of more than 25% of the voting stock of its electric utility subsidiaries. In addition, HEI is subject to an agreement entered into with the PUC when HECO became a wholly-owned subsidiary of HEI. This agreement provides that the acquisition of HEI by a third party, whether by purchase, merger, consolidation or otherwise, requires the prior written approval of the PUC.

 

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Federal law restricts acquisitions of a federal savings bank and any entity considered to be its holding company by establishing thresholds of “control” the acquisition of which requires prior regulatory approval and by limiting the types of persons and entities eligible to acquire such control. The primary federal banking regulator of ASB historically was the Office of Thrift Supervision (OTS), but the OTS was abolished on July 21, 2011 and its supervisory and regulatory functions have been transferred to the OCC. As a result of HEI’s indirect ownership of ASB, both HEI and ASHI, the direct parent corporation of ASB, are also subject to a certain degree of regulation as “unitary savings and loan holding companies” (i.e., companies which control one savings association). The supervision and regulation of HEI and ASHI have been moved to the FRB effective July 21, 2011. Since 1999, companies that engage in activities not permitted to financial services companies under federal law are not permitted to acquire control, directly or indirectly, of a savings institution. Nonfinancial companies that owned savings institutions prior to May 4, 1999, such as HEI and ASHI, however, are considered “grandfathered” so that HEI and its subsidiaries are able to continue to engage in their current activities and retain ownership of ASB. The effect of this prohibition therefore is that any acquisition of HEI by a third party is likely to require HEI to divest ASB or its assets and liabilities. The divestiture would be required to occur within a two year period following the FRB’s approval of the acquisition of HEI. Federal law also limits the entities eligible to acquire ASB or its assets and liabilities generally to those that engage in activities permissible to bank and financial holding companies under the Bank Holding Company Act.

 

The thresholds of “control” which will trigger the need for notice to the FRB and, in certain instances, prior FRB approval are set forth in federal statutes and FRB regulations. Generally, no existing savings and loan holding company may acquire direct or indirect ownership or control of more than 5% of the outstanding voting stock of a federal savings bank or its holding company without the prior written approval of the FRB. In addition, no other company or person may acquire control of a federal savings bank or savings and loan holding company, unless the FRB provides prior written approval. “Control” in this context means (i) the acquisition of, control of, or holding proxies representing, more than 25% of the voting shares of HEI or (ii) the power to control in any manner the election of a majority of the directors of HEI or (iii) the power, directly or indirectly, to exercise a controlling influence over the management or policies of HEI. A person that contributes more than 25% of the capital of HEI would also be deemed to control HEI. Moreover, under FRB regulations, one would be presumed to have acquired control if one acquires 10% or more of the voting shares of HEI or, in some circumstances, more than 5% of such voting shares. Any company subject to a preliminary determination of control by the FRB because it triggered a control presumption or was deemed to have the power to exercise a controlling influence over HEI may contest the determination and request a hearing, may file an application to retain the control relationship or may propose a plan to the FRB for prompt termination of the control relationship. The FRB may also deem acquisitions of less than 25% of the voting shares of HEI to be passive and noncontrolling, on the condition that the investor enter into certain passivity commitments with the FRB.

 

Dividend reinvestment and stock purchase plan

 

Any individual of legal age or entity is eligible to participate in the HEI Dividend Reinvestment and Stock Purchase Plan by making an initial cash investment in common stock, subject to applicable laws and regulations and the requirements of the plan. Holders of common stock, and holders of preferred stock of HEI’s electric utility subsidiaries, may automatically reinvest some or all of their dividends to purchase additional shares of common stock at market prices (as defined in the plan). Participants in the plan may also purchase additional shares of common stock at market prices (as defined in the plan) by making cash contributions to the plan. HEI reserves the right to suspend, modify or terminate the plan at any time. Shares of common stock issued under the plan may either be newly issued shares or shares purchased by the plan on the open market. Participants do not pay brokerage commissions or service charges in connection with purchases of newly issued shares, but do pay their pro rata share of brokerage commissions if the plan purchases shares for participants on the open market.

 

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Item 6. Exhibits

 

HEI Exhibit 12.1

 

Hawaiian Electric Industries, Inc. and Subsidiaries

Computation of ratio of earnings to fixed charges, three months ended March 31, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008

 

 

 

HEI Exhibit 31.1

 

Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)

 

 

 

HEI Exhibit 31.2

 

Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer)

 

 

 

HEI Exhibit 32.1

 

HEI Certification Pursuant to 18 U.S.C. Section 1350

 

 

 

HEI Exhibit 101.INS

 

XBRL Instance Document

 

 

 

HEI Exhibit 101.SCH

 

XBRL Taxonomy Extension Schema Document

 

 

 

HEI Exhibit 101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

 

HEI Exhibit 101.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document

 

 

 

HEI Exhibit 101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document

 

 

 

HEI Exhibit 101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document

 

 

 

HECO Exhibit 12.2

 

Hawaiian Electric Company, Inc. and Subsidiaries

Computation of ratio of earnings to fixed charges, three months ended March 31, 2013 and 2012 and years ended December 31, 2012, 2011, 2010, 2009 and 2008

 

 

 

HECO Exhibit 31.3

 

Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer)

 

 

 

HECO Exhibit 31.4

 

Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)

 

 

 

HECO Exhibit 32.2

 

HECO Certification Pursuant to 18 U.S.C. Section 1350

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.

 

HAWAIIAN ELECTRIC INDUSTRIES, INC.

 

HAWAIIAN ELECTRIC COMPANY, INC.

(Registrant)

 

(Registrant)

 

 

 

 

 

 

 

 

By

/s/ Constance H. Lau

 

By

/s/ Richard M. Rosenblum

 

Constance H. Lau

 

 

Richard M. Rosenblum

 

President and Chief Executive Officer

 

 

President and Chief Executive Officer

 

(Principal Executive Officer of HEI)

 

 

(Principal Executive Officer of HECO)

 

 

 

 

 

 

 

 

 

 

By

/s/ James A. Ajello

 

By

/s/ Tayne S. Y. Sekimura

 

James A. Ajello

 

 

Tayne S. Y. Sekimura

 

Executive Vice President,

 

 

Senior Vice President

 

Chief Financial Officer and Treasurer

 

 

and Chief Financial Officer

 

(Principal Financial Officer of HEI)

 

 

(Principal Financial Officer of HECO)

 

 

 

 

 

 

 

 

 

 

By

/s/ Jennifer B. Loo

 

By

/s/ Cathlynn L. Yoshida

 

Jennifer B. Loo

 

 

Cathlynn L. Yoshida

 

Interim Chief Accounting Officer

 

 

Controller

 

and Assistant Controller

 

 

(Principal Accounting Officer of HECO)

 

(Principal Accounting Officer of HEI)

 

 

 

 

 

 

Date:  May 8, 2013

 

Date:  May 8, 2013

 

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