Form 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 June 30, 2008

OR

 

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

 

 

HAWAIIAN ELECTRIC INDUSTRIES, INC.

Exact Name of Registrant as Specified in Its Charter

 

Commission File Number   I.R.S. Employer Identification No.
1-8503   99-0208097

and Principal Subsidiary

HAWAIIAN ELECTRIC COMPANY, INC.

Exact Name of Registrant as Specified in Its Charter

 

Commission File Number   I.R.S. Employer Identification No.
1-4955   99-0040500

 

 

State of Hawaii

(State or other jurisdiction of incorporation or organization)

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 Registrant Hawaiian Electric Industries, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. 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. (Check one):

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

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

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 July 30, 2008

Hawaiian Electric Industries, Inc. (Without Par Value)

  84,725,379 Shares

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

  12,805,843 Shares (not publicly traded)

 

 

 


Table of Contents

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q - Quarter ended June 30, 2008

INDEX

 

Page No.

         
ii    Glossary of Terms
iv    Forward-Looking Statements
   PART I. FINANCIAL INFORMATION
   Item 1.    Financial Statements
      Hawaiian Electric Industries, Inc. and Subsidiaries
1       Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2008 and 2007
2       Consolidated Balance Sheets (unaudited) - June 30, 2008 and December 31, 2007
3       Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - six months ended June 30, 2008 and 2007
4       Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2008 and 2007
5       Notes to Consolidated Financial Statements (unaudited)
      Hawaiian Electric Company, Inc. and Subsidiaries
16       Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2008 and 2007
17       Consolidated Balance Sheets (unaudited) – June 30, 2008 and December 31, 2007
18       Consolidated Statements of Changes in Common Stock Equity (unaudited) - six months ended June 30, 2008 and 2007
19       Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2008 and 2007
20       Notes to Consolidated Financial Statements (unaudited)
38    Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
38       HEI Consolidated
44       Electric Utilities
65       Bank
70    Item 3.    Quantitative and Qualitative Disclosures About Market Risk
71    Item 4.    Controls and Procedures
   PART II. OTHER INFORMATION
72    Item 1.    Legal Proceedings
72    Item 1A.    Risk Factors
72    Item 2    Unregistered Sales of Equity Securities and Use of Proceeds
72    Item 4.    Submission of Matters to a Vote of Security Holders
73    Item 5.    Other Information
74    Item 6.    Exhibits
75    Signatures

 

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Table of Contents

Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q - Quarter ended June 30, 2008

GLOSSARY OF TERMS

 

Terms

  

Definitions

AFUDC

   Allowance for funds used during construction

AOCI

   Accumulated other comprehensive income

ASB

   American Savings Bank, F.S.B., a wholly-owned subsidiary of HEI Diversified, Inc. and parent company of American Savings Investment Services Corp. (and its subsidiary, Bishop Insurance Agency of Hawaii, Inc.). Former subsidiaries include ASB Service Corporation (dissolved in January 2004), ASB Realty Corporation (dissolved in May 2005) and AdCommunications, Inc. (dissolved in May 2007).

CHP

   Combined heat and power

Company

  

When used in Hawaiian Electric Industries, Inc. sections, the “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); HEI Diversified, Inc. and its subsidiary, American Savings Bank, F.S.B. and its subsidiaries (listed under ASB); Pacific Energy Conservation Services, Inc.; HEI Properties, Inc.; HEI Investments, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.). Former subsidiaries of HEI (other than former subsidiaries of HECO and ASB and former subsidiaries of HEI sold or dissolved prior to 2004) include Hycap Management, Inc. (dissolution completed in 2007); Hawaiian Electric Industries Capital Trust I (dissolved and terminated in 2004)*, HEI Preferred Funding, LP (dissolved and terminated in 2004)*, Malama Pacific Corp. (discontinued operations, dissolved in June 2004), and HEI Power Corp. (discontinued operations, dissolved in 2006) and its dissolved subsidiaries. (*unconsolidated subsidiaries as of January 1, 2004) .

 

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

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

DBEDT

   State of Hawaii Department of Business, Economic Development and Tourism

D&O

   Decision and order

DG

   Distributed generation

DOD

   Department of Defense – federal

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

EITF

   Emerging Issues Task Force

EPA

   Environmental Protection Agency – federal

Exchange Act

   Securities Exchange Act of 1934

FASB

   Financial Accounting Standards Board

federal

   U.S. Government

FHLB

   Federal Home Loan Bank

FIN

   Financial Accounting Standards Board Interpretation No.

GAAP

   U.S. generally accepted accounting principles

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, Renewable Hawaii, Inc., Uluwehiokama Biofuels Corp. and HECO Capital Trust III. Former subsidiaries include HECO Capital Trust I (dissolved and terminated in 2004)* and HECO Capital Trust II (dissolved and terminated in 2004)*. (*unconsolidated subsidiaries as of January 1, 2004).

 

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Table of Contents

GLOSSARY OF TERMS, continued

 

Terms

  

Definitions

HEI

   Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., HEI Investments, 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.). Former subsidiaries (other than those sold or dissolved prior to 2004) are listed under Company.

HEIDI

   HEI Diversified, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.

HEIII

   HEI Investments, Inc. (formerly HEI Investment Corp.), a wholly owned subsidiary of Hawaiian Electric Industries, Inc.

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

IRP

   Integrated resource plan

Kalaeloa

   Kalaeloa Partners, L.P.

kV

   Kilovolt

kw

   Kilowatts

KWH

   Kilowatthour

MECO

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

MW

   Megawatt/s (as applicable)

NII

   Net interest income

NPV

   Net portfolio value

NQSO

   Nonqualified stock option

OPEB

   Postretirement benefits other than pensions

OTS

   Office of Thrift Supervision, Department of Treasury

PPA

   Power purchase agreement

PRPs

   Potentially responsible parties

PUC

   Public Utilities Commission of the State of Hawaii

RHI

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

ROACE

   Return on average common equity

ROR

   Return on average rate base

RPS

   Renewable portfolio standards

SAR

   Stock appreciation right

SEC

   Securities and Exchange Commission

See

   Means the referenced material is incorporated by reference

SFAS

   Statement of Financial Accounting Standards

SOIP

   1987 Stock Option and Incentive Plan, as amended

SPRBs

   Special Purpose Revenue Bonds

TOOTS

   The Old Oahu Tug Service, a wholly owned subsidiary of Hawaiian Electric Industries, Inc.

UBC

   Uluwehiokama Biofuels Corp., a newly formed, 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 and 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 in forward-looking statements and from historical results include, but are not limited to, the following:

 

   

the effects of international, national and local economic conditions, including the state of the Hawaii tourist 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 and mortgage-related securities held by American Savings Bank, F.S.B. (ASB)) and decisions concerning the extent of the presence of the federal government and military in Hawaii;

 

   

the effects of weather and natural disasters, such as hurricanes, earthquakes, tsunamis and the potential effects of global warming;

 

   

global developments, including the effects of terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan, potential conflict or crisis with North Korea and in the Middle East, Iran’s nuclear activities and potential avian flu pandemic;

 

   

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 financing;

 

   

the risks inherent in changes in the value of and market for securities available for sale and in the value of pension and other retirement plan assets;

 

   

changes in assumptions used to calculate retirement benefits costs and changes in funding requirements;

 

   

increasing competition in the electric utility and banking industries (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and increased price competition for deposits, or an outflow of deposits to alternative investments, may have an adverse impact on ASB’s cost of funds);

 

   

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

 

   

increased risk to generation reliability as generation peak reserve margins on Oahu continue to be strained;

 

   

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

 

   

the 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 and its subsidiaries) or their competitors;

 

   

federal, state and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (including changes in taxation, environmental laws and regulations, the potential regulation of greenhouse gas emissions and governmental fees and assessments); decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases (including decisions on ECACs) and other proceedings 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, for example with respect to environmental conditions or renewable portfolio standards (RPS)); enforcement actions by the Office of Thrift Supervision (OTS) and other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under the Bank Secrecy Act or other regulatory requirements or with respect to capital adequacy);

 

   

increasing operation and maintenance expenses for the electric utilities, resulting in the need for more frequent rate cases, and increasing noninterest expenses at ASB;

 

   

the risks associated with the geographic concentration of HEI’s businesses;

 

   

the effects of changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the adoption of new accounting principles, continued regulatory accounting under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” to PPAs with independent power producers;

 

   

the effects of 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;

 

   

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; and

 

   

other risks or uncertainties described elsewhere in this report and in other periodic 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.

 

iv


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
June 30
    Six months ended
June 30
 

(in thousands, except per share amounts and ratio of earnings to fixed charges)

   2008     2007     2008     2007  

Revenues

        

Electric utility

   $ 688,121     $ 492,712     $ 1,312,010     $ 940,390  

Bank

     85,950       107,526       191,794       211,986  

Other

     (16 )     525       (132 )     2,410  
                                
     774,055       600,763       1,503,672       1,154,786  
                                

Expenses

        

Electric utility

     632,725       463,923       1,205,631       898,609  

Bank

     116,942       87,832       199,423       173,864  

Other

     2,786       3,699       6,270       8,463  
                                
     752,453       555,454       1,411,324       1,080,936  
                                

Operating income (loss)

        

Electric utility

     55,396       28,789       106,379       41,781  

Bank

     (30,992 )     19,694       (7,629 )     38,122  

Other

     (2,802 )     (3,174 )     (6,402 )     (6,053 )
                                
     21,602       45,309       92,348       73,850  
                                

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

     (18,186 )     (19,282 )     (37,435 )     (39,793 )

Allowance for borrowed funds used during construction

     835       586       1,597       1,184  

Preferred stock dividends of subsidiaries

     (473 )     (473 )     (946 )     (946 )

Allowance for equity funds used during construction

     2,105       1,202       4,006       2,434  
                                

Income from before income taxes

     5,883       27,342       59,570       36,729  

Income taxes

     747       9,793       20,467       12,416  
                                

Net income

   $ 5,136     $ 17,549     $ 39,103     $ 24,313  
                                

Basic earnings per common share

   $ 0.06     $ 0.21     $ 0.47     $ 0.30  
                                

Diluted earnings per common share

   $ 0.06     $ 0.21     $ 0.47     $ 0.30  
                                

Dividends per common share

   $ 0.31     $ 0.31     $ 0.62     $ 0.62  
                                

Weighted-average number of common shares outstanding

     84,052       81,907       83,762       81,679  

Dilutive effect of stock-based compensation

     103       217       60       227  
                                

Adjusted weighted-average shares

     84,155       82,124       83,822       81,906  
                                

Ratio of earnings to fixed charges (SEC method)

        

Excluding interest on ASB deposits

         1.75       1.44  
                                

Including interest on ASB deposits

         1.52       1.29  
                                

See accompanying “Notes to Consolidated Financial Statements” for HEI.

 

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Table of Contents

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

 

(dollars in thousands)

   June 30,
2008
    December 31,
2007
 
Assets     

Cash and equivalents

   $ 147,774     $ 145,855  

Federal funds sold

     10,433       64,000  

Accounts receivable and unbilled revenues, net

     323,011       294,447  

Available-for-sale investment and mortgage-related securities

     887,162       2,140,772  

Investment in stock of Federal Home Loan Bank of Seattle (estimated fair value $97,764)

     97,764       97,764  

Loans receivable, net

     4,121,379       4,101,193  

Property, plant and equipment, net of accumulated depreciation of $1,800,911, and $1,749,386

     2,782,950       2,743,410  

Regulatory assets

     278,645       284,990  

Other

     449,998       338,405  

Goodwill, net

     83,080       83,080  
                
   $ 9,182,196     $ 10,293,916  
                

Liabilities and stockholders’ equity

    

Liabilities

    

Accounts payable

   $ 248,173     $ 202,299  

Deposit liabilities

     4,270,470       4,347,260  

Short-term borrowings - other than bank

     221,952       91,780  

Other bank borrowings

     634,148       1,810,669  

Long-term debt, net - other than bank

     1,206,965       1,242,099  

Deferred income taxes

     162,892       155,337  

Regulatory liabilities

     275,835       261,606  

Contributions in aid of construction

     302,925       299,737  

Other

     527,703       573,409  
                
     7,851,063       8,984,196  
                

Minority interests

    

Preferred stock of subsidiaries - not subject to mandatory redemption

     34,293       34,293  
                

Stockholders’ 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: 84,646,451 shares and 83,431,513 shares

     1,099,948       1,072,101  

Retained earnings

     212,275       225,168  

Accumulated other comprehensive loss, net of tax benefits

     (15,383 )     (21,842 )
                
     1,296,840       1,275,427  
                
   $ 9,182,196     $ 10,293,916  
                

See accompanying “Notes to Consolidated Financial Statements” for HEI.

 

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Table of Contents

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (unaudited)

 

     Common stock    Retained    

Accumulated
other

comprehensive

       

(in thousands, except per share amounts)

   Shares    Amount    earnings     loss     Total  

Balance, December 31, 2007

   83,432    $ 1,072,101    $ 225,168     $ (21,842 )   $ 1,275,427  

Comprehensive income:

            

Net income

   —        —        39,103       —         39,103  

Net unrealized losses on securities:

            

Net unrealized losses on securities arising during the period, net of tax benefits of $2,847

   —        —        —         (4,312 )     (4,312 )

Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $6,915

   —        —        —         10,473       10,473  

Retirement benefit plans:

            

Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,848

   —        —        —         2,916       2,916  

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $1,668

   —        —        —         (2,618 )     (2,618 )
                                    

Comprehensive income

   —        —        39,103       6,459       45,562  
                                    

Issuance of common stock, net

   1,214      27,847      —         —         27,847  

Common stock dividends ($0.62 per share)

   —        —        (51,996 )     —         (51,996 )
                                    

Balance, June 30, 2008

   84,646    $ 1,099,948    $ 212,275     $ (15,383 )   $ 1,296,840  
                                    

Balance, December 31, 2006

   81,461    $ 1,028,101    $ 242,667     $ (175,528 )   $ 1,095,240  

Comprehensive income:

            

Net income

   —        —        24,313       —         24,313  

Net unrealized losses on securities arising during the period, net of tax benefits of $1,989

   —        —        —         (3,012 )     (3,012 )

Retirement benefit plans - amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of taxes of $2,622

   —        —        —         4,108       4,108  
                                    

Comprehensive income

   —        —        24,313       1,096       25,409  
                                    

Adjustment to initially apply a PUC D&O related to defined benefit retirement plans, net of taxes of $11,595

   —        —        —         18,205       18,205  

Adjustment to initially apply FIN 48

   —        —        (228 )     —         (228 )

Issuance of common stock, net

   930      20,461      —         —         20,461  

Common stock dividends ($0.62 per share)

   —        —        (50,689 )     —         (50,689 )
                                    

Balance, June 30, 2007

   82,391    $ 1,048,562    $ 216,063     $ (156,227 )   $ 1,108,398  
                                    

See accompanying “Notes to Consolidated Financial Statements” for HEI.

 

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

 

Six months ended June 30

   2008     2007  
(in thousands)             

Cash flows from operating activities

    

Net income

   $ 39,103     $ 24,313  

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

    

Depreciation of property, plant and equipment

     75,733       74,057  

Other amortization

     4,203       4,576  

Provision for loan losses

     2,055       1,200  

Writedown of utility plant

     —         11,701  

Deferred income taxes

     (585 )     (12,120 )

Allowance for equity funds used during construction

     (4,006 )     (2,434 )

Excess tax benefits from share-based payment arrangements

     (613 )     (259 )

Loans receivable originated and purchased, held for sale

     (114,591 )     (19,174 )

Proceeds from sale of loans receivable, held for sale

     124,526       27,439  

Net loss on sale of investment and mortgage-related securities

     17,388       —    

Changes in assets and liabilities

    

Increase in accounts receivable and unbilled revenues, net

     (28,564 )     (2,351 )

Increase in fuel oil stock

     (69,254 )     (24,148 )

Increase in accounts payable

     45,874       6,436  

Change in prepaid and accrued taxes

     (68,490 )     (7,136 )

Changes in other assets and liabilities

     (6,327 )     (2,685 )
                

Net cash provided by operating activities

     16,452       79,415  
                

Cash flows from investing activities

    

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

     (376,809 )     (199,315 )

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

     329,669       258,625  

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

     1,291,609       —    

Proceeds from sale of investments

     —         8,775  

Net increase in loans held for investment

     (29,359 )     (114,094 )

Capital expenditures

     (101,976 )     (79,886 )

Contributions in aid of construction

     7,263       7,576  

Other

     750       458  
                

Net cash provided by (used in) investing activities

     1,121,147       (117,861 )
                

Cash flows from financing activities

    

Net decrease in deposit liabilities

     (76,790 )     (143,207 )

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

     130,172       (50,807 )

Net increase (decrease) in retail repurchase agreements

     (20,380 )     35,199  

Proceeds from other bank borrowings

     508,584       550,897  

Repayments of other bank borrowings

     (1,662,119 )     (436,385 )

Proceeds from issuance of long-term debt

     14,802       221,327  

Repayment of long-term debt

     (50,000 )     (126,000 )

Excess tax benefits from share-based payment arrangements

     613       259  

Net proceeds from issuance of common stock

     15,473       8,341  

Common stock dividends

     (41,497 )     (40,480 )

Decrease in cash overdraft

     (8,582 )     (9,098 )

Other

     477       (1,594 )
                

Net cash provided by (used in) financing activities

     (1,189,247 )     8,452  
                

Net decrease in cash and equivalents and federal funds sold

     (51,648 )     (29,994 )

Cash and equivalents and federal funds sold, beginning of period

     209,855       257,301  
                

Cash and equivalents and federal funds sold, end of period

   $ 158,207     $ 227,307  
                

See accompanying “Notes to Consolidated Financial Statements” for HEI.

 

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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 should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HEI’s Form 10-K for the year ended December 31, 2007 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2008.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the Company’s financial position as of June 30, 2008 and December 31, 2007 and the results of its operations for the three and six months ended June 30, 2008 and 2007 and its cash flows for the six months ended June 30, 2008 and 2007. 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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(2) Segment financial information

 

(in thousands)

   Electric Utility    Bank     Other     Total

Three months ended June 30, 2008

         

Revenues from external customers

   $ 688,087    $ 85,950     $ 18     $ 774,055

Intersegment revenues (eliminations)

     34      —         (34 )     —  
                             

Revenues

     688,121      85,950       (16 )     774,055
                             

Profit (loss)*

     44,329      (31,014 )     (7,432 )     5,883

Income taxes (benefit)

     16,897      (12,921 )     (3,229 )     747
                             

Net income (loss)

     27,432      (18,093 )     (4,203 )     5,136
                             

Six months ended June 30, 2008

         

Revenues from external customers

     1,311,936      191,794       (58 )     1,503,672

Intersegment revenues (eliminations)

     74      —         (74 )     —  
                             

Revenues

     1,312,010      191,794       (132 )     1,503,672
                             

Profit (loss)*

     84,135      (7,673 )     (16,892 )     59,570

Income taxes (benefit)

     32,118      (4,156 )     (7,495 )     20,467
                             

Net income (loss)

     52,017      (3,517 )     (9,397 )     39,103
                             

Assets (at June 30, 2008)

     3,586,441      5,585,278       10,477       9,182,196
                             

Three months ended June 30, 2007

         

Revenues from external customers

   $ 492,651    $ 107,526     $ 586     $ 600,763

Intersegment revenues (eliminations)

     61      —         (61 )     —  
                             

Revenues

     492,712      107,526       525       600,763
                             

Profit (loss)*

     17,168      19,746       (9,572 )     27,342

Income taxes (benefit)

     6,518      7,164       (3,889 )     9,793
                             

Net income (loss)

     10,650      12,582       (5,683 )     17,549
                             

Six months ended June 30, 2007

         

Revenues from external customers

     940,259      211,986       2,541       1,154,786

Intersegment revenues (eliminations)

     131      —         (131 )     —  
                             

Revenues

     940,390      211,986       2,410       1,154,786
                             

Profit (loss)*

     17,308      38,145       (18,724 )     36,729

Income taxes (benefit)

     6,205      13,967       (7,756 )     12,416
                             

Net income (loss)

     11,103      24,178       (10,968 )     24,313
                             

Assets (at June 30, 2007)

     3,128,278      6,817,246       12,032       9,957,556
                             

 

* Income (loss) before income taxes.

Intercompany electric sales of consolidated HECO 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.

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.

 

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(3) Electric utility subsidiary

For HECO’s consolidated financial information, including its contingencies, see pages 16 through 37.

(4) Bank subsidiary

Selected financial information

American Savings Bank, F.S.B. and Subsidiaries

Consolidated Statements of Income Data (unaudited)

 

     Three months ended
June 30
   Six months ended
June 30

(in thousands)

   2008     2007    2008     2007

Interest and dividend income

         

Interest and fees on loans

   $ 61,747     $ 60,093    $ 125,212     $ 120,374

Interest and dividends on investment and mortgage-related securities

     22,729       30,428      47,180       58,593
                             
     84,476       90,521      172,392       178,967
                             

Interest expense

         

Interest on deposit liabilities

     15,619       20,832      33,839       41,570

Interest on other borrowings

     16,265       18,581      35,414       36,987
                             
     31,884       39,413      69,253       78,557
                             

Net interest income

     52,592       51,108      103,139       100,410

Provision for loan losses

     1,155       1,200      2,055       1,200
                             

Net interest income after provision for loan losses

     51,437       49,908      101,084       99,210
                             

Noninterest income

         

Fees from other financial services

     5,413       6,885      12,236       13,386

Fee income on deposit liabilities

     6,767       6,457      13,561       12,512

Fee income on other financial products

     1,639       1,856      3,443       3,868

Loss on sale of securities

     (18,323 )     —        (17,388 )     —  

Other income

     5,978       1,807      7,550       3,253
                             
     1,474       17,005      19,402       33,019
                             

Noninterest expense

         

Compensation and employee benefits

     19,039       18,164      37,279       36,560

Occupancy

     5,390       5,341      10,787       10,289

Equipment

     3,221       3,785      6,335       7,263

Services

     4,170       7,895      9,843       16,253

Data processing

     2,609       2,646      5,225       5,203

Loss on early extinguishment of debt

     39,843       —        39,843       —  

Other expense

     9,653       9,336      18,847       18,516
                             
     83,925       47,167      128,159       94,084
                             

Income (loss) before income taxes

     (31,014 )     19,746      (7,673 )     38,145

Income taxes (benefit)

     (12,921 )     7,164      (4,156 )     13,967
                             

Net income (loss)

   $ (18,093 )   $ 12,582    $ (3,517 )   $ 24,178
                             

 

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American Savings Bank, F.S.B. and Subsidiaries

Consolidated Balance Sheet Data (unaudited)

 

(in thousands)

   June 30,
2008
    December 31,
2007
 

Assets

    

Cash and equivalents

   $ 135,471     $ 140,023  

Federal funds sold

     10,433       64,000  

Available-for-sale investment and mortgage-related securities

     887,162       2,140,772  

Investment in stock of Federal Home Loan Bank of Seattle

     97,764       97,764  

Loans receivable, net

     4,121,379       4,101,193  

Other

     249,989       234,661  

Goodwill, net

     83,080       83,080  
                
   $ 5,585,278     $ 6,861,493  
                

Liabilities and stockholder’s equity

    

Deposit liabilities - noninterest-bearing

   $ 709,658     $ 652,055  

Deposit liabilities - interest-bearing

     3,560,812       3,695,205  

Other borrowings

     634,148       1,810,669  

Other

     112,994       108,800  
                
     5,017,612       6,266,729  
                

Common stock

     327,251       325,467  

Retained earnings

     252,419       287,710  

Accumulated other comprehensive loss, net of tax benefits

     (12,004 )     (18,413 )
                
     567,666       594,764  
                
   $ 5,585,278     $ 6,861,493  
                

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $307 million and $327 million, respectively, as of June 30, 2008 and $765 million and $1.0 billion, respectively, as of December 31, 2007. The $1.2 billion decrease in other borrowings was primarily due to the early extinguishment of certain borrowings from the balance sheet restructuring described below.

As of June 30, 2008, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 billion.

Balance sheet restructure. In June 2008, ASB undertook and substantially completed the restructuring of its balance sheet through the sale of mortgage-related securities and agency notes and the early extinguishment of certain borrowings to strengthen future profitability ratios and enhance future net interest margin, while remaining “well-capitalized” and without significantly impacting future net income and interest rate risk. As a result of the restructuring, it is expected that ASB will, over the next one to three quarters, pay a special dividend of approximately $75 million to HEI (through HEI Diversified, Inc.), subject to regulatory approval. When such approval is received, HEI will use the funds from the dividend to reduce its short-term borrowings and for other corporate purposes.

On June 25, 2008, ASB completed a series of transactions which resulted in the sales to various broker/dealers of available-for-sale agency and private issue mortgage-related securities and agency notes with a weighted average yield of 4.33% for approximately $1.3 billion. ASB used the proceeds from the sales of these mortgage-related securities and agency notes to retire debt with a weighted average cost of 4.70%, comprised of approximately $0.9 billion of FHLB advances and $0.3 billion of securities sold under agreements to repurchase. These transactions resulted in a charge to net income of $36 million in the second quarter of 2008 ($12 million after-tax attributable to realized losses on the sales of the mortgage-related securities and $24 million after-tax attributable to fees associated with the early retirement of the FHLB advances and securities sold under agreements to repurchase). Although the sales of the mortgage-related securities resulted in losses in the second quarter of 2008, a portion of the losses on these available-for-sale securities had been previously recognized in ASB’s equity as a result of mark-to-market charges to other comprehensive income in earlier periods. ASB does

 

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not currently expect to sell additional mortgage-related securities or prepay additional borrowings in the near future.

ASB subsequently purchased approximately $0.3 billion of short-term agency notes and entered into approximately $0.2 billion of FHLB advances to facilitate the timing of the release of certain collateral. ASB anticipates that the notes and advances will mature over the remainder of 2008.

Guarantees. In October 2007, ASB, as a member financial institution of Visa U.S.A. Inc., received restricted shares of Visa, Inc. (Visa) as a result of a restructuring of Visa U.S.A. Inc. in preparation for an initial public offering by Visa. As a part of the restructuring, ASB entered into judgment and loss sharing agreements with Visa in order to apportion financial responsibilities arising from any potential adverse judgment or negotiated settlements related to indemnified litigation involving Visa. In November 2007, Visa announced that it had reached a settlement with American Express regarding certain of this litigation. In the fourth quarter of 2007, ASB recorded a charge of $0.3 million for its proportionate share of this settlement and a charge of approximately $0.6 million for potential losses arising from indemnified litigation that has not yet settled, which estimated fair value is highly judgmental. In March 2008, Visa funded an escrow account designed to address potential liabilities arising from litigation covered in the Retrospective Responsibility Plan and, based on the amount funded in the escrow account, ASB recorded a receivable of $0.4 million for its proportionate share of the escrow account. Because the extent of ASB’s obligations under this agreement depends entirely upon the occurrence of future events, ASB’s maximum potential future liability under this agreement is not determinable.

Regulatory compliance. ASB is subject to a range of bank regulatory compliance obligations. In connection with ASB’s review of internal compliance processes and OTS examinations, certain compliance deficiencies were identified in prior years. ASB has and continues to take steps to remediate these deficiencies and to strengthen ASB’s overall compliance programs. ASB agreed to a consent order (Order) issued by the OTS on January 23, 2008 as a result of issues relating to ASB’s compliance with certain laws and regulations, including the Bank Secrecy Act and Anti-Money Laundering (BSA/AML). The Order does not impose restrictions on ASB’s business activities; however it requires, among other things, various actions by ASB to strengthen its BSA/AML Program and its Compliance Management Program. ASB has implemented several initiatives to enhance its BSA/AML Program that address the requirements of the Order, and is on course with its remediation efforts. ASB is also implementing initiatives to enhance its Compliance Management Program in accordance with the requirements of the Order.

ASB also consented to the concurrent issuance of an order by the OTS for the assessment of a Civil Money Penalty of $37,730 related to non-compliance with certain flood insurance laws and regulations and paid the penalty in January 2008.

ASB is unable to predict what other actions, if any, may be initiated by the OTS and other governmental authorities against ASB as a result of these deficiencies, or the impact of any such measures or actions on ASB or the Company.

SFAS No. 157, Fair Value Measurements. SFAS No. 157 (which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements) was adopted prospectively and only partially applied as of the beginning of 2008. In accordance with FASB Staff Position (FSP) No. FAS 157-2, the Company has delayed the application of SFAS No. 157 to ASB’s goodwill. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. ASB grouped its financial assets measured at fair value in three levels outlined in SFAS No.157 as follows:

 

Level 1:   Inputs to the valuation methodology are quoted prices, unadjusted, for identical assets or liabilities in active markets. A quoted price in an active market provides the most reliable evidence of fair value and shall be used to measure fair value whenever available.
Level 2:   Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation

 

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  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.

Assets Measured at Fair Value on a Recurring Basis

Available-for-sale investment and mortgage-related securities. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are taken from identical or similar market transactions. Inputs to these valuation techniques reflect the assumptions market participants would use in pricing the asset based on market data obtained from independent sources.

The table below presents the balances of assets measured at fair value on a recurring basis:

 

          Fair value measurements using

Description

   June 30,
2008
   Quoted prices in
active markets for
identical assets
(Level 1)
   Significant other
observable
inputs

(Level 2)
   Significant
unobservable
inputs

(Level 3)
(in millions)                    

Available-for-sale securities

   $ 887    $ —      $ 887    $ —  

Assets Measured at Fair Value on a Nonrecurring Basis

Loans. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments to loans to reflect specific reserves on loans based on the current appraised value of the collateral or unobservable market assumptions. These adjustments to fair value usually result from the application of lower-of-cost-or-market accounting or write-downs of individual loans. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan.

The table below presents the balances of assets measured at fair value on a nonrecurring basis:

 

          Fair value measurements using

Description

   June 30,
2008
   Quoted prices in
active markets for
identical assets
(Level 1)
   Significant other
observable
inputs

(Level 2)
   Significant
unobservable
inputs

(Level 3)
(in millions)                    

Loans

   $ 9.8    $ —      $ 0.2    $ 9.6

Specific reserves for the first six months of 2008 were $4.9 million and were included in loans receivable held for investment, net. For the six months ended June 30, 2008, there were no adjustments to fair value for ASB’s loans held for sale.

 

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(5) Retirement benefits

Defined benefit plans. For the first six months of 2008, HECO contributed $4.8 million and HEI contributed $0.4 million to their respective retirement benefit plans, compared to $4.2 million and less than $0.1 million, respectively, in the first six months of 2007. The Company’s current estimate of contributions to its retirement benefit plans in 2008 is $14.5 million (including $13.7 million to be made by the utilities and $0.8 million by HEI), compared to contributions of $13.1 million in 2007 (including $12.1 million made by the utilities, $0.9 million by ASB and $0.1 million by HEI). In addition, the Company expects to pay directly $1 million of benefits in 2008, comparable to the $1 million paid in 2007.

For the first six months of 2008, the Company’s defined benefit retirement plans’ assets generated a loss, including investment management fees, of 7.8%. The market value of the defined benefit retirement plans’ assets as of June 30, 2008 was $1.0 billion compared to $1.1 billion at December 31, 2007, a decline of approximately $103 million. During the first six months of 2008, the trusts distributed $28 million in benefits to, or on behalf of, plan participants and beneficiaries.

The components of net periodic benefit cost were as follows:

 

     Three months ended June 30     Six months ended June 30  
     Pension benefits     Other benefits     Pension benefits     Other benefits  

(in thousands)

   2008 (1)     2007     2008 (1)     2007     2008     2007     2008     2007  

Service cost

   $ 6,989     $ 7,751     $ 1,182     $ 1,209     $ 13,845     $ 15,504     $ 2,347     $ 2,440  

Interest cost

     14,915       14,444       2,790       2,774       29,791       28,864       5,628       5,634  

Expected return on plan assets

     (18,269 )     (17,098 )     (2,742 )     (2,404 )     (36,501 )     (34,200 )     (5,482 )     (4,702 )

Amortization of unrecognized transition obligation

     1       1       784       784       2       2       1,569       1,569  

Amortization of prior service cost (gain)

     (99 )     (49 )     4       4       (189 )     (98 )     7       7  

Recognized actuarial loss (gain)

     1,691       2,835       —         —         3,381       5,690       —         —    
                                                                

Net periodic benefit cost

     5,228       7,884       2,018       2,367       10,329       15,762       4,069       4,948  

Impact of PUC D&Os

     1,547       —         230       —         3,204       —         423       —    
                                                                

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

   $ 6,775     $ 7,884     $ 2,248     $ 2,367     $ 13,533     $ 15,762     $ 4,492     $ 4,948  
                                                                

 

(1) Due to the freezing of ASB’s defined benefit plan as of December 31, 2007 (see below), there are no amounts for ASB employees for certain components (service cost, amortizations and recognized actuarial loss).

The Company recorded retirement benefits expense of $14 million and $17 million in the first six months of 2008 and 2007, respectively, and charged the remaining amounts primarily to electric utility plant.

Also, see Note 4, “Retirement benefits,” of HECO’s Notes to Consolidated Financial Statements.

Effective December 31, 2007, ASB ended the accrual of benefits in, and the addition of new participants to, ASB’s defined benefit pension plan. The change to the plan did not affect the vested pension benefits of former participants, including ASB retirees, as of December 31, 2007. All active participants who were employed by ASB on December 31, 2007 became fully vested in their accrued pension benefit as of December 31, 2007.

Defined contribution plan. On January 1, 2008, ASB began providing for employer contributions for ASB employees to HEI’s retirement savings plan with two contribution components in addition to employee contributions: 1) 401(k) matching of 100% on the first 4% of eligible pay contributed by participants; and 2) a discretionary employer value-sharing contribution (based on the participant’s number of years of vested service) up to 6% of eligible pay that is not contingent on contributions by participants. For the first six months of 2008, ASB’s total expense for its employees participating in the HEI retirement savings plan was $2.2 million and contributions were $0.9 million. ASB’s current estimate of contributions to the retirement savings plan in 2008 is $1.9 million.

 

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(6) Share-based compensation

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), HEI may issue an aggregate of 9.3 million shares of common stock (4,511,199 shares available for issuance under outstanding and future grants and awards as of June 30, 2008) to officers and key employees as incentive stock options, nonqualified stock options (NQSOs), restricted stock, stock appreciation rights (SARs), stock payments or dividend equivalents. HEI has issued new shares for NQSOs, restricted stock (nonvested stock), SARs and dividend equivalents under the SOIP. All information presented has been adjusted for the 2-for-1 stock split in June 2004.

For the NQSOs and SARs, the exercise price of each NQSO or SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. NQSOs, SARs and related dividend equivalents issued in the form of stock awarded prior to and through 2004 generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. The 2005 SARs awards, which have a ten year exercise life, generally become exercisable at the end of four years (i.e., cliff vesting) with the related dividend equivalents issued in the form of stock on an annual basis. Accelerated vesting is provided in the event of a change-in-control or upon retirement. NQSOs and SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.

Restricted stock grants generally become unrestricted three to five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. Dividends on restricted stock are paid quarterly in cash.

The Company’s share-based compensation expense and related income tax benefit (including a valuation allowance due to limits on the deductibility of executive compensation) are as follows:

 

     Three months ended
June 30
   Six months ended
June 30

($ in millions)

   2008     2007    2008    2007

Share-based compensation expense 1

   (0.1 )   0.4    0.2    0.7

Income tax benefit

   —       0.1    —      0.2

 

1

The Company has not capitalized any share-based compensation cost. For the second quarter of 2008, the estimated forfeiture rate for SARs was 14.3% and the estimated forfeiture rate for restricted stock was 30.6%. In the second quarter of 2008, the cumulative effect of the change in estimated forfeitures was recorded, resulting in negative share-based compensation expense.

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

 

June 30, 2008    Outstanding & Exercisable

Year of

grant

   Range of
exercise prices
   Number
of options
   Weighted-
average
remaining
contractual life
   Weighted-
average
exercise
price
1999    $ 17.61    1,000    0.8    $ 17.61
2000      14.74    46,000    1.8      14.74
2001      17.96    71,000    2.7      17.96
2002      21.68    122,000    3.7      21.68
2003      20.49    151,500    4.3      20.49
                       
   $ 14.74 – 21.68    391,500    3.5    $ 19.72
                       

As of December 31, 2007, NQSOs outstanding totaled 603,800, with a weighted-average exercise price of $19.68. As of June 30, 2008, exercisable NQSO had an aggregate intrinsic value (including dividend equivalents) of $3.4 million.

 

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NQSO activity and statistics are summarized as follows:

 

     Three months ended
June 30
   Six months ended
June 30

($ in thousands, except prices)

   2008    2007    2008    2007

Shares granted

     —        —        —        —  

Shares forfeited

     —        —        —        —  

Shares expired

     —        —        —        —  

Shares vested

     —        77,500      —        79,000

Aggregate fair value of vested shares

     —      $ 343      —      $ 350

Shares exercised

     200,300      36,700      212,300      56,200

Weighted-average exercise price

   $ 19.56    $ 18.77    $ 19.61    $ 19.70

Cash received from exercise

   $ 3,918    $ 689    $ 4,164    $ 1,107

Intrinsic value of shares exercised 1

   $ 2,101    $ 433    $ 2,185    $ 575

Tax benefit realized for the deduction of exercises

   $ 818    $ 169    $ 851    $ 224

Dividend equivalent shares distributed under Section 409A

     —        —        6,125      21,892

Weighted-average Section 409A distribution price

     —        —      $ 22.38    $ 26.15

Intrinsic value of shares distributed under Section 409A

     —        —      $ 137    $ 572

Tax benefit realized for Section 409A distributions

     —        —      $ 53    $ 223

 

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.

As of June 30, 2008, all NQSOs were vested.

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

 

June 30, 2008    Outstanding    Exercisable

Year of

grant

   Range of
exercise prices
   Number
of shares
underlying

SARs
   Weighted-
average
remaining
contractual life
   Weighted-
average
exercise
price
   Number
of shares
underlying

SARs
   Weighted-
average
remaining
contractual life
   Weighted-
average
exercise
price
2004    $ 26.02    325,000    3.1    $ 26.02    325,000    3.1    $ 26.02
2005      26.18    502,000    4.6      26.18    200,000    1.2      26.18
                                        
   $ 26.02 -26.18    827,000    4.0    $ 26.12    525,000    2.4    $ 26.08
                                        

As of December 31, 2007, the shares underlying SARs outstanding totaled 857,000, with a weighted-average exercise price of $26.12. As of June 30, 2008, the SARs outstanding and exercisable (including dividend equivalents) had no intrinsic value.

SARs activity and statistics are summarized as follows:

 

     Three months ended
June 30
   Six months ended
June 30

($ in thousands, except prices)

   2008    2007    2008    2007

Shares granted

     —        —        —        —  

Shares forfeited

     30,000      —        30,000      —  

Shares expired

     —        —        —        —  

Shares vested

     46,000      45,000      61,000      51,000

Aggregate fair value of vested shares

   $ 242    $ 234    $ 329    $ 269

Shares exercised

     —        —        —        4,000

Weighted-average exercise price

     —        —        —      $ 26.18

Cash received from exercise

     —        —        —        —  

Intrinsic value of shares exercised 1

     —        —        —      $ 3

Tax benefit realized for the deduction of exercises

     —        —        —      $ 1

Dividend equivalent shares distributed under Section 409A

     —        —        —        23,760

Weighted-average Section 409A distribution price

     —        —        —      $ 26.15

Intrinsic value of shares distributed under Section 409A

     —        —        —      $ 621

Tax benefit realized for Section 409A distributions

     —        —        —      $ 242

 

1

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

 

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As of June 30, 2008, there was $0.2 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 0.8 years.

Section 409A modification. As a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A), for the six months ended June 30, 2008 and 2007 a total of 6,125 and 45,652 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, respectively. Section 409A, which amended the rules on deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally dividend equivalents subject to Section 409A will be paid within 2 1/2 months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement or at the end of the calendar year.

Restricted stock. As of December 31, 2007, restricted stock shares outstanding totaled 146,000, with a weighted-average grant date fair value of $25.82. As of June 30, 2008, restricted stock shares outstanding totaled 170,200, with a weighted-average grant date fair value of $25.52. The grant date fair value of a grant of a restricted stock share was the closing or average price of HEI common stock on the date of grant.

During the first six months of 2008, no restricted stock shares vested, 18,500 shares of restricted stock with a grant date fair market value of $0.5 million were forfeited, and 42,700 shares of restricted stock with a grant date fair market value of $1.1 million were granted. During the second quarter of 2008, no restricted stock shares vested, 12,500 shares of restricted stock with a grant date fair market value of $0.3 million were forfeited and 42,700 shares of restricted stock with a grant date fair market value of $1.1 million were granted. During the first six months of 2007, 16,000 restricted stock shares vested, no restricted stock shares were forfeited, and 66,400 shares of restricted stock with a grant date fair market value of $1.7 million were granted. During the second quarter of 2007, 16,000 restricted stock shares vested and 57,700 shares of restricted stock with a grant date fair market value of $1.5 million were granted. The tax benefits realized for the tax deductions from restricted stock dividends were $47,000 and $0.2 million for the first six months of 2008 and 2007, respectively.

As of June 30, 2008, there was $2.2 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a weighted-average period of 3.0 years.

(7) Commitments and contingencies

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

(8) Cash flows

Supplemental disclosures of cash flow information. For the six months ended June 30, 2008 and 2007, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $104 million and $110 million, respectively.

For the six months ended June 30, 2008 and 2007, the Company paid income taxes amounting to $91 million and $3 million, respectively. The significant increase in taxes paid in the first half of 2008 versus 2007 was due primarily to the increase in operating income and the change in the Treasury regulations governing the calculation of estimated taxes due in 2008. The new regulations generally require a more ratable payment of estimated taxes. In calculating 2007 estimated taxes, taxable income was significantly larger in the fourth quarter when compared to the first three quarters, resulting in a larger portion of the 2007 taxes paid with the extension filed in the first quarter of 2008.

Supplemental disclosures of noncash activities. Noncash increases in common stock for director and officer compensatory plans of the Company were $1.3 million and $1.7 million for the six months ended June 30, 2008 and 2007, respectively.

Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $10 million for each of the six months ended June 30, 2008 and 2007. From March 23, 2004 to March 5, 2007, HEI satisfied the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan by acquiring for

 

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cash its common shares through open market purchases rather than the issuance of additional shares. On March 6, 2007, HEI began satisfying those requirements by the issuance of additional shares.

(9) Recent accounting pronouncements and interpretations

Business combinations. In December 2007, the FASB issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R requires an acquiring entity to recognize all the assets acquired and liabilities assumed at the acquisition-date fair value with limited exceptions. Under SFAS No. 141R, acquisition costs will generally be expensed as incurred, noncontrolling interests will be valued at acquisition-date fair value, and acquired contingent liabilities will be recorded at acquisition-date fair value and subsequently measured at the higher of such amount or the amount determined under existing guidance for non-acquired contingencies. The Company must adopt SFAS No. 141R for all business combinations for which the acquisition date is on or after January 1, 2009. Because the impact of adopting SFAS No. 141R will be dependent on future acquisitions, if any, management cannot predict such impact.

Noncontrolling interests. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” SFAS No. 160 requires the recognition of a noncontrolling interest (i.e., a minority interest) as equity in the consolidated financial statements, separate from the parent’s equity, and requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the income statement. Under SFAS No. 160, changes in the parent’s ownership interest that leave control intact are accounted for as capital transactions (i.e., as increases or decreases in ownership), a gain or loss will be recognized when a subsidiary is deconsolidated based on the fair value of the noncontrolling equity investment (not carrying amount), and entities must provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and of the noncontrolling owners. The Company must adopt SFAS No. 160 on January 1, 2009 prospectively, except for the presentation and disclosure requirements which must be applied retrospectively. Thus, beginning January 1, 2009, “Preferred stock of subsidiaries - not subject to mandatory redemption” will be presented as a separate component of “Stockholders’ equity,” rather than as “Minority interests” in the mezzanine section between liabilities and equity. Management has not yet determined what further impact, if any, the adoption of SFAS No. 160 will have on the Company’s financial statements.

Participating Securities. In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” according to which unvested share-based-payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” as defined in EITF 03-6 and therefore should be included in computing earnings per share using the two-class method. The Company must adopt FSP EITF 03-6-1 in the first quarter of 2009 retrospectively. Management has not yet determined the impact the adoption of FSP EITF 03-6-1 will have on the Company’s financial statements. Management believes the Company’s restricted stock grants (170,200 unvested shares outstanding as of June 30, 2008) will be considered “participating securities,” but its stock options and stock appreciation rights will not be considered “participating securities” as the associated dividend equivalents are contingent on the exercise of the option or right.

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

 

     Three months ended
June 30
    Six months ended
June 30
 

(in thousands, except for ratio of earnings to fixed charges)

   2008     2007     2008     2007  

Operating revenues

   $ 686,647     $ 491,249     $ 1,309,141     $ 938,046  
                                

Operating expenses

        

Fuel oil

     273,755       167,121       523,298       327,050  

Purchased power

     177,226       133,727       328,021       245,243  

Other operation

     59,422       53,643       115,001       100,836  

Maintenance

     23,990       29,869       47,603       57,205  

Depreciation

     35,401       34,272       70,835       68,539  

Taxes, other than income taxes

     62,371       44,903       119,857       87,450  

Income taxes

     17,094       6,492       32,472       10,998  
                                
     649,259       470,027       1,237,087       897,321  
                                

Operating income

     37,388       21,222       72,054       40,725  
                                

Other income

        

Allowance for equity funds used during construction

     2,105       1,202       4,006       2,434  

Other, net

     1,111       1,049       2,207       (5,149 )
                                
     3,216       2,251       6,213       (2,715 )
                                

Income before interest and other charges

     40,604       23,473       78,267       38,010  
                                

Interest and other charges

        

Interest on long-term debt

     11,810       11,390       23,534       22,886  

Amortization of net bond premium and expense

     639       646       1,270       1,192  

Other interest charges

     1,059       874       2,045       3,015  

Allowance for borrowed funds used during construction

     (835 )     (586 )     (1,597 )     (1,184 )

Preferred stock dividends of subsidiaries

     229       229       458       458  
                                
     12,902       12,553       25,710       26,367  
                                

Income before preferred stock dividends of HECO

     27,702       10,920       52,557       11,643  

Preferred stock dividends of HECO

     270       270       540       540  
                                

Net income for common stock

   $ 27,432     $ 10,650     $ 52,017     $ 11,103  
                                

Ratio of earnings to fixed charges (SEC method)

         3.90       1.58  
                                

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

See accompanying “Notes to Consolidated Financial Statements” for HECO.

 

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Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

 

(in thousands, except par value)

   June 30,
2008
    December 31,
2007
 

Assets

    

Utility plant, at cost

    

Land

   $ 37,789     $ 38,161  

Plant and equipment

     4,196,655       4,131,226  

Less accumulated depreciation

     (1,694,524 )     (1,647,113 )

Plant acquisition adjustment, net

     14       41  

Construction in progress

     177,920       151,179  
                

Net utility plant

     2,717,854       2,673,494  
                

Current assets

    

Cash and equivalents

     10,342       4,678  

Customer accounts receivable, net

     173,198       146,112  

Accrued unbilled revenues, net

     122,983       114,274  

Other accounts receivable, net

     6,441       6,915  

Fuel oil stock, at average cost

     161,125       91,871  

Materials and supplies, at average cost

     36,962       34,258  

Prepayments and other

     15,557       9,490  
                

Total current assets

     526,608       407,598  
                

Other long-term assets

    

Regulatory assets

     278,645       284,990  

Unamortized debt expense

     15,017       15,635  

Other

     48,317       42,171  
                

Total other long-term assets

     341,979       342,796  
                
   $ 3,586,441     $ 3,423,888  
                

Capitalization and liabilities

    

Capitalization

    

Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares

   $ 85,387     $ 85,387  

Premium on capital stock

     299,214       299,214  

Retained earnings

     762,632       724,704  

Accumulated other comprehensive income, net of income taxes

     1,272       1,157  
                

Common stock equity

     1,148,505       1,110,462  

Cumulative preferred stock - not subject to mandatory redemption

     34,293       34,293  

Long-term debt, net

     899,965       885,099  
                

Total capitalization

     2,082,763       2,029,854  
                

Current liabilities

    

Short-term borrowings - nonaffiliates

     117,427       28,791  

Accounts payable

     183,529       137,895  

Interest and preferred dividends payable

     15,403       14,719  

Taxes accrued

     153,167       189,637  

Other

     47,451       57,799  
                

Total current liabilities

     516,977       428,841  
                

Deferred credits and other liabilities

    

Deferred income taxes

     158,588       162,113  

Regulatory liabilities

     275,835       261,606  

Unamortized tax credits

     58,761       58,419  

Other

     190,592       183,318  
                

Total deferred credits and other liabilities

     683,776       665,456  
                

Contributions in aid of construction

     302,925       299,737  
                
   $ 3,586,441     $ 3,423,888  
                

See accompanying “Notes to Consolidated Financial Statements” for HECO.

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)

 

     Common stock    Premium
on capital
stock
   Retained
earnings
    Accumulated
other
comprehensive
income (loss)
    Total  

(in thousands, except per share amounts)

   Shares    Amount          

Balance, December 31, 2007

   12,806    $ 85,387    $ 299,214    $ 724,704     $ 1,157     $ 1,110,462  

Comprehensive income:

               

Net income

   —        —        —        52,017       —         52,017  

Retirement benefit plans:

               

Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,741

   —        —        —        —         2,733       2,733  

Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $1,668

   —        —        —        —         (2,618 )     (2,618 )
                                           

Comprehensive income

   —        —        —        52,017       115       52,132  
                                           

Common stock dividends

   —        —        —        (14,089 )     —         (14,089 )
                                           

Balance, June 30, 2008

   12,806    $ 85,387    $ 299,214    $ 762,632     $ 1,272     $ 1,148,505  
                                           

Balance, December 31, 2006

   12,806    $ 85,387    $ 299,214    $ 700,252     $ (126,650 )   $ 958,203  

Comprehensive income:

               

Net income

   —        —        —        11,103       —         11,103  

Retirement benefit plans - amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $2,337

   —        —        —        —         3,669       3,669  
                                           

Comprehensive income

   —        —        —        11,103       3,669       14,772  
                                           

Adjustment to initially apply a PUC D&O related to defined benefit retirement plans, net of taxes of $11,595

              —         18,205       18,205  

Adjustment to initially apply FIN 48

   —        —        —        (620 )     —         (620 )
                                           

Balance, June 30, 2007

   12,806    $ 85,387    $ 299,214    $ 710,735     $ (104,776 )   $ 990,560  
                                           

See accompanying “Notes to Consolidated Financial Statements” for HECO.

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

 

Six months ended June 30

   2008     2007  
(in thousands)             

Cash flows from operating activities

    

Income before preferred stock dividends of HECO

   $ 52,557     $ 11,643  

Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities

    

Depreciation of property, plant and equipment

     70,835       68,539  

Other amortization

     4,303       3,836  

Writedown of utility plant

     —         11,701  

Deferred income taxes

     (3,598 )     (12,484 )

Tax credits, net

     888       1,116  

Allowance for equity funds used during construction

     (4,006 )     (2,434 )

Changes in assets and liabilities

    

Increase in accounts receivable

     (26,612 )     (8,483 )

Decrease (increase) in accrued unbilled revenues

     (8,709 )     8,997  

Increase in fuel oil stock

     (69,254 )     (24,148 )

Increase in materials and supplies

     (2,704 )     (3,054 )

Increase in regulatory assets

     (1,095 )     (1,628 )

Increase (decrease) in accounts payable

     45,634       (133 )

Change in prepaid and accrued taxes

     (43,085 )     (14,746 )

Changes in other assets and liabilities

     2,211       7,262  
                

Net cash provided by operating activities

     17,365       45,984  
                

Cash flows from investing activities

    

Capital expenditures

     (99,924 )     (77,769 )

Contributions in aid of construction

     7,263       7,577  

Other

     733       —    
                

Net cash used in investing activities

     (91,928 )     (70,192 )
                

Cash flows from financing activities

    

Common stock dividends

     (14,089 )     —    

Preferred stock dividends

     (540 )     (540 )

Proceeds from issuance of long-term debt

     14,802       221,327  

Repayment of long-term debt

     —         (126,000 )

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

     88,636       (60,481 )

Decrease in cash overdraft

     (8,582 )     (9,096 )
                

Net cash provided by financing activities

     80,227       25,210  
                

Net increase in cash and equivalents

     5,664       1,002  

Cash and equivalents, beginning of period

     4,678       3,859  
                

Cash and equivalents, end of period

   $ 10,342     $ 4,861  
                

See accompanying “Notes to Consolidated Financial Statements” for HECO.

 

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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 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, 2007 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2008.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to present fairly the financial position of HECO and its subsidiaries as of June 30, 2008 and December 31, 2007 and the results of their operations for the three and six months ended June 30, 2008 and 2007 and their cash flows for the six months ended June 30, 2008 and 2007. 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 each of Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) in the respective principal amounts of $10 million, (iii) making distributions on the 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 redeemable at the issuer’s option without premium beginning on March 18, 2009. 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. 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 FIN 46R, “Consolidation of Variable Interest Entities.” Trust III’s balance sheets as of June 30, 2008 and December 31, 2007 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 six months ended June 30, 2008 and 2007 each consisted of $1.7 million of interest income received from the 2004 Debentures; $1.6 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures,

 

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then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Purchase power agreements. As of June 30, 2008, HECO and its subsidiaries had six PPAs for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the six months ended June 30, 2008 totaled $328 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $70 million, $127 million, $42 million and $29 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

Under FIN 46R, an enterprise with an interest in a variable interest entity (VIE) or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

HECO reviewed its significant PPAs and determined in 2004 that the IPPs at that time had no contractual obligation to provide such information. In March 2004, HECO and its subsidiaries sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of FIN 46R to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPOWER) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of FIN 46R, and HECO was unable to apply FIN 46R to these IPPs.

As required under FIN 46R, since 2004 HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006, 2007 and 2008, HECO and its subsidiaries sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs declined to provide necessary information, except that Kalaeloa provided the information pursuant to the amendments to the PPA (see below) and an entity owning a windfarm provided information as required under the PPA. Management has concluded that the consolidation of two entities owning windfarms was not required as MECO and HELCO do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

If the requested information is ultimately received from the other IPPs, a possible outcome of future analysis is the consolidation of one or more of such IPPs in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”

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

 

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Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery contract with another customer, the term of which coincides with the PPA. The cogeneration 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 provisions of FIN 46R, 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 absorb the majority of Kalealoa’s expected losses nor receive a majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO would 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 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.

(3) Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. HECO and its subsidiaries’ payments to the taxing authorities are based on the prior year’s revenues. For the six months ended June 30, 2008 and 2007, HECO and its subsidiaries included approximately $115 million and $83 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

(4) Retirement benefits

Defined benefit plans. For the first six months of 2008, HECO and its subsidiaries contributed $4.8 million to their retirement benefit plans, compared to $4.2 million in the first six months of 2007. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2008 is $13.7 million, compared to contributions of $12.1 million in 2007. In addition, HECO and its subsidiaries expect to pay directly $0.5 million of benefits in 2008, compared to $0.1 million paid in 2007.

For the first half of 2008, HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a loss, including investment management fees, of 7.8%. The market value of the defined benefit retirement plan’s assets as of June 30, 2008 was $0.9 billion compared to $1.0 billion at December 31, 2007, a decline of approximately $95 million. During the first six months of 2008, the trusts distributed $27 million in benefits to, or on behalf of, plan participants and beneficiaries.

The components of net periodic benefit cost were as follows:

 

     Three months ended June 30     Six months ended June 30  
     Pension benefits     Other benefits     Pension benefits     Other benefits  

(in thousands)

   2008     2007     2008     2007     2008     2007     2008     2007  

Service cost

   $ 6,643     $ 6,360     $ 1,150     $ 1,179     $ 13,176     $ 12,691     $ 2,285     $ 2,379  

Interest cost

     13,473       12,864       2,709       2,696       26,918       25,686       5,464       5,483  

Expected return on plan assets

     (16,277 )     (15,254 )     (2,697 )     (2,364 )     (32,528 )     (30,478 )     (5,392 )     (4,621 )

Amortization of unrecognized transition obligation

     —         1       783       783       —         1       1,565       1,565  

Amortization of prior service gain

     (190 )     (191 )     —         —         (381 )     (381 )     —         —    

Recognized actuarial loss (gain)

     1,644       2,620       —         —         3,289       5,236       —         —    
                                                                

Net periodic benefit cost

     5,293       6,400       1,945       2,294       10,474       12,755       3,922       4,806  

Impact of PUC D&Os

     1,547       —         230       —         3,204       —         423       —    
                                                                

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

   $ 6,840     $ 6,400     $ 2,175     $ 2,294     $ 13,678     $ 12,755     $ 4,345     $ 4,806  
                                                                

HECO and its subsidiaries recorded retirement benefits expense of $14 million in each of the first six months of 2008 and 2007. The electric utilities charged a portion of the net periodic benefit costs to plant.

In HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the utilities and the Consumer Advocate proposed adoption of pension and postretirement benefits other than pensions (OPEB) tracking

 

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mechanisms, which are intended to smooth the impact to ratepayers of potential fluctuations in pension and OPEB costs. Under the tracking mechanisms, costs determined under SFAS Nos. 87 and 106, as amended, 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.

The pension tracking mechanisms generally require the electric utilities to fund only the minimum level required under the law until the existing pension assets are reduced to zero, at which time the electric utilities would make contributions to the pension trust in the amount of the actuarially calculated net periodic pension costs, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitation on deductible contributions imposed by the Internal Revenue code. The OPEB tracking mechanisms generally require the electric utilities to make contributions to the OPEB trust in the amount of the actuarially calculated net periodic benefit costs.

A pension funding study was filed in the HECO rate case in May 2007. The conclusions in the study were consistent with the funding practice proposed with the pension tracking mechanism.

In its 2007 interim decisions for HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the PUC approved the adoption of the proposed pension and OPEB tracking mechanisms on an interim basis (subject to the PUC’s final decision and orders (D&Os)) and established the amount of net periodic benefit costs to be recovered in rates by each utility. HECO reflected the continuation of the pension and OPEB tracking mechanisms in its rate increase application based on a 2009 test year.

Under HELCO’s interim order, a regulatory asset (representing HELCO’s $12.8 million prepaid pension asset as of December 31, 2006 prior to the adoption of SFAS No. 158) was allowed to be recovered (and is being amortized) over a period of five years and was allowed to be included in HELCO’s rate base, net of deferred income taxes. In the interim PUC decisions in HECO’s and MECO’s 2007 test year rate cases, their pension assets ($51 million and $1 million, respectively, as of December 31, 2007) were not included in their rate bases and amortization of the pension assets was not included as part of the pension tracking mechanisms adopted in the proceedings on an interim basis. The issue of whether to amortize HECO’s prepaid pension asset, if allowed to be included in rate base by the PUC, has been deferred until HECO’s next rate case proceeding. HECO’s pension asset was not included in rate base, and amortization of the pension asset was not included in revenue requirements, in HECO’s rate increase application based on a 2009 test year.

(5) Commitments and contingencies

Interim increases. On April 4, 2007, the PUC issued an interim D&O in HELCO’s 2006 test year rate case granting a general rate increase on the island of Hawaii of 7.58%, or $25 million, which was implemented on April 5, 2007.

On October 22, 2007, the PUC issued, and HECO immediately implemented, an interim D&O in HECO’s 2007 test year rate case, granting HECO an increase of $70 million in annual revenues over rates effective at the time of the interim decision ($78 million in annual revenues over rates granted in the final decision in HECO’s 2005 test year rate case).

On December 21, 2007, the PUC issued, and MECO immediately implemented, an interim D&O in MECO’s 2007 test year rate case, granting MECO an increase of $13 million in annual revenues, or a 3.7% increase.

As of June 30, 2008, HECO and its subsidiaries had recognized $99 million of revenues with respect to interim orders ($15 million related to interim orders regarding certain integrated resource planning costs and $84 million related to interim orders with respect to interim surcharges to recover general rate increase requests).

Energy cost adjustment clauses (ECACs). Act 162 was signed into law in June 2006 and requires that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the utility and its customers, (2) provide the utility with incentive to manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through commercially reasonable means, such as through fuel hedging contracts, (4) preserve the utility’s financial integrity, and (5) minimize the utility’s need to apply for frequent

 

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general rate increases for fuel cost changes. While the PUC already had reviewed the automatic fuel adjustment clauses in rate cases, Act 162 requires that these five specific factors be addressed in the record.

In May 2008, the PUC issued a final D&O in HECO’s 2005 test year rate case in which the PUC agreed with the parties’ stipulation in the proceeding that it would not require the parties in the proceeding to submit a stipulated procedural schedule to address the Act 162 factors in the 2005 test year rate case proceeding, and stated it expects HECO and HELCO to develop information relating to the Act 162 factors for examination during their next rate case proceedings.

In the HELCO 2006 test year rate case, the filed testimony of the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. In April and December 2007, the PUC issued interim D&Os in the HELCO 2006 and MECO 2007 test year rate cases that reflected for purposes of the interim order the continuation of their ECACs, consistent with agreements reached between the Consumer Advocate and HELCO and MECO, respectively. The Consumer Advocate and MECO agreed that no further changes are required to MECO’s ECAC in order to comply with the requirements of Act 162.

In September 2007, HECO, the Consumer Advocate and the federal Department of Defense (DOD) agreed that the ECAC should continue in its present form for purposes of an interim rate increase in the HECO 2007 test year rate case and stated that they are continuing discussions with respect to the final design of the ECAC to be proposed for approval in the final D&O. In October 2007, the PUC issued an interim D&O, which reflected the continuation of HECO’s ECAC for purposes of the interim increase.

Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the utilities’ existing ECACs.

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 the PUC disallows cost recovery for all or part of the project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects (capitalized and deferred costs accumulated through June 30, 2008 noted in parentheses) include HELCO’s ST-7 ($23 million) and HECO’s East Oahu Transmission Project ($35 million), Customer Information system ($16 million) and generating unit in and transmission line to Campbell Industrial Park ($37 million).

HELCO generating units. In 1991, HELCO began planning to meet increased demand for electricity forecast for 1994. HELCO planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time the units would be converted to a 56 MW (net) dual-train combined-cycle unit. There were a number of environmental and other permitting challenges to construction of the units, including several lawsuits, which resulted in significant delays. However, in 2003, all but one of the parties actively opposing the plant expansion project entered into a settlement agreement with HELCO and several Hawaii regulatory agencies intended in part to permit HELCO to complete CT-4 and CT-5. The settlement agreement required HELCO to undertake a number of actions, which have been completed or are ongoing. As a result of the final resolution of various proceedings due primarily to the Settlement Agreement, there are no pending lawsuits involving the project.

CT-4 and CT-5 became operational in mid-2004 and additional noise mitigation work is ongoing to ensure compliance with the applicable night-time noise standard. Currently, HELCO can operate CT-4 and CT-5 as required to meet its system needs.

HELCO has commenced engineering, design and certain construction work for ST-7 and anticipates an in-service date in mid-2009. As of June 30, 2008, HELCO’s cost estimate for ST-7 was $92 million (of which $23 million had been incurred) and outstanding commitments for materials, equipment and outside services totaled $30 million, a substantial portion of which are subject to cancellation charges.

 

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CT-4 and CT-5 costs incurred and allowed. HELCO’s capitalized costs for CT-4 and CT-5 and related supporting infrastructure amounted to $110 million. HELCO sought recovery of these costs as part of its 2006 test year rate case.

In March 2007, HELCO and the Consumer Advocate reached a settlement of the issues in the 2006 rate case proceeding, subject to PUC approval. Under the settlement, HELCO agreed to write-off approximately $12 million of the costs relating to CT-4 and CT-5, resulting in an after-tax charge to net income in the first quarter of 2007 of $7 million (included in “Other, net” under “Other income (loss)” on HECO’s consolidated statement of income).

In April 2007, the PUC issued an interim D&O granting HELCO a 7.58% increase in rates, which D&O reflected the agreement to write-off $12 million of the CT-4 and CT-5 costs. However, the interim D&O does not commit the PUC to accept any of the amounts in the interim increase in its final D&O.

If it becomes probable that the PUC will disallow for rate-making purposes additional CT-4 and CT-5 costs in its final D&O or disallow any ST-7 costs, HELCO will be required to record an additional write-off.

East Oahu Transmission Project (EOTP). HECO had planned a project (EOTP) to construct a part underground 138 kilovolt (kV) line in order to close the gap between the Southern and Northern transmission corridors on Oahu and provide a third transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied.

HECO continued to believe that the proposed reliability project was needed and, in 2003, filed an application with the PUC requesting approval to commit funds (currently estimated at $74 million; see costs incurred below) for an EOTP, revised to use a 46 kV system and modified route, none of which is in conservation district lands. The environmental review process for the EOTP, as revised, was completed in 2005.

In written testimony filed in 2005, a consultant for the Consumer Advocate contended that HECO should always have planned for a project using only the 46 kV system and recommended that HECO be required to expense the $12 million incurred prior to the denial of the permit in 2002, and the related allowance for funds used during construction (AFUDC) of $5 million at the time. HECO contested the consultant’s recommendation, emphasizing that the originally proposed 138 kV line would have been a more comprehensive and robust solution to the transmission concerns the project addresses. In October 2007, the PUC issued a final D&O approving HECO’s request to expend funds for the EOTP, but stating that the issue of recovery of the EOTP costs would be determined in a subsequent rate case, after the project is installed and in service.

Subject to obtaining other construction permits, HECO plans to construct the EOTP in two phases. The first phase is currently in construction and projected to be completed in 2010. The projected completion date of the second phase is being evaluated.

As of June 30, 2008, the accumulated costs recorded for the EOTP amounted to $35 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $6 million of planning, permitting and construction costs incurred after 2002 and (iii) $17 million for AFUDC. Management believes no adjustment to project costs is required as of June 30, 2008. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

Environmental regulation. HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances.

HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of responding to its subsidiaries’ releases identified to date will not have a material adverse effect, individually or in the aggregate, on the Company’s or consolidated HECO’s financial statements.

Additionally, current environmental laws may require HEI and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time

 

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when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

Honolulu Harbor investigation. In response to inquiries by the Hawaii Department of Health (DOH), HECO has been involved since 1995 in a work group with several other potentially responsible parties (PRPs), including oil companies, in investigating and responding to historical subsurface petroleum contamination in the Honolulu Harbor area. The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Some of the PRPs (the Participating Parties) entered into a joint defense agreement and ultimately entered an Enforceable Agreement with the DOH. The Participating Parties are funding the investigative and remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work. Although the Honolulu Harbor investigation involves four units—Iwilei, Downtown, Kapalama and Sand Island, to date all the investigative and remedial work has focused on the Iwilei Unit.

Besides subsurface investigation, assessments and preliminary oil removal tasks that have been conducted by the Participating Parties, HECO and others investigated their ongoing operations in the Iwilei Unit in 2003 to evaluate whether their facilities were active sources of petroleum contamination in the area. HECO’s investigation concluded that its facilities were not then releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently releasing petroleum.

For administrative management purposes, the Iwilei Unit has been subdivided into four subunits. The Participating Parties have developed analyses of various remedial alternatives for the four subunits. The DOH uses the analyses to make a final determination of which remedial alternatives the Participating Parties will be required to implement. The DOH has completed remedial determinations for two subunits to date. The Participating Parties anticipate that the DOH will complete the remaining remediation determinations during the remainder of 2008.

Through June 30, 2008, HECO has accrued a total of $3.3 million (including $0.6 million in the third quarter of 2007 and $0.4 million in the first quarter of 2008) for estimates of HECO’s share of costs for continuing investigative work, remedial activities and monitoring for the Iwilei unit. As of June 30, 2008, the remaining accrual (amounts expensed less amounts expended) for the Iwilei unit was $1.9 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the PRPs has not yet been established and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei unit (such as its Honolulu power plant located in the Downtown unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material costs may be incurred.

Regional Haze Rule amendments. In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States were to adopt BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, which it has not done to date, HECO, HELCO and MECO will evaluate the plan’s impacts, if any. If any of the utilities’ generating units are ultimately required to install post-combustion control technologies to meet BART emission limits, the resulting capital and operation and maintenance costs could be significant.

Hazardous Air Pollutant (HAP) Control. In February 2008, the federal Circuit Court of Appeals for the District of Columbia vacated the EPA’s Delisting Rule, which had removed coal- and oil-fired electric generating units (EGUs) from the list of sources requiring control under Section 112 of the Clean Air Act. The EPA’s request for a rehearing was denied. The EPA is thus required to develop Maximum Achievable Control Technology (MACT) standards for oil-fired EGU HAP emissions, including nickel compounds. Depending on the MACT standards developed (and the success of a potential challenge, after the MACT standards are issued, that the EPA inappropriately listed oil-fired EGUs initially), costs to comply with the standards could be significant. The Company is currently evaluating its options regarding potential MACT standards for applicable HECO steam units.

Clean Water Act. Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental

 

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impacts. In 2004, the EPA issued a rule, which established design, construction and capacity standards for existing cooling water intake structures, such as those at HECO’s Kahe, Waiau and Honolulu generating stations, and required demonstrated compliance by March 2008. The rule provided a number of compliance options, some of which were far less costly than others. HECO had retained a consultant that was developing a cost effective compliance strategy.

In January 2007, the U.S. Circuit Court of Appeals for the Second Circuit issued a decision that remanded for further consideration and proceedings significant portions of the rule and found other portions to be impermissible. In July 2007, the EPA formally suspended the rule and provided guidance to federal and state permit writers that they should use their “best professional judgment” in determining permit conditions regarding cooling water intake requirements at existing power plants. HECO facilities are subject to permit renewal in mid-2009 and may be subject to new permit conditions to address cooling water intake requirements at that time. In April 2008, the U. S. Supreme Court agreed to review the Court of Appeal’s rejection of a cost-benefit test to determine compliance options. If the Supreme Court affirms the Court of Appeal’s decision, the compliance options available to HECO are reduced. Due to the uncertainties regarding the Court of Appeal’s decision, management is unable to predict which compliance options, some of which could entail significant capital expenditures to implement, will be applicable to its facilities. It is now expected that the Supreme Court will hear the case in November 2008, with a decision issued in the first half of 2009.

Collective bargaining agreements. As of June 30, 2008, approximately 57% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. On March 1, 2008, members of the union ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. The new agreements cover a three-year term, from November 1, 2007 to October 31, 2010, and provide for non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective January 1, 2009 and 4.5% effective January 1, 2010.

Limited insurance. HECO and its subsidiaries purchase insurance coverages to protect themselves against loss or damage to their properties against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $4 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations and financial condition could be materially adversely impacted. Also, certain insurance has substantial “deductibles”, limits on the maximum amounts that may be recovered and exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business, each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, HECO, HELCO and MECO could incur losses in amounts that would have a material adverse effect on its results of operations and financial condition.

(6) Cash flows

Supplemental disclosures of cash flow information. For the six months ended June 30, 2008 and 2007, HECO and its subsidiaries paid interest amounting to $24 million and $23 million, respectively.

For the six months ended June 30, 2008 and 2007, HECO and its subsidiaries paid income taxes amounting to $80 million and $5 million, respectively. The significant increase in taxes paid in the first half of 2008 versus 2007 was due primarily to the increase in operating income and the change in the Treasury regulations governing the calculation of estimated taxes due in 2008. The new regulations generally require a more ratable payment of estimated taxes. In calculating 2007 estimated taxes, taxable income was significantly larger in the fourth quarter when compared to the first three quarters, resulting in a larger portion of the 2007 taxes paid with the extension filed in the first quarter of 2008.

 

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Supplemental disclosure of noncash activities. The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $4.0 million and $2.4 million for the six months ended June 30, 2008 and 2007, respectively.

(7) Recent accounting pronouncements and interpretations

For a discussion of recent accounting pronouncements and interpretations, see Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

(8) Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income

 

     Three months ended June 30     Six months ended June 30  

(in thousands)

   2008     2007     2008     2007  

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

   $ 55,396     $ 28,789     $ 106,379     $ 41,781  

Deduct:

        

Income taxes on regulated activities

     (17,094 )     (6,492 )     (32,472 )     (10,998 )

Revenues from nonregulated activities

     (1,474 )     (1,463 )     (2,869 )     (2,344 )

Add: Expenses from nonregulated activities

     560       388       1,016       12,286  
                                

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

   $ 37,388     $ 21,222     $ 72,054     $ 40,725  
                                

(9) 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. As of the dates and for the periods presented for 2007, there were no amounts for Uluwehiokama Biofuels Corp., a newly-formed, unregulated HECO subsidiary.

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 and (b) relating to the trust preferred securities of Trust III. Also, see Note 2. 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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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended June 30, 2008

 

(in thousands)

   HECO     HELCO     MECO     RHI     UBC     Reclassifications
and
eliminations
    HECO
consolidated
 

Operating revenues

   $ 469,075     105,429     112,143     —       —       —       $ 686,647  
                                              

Operating expenses

              

Fuel oil

     188,374     25,000     60,381     —       —       —         273,755  

Purchased power

     126,914     40,586     9,726     —       —       —         177,226  

Other operation

     42,762     7,466     9,194     —       —       —         59,422  

Maintenance

     16,158     3,595     4,237     —       —       —         23,990  

Depreciation

     20,552     7,802     7,047     —       —       —         35,401  

Taxes, other than income taxes

     42,662     9,568     10,141     —       —       —         62,371  

Income taxes

     9,936     3,716     3,442     —       —       —         17,094  
                                              
     447,358     97,733     104,168     —       —       —         649,259  
                                              

Operating income

     21,717     7,696     7,975     —       —       —         37,388  
                                              

Other income

              

Allowance for equity funds used during construction

     1,633     351     121     —       —       —         2,105  

Equity in earnings of subsidiaries

     11,464     —       —       —       —       (11,464 )     —    

Other, net

     1,160     330     52     (17 )   (68 )   (346 )     1,111  
                                              
     14,257     681     173     (17 )   (68 )   (11,810 )     3,216  
                                              

Income (loss) before interest and other charges

     35,974     8,377     8,148     (17 )   (68 )   (11,810 )     40,604  
                                              

Interest and other charges

              

Interest on long-term debt

     7,587     1,958     2,265     —       —       —         11,810  

Amortization of net bond premium and expense

     400     117     122     —       —       —         639  

Other interest charges

     926     366     113     —       —       (346 )     1,059  

Allowance for borrowed funds used during construction

     (641 )   (145 )   (49 )   —       —       —         (835 )

Preferred stock dividends of subsidiaries

     —       —       —       —       —       229       229  
                                              
     8,272     2,296     2,451     —       —       (117 )     12,902  
                                              

Income (loss) before preferred stock dividends of HECO

     27,702     6,081     5,697     (17 )   (68 )   (11,693 )     27,702  

Preferred stock dividends of HECO

     270     133     96     —       —       (229 )     270  
                                              

Net income (loss) for common stock

   $ 27,432     5,948     5,601     (17 )   (68 )   (11,464 )   $ 27,432  
                                              

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Three months ended June 30, 2007

 

(in thousands)

   HECO     HELCO     MECO     RHI     Reclassifications
and
eliminations
    HECO
consolidated
 

Operating revenues

   $ 319,652     86,644     84,953     —       —       $ 491,249  
                                        

Operating expenses

            

Fuel oil

     109,775     15,667     41,679     —       —         167,121  

Purchased power

     92,419     33,420     7,888     —       —         133,727  

Other operation

     36,845     8,156     8,642     —       —         53,643  

Maintenance

     17,639     5,405     6,825     —       —         29,869  

Depreciation

     19,745     7,523     7,004     —       —         34,272  

Taxes, other than income taxes

     29,264     7,944     7,695     —       —         44,903  

Income taxes

     3,085     2,326     1,081     —       —         6,492  
                                        
     308,772     80,441     80,814     —       —         470,027  
                                        

Operating income

     10,880     6,203     4,139     —       —         21,222  
                                        

Other income

            

Allowance for equity funds used during construction

     1,044     68     90     —       —         1,202  

Equity in earnings of subsidiaries

     5,764     —       —       —       (5,764 )     —    

Other, net

     1,250     171     251     (14 )   (609 )     1,049  
                                        
     8,058     239     341     (14 )   (6,373 )     2,251  
                                        

Income (loss) before interest and other charges

     18,938     6,442     4,480     (14 )   (6,373 )     23,473  
                                        

Interest and other charges

            

Interest on long-term debt

     7,324     1,915     2,151     —       —         11,390  

Amortization of net bond premium and expense

     400     106     140     —       —         646  

Other interest charges

     802     608     73     —       (609 )     874  

Allowance for borrowed funds used during construction

     (508 )   (34 )   (44 )   —       —         (586 )

Preferred stock dividends of subsidiaries

     —       —       —       —       229       229  
                                        
     8,018     2,595     2,320     —       (380 )     12,553  
                                        

Income (loss) before preferred stock dividends of HECO

     10,920     3,847     2,160     (14 )   (5,993 )     10,920  

Preferred stock dividends of HECO

     270     133     96     —       (229 )     270  
                                        

Net income (loss) for common stock

   $ 10,650     3,714     2,064     (14 )   (5,764 )   $ 10,650  
                                        

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Six months ended June 30, 2008

 

(in thousands)

   HECO     HELCO     MECO     RHI     UBC     Reclassifications
and
eliminations
    HECO
consolidated
 

Operating revenues

   $ 883,588     210,621     214,932     —       —       —       $ 1,309,141  
                                              

Operating expenses

              

Fuel oil

     360,526     49,046     113,726     —       —       —         523,298  

Purchased power

     226,693     81,945     19,383     —       —       —         328,021  

Other operation

     80,731     16,360     17,910     —       —       —         115,001  

Maintenance

     31,434     8,300     7,869     —       —       —         47,603  

Depreciation

     41,104     15,636     14,095     —       —       —         70,835  

Taxes, other than income taxes

     81,110     19,187     19,560     —       —       —         119,857  

Income taxes

     19,430     6,303     6,739     —       —       —         32,472  
                                              
     841,028     196,777     199,282     —       —       —         1,237,087  
                                              

Operating income

     42,560     13,844     15,650     —       —       —         72,054  
                                              

Other income

              

Allowance for equity funds used during construction

     3,135     606     265     —       —       —         4,006  

Equity in earnings of subsidiaries

     20,765     —       —       —       —       (20,765 )     —    

Other, net

     2,571     597     110     (40 )   (322 )   (709 )     2,207  
                                              
     26,471     1,203     375     (40 )   (322 )   (21,474 )     6,213  
                                              

Income (loss) before interest and other charges

     69,031     15,047     16,025     (40 )   (322 )   (21,474 )     78,267  
                                              

Interest and other charges

              

Interest on long-term debt

     15,112     3,910     4,512     —       —       —         23,534  

Amortization of net bond premium and expense

     800     224     246     —       —       —         1,270  

Other interest charges

     1,788     771     195     —       —       (709 )     2,045  

Allowance for borrowed funds used during construction

     (1,226 )   (262 )   (109 )   —       —       —         (1,597 )

Preferred stock dividends of subsidiaries

     —       —       —       —       —       458       458  
                                              
     16,474     4,643     4,844     —       —       (251 )     25,710  
                                              

Income (loss) before preferred stock dividends of HECO

     52,557     10,404     11,181     (40 )   (322 )   (21,223 )     52,557  

Preferred stock dividends of HECO

     540     267     191     —       —       (458 )     540  
                                              

Net income (loss) for common stock

   $ 52,017     10,137     10,990     (40 )   (322 )   (20,765 )   $ 52,017  
                                              

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (unaudited)

Six months ended June 30, 2007

 

(in thousands)

   HECO     HELCO     MECO     RHI     Reclassifications
and
eliminations
    HECO
consolidated
 

Operating revenues

   $ 608,342     165,453     164,251     —       —       $ 938,046  
                                        

Operating expenses

            

Fuel oil

     210,837     35,705     80,508     —       —         327,050  

Purchased power

     170,719     60,482     14,042     —       —         245,243  

Other operation

     70,330     15,322     15,184     —       —         100,836  

Maintenance

     34,017     10,973     12,215     —       —         57,205  

Depreciation

     39,484     15,047     14,008     —       —         68,539  

Taxes, other than income taxes

     56,966     15,307     15,177     —       —         87,450  

Income taxes

     5,055     2,864     3,079     —       —         10,998  
                                        
     587,408     155,700     154,213     —       —         897,321  
                                        

Operating income

     20,934     9,753     10,038     —       —         40,725  
                                        

Other income

            

Allowance for equity funds used during construction

     2,131     133     170     —       —         2,434  

Equity in earnings of subsidiaries

     2,827     —       —       —       (2,827 )     —    

Other, net

     2,735     (6,692 )   257     (29 )   (1,420 )     (5,149 )
                                        
     7,693     (6,559 )   427     (29 )   (4,247 )     (2,715 )
                                        

Income (loss) before interest and other charges

     28,627     3,194     10,465     (29 )   (4,247 )     38,010  
                                        

Interest and other charges

            

Interest on long-term debt

     14,449     3,772     4,665     —       —         22,886  

Amortization of net bond premium and expense

     748     205     239     —       —         1,192  

Other interest charges

     2,824     1,365     246     —       (1,420 )     3,015  

Allowance for borrowed funds used during construction

     (1,037 )   (65 )   (82 )   —       —         (1,184 )

Preferred stock dividends of subsidiaries

     —       —       —       —       458       458  
                                        
     16,984     5,277     5,068     —       (962 )     26,367  
                                        

Income (loss) before preferred stock dividends of HECO

     11,643     (2,083 )   5,397     (29 )   (3,285 )     11,643  

Preferred stock dividends of HECO

     540     267     191     —       (458 )     540  
                                        

Net income (loss) for common stock

   $ 11,103     (2,350 )   5,206     (29 )   (2,827 )   $ 11,103  
                                        

 

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

June 30, 2008

 

(in thousands)

   HECO     HELCO     MECO     RHI    UBC    Reclassifications
and
Eliminations
    HECO
Consolidated
 

Assets

                

Utility plant, at cost

                

Land

   $ 28,461     4,982     4,346     —      —      —       $ 37,789  

Plant and equipment

     2,532,218     849,108     815,329     —      —      —         4,196,655  

Less accumulated depreciation

     (1,008,362 )   (338,716 )   (347,446 )   —      —      —         (1,694,524 )

Plant acquisition adjustment, net

     —       —       14     —      —      —         14  

Construction in progress

     127,108     41,663     9,149     —      —      —         177,920  
                                            

Net utility plant

     1,679,425     557,037     481,392     —      —      —         2,717,854  
                                            

Investment in wholly owned subsidiaries, at equity

     425,034     —       —       —      —      (425,034 )     —    
                                            

Current assets

                

Cash and equivalents

     6,702     1,213     2,232     154    41    —         10,342  

Advances to affiliates

     61,700     —       —       —      —      (61,700 )     —    

Customer accounts receivable, net

     113,611     31,216     28,371     —      —      —         173,198  

Accrued unbilled revenues, net

     86,931     17,815     18,237     —      —      —         122,983  

Other accounts receivable, net

     6,399     2,570     3,000     —      —      (5,528 )     6,441  

Fuel oil stock, at average cost

     123,386     12,154     25,585     —      —      —         161,125  

Materials & supplies, at average cost

     17,785     5,095     14,082     —      —      —         36,962  

Prepayments and other

     13,562     1,410     1,793     —      —      (1,208 )     15,557  
                                            

Total current assets

     430,076     71,473     93,300     154    41    (68,436 )     526,608  
                                            

Other long-term assets

                

Regulatory assets

     205,805     38,991     33,849     —      —      —         278,645  

Unamortized debt expense

     10,153     2,352     2,512     —      —      —         15,017  

Other

     33,504     7,618     7,066     —      129    —         48,317  
                                            

Total other long-term assets

     249,462     48,961     43,427     —      129    —         341,979  
                                            
   $ 2,783,997     677,471     618,119     154    170    (493,470 )   $ 3,586,441  
                                            

Capitalization and liabilities

                

Capitalization

                

Common stock equity

   $ 1,148,505     211,967     212,759     142    166    (425,034 )   $ 1,148,505  

Cumulative preferred stock–not subject to mandatory redemption

     22,293     7,000     5,000     —      —      —         34,293  

Long-term debt, net

     578,548     147,092     174,325     —      —      —         899,965  
                                            

Total capitalization

     1,749,346     366,059     392,084     142    166    (425,034 )     2,082,763  
                                            

Current liabilities

                

Short-term borrowings-nonaffiliates

     117,427     —       —       —      —      —         117,427  

Short-term borrowings-affiliate

     —       46,700     15,000     —      —      (61,700 )     —    

Accounts payable

     140,332     24,839     18,358     —      —      —         183,529  

Interest and preferred dividends payable

     10,356     2,407     2,757     —      —      (117 )     15,403  

Taxes accrued

     95,808     30,515     28,052     —      —      (1,208 )     153,167  

Other

     31,008     11,328     10,510     12    4    (5,411 )     47,451  
                                            

Total current liabilities

     394,931     115,789     74,677     12    4    (68,436 )     516,977  
                                            

Deferred credits and other liabilities

                

Deferred income taxes

     130,203     17,294     11,091     —      —      —         158,588  

Regulatory liabilities

     191,385     48,543     35,907     —      —      —         275,835  

Unamortized tax credits

     32,796     13,145     12,820     —      —      —         58,761  

Other

     108,980     52,108     29,504     —      —      —         190,592  
                                            

Total deferred credits and other liabilities

     463,364     131,090     89,322     —      —      —         683,776  
                                            

Contributions in aid of construction

     176,356     64,533     62,036     —      —      —         302,925  
                                            
   $ 2,783,997     677,471     618,119     154    170    (493,470 )   $ 3,586,441  
                                            

 

33


Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2007

 

(in thousands)

   HECO     HELCO     MECO     RHI    UBC    Reclassifications
and
Eliminations
    HECO
Consolidated
 

Assets

                

Utility plant, at cost

                

Land

   $ 28,833     4,982     4,346     —      —      —       $ 38,161  

Plant and equipment

     2,504,389     830,237     796,600     —      —      —         4,131,226  

Less accumulated depreciation

     (988,732 )   (324,517 )   (333,864 )   —      —      —         (1,647,113 )

Plant acquisition adjustment, net

     —       —       41     —      —      —         41  

Construction in progress

     114,227     26,262     10,690     —      —      —         151,179  
                                            

Net utility plant

     1,658,717     536,964     477,813     —      —      —         2,673,494  
                                            

Investment in wholly owned subsidiaries, at equity

     410,911     —       —       —      —      (410,911 )     —    
                                            

Current assets

                

Cash and equivalents

     203     3,069     773     198    435    —         4,678  

Advances to affiliates

     36,600     —       2,000     —      —      (38,600 )     —    

Customer accounts receivable, net

     98,129     26,554     21,429     —      —      —         146,112  

Accrued unbilled revenues, net

     82,550     16,795     14,929     —      —      —         114,274  

Other accounts receivable, net

     6,657     2,481     3,025     —      —      (5,248 )     6,915  

Fuel oil stock, at average cost

     57,289     12,494     22,088     —      —      —         91,871  

Materials & supplies, at average cost

     15,723     4,404     14,131     —      —      —         34,258  

Prepayments and other

     6,946     1,239     1,305     —      —      —         9,490  
                                            

Total current assets

     304,097     67,036     79,680     198    435    (43,848 )     407,598  
                                            

Other long-term assets

                

Regulatory assets

     209,034     40,663     35,293     —      —      —         284,990  

Unamortized debt expense

     10,555     2,458     2,622     —      —      —         15,635  

Other

     30,449     5,671     6,051     —      —      —         42,171  
                                            

Total other long-term assets

     250,038     48,792     43,966     —      —      —         342,796  
                                            
   $ 2,623,763     652,792     601,459     198    435    (454,759 )   $ 3,423,888  
                                            

Capitalization and liabilities

                

Capitalization

                

Common stock equity

   $ 1,110,462     201,820     208,521     182    388    (410,911 )   $ 1,110,462  

Cumulative preferred stock–not subject to mandatory redemption

     22,293     7,000     5,000     —      —      —         34,293  

Long-term debt, net

     567,657     145,811     171,631     —      —      —         885,099  
                                            

Total capitalization

     1,700,412     354,631     385,152     182    388    (410,911 )     2,029,854  
                                            

Current liabilities

                

Short-term borrowings-nonaffiliates

     28,791     —       —       —      —      —         28,791  

Short-term borrowings-affiliate

     2,000     36,600     —       —      —      (38,600 )     —    

Accounts payable

     97,699     21,810     18,386     —      —      —         137,895  

Interest and preferred dividends payable

     9,774     2,370     2,738     —      —      (163 )     14,719  

Taxes accrued

     119,032     35,380     35,225     —      —      —         189,637  

Other

     41,792     9,835     11,194     16    47    (5,085 )     57,799  
                                            

Total current liabilities

     299,088     105,995     67,543     16    47    (43,848 )     428,841  
                                            

Deferred credits and other liabilities

                

Deferred income taxes

     130,573     17,791     13,749     —      —      —         162,113  

Regulatory liabilities

     180,725     46,460     34,421     —      —      —         261,606  

Unamortized tax credits

     32,664     12,941     12,814     —      —      —         58,419  

Other

     103,876     51,972     27,470     —      —      —         183,318  
                                            

Total deferred credits and other liabilities

     447,838     129,164     88,454     —      —      —         665,456  
                                            

Contributions in aid of construction

     176,425     63,002     60,310     —      —      —         299,737  
                                            
   $ 2,623,763     652,792     601,459     198    435    (454,759 )   $ 3,423,888  
                                            

 

34


Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2008

 

(in thousands)

   HECO     HELCO     MECO     RHI     UBC     Reclassifications
and
eliminations
    HECO
consolidated
 

Balance, December 31, 2007

   $ 1,110,462     201,820     208,521     182     388     (410,911 )   $ 1,110,462  

Comprehensive income:

              

Net income (loss)

     52,017     10,137     10,990     (40 )   (322 )   (20,765 )     52,017  

Retirement benefit plans:

              

Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes

     2,733     379     307     —       —       (686 )     2,733  

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

     (2,618 )   (369 )   (295 )   —       —       664       (2,618 )
                                              

Comprehensive income (loss)

     52,132     10,147     11,002     (40 )   (322 )   (20,787 )     52,132  
                                              

Common stock dividends

     (14,089 )   —       (6,764 )   —       —       6,764       (14,089 )

Issuance of common stock

     —       —       —       —       100     (100 )     —    
                                              

Balance, June 30, 2008

   $ 1,148,505     211,967     212,759     142     166     (425,034 )   $ 1,148,505  
                                              

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2007

 

(in thousands)

   HECO     HELCO     MECO     RHI     Reclassifications
and
eliminations
    HECO
consolidated
 

Balance, December 31, 2006

   $ 958,203     175,099     192,231     265     (367,595 )   $ 958,203  

Comprehensive income:

            

Net income (loss)

     11,103     (2,350 )   5,206     (29 )   (2,827 )     11,103  

Retirement benefit plans - amortization of net loss, prior service cost and transition obligation included in net periodic benefit cost, net of tax benefits

     3,669     278     444     —       (722 )     3,669  
                                        

Comprehensive income (loss)

     14,772     (2,072 )   5,650     (29 )   (3,549 )     14,772  
                                        

Adjustment to initially apply a PUC D&O related to defined benefit plans

     18,205     18,205     —       —       (18,205 )     18,205  

Adjustment to initially apply FIN 48, net of tax benefits

     (620 )   (32 )   (42 )   —       74       (620 )
                                        

Balance, June 30, 2007

   $ 990,560     191,200     197,839     236     (389,275 )   $ 990,560  
                                        

 

35


Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2008

 

(in thousands)

   HECO     HELCO     MECO     RHI     UBC     Reclassifications
and
eliminations
    HECO
consolidated
 

Cash flows from operating activities

              

Income (loss) before preferred stock dividends of HECO

   $ 52,557     10,404     11,181     (40 )   (322 )   (21,223 )   $ 52,557  

Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities:

              

Equity in earnings

     (20,815 )   —       —       —       —       20,765       (50 )

Common stock dividends received from subsidiaries

     6,814     —       —       —       —       (6,764 )     50  

Depreciation of property, plant and equipment

     41,104     15,636     14,095     —       —       —         70,835  

Other amortization

     1,582     390     2,331     —       —       —         4,303  

Deferred income taxes

     (429 )   (503 )   (2,666 )   —       —       —         (3,598 )

Tax credits, net

     491     284     113     —       —       —         888  

Allowance for equity funds used during construction

     (3,135 )   (606 )   (265 )   —       —       —         (4,006 )

Changes in assets and liabilities:

              

Increase in accounts receivable

     (15,224 )   (4,751 )   (6,917 )   —       —       280       (26,612 )

Increase in accrued unbilled revenues

     (4,381 )   (1,020 )   (3,308 )   —       —       —         (8,709 )

Decrease (increase) in fuel oil stock

     (66,097 )   340     (3,497 )   —       —       —         (69,254 )

Decrease (increase) in materials and supplies

     (2,062 )   (691 )   49     —       —       —         (2,704 )

Decrease (increase) in regulatory assets

     238     (7 )   (1,326 )   —       —       —         (1,095 )

Increase (decrease) in accounts payable

     42,633     3,029     (28 )   —       —       —         45,634  

Change in prepaid and accrued taxes

     (30,308 )   (4,865 )   (7,912 )   —       —       —         (43,085 )

Changes in other assets and liabilities

     1,228     505     805     (4 )   (43 )   (280 )     2,211  
                                              

Net cash provided by (used in) operating activities

     4,196     18,145     2,655     (44 )   (365 )   (7,222 )     17,365  
                                              

Cash flows from investing activities

              

Capital expenditures

     (51,684 )   (33,202 )   (15,038 )   —       —       —         (99,924 )

Contributions in aid of construction

     4,043     2,102     1,118     —       —       —         7,263  

Advances from (to) affiliates

     (25,100 )   —       2,000     —       —       23,100       —    

Investment in consolidated subsidiary

     (100 )   —       —       —       —       100       —    

Other

     862     —       —       —       (129 )   —         733  
                                              

Net cash used in investing activities

     (71,979 )   (31,100 )   (11,920 )   —       (129 )   23,200       (91,928 )
                                              

Cash flows from financing activities

              

Common stock dividends

     (14,089 )   —       (6,764 )   —       —       6,764       (14,089 )

Preferred stock dividends

     (540 )   (267 )   (191 )   —       —       458       (540 )

Proceeds from issuance of long-term debt

     10,856     1,266     2,680     —       —       —         14,802  

Proceeds from issuance of common stock

     —       —       —       —       100     (100 )     —    

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

     86,636     10,100     15,000     —       —       (23,100 )     88,636  

Decrease in cash overdraft

     (8,581 )   —       (1 )   —       —       —         (8,582 )
                                              

Net cash provided by financing activities

     74,282     11,099     10,724     —       100     (15,978 )     80,227  
                                              

Net increase (decrease) in cash and equivalents

     6,499     (1,856 )   1,459     (44 )   (394 )   —         5,664  

Cash and equivalents, beginning of period

     203     3,069     773     198     435     —         4,678  
                                              

Cash and equivalents, end of period

   $ 6,702     1,213     2,232     154     41     —       $ 10,342  
                                              

 

36


Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2007

 

(in thousands)

   HECO     HELCO     MECO     RHI     Reclassifications
and
eliminations
    HECO
consolidated
 

Cash flows from operating activities

            

Income (loss) before preferred stock dividends of HECO

   $ 11,643     (2,083 )   5,397     (29 )   (3,285 )   $ 11,643  

Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities

            

Equity in (earnings) loss

     (2,877 )   —       —       —       2,827       (50 )

Common stock dividends received from subsidiaries

     50     —       —       —       —         50  

Depreciation of property, plant and equipment

     39,484     15,047     14,008     —       —         68,539  

Other amortization

     1,801     319     1,716     —       —         3,836  

Writedown of utility plant

     —       11,701     —       —       —         11,701  

Deferred income taxes

     (5,987 )   (5,078 )   (1,419 )   —       —         (12,484 )

Tax credits, net

     749     433     (66 )   —       —         1,116  

Allowance for equity funds used during construction

     (2,131 )   (133 )   (170 )   —       —         (2,434 )

Changes in assets and liabilities

            

Decrease (increase) in accounts receivable

     (5,799 )   241     (4,947 )   —       2,022       (8,483 )

Decrease (increase) in accrued unbilled revenues

     9,643     (617 )   (29 )   —       —         8,997  

Increase in fuel oil stock

     (19,057 )   (1,001 )   (4,090 )   —       —         (24,148 )

Increase in materials and supplies

     (1,395 )   (405 )   (1,254 )   —       —         (3,054 )

Decrease (increase) in regulatory assets

     172     (248 )   (1,552 )   —       —         (1,628 )

Increase (decrease) in accounts payable

     4,812     (4,163 )   (782 )   —       —         (133 )

Decrease in taxes accrued

     (14,237 )   (302 )   (207 )   —       —         (14,746 )

Changes in other assets and liabilities

     4,032     5,882     (634 )   4     (2,022 )     7,262  
                                        

Net cash provided by (used in) operating activities

     20,903     19,593     5,971     (25 )   (458 )     45,984  
                                        

Cash flows from investing activities

            

Capital expenditures

     (46,093 )   (20,875 )   (10,801 )   —       —         (77,769 )

Contributions in aid of construction

     4,322     1,708     1,547     —       —         7,577  

Advances to affiliates

     14,950     —       (1,000 )   —       (13,950 )     —    
                                        

Net cash used in investing activities

     (26,821 )   (19,167 )   (10,254 )   —       (13,950 )     (70,192 )
                                        

Cash flows from financing activities

            

Preferred stock dividends

     (540 )   (267 )   (191 )   —       458       (540 )

Proceeds from issuance of long-term debt

     135,770     19,990     65,567     —       —         221,327  

Repayment of long-term debt

     (62,280 )   (8,020 )   (55,700 )   —       —         (126,000 )

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

     (59,481 )   (9,950 )   (5,000 )   —       13,950       (60,481 )

Increase (decrease) in cash overdraft

     (7,589 )   (1,705 )   198     —       —         (9,096 )
                                        

Net cash provided by financing activities

     5,880     48     4,874     —       14,408       25,210  
                                        

Net increase (decrease) in cash and equivalents

     (38 )   474     591     (25 )   —         1,002  

Cash and equivalents, beginning of period

     2,328     738     518     275     —         3,859  
                                        

Cash and equivalents, end of period

   $ 2,290     1,212     1,109     250     —       $ 4,861  
                                        

 

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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” in HEI’s and HECO’s Form 10-K for the year ended December 31, 2007 and should be read in conjunction with the annual (as of and for the year ended December 31, 2007) and quarterly (as of and for the three months ended March 31, 2008, and as of and for the three and six months ended June 30, 2008) consolidated financial statements of HEI and HECO and accompanying notes.

HEI CONSOLIDATED

RESULTS OF OPERATIONS

 

(in thousands, except per share amounts)

   Three months ended June 30    %
change
   

Primary reason(s) for significant change*

   2008    2007     

Revenues

   $ 774,055    $ 600,763    29      Increase for the electric utility segment, slightly offset by decreases for the bank and “other” segments

Operating income

     21,602      45,309    (52 )   Decrease for the bank segment (resulting from the impact of the balance sheet restructuring), partly offset by an increase for the electric utility segment and decrease in losses for the “other” segment

Net income

     5,136      17,549    (71 )   Lower operating income, partly offset by higher AFUDC, lower “interest expense—other than on deposit liabilities and other bank borrowings” and lower taxes resulting from lower income before taxes and a lower effective income tax rate **

Basic earnings per common share

   $ 0.06    $ 0.21    (71 )   Lower net income

Weighted-average number of common shares outstanding

     84,052      81,907        Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans

(in thousands, except per share amounts)

   Six months ended June 30    %
change
   

Primary reason(s) for significant change*

   2008    2007     

Revenues

   $ 1,503,672    $ 1,154,786    30     Increase for the electric utility segment, slightly offset by decreases for the bank and “other” segments

Operating income

     92,348      73,850    25     Increase for the electric utility, partly offset by decrease for the bank segment (resulting from the impact of the balance sheet restructuring) and an increase in losses for the “other” segment

Net income

     39,103      24,313    61     Higher operating income and AFUDC and lower “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by higher taxes resulting from higher income before taxes **

Basic earnings per common share

   $ 0.47    $ 0.30    57     Higher net income

Weighted-average number of common shares outstanding

     83,762      81,679    3     Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans

 

* Also, see segment discussions which follow.
**

The Company’s effective tax rates for the second quarters of 2008 and 2007 were 13% and 36%, respectively. The second quarter of 2008 reflects the effect of utilizing state tax credits against a significantly lower income tax expense base. The

 

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Company’s effective tax rate for the first six months of 2008 and 2007 was 34%, which was lower than the effective statutory rate due primarily to state tax credits.

Dividends

On August 4, 2008, the HEI Board of Directors (Board) maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2007 and the first six months of 2008 were 120% and 132%, respectively. Excluding the net income impact ($35.6 million) of ASB’s balance sheet restructuring, the payout ratio for the first six months of 2008 would have been 70%. HEI’s Board believes that HEI should have a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.

Economic conditions

Note: The statistical data in this section is from public third party sources (e.g., State of Hawaii Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).

Because its core businesses provide local electric utility and banking services, the Company’s operating results are influenced by the strength of Hawaii’s economy.

In recent years, Hawaii’s economy experienced strong growth fueled by increases in tourism, military spending by the federal government to expand and revitalize its facilities, strength in the housing market and increases in residential and commercial construction. While some of these areas continue to support economic growth in the state, recently, the Hawaii economy has shown signs that growth is slowing.

Economic slowing was most visible in tourism. The closure of Aloha and ATA Airlines, departure of two Norwegian Cruise Line cruise ships from Hawaii, soaring oil prices and the downturn in the national economy have impacted the visitor industry. Total air arrivals and visitor days were down significantly in the second quarter causing a decline in year-to-date arrivals and days through June of 5% and 4%, respectively, compared with the same period last year. Total expenditures by visitors who arrived by air also declined 3.4% for the first half of 2008 compared with the first half of 2007. Local tourism authorities continue to increase marketing efforts in its base market, the western U.S., to help stimulate demand for travel.

Historically, tourism has been affected by the health of the U.S. and Japanese economies. The real gross domestic product (GDP) growth in the U.S. is estimated to be 1.4% in 2008, compared to 2.5% in 2007. For Japan, real GDP is estimated to be 1.3% in 2008, compared to 2% in 2007.

Hawaii’s real estate market saw record growth in 2004 and 2005 and slowing in 2006 and 2007. Total single family home sales on Oahu decreased 26% in the first half of 2008 compared with the same period in 2007. Oahu home median home prices held fairly stable for the first half of 2008, down 2.5% compared with the same period last year. Local economists expect the residential markets to see further slowing throughout the summer, but the reduction in demand may ease toward the end of the year.

The outlook for the construction industry in Hawaii remains positive. Construction activity, as measured by permitting activity (excluding military construction), peaked in 2006 and stabilized in 2007. Permit levels still remain high in terms of dollar values, suggesting solid construction activity in the coming months. Increased activity in the military, industrial and commercial construction activity sectors continue to be stabilizing factors and help to offset the decline in residential construction. Local economists expect the overall level of construction activity to remain relatively stable for this reason. Risks to this outlook include whether reduced market liquidity will impact funding of commercial construction projects in Hawaii and whether the federal government will reduce spending on new military projects.

Although Hawaii unemployment remains low and well-below national averages, recent data indicates an upward trend. Hawaii unemployment at the end of June 2008 was 3.8% (national average was 5.5%), compared to 2.6% at the end of June 2007.

Management also monitors (1) oil prices because of their impact on the rates the utilities charge for electricity and the potential effect of increased electricity prices on usage, and (2) interest rates because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital and pension costs, and HEI’s stock price. Crude oil prices continued to push higher amid strong global demand, geopolitical concerns in the Middle East and a weaker dollar. Crude oil traded at an average price of $109.78 per barrel during the first six months of

 

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2008 based on West Texas Intermediate markets, compared to an average price of $67.76 per barrel for the same period last year.

High energy costs also continue to contribute to inflation rates in Hawaii that are higher than the national inflation rate, which will in turn stress Hawaii consumers. Rising fuel costs have worked their way into the price of consumer goods because about 80% of those goods are shipped into Hawaii. Consumers have pulled back on their spending and the electric utilities have seen the effects of conservation on their electric sales. State economists expect inflation to be 4.2% for 2008, compared to 4.8% for 2007, due in large part in both years to rising fuel costs.

Short-term interest rates were relatively stable during the second quarter of 2008 while longer-term interest rates increased due to heightened inflationary expectations. The continued low level of short-term interest rates contributed to the increase in bank net interest margin in the second quarter.

Retirement benefits

Based on various assumptions (in Note 8 of HEI’s “Notes to Consolidated Financial Statements” in HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008) and assuming no further changes in retirement benefit plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s retirement benefits expense (including amounts for the defined benefit, defined contribution and other postemployment benefit plans), net of income tax benefits, is estimated to be $19 million, $17 million and $1 million, respectively, in 2008, compared to actual expense, net of income tax benefits, of $20 million, $16 million and $2 million, respectively, in 2007. Also, see Notes 5 and 4 to HEI’s and HECO’s “Notes to Consolidated Financial Statements,” respectively.

“Other” segment

 

     Three months ended June 30     %     

(in thousands)

   2008     2007     change   

Primary reason(s) for significant change

Revenues

   $ (16 )   $ 525     NM   

Second quarter 2007: leveraged lease investment income and gain of $0.4 million

 

Second quarter 2008: unrealized losses on venture capital investments of $19,000

Operating loss

     (2,802 )     (3,174 )   NM    See explanation for revenues, offset by lower consulting and other administrative and general expenses

Net loss

     (4,203 )     (5,683 )   NM    See explanation for operating loss and lower interest expense
     Six months ended June 30     %     

(in thousands)

   2008     2007     change   

Primary reason(s) for significant change

Revenues

   $ (132 )   $ 2,410     NM   

First half 2007: gain on the sale of Hoku shares of $1.4 million and leveraged lease investment income and gain of $0.7 million

 

First half 2008: unrealized losses on venture capital investments of $0.1 million

Operating loss

     (6,402 )     (6,053 )   NM    See explanation for revenues, largely offset by lower consulting and other administrative and general expenses

Net loss

     (9,397 )     (10,968 )   NM    See explanation for operating loss, offset by lower interest expense

 

NM Not meaningful.

The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company previously holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to an affiliated electric utility; HEI Properties, Inc., a company holding passive, venture capital investments; The Old Oahu Tug Service, Inc., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, holding companies; and eliminations of intercompany transactions. Since HEIII

 

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sold all of its leveraged lease investments by the end of 2007, the Company currently plans to wind up HEIII’s affairs during 2008.

Commitments and contingencies

See Note 7 of HEI’s “Notes to Consolidated Financial Statements” and Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations

See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

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 in the foreseeable future.

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

 

(in millions)

   June 30, 2008     December 31, 2007  

Short-term borrowings - other than bank

   $ 222    8 %   $ 92    4 %

Long-term debt, net - other than bank

     1,207    44       1,242    47  

Preferred stock of subsidiaries

     34    1       34    1  

Common stock equity

     1,297    47       1,275    48  
                          
   $ 2,760    100 %   $ 2,643    100 %
                          

As of August 1, 2008, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:

 

     S&P    Moody’s

Commercial paper

   A-2    P-2

Senior unsecured debt

   BBB    Baa2

The above ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

HEI’s overall S&P corporate credit rating is BBB/Stable/A-2 and Moody’s outlook for HEI is “stable.”

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HEI securities. In May 2008, S&P affirmed its corporate credit ratings and “stable” outlook of HEI. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P stated:

Unsupportive or lagged rate treatment or changes in the current fuel adjustment clause of the company that would result in erosion of key financial parameters, especially cash flow coverage of debt, would be cause for change in the current ratings and/or a negative outlook. A severe slump in the state economy could also contribute to downward rating pressure. Given these challenges, higher ratings are not foreseen during the outlook horizon and would need to be accompanied by sustained and improved financial performance.

S&P designates business risk profiles as “excellent,” “strong,” “satisfactory,” “weak” or “vulnerable.” S&P stated in May 2008 that: “HEI’s business profile is strong, reflecting a degree of diversification afforded by American’s banking business, which features a reasonably solid lending portfolio that is not expected to be

 

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adversely affected by the subprime crisis, and the generally stable, regulated utility assets of HEI’s three utilities. The consolidated business profile’s strengths are tempered by the reliance of both businesses on Hawaii’s economy, which is dependent on a limited number of industries for growth.”

S&P’s financial risk designations are “minimal,” “modest,” “intermediate,” “aggressive” and “highly leveraged.” In May 2008, S&P indicated that “[t]he consolidated financial profile is aggressive, reflecting in part the very heavy debt imputation we apply to the three utilities for power purchase agreements (PPA).”

In June 2008, Moody’s issued an Issuer Comment regarding ASB’s balance sheet restructuring. Moody’s viewed the Company’s announcement that ASB had substantially completed the balance sheet restructuring “as being positive to HEI’s credit quality, but not material enough to warrant a rating change or a change in the company’s stable outlook.”

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

As of June 30, 2008, $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration and an additional $50 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program. These registrations will expire to the extent the registered securities have not been issued by November 30, 2008.

HEI utilizes short-term debt, principally commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements, including the funding of loans by HECO to HELCO and MECO. HEI had an average outstanding balance of commercial paper for the first six months of 2008 of $90 million and had $105 million outstanding as of June 30, 2008, with the balance of HEI’s consolidated short-term debt as of June 30, 2008 being comprised of $117 million of HECO’s commercial paper. Management believes that if HEI’s commercial paper ratings were to be downgraded, it might not be able to sell commercial paper under current market conditions.

As a result of ASB’s balance sheet restructuring (see “Balance sheet restructure” in Note 4 of HEI’s Notes to Consolidated Financial Statements) and subject to regulatory approval, ASB is expected to distribute approximately $75 million to HEI over the next one to three quarters. HEI will use the funds to reduce its commercial paper borrowings and for other corporate purposes. Consequently, HEI’s commercial paper is expected to decrease below current levels in 2008 and 2009.

Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Effective February 19, 2008, HEI entered into a short-term, unsecured credit agreement establishing a line of credit facility of $50 million, expiring on November 18, 2008, with William Street LLC, an affiliate of Goldman, Sachs & Co. The commitments under this credit facility will be permanently reduced by any dividends received by HEI as a result of ASB’s balance sheet restructuring. As of August 1, 2008, the lines were undrawn. In the future, the Company may seek to enter into new lines of credit and may also seek to increase the amount of credit available under such lines as management deems appropriate.

For the first six months of 2008, net cash provided by operating activities of consolidated HEI was $16 million. Net cash provided by investing activities and net cash used in financing activities for the same period were $1.1 billion and $1.2 billion, respectively, primarily due to ASB’s balance sheet restructuring. Net cash provided by investing activities included ASB’s proceeds from the sale of investment and mortgage-related securities of $1.3 billion and repayments of investment and mortgage-related securities of $0.3 billion, partly offset by ASB’s purchases of investment and mortgage-related securities of $0.4 billion and HECO’s consolidated capital expenditures of $0.1 billion. Net cash used in financing activities included net decreases in ASB’s other borrowings of $1.2 billion, ASB’s deposit liabilities of $77 million and long-term debt of $35 million and the payment of common stock dividends of $41 million, partly offset by a net increase in short-term borrowings of $130 million.

Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 2008 through 2010 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction program, $50 million was required in March 2008 to repay maturing HEI medium-term notes, which were repaid with the proceeds from the issuance of commercial paper. Additional debt and/or equity financing may be utilized to pay down commercial paper or other

 

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short-term borrowings or may be required to fund unanticipated expenditures not included in the 2008 through 2010 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the utilities, utility capital expenditures that may be required by new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if tax positions taken by the Company do not prevail. In addition, existing debt may be refinanced prior to maturity (potentially at more favorable rates) with additional debt or equity financing (or both).

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 12 to 13, 36 to 40, and 47 to 49 of HEI’s MD&A which is incorporated into Part II, Item 7 of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

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

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 financial condition and results of operations, and currently require management’s most difficult, subjective or complex judgments.

For information about these material estimates and critical accounting policies, see pages 13 to 14, 40 to 41, and 49 of HEI’s MD&A which is incorporated into Part II, Item 7 of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

 

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

ELECTRIC UTILITIES

RESULTS OF OPERATIONS

 

(dollars in thousands,

except per barrel amounts)

   Three months ended June 30    %      
   2008    2007    change    

Primary reason(s) for significant change

Revenues

   $ 688,121    $ 492,712    40     Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($175 million), interim rate relief ($21 million) and higher amounts of DSM costs recovered through a surcharge ($3 million), partly offset by 1.0% lower sales ($5 million)

Expenses

          

Fuel oil

     273,755      167,121    64     Higher fuel oil costs

Purchased power

     177,226      133,727    33     Higher fuel costs, partially offset by less KWHs purchased

Other

     181,744      163,075    11     Higher depreciation expenses ($1 million) and taxes, other than income taxes ($17 million)

Operating income

     55,396      28,789    92     Interim rate relief

Net income

     27,432      10,650    158     Higher operating income and AFUDC, partly offset by higher interest and income tax expenses

Kilowatthour sales (millions)

     2,476      2,501    (1 )   Customer conservation, DSM activities and slowing economic activity, partly offset by warmer weather on Oahu

Cooling degree days (Oahu)

     1,295      1,255    3    

Average fuel oil cost per barrel

   $ 104.78    $ 62.74    67    

 

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(dollars in thousands,

except per barrel amounts)

   Six months ended June 30    %     
   2008    2007    change   

Primary reason(s) for significant change

Revenues

   $ 1,312,010    $ 940,390    40    Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($317 million), interim rate relief ($46 million) and higher amounts of DSM costs recovered through a surcharge ($6 million)

Expenses

           

Fuel oil

     523,298      327,050    60    Higher fuel oil costs, partly offset by less KWHs generated

Purchased power

     328,021      245,243    34    Higher fuel costs

Other

     354,312      326,316    9    Higher other operation and maintenance (O&M) ($5 million) and depreciation expenses ($2 million), and higher taxes, other than income taxes ($32 million), partly offset by the write-off of HELCO plant in service in 2007 ($12 million)

Operating income

     106,379      41,781    155    Interim rate relief and 2007 write-off of a portion of HELCO’s CT-4 and CT-5

Net income

     52,017      11,103    368    Higher operating income and AFUDC and lower interest expense, partly offset by higher income taxes

Kilowatthour sales (millions)

     4,885      4,905    —      Customer conservation, DSM activities and slowing economic activity, partly offset by warmer weather on Oahu

Cooling degree days (Oahu)

     2,249      2,100    7   

Average fuel oil cost per barrel

   $ 99.29    $ 60.43    64   

Note: The electric utilities’ effective tax rates for the first six months of 2008 and 2007 were 38% and 35%, respectively. The first six months of 2007 reflect the acceleration of state tax credits associated with the write-off of a portion of CT-4 and CT-5 and the effect of utilizing state tax credits against a significantly lower income tax expense base.

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

Results – three months ended June 30, 2008

Operating income for the second quarter of 2008 increased 92% from the same period in 2007 due primarily to $21 million of interim rate relief granted by the PUC to HECO (2007 test year), HELCO (2006 test year) and MECO (2007 test year) in October 2007, April 2007 and December 2007. Kilowatthour (KWH) sales in the second quarter of 2008 decreased 1.0% from the same period in 2007, primarily due to the impact of customer conservation efforts (largely in response to significant price increases primarily due to higher fuel costs) and DSM activities and slowing economic activity, partially offset by warmer weather on Oahu. Cooling degree days for Honolulu (on the island of Oahu) were 3.2% higher in the second quarter of 2008 when compared to the same period in 2007.

Other operation expenses for the second quarter increased 11% primarily due to higher DSM expenses that are generally passed on to customers through a surcharge ($2.8 million), and production operations expenses ($1.6 million). In spite of a 12.5 basis points higher discount rate assumption, pension and other postretirement benefit expenses for the electric utilities were comparable to the same period in 2007 primarily due to the adoption of the pension tracking mechanisms, including amortization of HELCO’s prepaid pension asset (approved on an interim basis by the PUC; see “Most recent rate requests”). Maintenance expenses for the second quarter of 2008 decreased by 20% primarily due to lower production maintenance expenses (primarily due to $5.2 million of lower

 

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costs related to the lower scope and timing of generating unit overhauls) and lower transmission and distribution maintenance expenses (primarily due to $0.9 million and $0.5 million of lower costs related to lower vegetation management and substation expenses, respectively). Higher depreciation expense ($1.1 million) was attributable to additions to plant in service in 2007.

Although O&M expenses for the second quarter of 2008 were flat when compared to the same quarter in 2007, the trend of increased O&M expenses in prior years is expected in the second half of 2008 as the electric utilities expect higher DSM expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved in an energy efficiency DSM Docket), higher production expenses, primarily due to increased utilization of HECO’s generating assets commensurate with the level of demand that has occurred over the past 5 years, and higher costs for materials and contract services.

As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability at least until HECO installs its planned new generating unit in 2009. Generation reserve margins on Oahu continued to be strained. HECO has taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying energy to meet growing demand, however, are increasing because of the tight peak reserve margin situation, and the trend of cost increases is not likely to ease.

Results – six months ended June 30, 2008

Operating income for the first six months of 2008 increased 155% from the same period in 2007 due primarily to $46 million of interim rate relief granted by the PUC and a write-off in the first quarter of 2007 of a portion of plant-in-service costs related to CT-4 and CT-5 (see “Most recent rate cases”). KWH sales in the six months ended June 30, 2008 decreased 0.4% from the same period in 2007, primarily due to the impact of customer conservation efforts and DSM activities and slowing economic activity, partially offset by warmer weather on Oahu and the impact of an additional leap year day in February 2008. Cooling degree days for Honolulu (on the island of Oahu) were 7.1% higher in the first six months of 2008 when compared to the same period in 2007.

Other operation expenses for the first six months of 2008 increased 14% primarily due to higher DSM expenses that are generally passed on to customers through a surcharge ($5.2 million), production operation expenses ($3.2 million) and administrative and general expenses ($3.3 million). Maintenance expenses for the six months ended June 30, 2008 decreased by 17% primarily due to lower production maintenance expenses (primarily due to $8.2 million of lower costs related to the lower scope and timing of generating unit overhauls) and lower transmission and distribution maintenance expenses (primarily due to $1.1 million and $0.7 million of lower costs related to lower substation and vegetation management expenses, respectively). Higher depreciation expense ($2.3 million) was attributable to additions to plant in service in 2007.

Renewable energy strategy

The electric utilities are taking actions intended to protect Hawaii’s island ecology and counter global warming, while continuing to provide reliable power to customers. A three-pronged strategy supports attainment of the State of Hawaii RPS and the Hawaii Global Warming Solutions Act of 2007 by: 1) the greening of existing assets, 2) the expansion of renewable energy generation and 3) the acceleration of energy efficiency and load management programs. Major initiatives are being pursued in each category.

In its June 27, 2008 filing with the PUC, HECO reported a consolidated RPS of 16.1% in 2007. This was accomplished through a combination of municipal solid waste, geothermal, wind, biomass, hydro, photovoltaic and biodiesel renewable generation resources; renewable energy displacement technologies; and energy savings from efficiency technologies.

The electric utilities are actively exploring the use of biofuels for existing and planned company-owned generating units. HECO has committed to using 100% biofuels for its new 110 MW generating unit planned for 2009. HECO is researching the possibility of switching its steam generating units from fossil fuels to biofuels, based upon economic and technical feasibility.

In February 2007, BlueEarth Biofuels LLC (BlueEarth) announced plans for a new biodiesel refining plant to be built on the island of Maui. BlueEarth Maui Biofuels LLC (BlueEarth Maui), a joint venture to pursue biodiesel development, was recently formed between BlueEarth and Uluwehiokama Biofuels Corp. (UBC), a non-regulated

 

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subsidiary of HECO. In February 2008, an Operating Agreement and an Investment Agreement were executed between BlueEarth and UBC, under which UBC invested $400,000 in BlueEarth Maui in exchange for a minority ownership interest. All of UBC’s profits from the project will be directed into a biofuels public trust to be created for the purpose of funding biofuels development in Hawaii. MECO intends to lease a portion of the land owned by MECO for its future Waena generation station as the site for the biodiesel plant, with lease proceeds to be credited to MECO ratepayers. In addition, MECO is negotiating a fuel purchase contract for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the land lease agreement and biodiesel fuel contract will require PUC approval. Although not required to do so, BlueEarth Maui has also announced plans to prepare an environmental impact study for the project. HECO, working closely with the Natural Resources Defense Council, developed an environmental policy, which focuses on sustainable palm oil and locally-grown feedstocks, to ensure that the project would procure biofuel and biofuel feedstocks only from sustainable sources.

The electric utilities also support renewable energy through their solar water heating and heat pump programs, and the negotiation and execution of purchased power contracts with non-utility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems). In November 2007, HECO entered into a contract to purchase energy from a photovoltaic system with a generating capacity of up to 300 kilowatts to be located at HECO’s Archer substation. The PUC approved the contract in May 2008. In September 2007, HECO issued a Solicitation of Interest for its planned Renewable Energy Request for Proposals (RFP) for combined renewable energy projects up to 100 MW on Oahu. In June 2008, the PUC approved HECO’s RFP and HECO issued the RFP. Bids are due in September 2008.

HECO’s unregulated subsidiary, Renewable Hawaii, Inc. (RHI), is seeking to stimulate renewable energy initiatives by prospecting for new projects and sites and taking a passive, minority interest in selected third party renewable energy projects. Since 2003, RHI has actively pursued a number of solicited and unsolicited projects, particularly those utilizing wind, landfill gas, and ocean energy. RHI will generally make project investments only after developers secure the necessary approvals and permits and independently execute a PUC-approved PPA with HECO, HELCO or MECO. While RHI has executed some memoranda of understanding and conditional investment agreements with project developers, no investments have been made to date.

The electric utilities promote research and development in the areas supporting renewable energy such as biofuels, ocean energy, battery storage, electronic shock absorber, and integration of non-firm power into the isolated island electric grids.

Energy efficiency and DSM programs for commercial and industrial customers, and residential customers, including load control programs, have resulted in reducing system peak load and contribute to the achievement of the RPS. Since the inception of the energy efficiency and DSM programs in 1996 and through the end of 2007, the total system peak load has been reduced by 118 MW (100 MW at HECO, 7 MW at HELCO, and 11 MW at MECO) at the gross generation level and net of estimated reductions from participants who would have installed the DSM measure without the program and rebate.

In January 2008, the State of Hawaii and U.S. Department of Energy (DOE) signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). The stated purpose of the HCEI is to establish a long-term partnership between the State of Hawaii and DOE that will result in a fundamental and sustained transformation in the way in which renewable energy efficiency resources are planned and used in the State. HECO is working with the State and the DOE and other stakeholders to align the utility’s energy plans with the State’s plans.

Also, see “Renewable Portfolio Standard” under “Legislation and regulation” below.

Competition

Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation.

In October 2003, the PUC opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.

Competitive bidding proceeding. The stated purpose of this proceeding was to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable, (2) the determination of whether to use competitive bidding for a future generation resource or a block of generation resources will be made by the PUC during its review of the utility’s integrated resource plan (IRP), (3) an

 

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exemption from the framework is granted for cooperatively-owned utilities, (4) the framework does not apply to two pending projects (HECO’s CIP-1 and HELCO’s ST-7), MECO’s M-18 project (which went into commercial operation in October 2006), specifically identified offers to sell energy on an as-available basis or to sell firm energy and/or capacity by non-fossil fuel producers that were under review by an electric utility at the time the framework was adopted (provided that negotiations with the nonfossil fuel producers for firm capacity were completed no later than December 31, 2007), and certain other situations identified in the framework, (5) waivers from competitive bidding for certain circumstances will be considered by the PUC and granted when considered appropriate, (6) for each project that is subject to competitive bidding, the utility is required to submit a report on the cost of parallel planning upon the PUC’s request, (7) the utility is required to consider the effects on competitive bidding of not allowing bidders access to utility-owned or controlled sites, and to present reasons to the PUC for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (8) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its RFP or when the PUC otherwise determines, (9) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP, (10) the evaluation of the utility’s bid should account for the possibility that the capital or running costs actually incurred, and recovered from ratepayers, over the plant’s lifetime, will vary from the levels assumed in the utility’s bid and (11) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC. In 2007, the PUC approved the utilities’ tariffs containing procedures for interconnection and transmission upgrades, a list of qualified candidates for the Independent Observer position for future competitive bidding processes and a Code of Conduct, and closed the competitive bidding docket.

In February 2008, HECO submitted to the PUC and Consumer Advocate a draft RFP, which seeks proposals for the supply of up to approximately 100 MW of long-term (i.e. 20 years) renewable energy for the island of Oahu under a power purchase agreement. The PUC approved and HECO issued the RFP in June 2008. A Bidders Conference was held in July 2008 and bids are due in September 2008.

In December 2007, in response to MECO’s request for approval to proceed with a competitive bidding process to acquire two separate increments of approximately 20 MW to 25 MW of firm generating capacity on the island of Maui in the 2011 and 2015 timeframes, the PUC issued an order opening a new docket to receive filings, review approval requests, and resolve disputes, if necessary, related to MECO’s proposed RFP. The order identified MECO and the Consumer Advocate as parties to this new docket and approved MECO’s contract with the Independent Observer for the proposed RFP. In June 2008, MECO developed a new sales and peak forecast, which projects lower sales and peaks compared to the previous, July 2007, forecast. Due primarily to a reduction in the forecast of the peak system demand on the island of Maui, MECO is reevaluating the scope and schedule for issuance of a draft RFP for the next increment of firm generating capacity, which is now projected to be needed in the 2014 timeframe.

In May 2008, the PUC issued a D&O stating that PGV’s proposal to modify its existing PPA to provide an additional 8 MW of firm capacity by expanding its existing facility is exempt from the Competitive Bidding Framework. The utilities have filed other applications for waivers from the Competitive Bidding Framework, decisions on which are pending.

Management cannot currently predict the ultimate effect of these developments on the ability of the utilities to acquire or build additional generating capacity in the future.

DG proceeding. In October 2003, the PUC opened a DG proceeding to determine DG’s potential benefits to and impact on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii.

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

 

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to promote the development of a competitive market for customer-sited DG. The PUC found that the “disadvantages outweigh the advantages” of allowing a utility to provide DG services on a customer’s site. However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the utilities from providing DG services at this early stage of DG market development. Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.

In April 2006, the PUC provided clarification to the conditions under which the utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework), and affirmed that the electric utility has the responsibility to demonstrate that it meets all applicable criteria included in the D&O in its application for PUC approval to proceed with a specific DG project.

The utilities are evaluating potential DG projects. In February 2008, MECO received PUC approval of an agreement for the installation of a CHP system at a hotel site on the island of Lanai.

The January 2006 D&O also required the utilities to file tariffs and establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services). The utilities filed their proposed modifications to existing DG interconnection tariffs and their proposed unbundled standby rates for PUC approval in the third quarter of 2006. The Consumer Advocate stated that it did not object to implementation of the interconnection and standby rate tariffs at the present time, but reserved the right to review the reasonableness of both tariffs in rate proceedings for each of the utilities. See “Distributed generation tariff proceeding” below.

Distributed generation tariff proceeding. In December 2006, the PUC opened a new proceeding to investigate the utilities’ proposed DG interconnection tariff modifications and standby rate tariffs. In March 2008, the parties to the proceeding filed a settlement agreement with the PUC that a standby service tariff agreed to by the parties should be approved. The interconnection tariffs, with modifications made in response to the PUC’s information requests, were approved in April 2008. In May 2008, the PUC approved the settlement agreement on the standby service tariff.

Most recent rate requests

The electric utilities initiate PUC proceedings from time to time 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 the application, but there is no guarantee of such an interim increase or its amount and amounts collected are refundable, with interest, to the extent they exceed the amount approved in the final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the return on average common equity (ROACE) and return on rate base (ROR)) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

As of August 1, 2008, the ROACE found by the PUC to be reasonable in the most recent final rate decision for each utility was 10.7% for HECO (D&O issued on May 1, 2008, based on a 2005 test year), 11.5% for HELCO (D&O issued on February 8, 2001, based on a 2000 test year) and 10.94% for MECO (amended D&O issued on April 6, 1999, based on a 1999 test year). The ROACEs used by the PUC in the interim rate increases in HECO, HELCO and MECO rate cases based on 2007, 2006 and 2007 test years issued in October, April and December 2007, respectively, were 10.7%.

For the 12 months ended June 30, 2008, the actual ROACEs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates, and reported to the PUC) for

 

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HECO, HELCO and MECO were 8.21%, 10.40% and 8.70%, respectively. HECO’s and MECO’s actual ROACEs were significantly lower than their authorized ROACEs primarily because of the timing of the interim rate relief for their respective 2007 test year rate cases and increased O&M expenses, which are expected to continue. The interim rate relief granted to the utilities by the PUC (see below) in their most recent cases was based in part on increased costs of operating and maintaining their systems, and the gap between allowed and actual ROACEs has been narrowing as interim rate relief has become effective.

As of August 1, 2008, the ROR found by the PUC to be reasonable in the most recent final rate decision for each utility was 8.66% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). The RORs used by the PUC for purposes of the interim D&Os in the HECO, HELCO and MECO rate cases based on 2007, 2006 and 2007 test years were 8.62%, 8.33% and 8.67%, respectively. For the 12 months ended June 30, 2008, the actual RORs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates, and reported to the PUC) for HECO, HELCO and MECO were 6.60%, 7.98% and 7.01%, respectively.

In 2007, HECO, HELCO and MECO received interim D&Os in their most recent rate cases, which included the reclassification to a regulatory asset of the charge for retirement benefits that would otherwise be recorded in accumulated other comprehensive income (AOCI).

HECO.

2005 test year rate case. In November 2004, HECO filed a request with the PUC to increase base rates, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. Disregarding an amount included in the request to transfer the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges, the requested base rates increase was $74 million, or 7.3%.

In September 2005, HECO, the Consumer Advocate and the DOD reached agreement (subject to PUC approval) on most of the issues in the rate case proceeding. The significant issue not resolved among the parties was the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes.

Later in September 2005, the PUC issued its interim D&O, authorizing an increase of $53 million ($41 million net additional revenues). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with an annual rate increase impact of approximately $7 million).

On October 25, 2007, the PUC issued an amended proposed final D&O, authorizing a net increase of 2.7%, or $34 million, in annual revenues, based on a 10.7% ROACE (and an 8.66% ROR on a rate base of $1.060 billion). The amended proposed final D&O, which has now been issued in final form with certain modifications (as described below), reversed the portion of the interim D&O related to the inclusion of HECO’s approximately $50 million pension asset, net of deferred income taxes, in rate base, and required a refund of revenues associated with that reversal, including interest, retroactive to September 28, 2005 (the date the interim increase became effective). In the third quarter of 2007, HECO accrued $15 million for the potential customer refunds, reducing third quarter 2007 net income by $8.3 million. The potential additional refund to customers for the amounts recorded under interim rates in excess of the amount in the amended proposed final D&O from October 1, 2007 through October 21, 2007, with interest through July 19, 2008, is approximately $1.8 million, which amount has been reserved for the refund and includes an adjustment for the interest synchronization method adopted by the PUC (as proposed by the DOD in its filed exception to the proposed final D&O). The refund, with interest, to customers is expected to be completed in the fourth quarter of 2008.

On May 1, 2008, the PUC issued the final D&O for HECO’s 2005 test year rate case, which was consistent with the stipulated revised results of operations filed by the parties on March 28, 2008, and authorized an increase of $45 million in annual revenues ($34 million net) based on a 10.7% ROACE (and an 8.66% ROR on a rate base of $1.060 billion). In the final D&O, the PUC accepted the parties’ position that the review of the ECAC under Act 162 would be made in HECO’s 2007 test year rate case. See Note 8 of HECO’s “Notes to Consolidated Financial Statements.”

 

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2007 test year rate case. On December 22, 2006, HECO filed a request with the PUC for a general rate increase of $99.6 million, or 7.1% over the electric rates currently in effect (i.e., over rates that included the interim rate increase discussed above of $53 million ($41 million net additional revenues) granted by the PUC in September 2005), based on a 2007 test year, an 8.92% ROR, an 11.25% ROACE and a $1.214 billion average rate base. This rate case excluded DSM surcharge revenues and associated incremental DSM costs because certain DSM issues, including cost recovery, were being addressed in the EE DSM Docket.

HECO’s 2006 application included a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase includes costs incurred to maintain and improve reliability, such as the new Dispatch Center building and associated equipment and the Energy Management System that became operational in 2006, new substations, a new outage management system (added in 2007) and increased O&M expenses. The application addresses the ECAC provisions of Act 162 and requests the continuation of HECO’s ECAC.

On December 29, 2006, the electric utilities’ Report on Power Cost Adjustments and Hedging Fuel Risks (ECAC Report) prepared by their consultant, National Economic Research Associates, Inc., was filed with the PUC. The testimonies filed in the latest rate cases for HECO, HELCO and MECO included or incorporated the ECAC Report, which concluded that (1) the electric utilities’ ECACs are well-designed and benefit the electric utilities and their ratepayers and (2) the ECACs comply with the statutory requirements of Act 162. With respect to hedging, the consultants concluded that (1) hedging of oil by HECO would not be expected to reduce fuel and purchased power costs and in fact would be expected to increase the level of such costs and (2) even if rate smoothing is a desired goal, there may be more effective means of meeting the goal, and there is no compelling reason for the electric utilities to use fuel price hedging as the means to achieving the objective of increased rate stability.

HECO’s application requested a return on HECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred taxes) in rate base. In a separate AOCI proceeding, the electric utilities had earlier requested PUC approval to record as a regulatory asset for financial reporting purposes, the amounts that would otherwise be charged to AOCI in stockholders’ equity as a result of adopting SFAS No. 158, but that request was denied. HECO thus proposed in the 2007 test year rate case to restore to book equity for ratemaking purposes the amounts charged to AOCI as a result of adopting SFAS No. 158. The authorized ROACE found to be fair in a rate case is applied to the equity balance in determining the utility’s weighted cost of capital, which is the rate of return applied to the rate base in determining the utility’s revenue requirements. HECO’s position was that, if the reduction in equity balance resulting from the AOCI charges is not restored for ratemaking purposes, a higher ROACE will be required.

In March 2007, a public hearing on the rate case was held. In April 2007, the PUC granted the DOD’s motion to intervene.

In a June 2007 update to its direct testimonies, HECO proposed pension and OPEB tracking mechanisms, similar to the mechanisms that were agreed to by HELCO and the Consumer Advocate and approved on an interim basis by the PUC in the HELCO 2006 test year rate case. A pension funding study (required by the PUC in the AOCI proceeding) was filed in the HECO rate case in May 2007. The conclusions in the study were consistent with the funding practice proposed with the pension tracking mechanism. For a discussion of this mechanism and related pension issues, see Note 8, “Retirement Benefits” of HEI’s “Notes to Consolidated Financial Statements.”

On September 6, 2007, HECO, the Consumer Advocate and the DOD (the parties) executed and filed an agreement on most of the issues in HECO’s 2007 test year rate case and HECO submitted a statement of probable entitlement with the PUC. The agreement was subject to approval by the PUC.

The amount of the revenue increase based on the stipulated agreement was $70 million annually, or a 4.96% increase over current effective rates at the time of the stipulation. The settlement agreement included, as a negotiated compromise of the parties’ respective positions, an ROACE of 10.7% (and an 8.62% ROR of $1.158 billion) to determine revenue requirements in the proceeding. In the settlement agreement, the parties agreed that the final rates set in HECO’s 2005 test year rate case may impact revenues at current effective rates and at present rates, and indicated that the amount of the stipulated interim rate increase would be adjusted to take into account any such changes. For purposes of the settlement, the parties agreed to a pension tracking mechanism that does not include amortization of HECO’s pension asset (comprised of accumulated contributions

 

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to its pension plan in excess of net periodic pension cost and amounting to $68 million at December 31, 2006) as part of the pension tracking mechanism in the proceeding. (This has the effect of deferring the issue of whether the pension asset should be amortized for rate making purposes to HECO’s next rate case.)

In accordance with Act 162 (Hawaii Revised Statutes §269-16(g)), the PUC, by an order issued August 24, 2007, had added as an issue to be addressed in the rate case whether HECO’s ECAC complies with the requirements of Act 162. In the settlement agreement, the parties agreed that the ECAC should continue in its present form for purposes of an interim rate increase and stated that they are continuing discussions with respect to the final design of the ECAC to be proposed for approval in the final D&O. The parties will file proposed findings of fact and conclusions of law on all issues in this proceeding, including the ECAC, and the schedule for that filing is being determined. The parties agreed that their resolution of this issue would not affect their agreement regarding revenue requirements in the proceeding.

On October 22, 2007, the PUC issued, and HECO implemented, an interim D&O granting HECO an increase of $70 million in annual revenues over rates effective at the time of the interim D&O, subject to refund with interest. The interim increase is based on the settlement agreement described above and did not include in rate base the HECO pension asset. The interim D&O also approves, on an interim basis, the adoption of the pension tracking mechanism and a tracking mechanism for OPEB. See “Interim increases” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

On May 1, 2008, the PUC issued the final D&O for HECO’s 2005 test year rate case, which was consistent with the stipulated revised results of operations filed by the parties on March 28, 2008. Consistent with the previous settlement agreement with the parties in this case, HECO filed a motion with the PUC in May 2008 to adjust the amount of the interim increase in this proceeding from $70 million to $78 million to take into account the changes in current effective rates as a result of the final decision in the 2005 test year rate case, and to have the change be effective at the same time the tariff sheets reflecting the final decision in the 2005 rate case become effective. In June 2008, the PUC approved HECO’s motion.

Management cannot predict the timing, or the ultimate outcome, of a final D&O in HECO’s 2007 test year rate case.

2009 test year rate case. On July 3, 2008, HECO filed a request for a general rate increase of $97 million or 5.2% over the electric rates currently in effect (i.e., over rates that included the interim rate increase discussed above granted by the PUC in HECO’s 2007 test year rate case, which amount is $78 million based on the final decision in HECO’s 2005 test year rate case), based on a 2009 test year, an 8.81% ROR, an 11.25% ROACE, and a $1.408 billon rate base. HECO’s application requested an interim increase of $73 million on or before the statutory deadline for interim rate relief and a step increase of $24 million based on the return on net investment of the new combustion turbine generating unit at Campbell Industrial Park and recovery of associated expenses to be effective at the in-service date of the new unit, scheduled for the end of July 2009.

The requested rate increase will support anticipated plant additions of $375 million in 2008 and 2009 (including $162 million for the new generating unit) to maintain and improve system reliability, higher operation and maintenance costs required for HECO’s electrical system, and higher depreciation expenses since the last rate case. As in its 2007 test year rate case, HECO requests continuation of its ECAC in its present form.

The request excludes incremental DSM costs from the test year revenue requirement due to the transition of HECO’s DSM programs to a third-party program administrator in 2009 as ordered by the PUC.

Management cannot predict the timing, or the ultimate outcome, of an interim or final D&O.

HELCO. In May 2006, HELCO filed a request with the PUC to increase base rates by $29.9 million, or 9.24% in annual base revenues, based on a 2006 test year, an 8.65% ROR, an 11.25% ROACE and a $369 million average rate base. HELCO’s application included a proposed new tiered rate structure, which would enable most residential users to see smaller increases in the range of 3% to 8%. The tiered rate structure is designed to minimize the increase for residential customers using less electricity and is expected to encourage customers to take advantage of solar water heating programs and other energy management options. In addition, HELCO’s application proposes new time-of-use service rates for residential and commercial customers. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution line

 

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improvements and the two generating units at the Keahole power plant (CT-4 and CT-5), and increased O&M expenses. The application requests the continuation of HELCO’s ECAC.

The PUC held public hearings on HELCO’s application in June 2006. In February 2007, the Consumer Advocate submitted its testimony in the proceeding, recommending a revenue increase of $16.6 million based on its proposed ROR of 7.95%, a ROACE ranging between 9.50% and 10.25% and a proposed average rate base of $345 million. The Consumer Advocate recommended adjustments of $21.5 million to HELCO’s rate base for a portion of CT-4 and CT-5 costs (primarily relating to HELCO’s AFUDC, land use permitting costs, and related litigation expenses). In the filing, the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. In July 2008, HELCO submitted responses to information requests from the PUC regarding the impacts of passing changes in fuel and purchased energy costs to customers through the ECAC.

Keahole Defense Coalition (whose participation in the proceeding is limited) submitted a Position Statement in which it contended that the PUC should exclude from rate base a greater amount of the CT-4 and CT-5 costs than proposed by the Consumer Advocate.

In March 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement issues in the HELCO 2006 rate case proceeding, which were documented in an April 5, 2007 settlement letter. Under the revenue requirement agreement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, which resulted in an after-tax charge of approximately $7 million in the first quarter of 2007.

On April 4, 2007, the PUC issued an interim D&O, which was implemented by tariff changes made effective on April 5, 2007, granting HELCO an increase of 7.58%, or $24.6 million in annual revenues, over revenues at present rates for a normalized 2006 test year. The interim increase reflects the settlement of the revenue requirement issues reached between HELCO and the Consumer Advocate and is based on an average rate base of $357 million (which reflects the write-off of a portion of CT-4 and CT-5 costs) and an ROR of 8.33% (incorporating an ROACE of 10.7%). In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms.

Pursuant to an agreed upon schedule of proceedings, Keahole Defense Coalition filed a response to HELCO’s rebuttal testimony on April 28, 2007, to which HELCO responded on May 11, 2007. On May 15, 2007, HELCO and the Consumer Advocate filed a settlement letter that reflected their agreement on the remaining rate design issues in the proceeding. HELCO and the Consumer Advocate filed their opening briefs in support of their settlement on June 4, 2007 and agreed not to file reply briefs. In April 2008, HELCO and the Consumer Advocate filed a supplement providing additional record cites and supporting information relevant to their April 2007 settlement letter.

Management cannot predict the timing, or the ultimate outcome, of a final D&O.

MECO. In February 2007, MECO filed a request with the PUC to increase base rates by $19.0 million, or 5.3% in annual base revenues, based on a 2007 test year, an 8.98% ROR, an 11.25% ROACE and a $386 million average rate base. MECO’s application includes a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase would pay for improvements to increase reliability, including two new generating units added since MECO’s last rate case (which was based on a 1999 test year) at its Maalaea Power plant (M19, a 20 MW combustion turbine placed in service in 2000 and M18, an 18 MW steam turbine placed in service in October 2006 to complete the installation of a second dual-train combined cycle unit), and transmission and distribution infrastructure improvements. The proposed rate structure also includes continuation of MECO’s ECAC. The application requested a return on MECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred income taxes) in rate base. The application also proposed to restore book equity (in determining the equity balance for ratemaking purposes) for the amounts that were charged against equity (i.e., to AOCI) as a result of recording a pension and other postretirement benefits liability after implementing SFAS No. 158.

In an update to its direct testimonies filed in September 2007, MECO proposed a lower increase in annual revenues of $18.3 million, or 5.1%, but its request continued to be based on an 8.98% ROR and an 11.25% ROACE. Also in the update, MECO proposed tracking mechanisms for pension and OPEB, similar to the mechanisms proposed by HECO and HELCO, and approved by the PUC on an interim basis, in their 2007 and

 

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2006 test year rate cases, respectively. In October 2007, the Consumer Advocate filed its direct testimony which recommended a revenue increase of $8.9 million, based on a ROR of 8.29% and a ROACE of 10.0%. $4.75 million of the $9.4 million difference between MECO’s and the Consumer Advocate’s proposed increase is caused by the Consumer Advocate’s lower recommended ROR and ROACE.

On December 7, 2007, MECO and the Consumer Advocate (for purposes of this section, the “Parties”) reached a settlement of all the revenue requirement issues in this rate case proceeding. For purposes of the settlement agreement, the parties agreed that MECO’s energy cost adjustment clause provides a fair sharing of the risks of fuel cost changes between MECO and its ratepayers and no further changes are required for MECO’s energy adjustment clause to comply with the requirements of Act 162.

On December 21, 2007, the PUC issued an interim D&O granting MECO an increase of $13.2 million in annual revenues, or a 3.7% increase, subject to refund with interest. The interim increase is based on the settlement agreement, which included, as a negotiated compromise of the Parties’ respective positions, an increase of $13.2 million in annual revenue, a 10.7% ROACE, an 8.67% ROR and a rate base of $383 million (which did not include MECO’s pension asset, which amounted to $1 million as of December 31, 2007).

In the interim D&O, the PUC also approved on an interim basis the adoption of pension and OPEB tracking mechanisms.

Management cannot predict the timing, or the ultimate outcome, of a final D&O.

Other regulatory matters. In addition to the items below, also see “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Demand-side management programs. On February 13, 2007, the PUC issued its D&O in the EE DSM Docket that had been opened by the PUC to bifurcate the EE DSM issues originally raised in the HECO 2005 test year rate case. In the D&O, the PUC authorized HECO to implement its eight proposed EE DSM programs (which include enhancements to its six existing programs, and two new programs, the Residential Low Income (RLI) and the Residential Customer Energy Awareness (RCEA) Programs), with certain modifications. In approving the EE DSM program portfolio, the PUC found that: (1) the EE DSM portfolio should achieve Energy Efficiency goals and should be implemented in a cost-effective manner and (2) the EE DSM programs are necessary to help address HECO’s current reserve capacity shortfall.

In addition, the PUC required that the administration of all EE DSM programs be turned over to a non-utility, third-party administrator, with the transition to the administrator, funded through a public benefits fund (PBF) surcharge, to become effective around January 2009. The PUC opened a new docket to select a third-party administrator and to refine details of the new market structure in an order issued in September 2007. In the order, the PUC stated that “[u]pon selection of the PBF Administrator, the PUC intends, in this docket, to determine whether the electric utilities will be allowed to compete for the implementation of the Energy Efficiency DSM programs.” The PUC has issued a draft RFP for the PBF Administrator. In July 2008, the PUC issued an Order to Initiate the Collection of Funds for the PBF Administrator of Energy Efficiency Programs, which authorized the electric utilities to expense $50,000 per quarter beginning July 1, 2008 for the initial start-up costs associated with the PBF Administrator and recover the cost in the DSM surcharge; confirmed that the load management, SolarSaver and RCEA programs shall remain with the electric utilities; directed the electric utilities to continue to operate the DSM programs through June 30, 2009, and after the transition period, the electric utilities can compete for implementation of DSM programs as a subcontractor.

The EE Docket D&O also provides for HECO’s recovery of DSM program costs and utility incentives. With respect to cost recovery, the PUC continues to permit recovery of reasonably-incurred DSM implementation costs, under the IRP framework. DSM utility incentives will be derived from a graduated performance-based schedule of net system benefits. In order to qualify for an incentive, the utility must meet MW and MWh reduction goals for its EE DSM programs in both the commercial and industrial sector, and the residential sector. The amount of the annual incentive is capped at $4 million for HECO, and may not exceed either 5% of the net system benefits, or utility earnings opportunities foregone by implementing DSM programs in lieu of supply-side rate based investments. Negative incentives will not be imposed for underperformance. In 2007, HECO recorded incentives of $4 million. HELCO and MECO proposed goals for their programs, based on the goals established for HECO’s

 

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programs, but recorded no incentives in 2007. In June 2008, the PUC issued an order approving MECO’s proposed cumulative energy and demand savings goals for 2007 and 2008, but set MECO’s annual incentive cap at $320,000. Thus, in the second quarter of 2008, MECO recorded an incentive of $320,000 related to 2007. A decision on HELCO’s proposed goals is pending.

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

In April 2008, HECO filed an application for approval of a Dynamic Pricing Pilot Program and for recovery of the incremental costs of the program through the DSM Adjustment component of the IRP Cost Recovery Provision. Dynamic pricing is a type of demand response program that allows prices to change from normal tariff rates as system conditions change and encourages customer curtailment of load through price incentives when there is insufficient generation to meet a projected peak demand period. The proposed pilot will run for approximately one year and will test the effect of a demand response program on a sample of residential customers.

Avoided cost generic docket. In May 1992, the PUC instituted a generic investigation to examine the proxy method and formula used by the electric utilities to calculate their avoided energy costs and Schedule Q rates. In general, Schedule Q rates are available to customers with cogeneration and/or small power production facilities with a capacity of 100 KWHs or less who buy power from or sell power to the electric utility. In March 1994, the parties to the docket entered into a Stipulation to Resolve Proceeding, which was subject to PUC approval. In December 2006, the parties filed an updated stipulation with the PUC. The parties agreed that avoided fuel costs, except for Lanai and Molokai, will be determined using a computer production simulation model and agreed on certain parameters that would be used to calculate avoided costs. In March 2008, the PUC issued an order which approved the updated stipulation and ordered that the new avoided energy cost rates and Schedule Q rates will go into effect on August 1, 2008. Avoided energy costs will be determined using the “resource-in / resource-out” methodology instead of the proxy method. Whether avoided energy costs are higher or lower under this methodology than the proxy method will depend on several factors, including the planned outage schedule of the generating units, the mix of resources on the particular system, the forecast demand, and, for MECO and HELCO, the relative pricing of diesel fuel and industrial fuel oil. In July 2008, the electric utilities filed avoided energy cost rates and Schedule Q rates using the new methodology, to be effective August 1, 2008 through December 31, 2008, and will adjust the fuel component of the rates monthly for changes in fuel prices.

Integrated resource planning, requirements for additional generating capacity and adequacy of supply. The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop IRPs, which may be approved, rejected or modified by the PUC. The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. The utilities’ proposed IRPs are planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the PUC’s IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed.

The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities were able to recover their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery in the docket for each year’s costs. HELCO (since

 

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February 2001), HECO (since September 2005) and MECO (since December 2007) now recover IRP costs (which are included in O&M) through base rates. Previously, HECO, HELCO and MECO recovered their costs through a surcharge. The Consumer Advocate has objected to the recovery of $2.9 million (before interest) of the $9.0 million of incremental IRP costs incurred by the utilities during the 1997-2006 period, and the PUC’s decisions are pending on these costs. Also, see Note 5 in HECO’s “Notes to Consolidated Financial Statements” and “Demand-side management programs” above.

HECO’s IRP. In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation (including a combustion turbine generating unit in 2009 described under “HECO’s 2009 Campbell Industrial Park generating unit” ). In addition, HECO currently plans for all existing generating units to remain in operation (future environmental and other regulatory considerations permitting) beyond the 20-year IRP planning period (2006-2025). In May 2008, HECO filed its Evaluation Report for IRP-3, which expresses a strong preference for renewable energy and identifies near term, supply-side and demand-side resources that HECO is seeking to add. HECO anticipates that the firm capacity currently expected to be needed in 2022, which will be re-evaluated in IRP-4, will be met by renewable firm capacity resource/s. HECO is also considering conversion of its generating units to biofuels or biofuel blends. In June 2008, the PUC granted HECO’s request for an extension of time to file its IRP-4, which now must be filed by September 30, 2008.

HELCO’s IRP. In May 2007, HELCO filed its third IRP, which proposes multiple solutions to meet future energy needs on the island of Hawaii. The plan includes the installation of a nominal 16 MW steam turbine (ST-7) in 2009 at its Keahole Generating Station (see “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”). The plan also follows through on a commitment to have no new fossil-fired generation installed after ST-7. The plan anticipates increasing customer photovoltaic systems plus a 37 gigawatthours per year renewable energy resource in the 2014 to 2020 timeframe, a firm capacity renewable energy resource in 2022, energy efficiency (continuation of existing DSM programs) and CHP. In November 2007, HELCO and the Consumer Advocate filed a stipulated agreement which recommended that the PUC approve HELCO’s IRP-3 and in which HELCO agreed to make improvements to the IRP process and to submit evaluation reports by March 31, 2009 and March 31, 2010. In January 2008, the PUC issued its D&O approving HELCO’s IRP-3 and required HELCO to file its IRP-4 by May 31, 2010.

MECO’s IRP. In April 2007, MECO filed its third IRP, which proposes multiple solutions to meet future energy needs on the islands of Maui, Lanai and Molokai, including renewable energy resources (such as photovoltaics, additional wind, biomass and waste-to-energy), energy efficiency (continuation of existing and addition of new DSM programs), technology (such as CHP and DG) and competitive bidding for generation or blocks of generation on Maui for 20 MW in each of 2011 and 2013 and 18 MW in 2024 which, under the utility parallel plan, could be located at its Waena site. In July 2008, the PUC approved MECO’s IRP-3 and directed MECO to submit evaluation reports by December 31, 2008 and December 31, 2009, to make various improvements to the IRP process and to submit its IRP-4 by April 30, 2010.

The PPA between MECO and Hawaiian Commercial & Sugar Company (HC&S), which provides for 16 MW of firm capacity, continues in effect from year to year, subject to termination on written notice by either party of not less than two years. In July 2007, however, the parties agreed to not issue a notice of termination that would result in the termination of the PPA prior to the end of 2014. In June 2008, MECO developed a new sales and peak forecast, which projects lower sales and peaks compared to the previous, July 2007, forecast. In July 2008, MECO filed an update to its 2008 Adequacy of Supply letter in which it indicated that the date the next increment of additional firm generating capacity on Maui is needed has changed from 2011 to 2014.

HECO’s 2009 Campbell Industrial Park (CIP) generating unit. HECO is building a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and plans to add an additional 138 kilovolt transmission line to transmit power from generating units at CIP (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). Plans are for the CT to be run primarily as a “peaking” unit beginning in mid-2009, fueled

 

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by biodiesel. On December 15, 2005, HECO signed a contract with Siemens to purchase a 110 MW CT unit.

HECO’s Final Environmental Impact Statement for the Project was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and to take the steps necessary for HECO to reach that goal. In May 2007, the PUC issued a D&O approving the Project and the DOH issued the final air permit, which became effective at the end of June 2007. The D&O further stated that no part of the Project costs may be included in HECO’s rate base unless and until the Project is in fact installed, and is used and useful for public utility purposes. HECO’s 2009 test year rate case application, filed in June 2008, requests inclusion of the Project investment in rate base when the new unit is placed in service (expected to be at the end of July 2009).

In a related application filed with the PUC in June 2005, HECO requested approval of community benefit measures to mitigate the impact of the new generating unit on communities near the proposed generating unit site. In June 2007, the PUC issued a D&O which (1) approved HECO’s request to commit funds for HECO’s project to use recycled instead of potable water for industrial water consumption at the Kahe power plant, (2) approved HECO’s request to commit funds for the environmental monitoring programs and (3) denied HECO’s request to provide a base electric rate discount for HECO’s residential customers who live near the proposed generation site. The approved measures are estimated to cost $9 million (through the first 10 years of implementation).

Costs for the Project (exclusive of the costs of the community benefit measures described above) are currently estimated at $164 million. As of June 30, 2008, Project costs amounted to $37 million.

In August 2007, HECO entered into a contract with Imperium Services, LLC, to supply biodiesel for the planned generating unit, subject to PUC approval. Imperium Services, LLC agreed to comply with HECO’s procurement policy requiring sustainable sources of biofuel and biofuel feedstocks. In October 2007, HECO filed an application with the PUC for approval of this biodiesel supply contract.

Adequacy of supply.

HECO. HECO’s 2008 Adequacy of Supply (AOS) letter, filed in January 2008, indicates that HECO’s analysis estimates its reserve capacity shortfall to be approximately 80 MW in the 2008 to 2009 period (before the addition of the Campbell Industrial Park combustion turbine planned to be installed in 2009). The availability rates for HECO units have generally declined since 2002 and, based on this experience, the manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects availability rates to remain suppressed in the near-term. Although the availability rates for generating units on Oahu continue to be better than those of comparable units on the U.S. mainland, HECO generating units may continue to be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes.

To mitigate the projected reserve capacity shortfalls, HECO has implemented and is continuing to plan and implement mitigation measures, such as installing distributed generators at substations or other sites, implementing additional load management and other demand reduction measures, and pursuing efforts to improve the availability of generating units. HECO will operate at lower than desired reliability levels and take steps to mitigate the reserve capacity shortfall situation until the next generating unit is installed. Until sufficient generating capacity can be added to the system, HECO will experience a higher risk of generation-related customer outages.

After the planned 2009 addition of the Campbell Industrial Park generating unit, and in recognition of the uncertainty underlying key forecasts, HECO reported in its 2008 AOS letter that it anticipates the potential for continued reserve capacity shortfalls could range between 20 MW to 80 MW in 2010, up to a range of 70 MW to 130 MW in 2014, and may seek a firm, dispatchable resource (with a strong preference for a renewable resource) to meet this need, while continuing contingency planning activities. Any plan to seek additional firm capacity is required to proceed under the guidance of the Competitive Bidding Framework issued by the PUC in December 2006. HECO is currently conducting its IRP-4 process, which includes an assessment of the firm capacity resource additions needed to address expected continuing reserve capacity shortfall.

 

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HECO’s gross peak demand was 1,327 MW in 2004, 1,273 MW in 2005, 1,315 MW in 2006 and 1,261 MW in 2007. Peak demand may vary from year to year, but over time, demand for electricity on Oahu is projected to increase. On occasions in 2004, 2005, 2006 and 2007, HECO issued public requests that its customers voluntarily conserve electricity as generating units were out for scheduled maintenance or were unexpectedly unavailable. In addition to making the requests, in 2005, 2006 and 2007, HECO on occasion remotely turned off water heaters for a number of residential customers who participate in its load-control program.

HELCO. HELCO’s 2008 Adequacy of Supply letter filed in January 2008 indicated that HELCO’s generation capacity for the next three years, 2008 through 2010, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.

MECO. MECO’s 2008 Adequacy of Supply letter filed in January 2008 indicated that MECO’s generation capacity for the next three years, 2008 through 2010, is sufficient to meet the forecasted demands on the islands of Maui, Lanai and Molokai. Although MECO may not at times have sufficient capacity on the Maui system to cover for the loss of the largest unit, MECO will implement appropriate mitigation measures to overcome any reserve capacity situations.

In July 2008, MECO filed an update to its 2008 Adequacy of Supply letter in which it indicated that the date the next increment of additional firm generating capacity on Maui is needed has changed from 2011 to 2014, due primarily to a reduction in the forecast of peak demand.

On occasions in 2006 and 2007, MECO experienced lower than normal generation capacity due to the unexpected temporary losses of several of its generating units, and issued public requests that its customers voluntarily conserve electricity.

October 2006 outages. On Sunday, October 15, 2006, shortly after 7 a.m., two earthquakes centered on the island of Hawaii with magnitudes of 6.7 and 6.0 triggered power outages throughout most of the state and disrupted air traffic on all major islands. On Oahu, following the impact of the earthquakes, a series of protective actions and automatic systems operated to successively shut down all generators to protect them from potential damage. As a result, no significant damage to any of HECO’s generators, or to its transmission and distribution systems, occurred. Following the island-wide outage, HECO restored power to customers in a careful, methodical manner to further protect its system, and as a result power was restored to over 99% of its customers within a period of time ranging from approximately 4 1/2 to 18 hours. Management believes the shutdown and methodical restoration of power were necessary to prevent severe damage to HECO’s generating equipment and power grid and to avoid a more prolonged blackout. HELCO’s and MECO’s smaller electric systems also experienced sustained outages from the earthquakes; however, their systems were, for the most part, back online by mid to late afternoon.

As is the electric utilities’ practice with all major system emergencies, management immediately committed to investigating the outage caused by the earthquakes, and brought in an outside industry expert to help identify any potential improvements to procedures or systems, and also made arrangements for a preliminary briefing of the PUC on October 19 and 20, 2006. HECO also conducted a public briefing on October 23, 2006. HECO has made it clear that in addition to any investigation it undertakes, it will cooperate fully with any other reviews conducted by its regulators.

Following requests by members of a state Senate energy subcommittee and the Consumer Advocate that the PUC investigate the power failure, to which investigation HECO stated it did not object, the PUC issued an order on October 27, 2006 opening an investigative proceeding on the outages at HECO, HELCO and MECO. The questions the PUC asked to be addressed in the proceeding include (1) aside from the earthquake, are there any underlying causes that contributed or may have contributed to the power outages, (2) were the actions of the electric utilities prior to and during the power outages reasonable and in the public interest, and were the power restoration processes and communication regarding the outages reasonable and timely under the circumstances, (3) could the island-wide power outages on Oahu and Maui have been avoided, and what are the necessary steps to minimize and improve the response to such occurrences in the future and (4) what penalties, if any, should be imposed on the electric utilities. Pursuant to the PUC’s order, HECO’s 2006 Outage

 

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Report was filed in December 2006, and the outage reports of HELCO and MECO were filed in March 2007. The investigation consultants retained by HECO, POWER Engineers, Inc., concluded that, “HECO’s performance prior to and during the outage demonstrated reasonable actions in the public interest” in a “distinctly extraordinary event.” Power Engineers, Inc. also concluded that HELCO and MECO personnel responded in a “reasonable, responsible, and professional manner.” The consultants also made a number of recommendations, mostly of a technical nature, regarding the operation of the electric system during such an incident. The Consumer Advocate submitted its findings in August 2007 and found the activities and performance of HECO, HELCO and MECO personnel prior to and during the outages were reasonable and in the public interest, and recommended no penalties for “these uncommon power outages.” The Consumer Advocate also made several recommendations regarding training and potential electric system modifications. In October 2007, the electric utilities filed a final statement of position, which included proposed plans to address recommendations made by both POWER Engineers, Inc. and the Consumer Advocate. The docket is awaiting a decision by the PUC.

Management cannot predict the outcome of the investigation or its impacts on the utilities. Management currently believes the financial impacts of property damage and claims resulting from the earthquakes and outages are not material, but future findings and developments may change that belief.

Intra-governmental wheeling of electricity. In June 2007, the PUC initiated an investigation to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii. The issues in the proceeding adopted by the PUC include (1) identifying what impact, if any, wheeling will have on Hawaii’s electric industry, (2) addressing interconnection matters, (3) identifying the costs to utilities, (4) identifying any rate design and cost allocation issues, (5) considering the financial cost and impact on non-wheeling customers, (6) identifying any power back-up issues, (7) addressing how rates would be set, (8) identifying the environmental impacts, (9) identifying and evaluating the various forms of intra-governmental wheeling and (10) identifying and evaluating the resulting impact to any and all governmental entities, including but not limited to economic, feasibility and liability impacts. Parties to this proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative and the Consumer Advocate, as well as governmental agencies (the DOD, the DBEDT, the City and County of Honolulu and the Counties of Hawaii, Maui and Kauai), two environmental groups, and two renewable energy developers. Two renewable energy contractors and a renewable energy developer also have been granted more limited participant status. The procedural schedule includes technical workshops and meetings through November 2008, with a formal process to commence thereafter.

Collective bargaining agreements

See “Collective bargaining agreements” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Legislation and regulation

Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. Also see “Environmental regulation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Energy Policy Act of 2005. On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (the Act). The Act provides $14.5 billion in tax incentives over a 10-year period designed to boost conservation efforts, increase domestic energy production and expand the use of alternative energy sources, such as solar, wind, ethanol, biomass, hydropower and clean coal technology. Ocean energy sources, including wave power, are identified as renewable technologies. Section 355 of the Act authorizes a study by the U.S. Department of Energy of Hawaii’s dependence on oil; however, that provision is subject to appropriation, as is $9 million authorized under Section 208 for a sugar cane ethanol program in Hawaii. No funds have been appropriated to date. Incentives also include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. The Act’s primary direct impact on HECO and its subsidiaries is currently expected to be the reduction in the depreciable tax life, from 20 years to 15 years, of certain electric transmission equipment placed into service after April 11, 2005.

 

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Renewable Portfolio Standard. Hawaii has a RPS law requiring electric utilities to meet an RPS of 8% of KWH sales by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. These standards may be met by the electric utilities on an aggregated basis and were met in 2005 when the electric utilities attained a RPS of 11.7%. It may be difficult, however, for the electric utilities to attain the required RPS percentages in the future, and management cannot predict the future consequences of failure to do so (including potential penalties to be established by the PUC).

The RPS law provides that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources, such as wind or solar, versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The RPS law also provides for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control.

The law directed that the PUC, by December 31, 2007, develop and implement a utility ratemaking structure to provide incentives that encourage Hawaii’s electric utility companies to use cost-effective renewable energy resources found in Hawaii to meet the RPS, while allowing for deviation from the standards in the event that the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the utility which could not have been reasonably anticipated or ameliorated.

In January 2007, the PUC opened a new docket (RPS Docket) to examine Hawaii’s RPS law, to establish the appropriate penalties for failure to meet RPS targets and to determine the circumstances under which penalties should be levied. In December 2007, the PUC issued a decision and order approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. The PUC also directed the parties to file supplemental briefs regarding: (1) the reasonable range of penalties (in $/MWh) to include in the framework, (2) whether RPS non-compliance penalties should be paid into a special fund or to the State of Hawaii and (3) whether electric utilities should be expressly prohibited from recovering RPS non-compliance penalties through electric rates. Supplemental briefs and reply briefs have been filed.

In its December 2007 decision and order, the PUC deferred the RPS incentive framework to a new generic docket (Renewable Energy Infrastructure Program or REIP Docket). The Renewable Energy Infrastructure Program proposed by HECO consists of two components: (1) renewable energy infrastructure projects that facilitate third-party development of renewable energy resources, maintain existing renewable energy resources and/or enhance energy choices for customers, and (2) the creation and implementation of a temporary renewable energy infrastructure surcharge to recover the capital costs, deferred costs for software development and licenses, and/or other relevant costs approved by the PUC. These costs would be removed from the surcharge and included in base rates in the utility’s next rate case. The parties to the REIP Docket include the electric utilities, the Consumer Advocate, an environmental organization and Hawaii Renewable Energy Alliance. Public hearings were held in May 2008.

Management cannot predict the outcome of this process.

Net energy metering. Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly).

In 2005, the Legislature amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kilowatts (kw) and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC), the Consumer Advocate, a renewable energy organization and a solar vendor organization. In March 2008, the PUC approved a stipulated agreement filed by the parties (except for KIUC, which has its own stipulated agreement) to increase the maximum size of the eligible customer-generators from 50 kw to 100 kw and the system cap from 0.5% to 1.0% of system peak demand, to

 

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reserve a certain percentage of the 1.0% system peak demand for generators 10 kw or less and to consider in the IRP process any further increases in the maximum capacity of customer-generators and the system cap. The PUC further required the utilities: (1) to consider specific items relating to net energy metering in their respective IRP processes, (2) to evaluate the economic effects of net energy metering in future rate case proceedings and (3) to design and propose a net energy metering pilot program for the PUC’s review and approval that will allow, on a trial basis, the use of a limited number of larger generating units (i.e., at least 100kw to 500kw, and may allow for larger units) for net energy metering purposes.

In April 2008, the electric utilities filed a proposed four-year net energy metering pilot program to evaluate the effects on the grid of units larger than the currently approved maximum size. The program will consist of analytical investigations and field testing and is designed for a limited number of participants that own (or lease from a third party) and operate a solar, wind, biomass, or hydroelectric generator, or a hybrid system. The electric utilities propose to recover program costs through the IRP cost recovery provision.

In 2008, the net energy metering law was again amended to authorize the PUC in its discretion, by rule or order, to modify the maximum size of the eligible net metered systems and evaluate on an island-by-island basis whether to exempt an island or utility grid system from the total rated generating capacity limits available for net energy metering.

DSM programs. See “Demand-side management programs” above.

Non-fossil fuel purchased power contracts. In 2006, a law was enacted that required that the PUC establish a methodology that removes or significantly reduces any linkage between the price paid for non-fossil-fuel-generated electricity under future power purchase contracts and the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation (in connection with the PUC’s determination of just and reasonable rates in purchased power contracts).

Greenhouse gas emissions reduction. In July 2007, Act 234 became law, which requires a statewide reduction of greenhouse gas (GHG) emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990. It also establishes a task force, comprised of representatives of state government, business (including the electric utilities), the University of Hawaii and environmental groups, which is charged with preparing a work plan and regulatory approach for “implementing the maximum practically and technically feasible and cost-effective reductions in greenhouse gas emissions from sources or categories of sources of greenhouse gases” to achieve 1990 statewide GHG emission levels. The electric utilities are participating in the Task Force, as well as in initiatives aimed at reducing their GHG emissions. Because the full scope of the Task Force report remains to be determined and regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the electric utilities and the Company.

On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts v. EPA, that, contrary to the EPA’s position, the EPA has the authority to regulate greenhouse gases under the Clean Air Act. Since then, the EPA has denied a California request for a waiver under the Clean Air Act to allow control of greenhouse gas emissions from motor vehicles, but has announced its intention to commence rulemaking to address greenhouse gas emissions. Although several bills addressing greenhouse gas emission reductions also have been introduced in Congress, none has yet been adopted. Accordingly, it is too early to assess the ultimate impact of the ruling.

On July 11, 2008, the EPA issued its Advance Notice of Proposed Rulemaking (ANPR) inviting public comment on the benefits and ramifications of regulating GHGs under the Clean Air Act (CAA or Act). The ANPR is one of the steps the EPA has taken in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, in which the Court found that the CAA authorizes the EPA to regulate tailpipe GHG emissions if the EPA determines they cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The ANPR reflects the EPA’s assessment of the complexity and magnitude of the question of whether and how GHGs could be effectively controlled under the CAA. Because the CAA language authorizing regulation of tailpipe emissions is virtually identical to the Act’s language regarding stationary source emissions, such as those emitted from the electric utilities’ facilities, the utilities have begun their review of the ANPR in order to determine whether to make comments, which are due by November 28, 2008.

 

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Renewable energy. In 2007, a law was enacted that stated that the PUC may consider the need for increased renewable energy in rendering decisions on utility matters. Due to this measure, it is possible that, if energy from a renewable source were more expensive than energy from fossil fuel, the PUC may still approve the purchase of energy from the renewable source.

In 2008, a law was enacted to promote and encourage the use of solar thermal energy. This measure will require the installation of solar thermal water heaters in residences constructed after January 1, 2010, but allow for limited variances in cases where installation of solar water heating is deemed inappropriate. The measure will establish standards for quality and performance of such systems. Also in 2008, a law was enacted that is intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects.

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

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

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

Other developments

Advanced Meter Infrastructure (AMI). HECO continues to evaluate two-way wireless technologies for utility applications through ongoing field tests of a pilot AMI system. The AMI system uses two-way Sensus Metering Systems’ FlexNet technology to communicate with 6,900 advanced meters at both residential and commercial customer sites. AMI technology enables automated meter reading, time-of-use pricing and conservation options for HECO customers. Other utility applications being evaluated include distribution system line monitoring and water heater and air conditioning load control for improved reliability for residential and commercial customers. HECO currently plans to file an application with the PUC for approval of a full-scale AMI project in the second half of 2008.

Commitments and contingencies

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

Recent accounting pronouncements and interpretations

See Note 7 of HECO’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources

HECO believes that its 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 capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.

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

 

(in millions)

   June 30, 2008     December 31, 2007  

Short-term borrowings

   $ 117    5 %   $ 29    1 %

Long-term debt

     900    41       885    43  

Preferred stock

     34    2       34    2  

Common stock equity

     1,149    52       1,110    54  
                          
   $ 2,200    100 %   $ 2,058    100 %
                          

 

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As of August 1, 2008, the S&P and Moody’s ratings of HECO securities were as follows:

 

     S&P     Moody’s  

Commercial paper

   A-2     P-2  

Revenue bonds (principal amount noted in parentheses, senior unsecured, insured as follows):

    

Ambac Assurance Corporation ($0.2 billion)

   AA     Aa3  

Financial Guaranty Insurance Company ($0.3 billion)

   BBB *   Baa1 *

MBIA Insurance Corporation ($0.3 billion)

   AA     A2  

XL Capital Assurance Inc. ($0.1 billion)

   BBB *   Baa1 *

HECO-obligated preferred securities of trust subsidiary

   BB+     Baa2  

Cumulative preferred stock (selected series)

   Not rated     Baa3  

The above ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating. HECO’s overall S&P corporate credit rating is BBB/Stable/A-2.

 

* As a result of downgrades, Financial Guaranty Insurance Company’s (FGIC’s) and XL Capital Assurance Inc’s (XLCA’s) current financial strength ratings by S&P are BB and BBB-, respectively, and their insurance financial strength ratings by Moody’s are B1 and B2, respectively. The revenue bonds insured by FGIC and XLCA referenced in the table above reflect a rating which corresponds to HECO’s senior unsecured debt rating by S&P, and HECO’s issuer rating by Moody’s, because those ratings are higher than those of the applicable bond insurer.

The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HECO securities. In May 2008, S&P affirmed its ratings for HECO and indicated a stable outlook. S&P’s rating outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” In May 2008, S&P stated:

Unsupportive or lagged rate treatment or changes in the current fuel adjustment clause of the company that would result in erosion of key financial parameters, especially cash flow coverage of debt, would be cause for change in the current ratings and/or a negative outlook. A severe slump in the state economy could also contribute to downward rating pressure. Given these challenges, higher ratings are not foreseen during the outlook horizon and would need to be accompanied by sustained and improved financial performance.

S&P designates business risk profiles as “excellent,” “strong,” “satisfactory,” “weak” or “vulnerable.” S&P stated in May 2008 that: “HECO’s strong business profile reflects stable, regulated utility assets of all three utilities, which serve about 95% of Hawaii’s population.”

S&P’s financial risk designations are “minimal,” “modest,” “intermediate,” “aggressive” and “highly leveraged.” In May 2008, S&P indicated that “[t]he consolidated financial profile is aggressive, reflecting in part the very heavy debt imputation we apply to the three utilities for power purchase agreements (PPA).”

In December 2007, Moody’s maintained its ratings and stable outlook for HECO. Moody’s stated, “The rating could be downgraded should weaker than expected regulatory support emerge at HECO, including the continuation of regulatory lag, which ultimately causes earnings and sustainable cash flows to suffer.” To that end, if the utilities’ financial ratios declined on a permanent basis such that the Adjusted Cash Flow (net cash flow from operations less net changes in working capital items) to Adjusted Debt fell below 17% (16% as of September 30, 2007-latest reported by Moody’s) or Adjusted Cash Flow to Adjusted Interest declined to less than 3.6x (3.8x as of September 30, 2007-latest reported by Moody’s) for an extended period, the rating could be lowered.

HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the consolidation of HECO’s financial

 

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statements. As of June 30, 2008, HELCO and MECO had $46.7 million and $15.0 million, respectively, of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first six months of 2008 of $63 million and had $117 million of commercial paper outstanding as of June 30, 2008. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult and expensive for HECO to sell commercial paper under current market conditions.

Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement expires on March 31, 2011. As of August 1, 2008, the line was undrawn. In the future, HECO may seek to modify the credit facility in accordance with the expedited approval process approved by the PUC, including to increase the amount of credit available under the agreement, and/or to enter into new lines of credit, as management deems appropriate.

Revenue bonds are issued by the Department of Budget and Finance of the State of Hawaii for the benefit of HECO and its subsidiaries, but the source of their repayment are the unsecured obligations of HECO and its subsidiaries under loan agreements and notes issued to the Department, including HECO’s guarantees of its subsidiaries’ obligations. The payment of principal and interest due on all revenue bonds currently outstanding are insured either by Ambac Assurance Corporation (Ambac), Financial Guaranty Insurance Company (FGIC), MBIA Insurance Corporation (MBIA) or XL Capital Assurance, Inc. (XLCA). The currently outstanding revenue bonds were initially issued with S&P and Moody’s ratings of AAA and Aaa, respectively, based on the ratings at the time of issuance of the applicable bond insurer. In 2008, however, ratings of Ambac, MBIA, FGIC and XLCA were downgraded by S&P and Moody’s resulting in a downgrade of the bond ratings of all of the bonds as shown in the table above. S&P and/or Moody’s ratings of Ambac, FGIC, MBIA and XLCA are reported to be on watch and/or negative outlook.

Operating activities provided $17 million in net cash during the first six months of 2008. Investing activities during the same period used net cash of $92 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $80 million, primarily due to an $89 million net increase in short-term borrowings and drawdown of $15 million in Special Purpose Revenue Bonds (SPRBs), partly offset by the payment of $15 million of common and preferred dividends and $9 million decrease in cash overdraft.

SPRBs of up to $20 million (for HELCO) and up to $400 million ($260 million for HECO, $115 million for HELCO and $25 million for MECO) may be issued by the Department of Budget and Finance of the State of Hawaii under 2005 and 2007 legislative authorizations prior to the end of June 30, 2010 and June 30, 2012, respectively, to finance the electric utilities’ capital improvement projects.

The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.

As part of HECO’s 2009 test year rate case filing, HECO’s financing cost was based in part on gross capital expenditures of $205 million in 2009. The $205 million reflects a $33 million increase from the estimate of gross capital expenditures for 2009 included in the previous five-year (2008-2012) consolidated utility forecast of $1.3 billion, as a result of further review of investments needed for infrastructure reliability.

 

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BANK

RESULTS OF OPERATIONS

 

     Three months ended June 30    %
change
     

(in thousands)

   2008     2007     

Primary reason(s) for significant change

Revenues

   $ 85,950     $ 107,526    (20 )   Lower interest and noninterest income, including a $19 million loss on the sale of securities related to the balance sheet restructure

Operating income (loss)

     (30,992 )     19,694    NM     Higher net interest income, offset by lower noninterest income and higher noninterest expense, including a $40 million loss on the early extinguishment of debt related to the balance sheet restructure

Net income (loss)

     (18,093 )     12,582    NM     See operating income (loss) above, partly offset by lower income taxes
     Six months ended June 30    %
change
     

(in thousands)

   2008     2007     

Primary reason(s) for significant change

Revenues

   $ 191,794     $ 211,986    (10 )   Lower interest and noninterest income, including a $19 million loss on the sale of securities related to the balance sheet restructure

Operating income (loss)

     (7,629 )     38,122    NM     Higher net interest income, offset by lower noninterest income and higher noninterest expense, including a $40 million loss on the early extinguishment of debt related to the balance sheet restructure

Net income (loss)

     (3,517 )     24,178    NM     See operating income (loss) above, partly offset by lower income taxes

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

Net interest margin and other factors

Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The current interest rate environment is very volatile due to disruptions in the financial markets and may have a negative impact on ASB’s net interest margin.

Loan originations and purchases of loans and mortgage-related securities are ASB’s primary sources of earning assets. 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. As of June 30, 2008, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 12% commercial loans, 7% commercial real estate loans and 7% consumer loans. As of December 31, 2007, ASB’s loan portfolio mix, net, consisted of 75% residential loans, 11% commercial loans, 7% commercial real estate loans and 7% consumer loans. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand.

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. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds. As of June 30, 2008, ASB’s costing liabilities consisted of 87% deposits and 13% other borrowings. As of December 31, 2007, ASB’s costing liabilities consisted of 71% deposits and 29% other borrowings. The decrease in the relative level of other borrowings and corresponding increase in the level of deposits was due to the early extinguishment of certain borrowings through the restructuring of ASB’s balance sheet. (See “Balance sheet restructure” in Note 4 of HEI’s Notes to Consolidated Financial Statements.) Competition for deposits and the level of short-term interest rates

 

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have made it difficult to retain deposits and control funding costs. Deposit retention and growth will remain a challenge in the current environment.

Pressures from declines in the housing market will continue to impact securities held in ASB’s investment portfolio. Foreclosures within the subprime sector of the market have increased risk premiums for all mortgage-related securities, especially those underwritten in 2006 and 2007 for which underwriting standards for the collateral of the mortgage-related securities were thought to be most troublesome. While ASB does not have material exposure to securities backed by subprime collateral and does not hold any subprime positions issued within the last five years, a deep recession led by a material decline in housing prices could materially impair the value of the securities it currently holds. As of June 30, 2008, 57% of ASB’s portfolio is held in debentures or mortgage-related securities issued by government-sponsored entities. The remaining 43% of the portfolio is composed of mortgage-related securities issued by private issuers (41% are rated AAA and 2% are rated AA, A, or BBB by nationally recognized statistical rating organizations). While the credit quality of the portfolio remains sound, a significant downturn in housing prices combined with a prolonged recession could erode credit support of non-agency mortgage-related securities and result in realized and unrealized losses in ASB’s portfolio, and these losses could be material. The mortgage-related securities portfolio currently holds two positions whose principal is guaranteed by bond insurance companies whose ratings have been downgraded. The two positions, with a current book value of $0.3 million, are not impaired and ASB has the ability and intent to hold these positions to maturity.

Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) could reduce the market value of available-for-sale investment and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities (such as those that occurred in the balance sheet restructure) or an “other-than-temporary” impairment in the value of the securities. As of June 30, 2008 and December 31, 2007, the unrealized losses, net of tax benefits, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $12 million and $18 million, respectively. See “Quantitative and qualitative disclosures about market risk.”

 

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The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for certain categories of earning assets and costing liabilities for the three and six months ended June 30, 2008 and 2007.

 

     Three months ended June 30     Six months ended June 30  

($ in millions)

   2008    2007    Change     2008    2007    Change  

Loans receivable

                

Average balances1

   $ 4,138    $ 3,800    $ 338     $ 4,137    $ 3,802    $ 335  

Interest income2

     62      60      2       125      120      5  

Weighted-average yield (%)

     5.97      6.33      (0.36 )     6.06      6.35      (0.29 )

Investments and mortgage-related securities

                

Average balances

   $ 1,917    $ 2,376    $ (459 )   $ 2,022    $ 2,379    $ (357 )

Interest income

     22      29      (7 )     46      56      (10 )

Weighted-average yield (%)

     4.62      4.85      (0.23 )     4.55      4.67      (0.12 )

Other investments3

                

Average balances

   $ 147    $ 209    $ (62 )   $ 142    $ 206    $ (64 )

Interest and dividend income

     1      2      (1 )     1      3      (2 )

Weighted-average yield (%)

     1.59      3.03      (1.44 )     1.61      2.95      (1.34 )

Total earning assets

                

Average balances

   $ 6,202    $ 6,385    $ (183 )   $ 6,301    $ 6,387    $ (86 )

Interest and dividend income

     85      91      (6 )     172      179      (7 )

Weighted-average yield (%)

     5.45      5.67      (0.22 )     5.47      5.61      (0.14 )

Deposit liabilities

                

Average balances

   $ 4,294    $ 4,498    $ (204 )   $ 4,312    $ 4,515    $ (203 )

Interest expense

     16      21      (5 )     34      42      (8 )

Weighted-average rate (%)

     1.46      1.86      (0.40 )     1.57      1.86      (0.29 )

Other borrowings

                

Average balances

   $ 1,644    $ 1,645    $ (1 )   $ 1,725    $ 1,640    $ 85  

Interest expense

     16      19      (3 )     35      37      (2 )

Weighted-average rate (%)

     3.96      4.51      (0.55 )     4.11      4.53      (0.42 )

Total costing liabilities

                

Average balances

   $ 5,938    $ 6,143    $ (205 )   $ 6,037    $ 6,155    $ (118 )

Interest expense

     32      40      (8 )     69      79      (10 )

Weighted-average rate (%)

     2.15      2.57      (0.42 )     2.30      2.57      (0.27 )

Net average balance

   $ 264    $ 242    $ 22     $ 264    $ 232    $ 32  

Net interest income

     53      51      2       103      100      3  

Interest rate spread (%)

     3.30      3.10      0.20       3.17      3.04      0.13  

Net interest margin (%)4

     3.39      3.20      0.19       3.27      3.14      0.13  

 

1 Includes nonaccrual loans.
2 Includes loan fees of $1.3 million and $1.2 million for three months and $2.4 million and $2.4 million for the six months ended June 30, 2008 and 2007, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans.
3 Includes federal funds sold and interest bearing deposits and stock in the FHLB of Seattle ($98 million as of June 30, 2008).
4 Defined as net interest income as a percentage of average earning assets.

 

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Results – three months ended June 30, 2008

Net interest income before provision for loan losses for the second quarter of 2008 increased by $1.5 million, or 3%, when compared to the same period in 2007. Net interest margin increased from 3.20% in the second quarter of 2007 to 3.39% in the second quarter of 2008 as lower yields on earning assets and lower balances of investment and mortgage-related securities were more than offset by lower funding costs and higher balances on loans. The increase in the average loan portfolio balance was due, in part, to growth in the residential loan portfolio in 2007 as a result of the strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the sale of mortgage-related securities and agency notes in the balance sheet restructuring and the use of proceeds from repayments in the portfolio to fund loans. (See “Balance sheet restructure” in Note 4 of HEI’s Notes to Consolidated Financial Statements.) Second quarter of 2008 average deposit balances decreased by $204 million compared to the second quarter of 2007, and decreased by $36 million compared to the first quarter of 2008. ASB experienced outflows in 2007 and 2008 as competitive factors and the level of short-term interest rates made it difficult to retain deposits. The shift in deposit mix from higher cost certificates to lower cost savings and checking accounts, along with the repricing of deposits as a result of a downward movement in the general level of interest rates, has contributed to decreased funding costs.

During the second quarter of 2008, ASB recorded a provision for losses of $1.2 million primarily due to the reclassification of certain commercial loans. During the second quarter of 2007, ASB recorded a provision for loan losses of $1.2 million primarily for a single commercial borrower.

Second quarter of 2008 noninterest income decreased by $15.5 million, or 91%, when compared to the second quarter of 2007, primarily due to losses on the sale of mortgage-related securities and agency notes from the balance sheet restructuring. Excluding the losses from the balance sheet restructuring, noninterest income increased by $3.8 million due to $4.3 million of insurance recoveries on legal and litigation matters and a $1.0 million gain on sale of stock in a member organization.

Noninterest expense for the second quarter of 2008 increased by $36.8 million, or 78%, when compared to the second quarter of 2007, primarily due to losses on early extinguishment of certain borrowings from the balance sheet restructuring. Excluding the losses from the balance sheet restructuring, noninterest expense decreased by $3.1 million due in part to lower consulting and legal expenses, partly offset by the write-off of $1.9 million for the disposal of software.

Results – six months ended June 30, 2008

Net interest income before provision for loan losses for six months ended June 30, 2008 increased by $2.7 million, or 3%, when compared to the same period in 2007. Net interest margin increased from 3.14% in the first six months of 2007 to 3.27% in the first six months of 2008 as lower yields on earning assets and lower balances of investment and mortgage-related securities were more than offset by lower funding costs and higher balances on loans. The increase in the average loan portfolio balance was due, in part, to growth in the residential loan portfolio in 2007 as a result of the strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the sale of mortgage-related securities and agency notes in the balance sheet restructuring and the use of proceeds from repayments in the portfolio to fund loans. Average deposit balances decreased by $203 million compared to the first six months of 2007. ASB experienced outflows in 2007 and 2008 as competitive factors and the level of short-term interest rates made it difficult to retain deposits. The shift in deposit mix from higher cost certificates to lower cost savings and checking accounts, along with the repricing of deposits as a result of a downward movement in the general level of interest rates, has contributed to decreased funding costs.

 

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During the first six months of 2008, ASB recorded a provision for losses of $2.1 million due to loan growth as well as the reclassification of certain commercial loans. During the first six months of 2007, ASB recorded a provision for losses of $1.2 million primarily for a single commercial borrower.

 

     Six months ended
June 30
   

Year ended

December 31,

 
     2008     2007     2007  
(in thousands)                   

Allowance for loan losses, January 1

   $ 30,211     $ 31,228     $ 31,228  

Provision for loan losses

     2,055       1,200       5,700  

Less: net charge-offs

     1,883       1,106       6,717  
                        

Allowance for loan losses, end of period

   $ 30,383     $ 31,322     $ 30,211  
                        

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

     0.73 %     0.82 %     0.78 %
                        

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

     0.05 %     0.03 %     0.17 %
                        

Nonaccrual loans

     8,232       7,457       3,195  
                        

Nonperforming assets to total assets

     0.15 %     0.11 %     0.05 %
                        

For the six months ended June 30, 2008, noninterest income decreased by $13.6 million, or 41%, when compared to the same period of 2007, primarily due to losses on the sale of securities from the balance sheet restructuring. Excluding the losses from the balance sheet restructuring, noninterest income increased by $5.7 million primarily due to insurance recoveries on legal and litigation matters and gain on sales of stock in membership organizations.

Noninterest expense for the first six months of 2008 increased by $34.1 million, or 36%, when compared to the first six months of 2007, primarily due to losses on early extinguishment of certain borrowings from the balance sheet restructuring. Excluding the losses from the balance sheet restructuring, noninterest expenses decreased by $5.8 million primarily due to lower consulting and legal expenses.

FINANCIAL CONDITION

Liquidity and capital resources

 

(in millions)

   June 30,
2008
   December 31,
2007
   %
change
 

Total assets

   $ 5,585    $ 6,861    (19 )

Available-for-sale investment and mortgage-related securities

     887      2,141    (59 )

Investment in stock of FHLB of Seattle

     98      98    —    

Loans receivable, net

     4,121      4,101    —    

Deposit liabilities

     4,270      4,347    (2 )

Other bank borrowings

     634      1,811    (65 )

As of June 30, 2008, ASB was the fourth largest financial institution in Hawaii based on assets of $5.6 billion. The decrease in assets since year-end was primarily due to the balance sheet restructuring.

In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3 and acknowledged ASB’s high capital ratios, excellent asset quality indicators and prudent liquidity posture. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3 and in May 2008 maintained the rating following its annual review of ASB. These ratings reflect only the view of the applicable rating agency at the time the ratings are issued, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.

As of June 30, 2008, ASB’s unused FHLB borrowing capacity was approximately $1.5 billion. As of June 30, 2008, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.3 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 six months of 2008, net cash provided by ASB’s operating activities was $11 million. Net cash provided during the same period by ASB’s investing activities was $1.2 billion, primarily due to proceeds from the

 

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sale of investment and mortgage-related securities of $1.3 billion and repayments of investment and mortgage-related securities of $0.3 billion, partly offset by purchases of investment and mortgage-related securities of $0.4 billion. Net cash used in financing activities during this period was $1.3 billion, primarily due to net decreases in Federal Home Loan Bank advances, securities sold under agreements to repurchase and deposit liabilities of $0.7 billion, $0.4 billion, and $0.1 billion, respectively.

As of June 30, 2008, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.0% (5.0%), a Tier-1 risk-based capital ratio of 13.4% (6.0%) and a total risk-based capital ratio of 14.2% (10.0%)

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 financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 50 to 52, HEI’s Quantitative and qualitative disclosures about market risk, which is incorporated into Part II, Item 7A of HEI’s 2007 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21, 2008.

ASB’s interest-rate risk sensitivity measures as of June 30, 2008 and December 31, 2007 constitute “forward-looking statements” and were as follows:

 

     June 30, 2008     December 31, 2007  
   Change in
NII
    NPV
ratio
    NPV ratio
sensitivity*
    Change in
NII
    NPV
ratio
    NPV ratio
sensitivity*
 

Change in interest rates (basis points)

   Gradual
change
    Instantaneous change     Gradual
change
    Instantaneous change  

+300

   (2.7 )%   7.83 %   (455 )   (2.2 )%   6.97 %   (334 )

+200

   (1.8 )   9.36     (302 )   (0.9 )   8.27     (204 )

+100

   (0.9 )   10.92     (146 )   (0.2 )   9.46     (85 )

Base

       12.38             10.31      

-100

   0.6     13.37     99     (0.5 )   10.40     9  

-200

   * *   * *   * *   (3.0 )   9.67     (64 )

-300

   * *   * *   * *   (6.9 )   8.68     (163 )

 

* Change from base case in basis points (bp).
** For June 30, 2008, the -200 and -300 bp scenarios were not performed because they would have resulted in negative Treasury interest rates.

ASB’s net interest income (NII) sensitivity as of June 30, 2008 is slightly more liability sensitive than it was as of December 31, 2007. In June 2008, ASB undertook and substantially completed the restructuring of its balance sheet through the sale of investment securities and early extinguishment of certain borrowings. The increase in sensitivity is partially due to the changes in the balance sheet mix following the balance sheet restructuring as well as expectations for slower prepayments compared to December 31, 2007.

The increase in ASB’s base net portfolio value (NPV) ratio as of June 30, 2008 compared to December 31, 2007 is primarily due to the reduction in the size of the bank’s total assets. Total assets as of June 30, 2008 were approximately $1.3 billion lower than as of December 31, 2007, of which, about $1 billion was due to the balance sheet restructuring transactions. The reduction in asset size resulted in higher capital ratios as of June 30, 2008 and a higher base NPV ratio. Additionally, the early termination of selected wholesale borrowings contributed to an increase in the NPV ratio due to the fact that the market value of the borrowings exceeded their book value.

ASB’s NPV ratio sensitivity measure as of June 30, 2008 is more sensitive in rising rate scenarios when compared to the NPV ratio sensitivity measure as of December 31, 2007. This was primarily due to the modeling of slower prepayment expectations.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses 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 (see page 51 of HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 21,

 

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2008 for a more detailed description of key modeling assumptions used in the NII sensitivity analysis). 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.

Item 4. Controls and Procedures

HEI:

Changes in Internal Control over Financial Reporting

During the second quarter of 2008, there was no change 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 June 30, 2008 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 Curtis Y. Harada, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of June 30, 2008. Based on their evaluations, as of June 30, 2008, 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 second quarter of 2008, there was no change 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 June 30, 2008 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

Constance H. Lau, HECO Principal Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of June 30, 2008. Based on their evaluations, as of June 30, 2008, 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 II. Item 1. Legal Proceedings”) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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

For information about Risk Factors, see pages 30 to 39 of HEI’s 2007 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on page v of HEI’s 2007 Form 10-K, as updated on page iv herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(a) For the six months ended June 30, 2008, HEI issued an aggregate of 31,600 shares of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 6, 2008 (the HEI Nonemployee Director Plan). Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,800 shares of HEI common stock (2,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (1,000 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.

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

Item 4. Submission of matters to a vote of security holders

HEI: The Annual Meeting of Shareholders of HEI was held on May 6, 2008. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Exchange Act of 1934. As of February 27, 2008, the record date for the Annual Meeting, there were 83,580,279 shares of common stock issued and outstanding and entitled to vote. There was no solicitation in opposition to the Class III management nominees to the Board of Directors with terms ending at the 2011 Annual Meeting as listed in the proxy statement for the meeting and all such nominees were elected to the Board of Directors. Shareholders also ratified the appointment of KPMG LLP as HEI’s independent registered public accounting firm for 2008 and approved the amended and restated 1990 Nonemployee Director Stock Plan and the amended and restated 1987 Stock Option and Incentive Plan.

 

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The record of the voting of shares at the Annual Meeting is as follows:

 

     Shares of Common Stock
     For    Withheld    Against    Abstain    Broker
Nonvotes

Election of Class III Directors

              

Don E. Carroll

   74,484,187    3,267,858    —      —      —  

Richard W. Gushman, II

   75,029,397    2,722,648    —      —      —  

Victor Hao Li

   74,956,902    2,795,143    —      —      —  

Bill D. Mills

   74,788,683    2,963,362    —      —      —  

Barry K. Taniguchi

   75,052,993    2,699,052    —      —      —  

Ratification of KPMG LLP as independent registered public accounting firm

   75,646,010    —      1,305,156    800,879    —  

Approval of the 1990 Nonemployee Director Stock Plan, as amended and restated

   49,904,351    —      6,260,946    2,672,388    18,914,360

Approval of the 1987 Stock Option and Incentive Plan, as amended and restated

   65,697,253    —      9,017,590    3,037,202    —  

Class I Directors—Shirley J. Daniel, Constance H. Lau, A. Maurice Myers and James K. Scott—continue in office with terms ending at the 2009 Annual Meeting. Class II Directors—Thomas B. Fargo, Diane J. Plotts, Kelvin H. Taketa and Jeffrey N. Watanabe—continue in office with terms ending at the 2010 Annual Meeting.

HECO: Effective May 6, 2008, HEI, HECO’s sole common shareholder, elected by written consent in lieu of an annual meeting (1) all eleven incumbent HECO directors and (2)  KPMG LLP as independent registered public accounting firm of HECO for 2008.

Item 5. Other Information

 

A. Ratio of earnings to fixed charges.

 

     Six months ended
June 30
   Years ended December 31
     2008    2007    2007    2006    2005    2004    2003

HEI and Subsidiaries

                    

Excluding interest on ASB deposits

   1.75    1.44    1.78    2.08    2.31    2.32    2.11

Including interest on ASB deposits

   1.52    1.29    1.52    1.73    1.98    2.00    1.84

HECO and Subsidiaries

   3.90    1.58    2.43    3.14    3.23    3.49    3.36

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

 

B. News release.

On August 4, 2008, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports Solid Second Quarter 2008 Performance.” See HEI Exhibit 99.1.

 

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Item 6. Exhibits

 

HEI

Exhibit 10.1

   HEI Executive Incentive Compensation Plan
HEI

Exhibit 10.2

   HEI Long-Term Incentive Plan
HEI

Exhibit 10.3

   1987 Stock Option and Incentive Plan of HEI (as amended and restated effective January 22, 2008)
HEI

Exhibit 10.4

   HEI 1990 Nonemployee Director Stock Plan As Amended and Restated: May 6, 2008
HEI

Exhibit 12.1

  

Hawaiian Electric Industries, Inc. and Subsidiaries

Computation of ratio of earnings to fixed charges, six months ended June 30, 2008 and 2007 and years ended December 31, 2007, 2006, 2005, 2004 and 2003

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 Curtis Y. Harada (HEI Chief Financial Officer)
HEI

Exhibit 32.1

   Written Statement of Constance H. Lau (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
HEI

Exhibit 32.2

   Written Statement of Curtis Y. Harada (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
HEI

Exhibit 99.1

   News release, dated August 4, 2008, “Hawaiian Electric Industries, Inc. Reports Solid Second Quarter 2008 Performance”
HECO

Exhibit 12.2

  

Hawaiian Electric Company, Inc. and Subsidiaries

Computation of ratio of earnings to fixed charges, six months ended June 30, 2008 and 2007 and years ended December 31, 2007, 2006, 2005, 2004 and 2003

HECO

Exhibit 31.3

   Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HECO Principal 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 32.3

   Written Statement of Constance H. Lau (HECO Principal Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002
HECO

Exhibit 32.4

   Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

 

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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/ Constance H. Lau

  Constance H. Lau      Constance H. Lau
  President and Chief Executive Officer      Chairman of the Board
  (Principal Executive Officer of HEI)      (Principal Executive Officer of HECO)
By  

/s/ Curtis Y. Harada

   By  

/s/ Tayne S. Y. Sekimura

  Curtis Y. Harada      Tayne S. Y. Sekimura
  Controller and Acting Financial Vice President,      Senior Vice President, Finance and Administration
  Treasurer and Chief Financial Officer      (Principal Financial Officer of HECO)
  (Principal Accounting and Financial Officer of HEI)     
     By  

/s/ Patsy H. Nanbu

       Patsy H. Nanbu
       Controller
       (Principal Accounting Officer of HECO)
Date: August 4, 2008    Date: August 4, 2008

 

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