UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the quarterly period ended September 30, 2005
OR
Exact Name of Registrant as
Specified in Its Charter
Commission
File Number
I.R.S. Employer
Identification No.
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 each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that each 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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
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 October 31, 2005
Hawaiian Electric Industries, Inc. (Without Par Value)
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)
Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended September 30, 2005
INDEX
Consolidated Statements of Changes in Stockholders’ Equity (unaudited) - nine months ended September 30, 2005 and 2004
Consolidated Statements of Retained Earnings (unaudited) - three and nine months ended September 30, 2005 and 2004
Bank
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GLOSSARY OF TERMS
Terms
Definitions
AES Hawaii
AES Hawaii, Inc., formerly known as AES Barbers Point, Inc.
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.) and AdCommunications, Inc. Former subsidiaries include ASB Realty Corporation (dissolved in May 2005) and ASB Service Corporation (dissolved in January 2004).
BLNR
Board of Land and Natural Resources of the State of Hawaii
CHP
Combined heat and power
Company
Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III*, Renewable Hawaii, Inc., HEI Diversified, Inc., American Savings Bank, F.S.B. and its subsidiaries, Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II*, Hawaiian Electric Industries Capital Trust III*, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.) and HEI Power Corp. and its subsidiaries (discontinued operations, except for subsidiary HEI Investments, Inc.). Former subsidiaries include HECO Capital Trust I (dissolved in April 2004 and terminated in December 2004)*, HECO Capital Trust II (dissolved in April 2004 and terminated in December 2004)*, Hawaiian Electric Industries Capital Trust I (dissolved in April 2004 and terminated in December 2004)*, HEI Preferred Funding, LP (dissolved in April 2004 and terminated in December 2004)* and Malama Pacific Corp. (discontinued operations, dissolved in June 2004). (*unconsolidated subsidiaries as of January 1, 2004)
Consumer Advocate
Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
D&O
Decision and order
DG
Distributed generation
DOD
Department of Defense — federal
DOH
Department of Health of the State of Hawaii
DOT
Department of Taxation of the State of Hawaii
DRIP
HEI Dividend Reinvestment and Stock Purchase Plan
DSM
Demand-side management
EITF
Emerging Issues Task Force
EPA
Environmental Protection Agency — federal
FASB
Financial Accounting Standards Board
Federal
U.S. Government
FHLB
Federal Home Loan Bank
FIN
Financial Accounting Standards Board Interpretation No.
GAAP
Accounting principles generally accepted in the United States of America
HECO
Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III* and Renewable Hawaii, Inc. Former subsidiaries include HECO Capital Trust I (dissolved in April 2004 and terminated in December 2004)* and HECO Capital Trust II (dissolved in April 2004 and terminated in December 2004)*. (*unconsolidated subsidiaries as of January 1, 2004)
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GLOSSARY OF TERMS, continued
HEI
Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust II*, Hawaiian Electric Industries Capital Trust III*, The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.) and HEI Power Corp. (discontinued operations, except for subsidiary HEI Investments, Inc.). Former subsidiaries include Hawaiian Electric Industries Capital Trust I (dissolved in April 2004 and terminated in December 2004)* and Malama Pacific Corp. (discontinued operations, dissolved in June 2004). (*unconsolidated subsidiaries as of January 1, 2004)
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 subsidiary of HEI Power Corp.
HEIPC
HEI Power Corp., a wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the parent company of numerous subsidiaries, several of which were dissolved or otherwise wound up in 2002, 2003 and 2004, pursuant to a formal plan to exit the international power business (formerly engaged in by HEIPC and its subsidiaries) adopted by the HEI Board of Directors in October 2001
HEIPC Group
HEI Power Corp. and its subsidiaries
HEIRSP
Hawaiian Electric Industries Retirement Savings Plan
HELCO
Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HTB
Hawaiian Tug & Barge Corp. In November 1999, HTB sold substantially all of its operating assets and the stock of Young Brothers, Limited, and changed its name to The Old Oahu Tug Services, Inc.
IPP
Independent power producer
IRP
Integrated resource plan
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
PPA
Power purchase agreement
PRPs
Potentially responsible parties
PUC
Public Utilities Commission of the State of Hawaii
REIT
Real estate investment trust
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
SEC
Securities and Exchange Commission
See
Means the referenced material is incorporated by reference
SFAS
Statement of Financial Accounting Standards
SOX
Sarbanes-Oxley Act of 2002
SPRBs
Special Purpose Revenue Bonds
TOOTS
The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.), a wholly owned subsidiary of Hawaiian Electric Industries, Inc. On November 10, 1999, HTB sold the stock of YB and substantially all of HTB’s operating assets and changed its name.
VIE
Variable interest entity
YB
Young Brothers, Limited, which was sold on November 10, 1999, was formerly a wholly owned subsidiary of Hawaiian Tug & Barge Corp.
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Cautionary Statements and Risk Factors that May Affect Future Results
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:
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 and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets (unaudited)
(dollars in thousands)
Cash and equivalents
Federal funds sold
Accounts receivable and unbilled revenues, net
Available-for-sale investment and mortgage-related securities
Available-for-sale mortgage-related securities pledged for repurchase agreements
Investment in Federal Home Loan Bank of Seattle stock (estimated fair value $97,764 and $97,365)
Loans receivable, net
Property, plant and equipment, net of accumulated depreciation of $1,516,119 and $1,434,840
Regulatory assets
Other
Goodwill and other intangibles
Accounts payable
Deposit liabilities
Short-term borrowings
Securities sold under agreements to repurchase
Advances from Federal Home Loan Bank
Long-term debt, net
Deferred income taxes
Regulatory liabilities
Contributions in aid of construction
Minority interests
Preferred stock of subsidiaries - not subject to mandatory redemption
Preferred stock, no par value, authorized 10,000,000 shares; issued: none
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 80,955,756 shares and 80,687,350 shares
Retained earnings
Accumulated other comprehensive loss, net of tax benefits
See accompanying “Notes to Consolidated Financial Statements” for HEI.
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Consolidated Statements of Income (unaudited)
(in thousands, except per share amounts and
ratio of earnings to fixed charges)
Electric utility
Interest expense—other than bank
Allowance for borrowed funds used during construction
Preferred stock dividends of subsidiaries
Allowance for equity funds used during construction
Income from continuing operations before income taxes
Income taxes
Income from continuing operations
Discontinued operations-gain (loss) on disposal, net of income taxes
Net income
Basic earnings (loss) per common share
Continuing operations
Discontinued operations
Diluted earnings (loss) per common share
Dividends per common share
Weighted-average number of common shares outstanding
Dilutive effect of stock options and dividend equivalents
Adjusted weighted-average shares
Ratio of earnings to fixed charges (SEC method)
Excluding interest on ASB deposits
Including interest on ASB deposits
2
Consolidated Statements of Changes in Stockholders’ Equity (unaudited)
(in thousands, except per share amounts)
Retained
earnings
Accumulatedothercomprehensive
income (loss)
Total
Balance, December 31, 2004
Comprehensive income:
Net unrealized losses on securities:
Net unrealized losses on securities arising during the period, net of tax benefits of $15,459
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $70
Comprehensive income (loss)
Issuance of common stock, net
Common stock dividends ($0.93 per share)
Balance, September 30, 2005
Balance, December 31, 2003
Net unrealized losses arising during the period, net of tax benefits of $2,621
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $2,002
Minimum pension liability adjustment, net of tax benefits of $19
Balance, September 30, 2004
3
Consolidated Statements of Cash Flows (unaudited)
(in thousands)
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation of property, plant and equipment
Other amortization
Reversal of allowance for loan losses
Gain on sale of income notes
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net
Increase in tax deposit
Increase in accounts payable
Increase in taxes accrued
Changes in other assets and liabilities
Net cash provided by operating activities
Available-for-sale mortgage-related securities purchased
Principal repayments on available-for-sale mortgage-related securities
Proceeds from sale of available-for-sale mortgage-related securities
Net decrease (increase) in loans held for investment
Proceeds from sale of real estate acquired in settlement of loans
Capital expenditures
Distributions from unconsolidated subsidiaries
Net cash used in investing activities
Net increase in deposit liabilities
Net increase in short-term borrowings with maturities of three months or less
Net increase in retail repurchase agreements
Proceeds from securities sold under agreements to repurchase
Repayments of securities sold under agreements to repurchase
Proceeds from advances from Federal Home Loan Bank
Principal payments on advances from Federal Home Loan Bank
Proceeds from issuance of long-term debt
Repayment of long-term debt
Net proceeds from issuance of common stock
Common stock dividends
Net cash provided by financing activities
Net cash provided by (used in) discontinued operations
Net increase (decrease) in cash and equivalents and federal funds sold
Cash and equivalents and federal funds sold, beginning of period
Cash and equivalents and federal funds sold, end of period
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of presentation
The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (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, 2004 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005.
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 September 30, 2005 and December 31, 2004 and the results of its operations for the three and nine months ended September 30, 2005 and 2004 and its cash flows for the nine months ended September 30, 2005 and 2004. 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. For example, assets and liabilities at December 31, 2004 have been restated for the reclassification of regulatory assets from “Regulatory liabilities, net” to “Regulatory assets.”
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(2) Segment financial information
Revenues from external customers
Intersegment revenues (eliminations)
Revenues
Profit (loss)*
Income taxes (benefit)
Income (loss) from continuing operations
Assets (at September 30, 2005, including net assets of discontinued operations)
Assets (at September 30, 2004, including net assets of discontinued operations)
Long-lived assets located in foreign countries as of the dates and for the periods identified above were not material.
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.
In June 2004, ASB recorded a cumulative after-tax charge to net income of $24 million for an unfavorable tax ruling involving its real estate investment trust subsidiary, which was settled in December 2004.
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(3) Electric utility subsidiary
For HECO’s consolidated financial information, including its commitments and contingencies, see pages 13 through 32.
(4) Bank subsidiary
Selected financial information
American Savings Bank, F.S.B. and Subsidiaries
Consolidated Balance Sheet Data (unaudited)
December 31,
2004
Assets
Investment in Federal Home Loan Bank of Seattle stock(estimated fair value $97,764 and $97,365)
Liabilities and stockholder’s equity
Deposit liabilities–noninterest bearing
Deposit liabilities–interest bearing
Common stock
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Consolidated Statements of Income Data (unaudited)
Interest and fees on loans
Interest on mortgage-related securities
Interest and dividends on investment securities
Interest on deposit liabilities
Interest on Federal Home Loan Bank advances
Interest on securities sold under repurchase agreements
Net interest income after reversal of allowance for loan losses
Fees from other financial services
Fee income on deposit liabilities
Fee income on other financial products
Gain (loss) on sale of securities
Other income
Compensation and employee benefits
Occupancy
Equipment
Data processing
Services
Interest on income taxes
Income before minority interests and income taxes
Income before preferred stock dividends
Preferred stock dividends
Net income for common stock
In December 2004, ASB’s capital structure changed when ASB redeemed its preferred stock held by HEIDI ($75 million) and HEIDI infused common equity into ASB ($75 million).
At September 30, 2005, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 billion.
In the first quarter of 2005, ASB recorded a $3 million reserve for potential interest on the disputed timing of dividend income recognition for federal income tax purposes. In the second quarter of 2005, ASB made a $30 million deposit primarily to stop the further accrual of interest on the disputed timing of dividend income recognition related to a change in ASB’s 2000 and 2001 tax year-ends. ASB believes it has adequately provided for this disputed issue and other minor unresolved income tax issues with federal and state tax authorities and related interest.
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ASB Realty Corporation
In 1998, ASB formed a subsidiary, ASB Realty Corporation, which elected to be taxed as a real estate investment trust (REIT). This reorganization had reduced Hawaii bank franchise taxes as a result of ASB taking a dividends received deduction on dividends paid to it by ASB Realty Corporation. The State of Hawaii Department of Taxation (DOT) challenged ASB’s position on the dividends received deduction and issued notices of tax assessment for 1999 through 2001. ASB filed an appeal with the State Board of Review, First Taxation District (Board), which issued its decision in favor of the DOT. ASB filed a notice of appeal with the Hawaii Tax Appeal Court, which issued its decision in favor of the DOT in June 2004. As a result of the decision, ASB recorded a cumulative after-tax charge to net income in the second quarter of 2004 of $24 million ($21 million for the bank franchise taxes and $3 million for interest). ASB appealed the decision to the Hawaii Supreme Court, which appeal was dismissed as part of a settlement on December 31, 2004. ASB agreed to settle its dispute with the DOT and close the tax years 1999 through 2004 (relating to the financial performance of ASB for the years 1998 through 2003) for purposes of audit, examination, assessment, refund and judicial review. Under the terms of the settlement, ASB agreed to pay the DOT $12 million, in addition to $17 million previously paid under protest, dismiss its appeal to the Hawaii Supreme Court and not take the dividends received deduction in future years. As a result, ASB recognized $3 million in additional net income in the fourth quarter of 2004, representing a partial reversal of the $24 million previously charged against net income. ASB Realty Corporation was dissolved in the second quarter of 2005, with substantially all of its assets being distributed to ASB.
(5) Discontinued operations - HEI Power Corp. (HEIPC)
In 2001, the HEI Board of Directors adopted a formal plan to exit the international power business (engaged in by HEIPC and its subsidiaries, the HEIPC Group). HEIPC management has carried out a program to dispose of all of the HEIPC Group’s remaining projects and investments. Accordingly, the HEIPC Group has been reported as a discontinued operation in the Company’s consolidated statements of income.
In the third quarter of 2004, the HEIPC Group transferred its interest in a China joint venture to its partner and another entity for $3 million and recorded a gain on disposal, net of income taxes, of $2 million. The HEIPC Group pursued recovery of a significant portion of its losses through arbitration of its claims under a political risk insurance policy. In the second quarter of 2005, HEIPC increased its reserve for future expenses by $1 million primarily due to higher than expected arbitration costs. In the fourth quarter of 2005, the arbitration panel issued its decision denying HEIPC’s claims for recovery of losses under the political risk insurance policy.
As of September 30, 2005, the remaining net assets of the discontinued international power operations amounted to $12 million (included in “Other” assets) and consisted primarily of deferred taxes receivable, reduced by a reserve for losses from operations during the phase-out period (primarily for legal fees).
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(6) Retirement benefits
In the first nine months of 2005, ASB paid $6 million and HECO paid $8 million of contributions to the retirement benefit plans, compared to $1 million and $22 million, respectively, in the first nine months of 2004. The Company’s current estimate of contributions to the retirement benefit plans in 2005 is $17 million, compared to contributions of $37 million in 2004. The balance of the estimated 2005 contributions is expected to be made primarily by the electric utilities.
The components of net periodic benefit cost were as follows:
Three months ended
September 30
Nine months ended
Service cost
Interest cost
Expected return on plan assets
Amortization of unrecognized transition obligation
Amortization of prior service cost (gain)
Recognized actuarial loss
Net periodic benefit cost
Of the net periodic benefit costs, the Company recorded expense of $14 million and $9 million in the first nine months of 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant.
(7) Common stock split
On April 20, 2004, the HEI Board of Directors approved a 2-for-1 stock split in the form of a 100% stock dividend with a record date of May 10, 2004 and a distribution date of June 10, 2004. All share and per share information in the accompanying financial statements, notes and elsewhere in this Form 10-Q have been adjusted to reflect the stock split for all periods presented (unless otherwise noted).
(8) Commitments and contingencies
See Note 5, “Discontinued operations,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”
(9) Cash flows
Supplemental disclosures of cash flow information
For the nine months ended September 30, 2005 and 2004, the Company paid interest amounting to $126.8 million and $116.6 million, respectively.
For the nine months ended September 30, 2005 and 2004, the Company paid income taxes amounting to $20.7 million and $5.2 million, respectively. The increase for the first nine months of 2005 compared to the first nine months of 2004 is primarily due to the payments of previously accrued bank franchise and federal income taxes in settlement of prior years’ liabilities.
Supplemental disclosures of noncash activities
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 $4.5 million for the nine months ended September 30, 2004. Beginning in March 2004, HEI began satisfying the requirements of the HEI DRIP and the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the issuances of additional shares.
Other noncash increases in common stock for director and officer compensatory plans were $4.6 million and $2.4 million for the nine months ended September 30, 2005 and 2004, respectively.
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(10) Recent accounting pronouncements and interpretations
For a discussion of recent accounting pronouncements and interpretations regarding the consolidation of variable interest entities and the tax effects of income from domestic production activities, see Note 7 of HECO’s “Notes to Consolidated Financial Statements.”
Other-than-temporary impairment and its application to certain investments
In March 2004, the Financial Accounting Standards Board (FASB) ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” EITF Issue No. 03-1 provides guidance for determining whether an investment in debt or equity securities is impaired, evaluating whether an impairment is other-than-temporary and measuring impairment. EITF Issue No. 03-1 also provides disclosure guidance. The recognition and measurement guidance would have applied prospectively to all current and future investments within the scope of EITF Issue No. 03-1 in reporting periods beginning after June 15, 2004. However, in September 2004, the FASB issued FASB Staff Position (FSP) EITF 03-1-1 to delay the effective date of the recognition and measurement guidance. At its June 29, 2005 meeting, the FASB decided not to provide additional guidance on the meaning of other-than-temporary impairment, but directed its staff to issue proposed FSP EITF 03-1-a as final (retitled as FSP FAS 115-1 and FAS 124-1). The guidance in FSP FAS 115-1 and FAS 124-1 addresses the determination of when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and FASB Statement No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and adds a footnote to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The guidance in this FSP nullifies certain requirements of EITF Issue No. 03-1 and supersedes EITF Abstracts, Topic D-44, “Recognition of Other-Than-Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value.” The guidance in this FSP is required to be applied to reporting periods beginning after December 15, 2005.
Share-based payment
In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which requires companies to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the income statement. Since the Company adopted the recognition provisions of SFAS No. 123 as of January 1, 2002, the only change the Company expects to make upon adoption of SFAS No. 123 (revised 2004) is how it accounts for forfeitures. Historically, forfeitures have not been significant. SFAS No. 123 (revised 2004) is effective as of January 1, 2006 for the Company. Also, in March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, which provides accounting, disclosure, valuation and other guidance related to share-based payment arrangements. The Company will adopt the provisions of SFAS No. 123 (revised 2004) and the guidance in SAB No. 107 on January 1, 2006 and expects the impact of adoption will be immaterial.
Asset retirement obligations
In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which will require recognition of a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event if the amount can be reasonably estimated. The Company must adopt the provisions of FIN 47 no later than December 31, 2005. Management has not yet determined the impact of adoption on the Company’s financial position or results of operations.
Accounting changes and error corrections
In June 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This new standard replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively so that all prior period financial statements presented are based on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was
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effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” SFAS No. 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005. Because the impact of adopting the provisions of SFAS No. 154 will be dependent on future events and circumstances, management cannot predict such impact.
(11) Income taxes
In the first quarter of 2005, the Company recorded a $3 million reserve for potential interest on the disputed timing of dividend income recognition. In the second quarter of 2005, the Company made a $30 million deposit primarily to stop the further accrual of interest on the disputed timing of dividend income recognition related to a change in ASB’s 2000 and 2001 tax year-ends. As of September 30, 2005, $3 million, net of tax effects, was accrued for unresolved tax issues and related interest. In the second quarter of 2005, $1 million of income taxes and interest payable were reversed due to the resolution of audit issues with the Internal Revenue Service. The Company believes it has adequately provided for the issue involving the disputed timing of dividend income recognition and other minor unresolved income tax issues with federal and state tax authorities and related interest. Although not probable, adverse developments on unresolved issues could result in additional charges to net income in the future. Based on information currently available, the Company believes the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.
(12) Investment in Hoku Scientific, Inc.
As of September 30, 2005, HEI Properties, Inc. (HEIPI) held 666,667 shares of Hoku Scientific, Inc. (Hoku), a Hawaii fuel cell technology startup company. Prior to August 5, 2005, the investment had been accounted for under the cost method since Hoku was a non-controlled corporation, HEIPI did not have the ability to exercise significant influence over the operating and financial policies of Hoku, and Hoku’s shares were not publicly traded. Hoku went public and shares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005 (closing price of $10.70 on September 30, 2005 and $10.59 on October 31, 2005). HEIPI is subject to certain “lockup” provisions that expire in February 2006. Since August 5, 2005, Hoku shares have been considered marketable and HEIPI has classified the shares as trading securities, carried at fair value with changes in fair value recorded in earnings. As of September 30, 2005, HEIPI carried its investment in Hoku shares at $7 million, and in the third quarter of 2005, HEIPI recognized a $4 million unrealized after-tax gain on the Hoku shares.
(13) Subsequent event
In May 2005, HEI and HEI Investments, Inc. (HEIII) entered into an agreement with a third party for the sale of HEIII’s approximate 25% interest in the trust that is the lessor under a lease of a 60% undivided interest in a coal-fired electric generating plant in Georgia. The sale closed on October 28, 2005 and HEIII will recognize a gain of $14 million ($9 million after-tax) in the fourth quarter of 2005.
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(in thousands, except par value)
Utility plant, at cost
Land
Plant and equipment
Less accumulated depreciation
Plant acquisition adjustment, net
Construction in progress
Net utility plant
Current assets
Customer accounts receivable, net
Accrued unbilled revenues, net
Other accounts receivable, net
Fuel oil stock, at average cost
Materials and supplies, at average cost
Prepaid pension benefit cost
Total current assets
Other long-term assets
Unamortized debt expense
Total other long-term assets
Capitalization and liabilities
Capitalization
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares
Premium on capital stock
Common stock equity
Cumulative preferred stock – not subject to mandatory redemption
Total capitalization
Current liabilities
Short-term borrowings–nonaffiliates
Short-term borrowings–affiliate
Interest and preferred dividends payable
Taxes accrued
Total current liabilities
Deferred credits and other liabilities
Unamortized tax credits
Total deferred credits and other liabilities
See accompanying “Notes to Consolidated Financial Statements” for HECO.
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(in thousands, except for ratio of earnings to fixed charges)
Operating revenues
Operating expenses
Fuel oil
Purchased power
Other operation
Maintenance
Depreciation
Taxes, other than income taxes
Operating income
Other, net
Income before interest and other charges
Interest and other charges
Interest on long-term debt
Amortization of net bond premium and expense
Other interest charges
Income before preferred stock dividends of HECO
Preferred stock dividends of HECO
Consolidated Statements of Retained Earnings (unaudited)
Retained earnings, beginning of period
Retained earnings, end of period
HEI owns all the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.
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Cash flows from operating activities
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities
Tax credits, net
Increase in accounts receivable
Increase in accrued unbilled revenues
Increase in fuel oil stock
Increase in materials and supplies
Increase in regulatory assets
Increase (decrease) in accounts payable
Cash flows from investing activities
Cash flows from financing activities
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less
Net cash provided by (used in) financing activities
Net increase in cash and equivalents
Cash and equivalents, beginning of period
Cash and equivalents, end of period
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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 included in HECO’s SEC Form 10-K for the year ended December 31, 2004 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005.
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 September 30, 2005 and December 31, 2004 and the results of their operations for the three and nine months ended September 30, 2005 and 2004 and their cash flows for the nine months ended September 30, 2005 and 2004. 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. For example, assets and liabilities at December 31, 2004 have been restated for the reclassification of regulatory assets from “Regulatory liabilities, net” to “Regulatory assets.”
(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 Maui Electric Company, Limited (MECO) and HELCO 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, MECO and HELCO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECO and HELCO 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 sheet as of September 30, 2005 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for nine months ended September 30, 2005 consisted of $2.5 million of interest income received from the 2004 Debentures; $2.4 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.
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Kalaeloa Partners, L.P.
In October 1988, HECO entered into a power purchase agreement (PPA) with Kalaeloa Partners, L.P. (Kalaeloa), 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, which together effectively increased the firm capacity from 180 MW to 208 MW. The PPA and amendments have been approved by the PUC. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, 2) a fuel additives cost component, and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA.
Kalaeloa is a Delaware limited partnership formed on October 13, 1988 for the purpose of designing, constructing, owning and operating a 200 MW cogeneration facility on Oahu, which includes two 75 MW oil-fired combustion turbines, two waste heat recovery steam generators, a 50 MW turbine generator and other electrical, mechanical and control equipment. The two combustion turbines were upgraded during 2004 resulting in an increase in the facility’s nominal output rating to approximately 220 MW. Kalaeloa has a PPA with HECO (described above) and a steam delivery contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualified Facility under the Public Utilities Regulatory Policies Act of 1978.
Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa via 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 which affected 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 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 energy cost adjustment clause 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 nine months ended September 30, 2005 and 2004, HECO and its subsidiaries included approximately $114 million and $99 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.
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(4) Retirement benefits
In the first nine months of 2005 and 2004, HECO and its subsidiaries paid contributions of $8 million and $22 million, respectively, to the retirement benefit plans. HECO and its subsidiaries’ current estimate of contributions to the retirement benefit plans in 2005 is $11 million, compared to their contributions of $34 million in 2004.
Amortization of prior service gain
Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $10 million and $5 million in the first nine months of 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant.
(5) Commitments and contingencies
Interim increases
As of September 30, 2005, HECO and its subsidiaries had recognized $19 million of revenues with respect to interim orders regarding certain integrated resource planning costs and an Oahu general rate increase, which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders. On September 27, 2005, the PUC issued an Interim Decision and Order (D&O) granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges). The tariff changes implementing the interim rate increase were effective September 28, 2005.
HELCO power situation
Historical context. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. It planned to install at its Keahole power plant two 20 megawatt (MW) combustion turbines (CT-4 and CT-5), followed by an 18 MW heat steam recovery generator (ST-7), at which time these units would be converted to a 56 MW (net) dual train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”
Status. Installation of CT-4 and CT-5 was significantly delayed as a result of land use and environmental permitting delays and related administrative proceedings and lawsuits, which have been described in previous periodic reports filed with the SEC. However, in 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposes the settlement) 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 (Settlement Agreement). Subsequently, CT-4 and CT-5 were installed and put into limited commercial operation in May and June 2004, respectively. The BLNR’s construction deadline of July 31, 2005 has been met. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work for CT-5 (not requiring any further construction) is ongoing to ensure compliance with the night-time standard. Currently, HELCO can operate Keahole as required to meet its system needs.
Currently, three appeals to the Hawaii Supreme Court by Waimana have been briefed and are awaiting decision. These are appeals to judgments of the Third Circuit Court involving (i) vacating of a November 2002 Final Judgment which had halted construction; (ii) the Board of Land and Natural Resources (BLNR) 2003 construction period extension; and (iii) the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the
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primary source of water for operating the Keahole plant. In the third appeal, additional briefs were filed on July 15, 2005 on the question of whether the appeal is moot given the granting by the BLNR of a long-term water lease allowing HELCO to use brackish water. On March 2, 2005, Waimana and another party appealed a judgment upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water, and Waimana has also appealed the denial of its motion seeking relief from judgment in the water lease case. In July 2005, the two appeals relating to the water lease were consolidated by the Hawaii Supreme Court. Full implementation of the Settlement Agreement is conditioned on obtaining final dispositions of all litigation pending at the time of the Settlement Agreement. If the remaining dispositions are obtained, as HELCO believes they will be, then HELCO must undertake a number of actions under the Settlement Agreement, including expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction emissions control equipment, assisting the Department of Hawaiian Home Lands in installing solar water heating in its housing projects, supporting the Keahole Defense Coalition’s participation in certain PUC cases, and cooperating with neighbors and community groups (including a Hot Line service).
In November 2003, HELCO filed a boundary amendment petition (to reclassify the Keahole plant site from conservation land use to urban land use) with the State Land Use Commission, which was approved in October 2005. HELCO’s plans for ST-7 are progressing, but construction cannot start until HELCO obtains a contemplated County rezoning to a “General Industrial” classification and obtains the necessary permits.
Costs incurred; management’s evaluation. As of September 30, 2005, HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $109 million, including $43 million for equipment and material purchases, $46 million for planning, engineering, permitting, site development and other costs and $20 million for an allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date management decided not to continue accruing AFUDC. Of this amount, $103 million has been reclassified from construction in progress to plant and equipment and depreciation has been recorded since January 1, 2005.
Management believes that the prospects are good that the remaining Settlement Agreement conditions will be satisfied and that any further necessary permits will be obtained and that the appeals will be favorably resolved. However, HELCO’s electric rates will not change specifically as a result of including CT-4 and CT-5 in plant and equipment until HELCO files a rate increase application and the PUC grants HELCO rate relief. While management believes that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of September 30, 2005, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of these costs.
East Oahu Transmission Project (EOTP)
HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a partial underground/partial overhead 138 kV line from the Kamoku substation to the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, in order to close the gap between the Southern and Northern corridors and provide a third transmission line to the Pukele substation, but a permit which would have allowed construction in the originally planned route through conservation district lands was denied in June 2002.
HECO continues to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $55 million; see costs incurred below) for a revised EOTP using the 46 kV system. In March 2004, the PUC granted intervenor status to an environmental organization and three elected officials (collectively treated as one party), and a more limited participant status to four community organizations. The environmental review process has been completed and the PUC issued a Finding of No Significant Impact in April 2005. Subject to PUC approval, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases, currently projected for completion in 2007 and 2009.
As of September 30, 2005, the accumulated costs recorded for the EOTP amounted to $25 million, including $12 million of planning and permitting costs incurred prior to 2003, when HECO was denied the approval necessary for the partial underground/partial overhead 138 kV line, $3 million of planning and permitting costs incurred after
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2002, and $10 million for AFUDC. In the written testimony filed in June 2005, the Consumer Advocate’s consultant 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 before 2003, and the related AFUDC. In rebuttal testimony filed in August 2005, 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 addressed. The PUC has scheduled an evidentiary hearing on HECO’s application in November 2005. In November 2005, the PUC approved a stipulation between HECO and the Consumer Advocate that this proceeding should determine whether HECO should be given approval to expend funds for the EOTP provided that no part of the EOTP costs may be recovered from ratepayers unless and until the PUC grants HECO recovery in a rate case (which is consistent with other projects), and that the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs is reserved to, and may be raised in, the next HECO rate case (or other proceeding). Management believes no adjustment to project costs is required as of September 30, 2005. 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
HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations at their generation plants and other facilities 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 and in the aggregate, on the Company’s or consolidated HECO’s financial statements.
Additionally, current environmental laws may require the 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 when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.
Honolulu Harbor investigation. In 1995, the Department of Health of the State of Hawaii (DOH) issued letters indicating that it had identified a number of parties, including HECO, who appeared to be potentially responsible for historical subsurface petroleum contamination and/or operated their facilities upon petroleum-contaminated land at or near Honolulu Harbor in the Iwilei district of Honolulu. Certain of the identified parties formed a work group to determine the nature and extent of any contamination and appropriate response actions, as well as identify additional potentially responsible parties (PRPs). The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Later in 2000, the DOH issued notices to additional PRPs. The parties in the work group and some of the new PRPs (collectively, the Participating Parties) entered into a joint defense agreement and signed a voluntary response agreement with the DOH. The Participating Parties agreed to fund 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.
Since 2001, subsurface investigation and assessment have been conducted and several preliminary oil removal tasks have been performed at the Iwilei Unit in accordance with notices of interest issued by the EPA and DOH. Currently, the Participating Parties are preparing Remediation Alternatives Analyses, which will identify and recommend remedial approaches. HECO routinely maintains its facilities and has investigated its operations in the Iwilei area and ascertained that they are not releasing petroleum.
In 2001, management developed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (which was expensed in 2001 and of which $0.5 million has been incurred through September 30, 2005). Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time, (2) the final cost allocation method has not yet been determined and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (including its Honolulu power plant site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.
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State of Hawaii, ex rel., Bruce R. Knapp, Qui Tam Plaintiff, and Beverly Perry, on behalf of herself and all others similarly situated, Class Plaintiff, vs. The AES Corporation, AES Hawaii, Inc., HECO and HEl
In April 2002, HECO and HEI were served with an amended complaint filed in the First Circuit Court of Hawaii alleging that the State of Hawaii and HECO’s other customers had been overcharged for electricity by over $1 billion since September 1992 due to alleged excessive prices in the PUC-approved amended PPA between HECO and AES Hawaii, Inc. (AES Hawaii). The PUC proceedings in which the amended PPA was approved addressed a number of issues, including whether the terms and conditions of the PPA were reasonable.
As a result of rulings by the First Circuit Court in 2003, all claims for relief and causes of action in the amended complaint were dismissed. In October 2003, plaintiff Beverly Perry filed a notice of appeal to the Hawaii Supreme Court and the Intermediate Court of Appeals, on the grounds that the Circuit Court erred in its reliance on the doctrine of primary jurisdiction and the statute of limitations. On July 16, 2004, the Supreme Court retained jurisdiction of the appeal (rather than assign the appeal to the Intermediate Court of Appeals) and a decision is pending. In the opinion of management, the ultimate disposition of this matter will not have a material adverse effect on the Company’s or HECO’s consolidated financial position, results of operations or liquidity.
Collective bargaining agreements
Approximately 60% of the electric utilities’ employees are members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. The current collective bargaining and benefit agreements cover a four-year term, from November 1, 2003 to October 31, 2007, and provide for non-compounded wage increases (3% on November 1, 2003; 1.5% on November 1, 2004, May 1, 2005, November 1, 2005 and May 1, 2006; and 3% on November 1, 2006).
(6) Cash flows
For the nine months ended September 30, 2005 and 2004, HECO and its subsidiaries paid interest amounting to $30.0 million and $30.1 million, respectively.
For the nine months ended September 30, 2005 and 2004, HECO and its subsidiaries paid income taxes amounting to $5.3 million and $6.5 million, respectively.
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 $3.7 million and $5.1 million for the nine months ended September 30, 2005 and 2004, respectively.
In March 2004, HECO, HELCO and MECO issued 6.50% Junior Subordinated Deferrable Interest Debentures to HECO Capital Trust III in the aggregate principal amount of approximately $51.5 million and directed that the proceeds from the issuance of the debentures be deposited with the trustee for HECO Capital Trust I and ultimately be used in April 2004 to redeem HECO Capital Trust I’s 8.05% Cumulative Quarterly Income Preferred Securities ($50 million aggregate liquidation preference) and its common securities of approximately $1.5 million. In March 2004, HECO, HELCO and MECO recorded noncash transactions to reflect the aggregate $51.5 million receivable from HECO Capital Trust I (included in “Other accounts receivable, net”) and the aggregate $51.5 million obligation under the 6.50% Junior Subordinated Deferrable Interest Debentures (included in “Long-term debt, net”).
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(7) Recent accounting pronouncements and interpretations
For a discussion of recent accounting pronouncements and interpretations regarding other-than-temporary impairment and its application to certain investments, asset retirement obligations and accounting changes and error corrections, see Note 10 of HEI’s “Notes to Consolidated Financial Statements.”
Consolidation of variable interest entities
In December 2003, the FASB issued FIN 46R, “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity.
As of September 30, 2005, HECO and its subsidiaries had six PPAs for a total of 540 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, Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (Hamakua) and H-POWER. Purchases from all IPPs for the nine months ended September 30, 2005 totaled $330 million, with purchases from AES Hawaii, Kalaeloa, Hamakua and H-POWER totaling $102 million, $121 million, $44 million and $24 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries. 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 VIE or potential VIE created before December 31, 2003 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 and its subsidiaries have reviewed their significant PPAs and determined that the IPPs 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 by telephone to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because HECO and its subsidiaries’ variable interest in the provider would not be significant to HECO and its subsidiaries and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO and its subsidiaries to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (H-POWER) 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 and its subsidiaries to determine the applicability of FIN 46R, and HECO and its subsidiaries have been unable to apply FIN 46R to these IPPs. In January 2005, HECO and its subsidiaries again 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 again declined to provide the necessary information.
As required under FIN 46R, HECO and its subsidiaries have continued their efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. If the requested information is ultimately received, a possible outcome of future analysis is the consolidation of an IPP 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.
In October 2004, Kalaeloa and HECO executed two amendments to their PPA, under which Kalaeloa would make available up to 29 MW of additional firm capacity to HECO, if certain conditions were satisfied. The conditions have been satisfied. The amendments became effective when the costs of the additional capacity and purchased power were included in HECO’s rates as a result of the Interim D&O. As a result of the completion of the required performance test, the additional firm capacity to be provided by Kalaeloa is 28 MW. Kalaeloa provided HECO the information HECO needed to complete its determination of whether Kalaeloa is a variable interest entity, and, whether HECO is the primary beneficiary. While it has been determined that Kalaeloa is a variable interest entity, HECO has concluded that it is not the primary beneficiary of that entity and accordingly Kalaeloa need not be consolidated in HECO’s consolidated financial statements. See Note 2 for additional information regarding the application of FIN 46R to Kalaeloa.
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In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its existing 7 MW facility, and install an additional 13.5 MW of capacity, for a total windfarm capacity of 20.5 MW. In December 2004, MECO executed a new PPA with Kaheawa Wind Power, LLC (KWP), which plans to install a 30 MW windfarm on Maui. The revised PPA with Apollo and new PPA with KWP were approved by the PUC in March 2005, and became effective in April 2005. The PPAs require Apollo and KWP to provide information necessary to (1) determine if HELCO and MECO must consolidate Apollo and KWP, respectively, under FIN 46R, (2) consolidate Apollo and/or KWP, if necessary under FIN 46R, and (3) comply with Section 404 of SOX. Management is in the process of obtaining the information necessary to complete its determination of whether Apollo or KWP are VIEs and, if so, whether HELCO or MECO, respectively, is the primary beneficiary. Based on information currently available, management believes the impact on consolidated HECO’s financial statements for the consolidation of Apollo and/or KWP, if necessary, would not be material. However, depending on the magnitude of the improvements contemplated in the PPAs, the impact of a required consolidation of Apollo and KWP could be material in the future.
See Note 2 for additional information regarding the application of FIN 46R to HECO Capital Trust III.
Tax effects of income from domestic production activities
In December 2004, the FASB issued FSP No. 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, for the Tax Deduction Provided to U.S. Based Manufacturers by the American Jobs Creation Act of 2004,” which was effective upon issuance. FSP No. 109-1 clarifies that the new deduction for qualified domestic production activities should be accounted for as a special deduction under SFAS No. 109, and not as a tax-rate reduction, because the deduction is contingent on performing activities identified in the new tax law.
Management is currently reviewing various aspects of the American Jobs Creation Act of 2004 (the 2004 Act), including proposed regulations relating to the 2004 Act recently issued by the Internal Revenue Service. There are at least two provisions with potential implications for HECO and its subsidiaries:
Management has not yet determined the impact of these provisions on HECO’s consolidated results of operations, financial condition or liquidity. However, based on current estimates, management expects that the provisions would not have a significant impact on HECO and its subsidiaries.
(8) Income taxes
HECO and its subsidiaries believe they have adequately provided for income tax issues not yet resolved with federal and state tax authorities. At September 30, 2005, $0.4 million, net of tax effects, was accrued for these issues, which are primarily comprised of asset recovery period classification issues. Although not probable, adverse developments on certain issues could result in additional charges to net income in the future. Based on information currently available, HECO and its subsidiaries believe the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on HECO’s consolidated results of operations, financial condition or liquidity.
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(9) Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)
Deduct:
Income taxes on regulated activities
Revenues from nonregulated activities
Add: Expenses from nonregulated activities
Operating income from regulated activities after income taxes(per HECO consolidated statements of income)
(10) Consolidating financial information
HECO is not required to provide separate financial statements and 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 these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated. HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on their Special Purpose Revenue Bonds and (b) relating to the trust preferred securities of Trust III. Also, see Note 2. HECO is also obligated 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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Consolidating Balance Sheet (unaudited)
September 30, 2005
Reclassi-ficationsand elimina-
tions
consoli-
dated
Investment in subsidiaries, at equity
Advances to affiliates
Cumulative preferred stock–not subject to mandatory redemption
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December 31, 2004
consolidated
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Consolidating Statement of Income (unaudited)
Three months ended September 30, 2005
Equity in earnings of subsidiaries
Income (loss) before interest and other charges
Income (loss) before preferred stock dividends of HECO
Net income (loss) for common stock
Consolidating Statement of Retained Earnings (unaudited)
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Three months ended September 30, 2004
Reclassi-fications
and
elimina-
28
Nine months ended September 30, 2005
29
Nine months ended September 30, 2004
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Consolidating Statement of Cash Flows (unaudited)
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities
Equity in earnings
Common stock dividends received from subsidiaries
Decrease (increase) in fuel oil stock
Decrease (increase) in regulatory assets
Net cash provided by (used in) operating activities
Net increase (decrease) in cash and equivalents
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Proceeds from sale of property
Investment in subsidiary
Advances from (advances to) affiliates
Net cash provided by (used in) investing activities
Proceeds from issuance of common stock
Net increase in short-term borrowings from affiliate with original maturities of three months or less
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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 2004 Form 10-K and Form 10-Q for the second quarter of 2005 and should be read in conjunction with those reports and the annual (as of and for the year ended December 31, 2004) and quarterly (as of and for the three and six months ended June 30, 2005) consolidated financial statements of HEI and HECO and accompanying notes.
HEI CONSOLIDATED
RESULTS OF OPERATIONS
%
change
Primary reason(s) for significant change*
Income from:
Basic earnings per common share–
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Income (loss) from:
Basic earnings (loss) per common share–
The results of operations for the first nine months of 2004 include a net charge of $24 million, or $0.30 per share, due to an adverse tax ruling as discussed in Note 4 of HEI’s “Notes to Consolidated Financial Statements” under “ASB Realty Corporation.” The $24 million net charge includes a net $21 million of cumulative bank franchise taxes through March 31, 2004, plus a net $3 million of interest (which gross interest of $5 million is included in general and administrative expenses of ASB). The following table presents a reconciliation of HEI’s consolidated income from continuing operations to income from continuing operations excluding this $24 million charge and including additional bank franchise taxes in prior periods as if the Company had not taken a dividends received deduction on income from its REIT subsidiary. The Company believes the adjusted information below presents results from continuing operations on a more comparable basis for the periods shown. However, net income, or earnings per share, including these adjustments is not a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.
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Basic earnings per share - continuing operations
Cumulative franchise tax charge, net
Additional franchise taxes, net (if recorded in prior periods)
Total adjustments
As adjusted
Taking into account the adjustments in the table above, HEI’s consolidated income from continuing operations would have decreased 15% for the nine months ended September 30, 2005, compared to the same period last year as all segments had lower results.
Stock split
See Note 7 of HEI’s “Notes to Consolidated Financial Statements.”
Pension and other postretirement benefits
For the first nine months of 2005, the retirement benefit plan assets generated a total return of 5.6%, resulting in realized and unrealized net gains of approximately $51 million, compared to a 9% annual expected return on plan assets assumption and a total return of 10.5% for 2004. The market value of the retirement benefit plans’ assets as of September 30, 2005 was $920 million. The Company made cash contributions to the retirement benefit (i.e., pension and other postretirement benefit) plans totaling $15 million for the first nine months of 2005 and intends to make additional cash contributions of $2 million by December 31, 2005.
Depending on the 2005 investment experience and interest rates at year-end (measurement date), the Company could be required to recognize an additional minimum liability at December 31, 2005 as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.” The recognition of an additional minimum liability is required if the accumulated benefit obligation exceeds the fair value of plan assets at measurement date. The recognition of an additional minimum liability would also result in the removal of the prepaid pension asset ($120 million at December 31, 2004) from the Company’s balance sheet. The liability would largely be recorded as a reduction to stockholders’ equity through a noncash charge to accumulated other comprehensive income (AOCI), and would not affect net income for 2005. The additional minimum liability does not apply to other postretirement benefits. Although the Company was not required to make any contributions to the pension plan to meet minimum funding requirements (under the Employee Retirement Income Security Act of 1974) in 2003 and 2004, the Company made pension contributions totaling $66 million in part to avoid the risk of a charge to AOCI that could have resulted if the accumulated benefit obligation had exceeded the fair value of plan assets at year-end.
The amount of additional minimum liability and charge to AOCI, if any, to be recorded at December 31, 2005, could be material and will depend upon a number of factors, including the year-end discount rate assumption, asset returns experienced in 2005, any changes to actuarial assumptions or plan provisions, and contributions made by the Company to the plans during 2005. In addition, retirement benefits expense and cash funding requirements could increase in future years depending on the performance of the equity markets and changes in interest rates.
In part, the Company benchmarks its discount rate assumption to the Moody’s Daily Long-Term Corporate Bond Aa Yield Average, which was 5.36% at September 30, 2005 compared to 5.66% at December 31, 2004. The discount rate used at December 31, 2004 was 6.00%. The Company anticipates the discount rate at December 31, 2005 will be between 5.50% and 6.00%.
The Company has determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in the first year and 25% in years two to five, and finally adding or subtracting the
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unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual net periodic benefit cost.
Based on the market value of the pension plans’ assets as of December 31, 2004 and assuming a range of returns on plan assets of 0% to 9% for 2005, cash contributions of $17 million in 2005, a range of 5.50% to 6.00% for the discount rate at December 31, 2005, and no further changes in assumptions or pension plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s AOCI balances, net of tax benefits, related to the minimum pension liabilities at December 31, 2005 are estimated to be as follows:
AOCI balance, net of tax benefits
($ in millions)
Consolidated HEI
0% return on plan asset assumption
9% return on plan asset assumption
Consolidated HECO
If the Company and consolidated HECO are required to record substantially greater charges to AOCI in the future, there may be possible financial covenant violations (although there are no advances currently outstanding under any credit facility subject to financial covenants) as certain bank lines of credit of the Company and HECO require that HECO maintain a minimum ratio of consolidated equity to consolidated capitalization as defined in the debt agreements of 35% (actual ratio of 56% as of September 30, 2005); the Company maintain a consolidated net worth, exclusive of intangible assets, of at least $900 million (actual net worth, exclusive of intangible assets, of $1.1 billion as of September 30, 2005); and HEI, on a non-consolidated basis, maintain a ratio of indebtedness to capitalization of not more than 50% (actual ratio of 27% as of September 30, 2005). Also, if prepaid pension assets that the electric utilities have been allowed to include in their rate bases for rate making purposes are eliminated, then the electric utilities’ reported rates of return on rate base (RORs) would be higher, which could impact the rates that the electric utilities are allowed to charge. (See discussion in “Most recent rate request” concerning the issue of including the prepaid pension asset in HECO’s rate base. In the HECO rate case, there was no issue among the parties with respect to including the estimated pension expense based on SFAS No. 87 in the test year expenses, but the Consumer Advocate and DOD proposed to exclude the estimated amount of the prepaid pension asset, net of the related accumulated deferred income taxes, from rate base.)
The electric utilities may submit a request for PUC approval to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the portion of any minimum pension liability charged directly to AOCI at a measurement date, as required by SFAS No. 87 and SFAS No. 130, including approval to adjust the aforementioned regulatory asset based on changes in the minimum pension liability amount at annual measurement dates thereafter. Under such an accounting treatment, if in future years the fair values of the electric utilities’ pension plan assets exceed their accumulated benefit obligations, the electric utilities would remove the regulatory assets and associated remaining minimum liabilities from their accounts. Under this approach, amortization of the regulatory assets would not be necessary. Management has not determined whether to submit such a request in 2005, and cannot predict with certainty whether the PUC would approve such a request.
Consolidated HEI’s, consolidated HECO’s and ASB’s net periodic pension and other postretirement benefits costs (net of tax benefits) are estimated to be $11 million, $8 million and $2 million, respectively, for 2005 compared to $7 million, $4 million and $2 million, respectively, for 2004.
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Based on the market value of the retirement benefit plans’ assets as of December 31, 2004 and using the 9% return on plan asset assumption used in the estimation of a potential year-end AOCI charge above, 2006 retirement benefit expense, net of amounts capitalized and tax benefits, is expected to be:
Retirement benefit expense, net of amounts capitalized and tax benefits
Retirement benefit expenses based on net periodic pension and other postretirement benefit costs that are related to utility operations have been an allowable expense for rate-making, and higher benefit expenses, along with other factors, may affect the timing and amount of future electric rate increase requests.
Dividends
On November 9, 2005, HEI’s Board maintained the quarterly dividend of $0.31 per common share. The payout ratio for 2004 and the first nine months of 2005 was 90% and 85% (payout ratio of 91% and 84% based on income from continuing operations), respectively. HEI’s Board and management believe that HEI should achieve a 65% payout ratio on a sustainable basis before it considers increasing the common stock dividend above its current level.
Economic conditions
Because its core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The Bureau of Economic Analysis ranked Hawaii the 4th fastest growing state in the U.S. in 2004. State economists reported 3.5% growth in 2004 with more modest growth for Hawaii of 3.1% in 2005 and 2.3% in 2006.
For the federal fiscal year ended September 30, 2003 (latest available data), total federal government expenditures in Hawaii, including military expenditures, were $11.3 billion, compared to $10.5 billion for fiscal year 2002. The 2003 total was $1.2 billion more than tourism expenditures for the same period. A 13% increase in military expenditures for fiscal year 2003 over fiscal year 2002 was the primary reason for the increase in total federal government expenditures. While fiscal year 2004 statistics are not yet available for federal government expenditures, continued growth is expected because Department of Defense expenditures increased 5% in fiscal year 2004 over fiscal year 2003 and several key military projects are expected to bring $3.8 billion in construction into the state over the next several years, including plans for an Army Stryker Brigade, the arrival of eight C-17 Air Force cargo planes and military housing renewal projects. Offsetting such growth is the planned net deployments of Hawaii soldiers over the next year.
Tourism is widely acknowledged as a significant component of the Hawaii economy, second only to the federal government. In 2004, visitor days—visitor arrivals multiplied by the average length of stay—hit a record 63 million, exceeding the record set in 2003 of 59 million by 7%. State economists expect visitor days to increase by 6.3% in 2005, largely due to the expectation that arrivals will top the previous record of just under 7 million set in 2000. Visitor days and expenditures were up 7.4% and 7.8%, respectively for the first eight months of 2005 compared with the same period of 2004.
Unemployment remains low. At the end of September 2005, Hawaii unemployment stood at 2.7% compared with the national unemployment rate of 5.1%.
The Hawaii construction industry remains healthy, due in part to military construction projects. Local economists forecast nominal contracting receipts to grow by 12% in 2005 as the privatization of military housing ramps-up. Growth in contracting receipts is expected to moderate to near 5% in 2006.
The price of Hawaii real estate continues to climb in 2005, reflecting tight inventory levels. Median single-family home prices on Oahu were $615,000 in September 2005, $120,000 more than the December 2004 Oahu median price of $495,000.
Overall, the outlook for the Hawaii economy remains positive. However, economic growth is affected by the rate of expansion in the mainland U.S. and Japan economies and growth in military spending. It is also vulnerable to uncertainties in the world’s geopolitical environment.
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Management monitors interest rates because ASB’s earnings are affected by changes in the interest rate environment. Generally, a flat yield curve is indicative of a difficult earning environment for ASB. As of September 30, 2005, the spread between the 2-year and 10-year Treasuries was 0.15%, compared to 0.28% at June 30, 2005 and 1.15% at December 31, 2004 (as this spread approaches zero, a flat yield curve is indicated).
“Other” segment
Primary reason(s) for significant change
Net loss from continuing operations
Operating loss
The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily 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. (HEIPI), a company holding passive investments; Hycap Management, Inc. (which is in dissolution); The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; HEI and HEIDI, holding companies; and eliminations of intercompany transactions. The first nine months of 2004 also includes the results of operations for unconsolidated subsidiaries, Hawaiian Electric Industries Capital Trust I and its subsidiary (HEI Preferred Funding, LP), which were dissolved in April 2004 and terminated in December 2004. Together with Hycap Management, Inc., these were financing entities formed to effect the issuance in 1997 of 8.36% Trust Originated Preferred Securities that were redeemed in April 2004.
See Note 13 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of the closing of HEIII’s sale of its interest in a leveraged lease asset in October 2005.
See Note 5 of HEI’s “Notes to Consolidated Financial Statements.”
Contingencies
See Note 8 of HEI’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretations
See Note 10 of HEI’s “Notes to Consolidated Financial Statements.”
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FINANCIAL CONDITION
Liquidity and capital resources
HEI believes that its ability, and that of its subsidiaries, 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 capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.
The consolidated capital structure of HEI (excluding ASB’s deposit liabilities, securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle) was as follows:
(in millions)
Preferred stock of subsidiaries
As of October 31, 2005, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:
Commercial paper
Medium-term notes
The above 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/Negative/A-2.
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 April 2005, S&P affirmed its corporate credit ratings of HEI, but revised its outlook from stable to negative, citing HECO’s need for a rate increase to cover its growing expenses and yet to be recovered investments. 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).” In response to the PUC’s interim rate decision for HECO, S&P stated “a final order that closely mirrors the interim ruling appears to be sufficient to lift key financial metrics to levels that are marginally suitable for Standard & Poor’s guideposts for the ‘BBB’ rating category.” However, S&P will maintain its negative outlook until the PUC issues its final order. In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). There was no change in HEI’s business profile rank of “6”. Moody’s maintains a stable outlook on HEI.
At September 30, 2005, an additional $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration, and an additional $150 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program.
HEI periodically utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements and on behalf of HELCO and MECO. HEI had short-term loans to HECO of $13 million at September 30, 2005. HEI had an average outstanding balance of commercial paper for the first nine months of 2005 of $2 million and had $8 million outstanding at September 30, 2005. 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.
At September 30, 2005, HEI maintained bank lines of credit with four different banks totaling $80 million ($45 million expiring in the fourth quarter of 2005 and $35 million expiring in 2006). These lines of credit are maintained by HEI principally to support the issuance of commercial paper, but also may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade were to reduce or eliminate access to the commercial paper markets. Lines of credit to HEI totaling $30 million contain provisions for revised pricing in the event of a ratings change (e.g., a ratings downgrade of HEI
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medium-term notes from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively, would result in a 12.5 to 50 basis points higher interest rate; a ratings upgrade from BBB/Baa2 to BBB+/Baa1 by S&P and Moody’s, respectively, would result in a 12.5 to 20 basis points lower interest rate). There are no such provisions in HEI’s other lines of credit. None of HEI’s line of credit agreements contain clauses that would affect access to the lines by reason of a ratings downgrade, nor do they have broad “material adverse change” clauses that could affect access to the lines in the event of any material adverse event so long as any such event is timely disclosed. However, access to some or all of the lines could be restricted, or defaults under the lines could occur, if representations and warranties in the agreements, as permitted to be updated, are not true and correct at the time an advance is requested or if HEI is not in compliance with the covenants in such agreements. Management believes that it is not likely that any such restriction or default will occur. At September 30, 2005, the lines were undrawn. To the extent deemed necessary, HEI anticipates arranging similar lines of credit as existing lines of credit expire.
For the first nine months of 2005, net cash provided by operating activities of consolidated HEI was $156 million. Net cash used in investing activities for the same period was $207 million due to a net increase in loans receivable at ASB, and HECO’s consolidated capital expenditures, partly offset by repayments and sales of mortgage-related securities held by ASB, net of purchases, and contributions in aid of construction at the electric utilities. Net cash provided by financing activities during this period was $112 million as a result of several factors, including net increases in deposit liabilities, short-term borrowings, advances from the FHLB and long-term debt and proceeds from issuances of common stock, partly offset by a net decrease in securities sold under agreements to repurchase and the payment of common stock dividends.
Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.
ELECTRIC UTILITIES
(dollars in thousands, except per barrel amounts)
Expenses
Kilowatthour sales (millions)
Oahu cooling degree days (CDD)
Fuel oil cost per barrel
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See “Pension and other postretirement benefits” and “Economic conditions” in the “HEI Consolidated” section above.
Results – three months ended September 30, 2005
Kilowatthour (KWH) sales in the third quarter of 2005 were flat when compared to the same quarter in 2004 as new load growth (i.e., increase in the number of customers) was more than offset by the impacts of less humid weather and major commercial repair and renovation projects (which resulted in temporary load loss). Although KWH sales were flat, operating income decreased 10% from the third quarter 2004, primarily due to higher expenses other than for fuel oil and purchased power. Other operation expense increased 7% primarily due to higher transmission and distribution operations expense and higher retirement benefits expense. Pension and other postretirement benefit expenses for the electric utilities increased $1.6 million over the same period in 2004 due in part to a 25 basis points lower discount rate at December 31, 2004. Maintenance expense increased by 23% due to $1.6 million higher production maintenance expense (primarily higher steam generation station maintenance) and $2.3 million higher transmission and distribution maintenance expense. Further, other operation and maintenance expenses were higher partly due to increased staffing and other costs to support increased demand, reliability and customer service programs. Higher depreciation expense was attributable to additions to plant in service in 2004 (including HELCO’s CT-4 and CT-5 and HECO’s Waiau fuel oil pipeline), offset in part by lower depreciation expense resulting from the PUC’s approval in September 2004 of changes in the depreciation rates and accounting methodology applicable to HECO’s depreciable assets on Oahu.
Results – nine months ended September 30, 2005
KWH sales in the first nine months of 2005 increased 0.3% from the same period in 2004, primarily due to new load growth (i.e., increase in number of customers), largely offset by the impacts of less humid weather and major commercial repair and renovation projects. Although KWH sales increased slightly, operating income decreased 15% from the same period in 2004, primarily due to higher other expenses. Other operation expense increased 13% primarily due to higher expenses for production operations (including higher environmental expense as there was a DOH emission fee waiver in the first quarter of 2004, which was not repeated in the first quarter of 2005),
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transmission and distribution operations (due in part to increased line inspections) and retirement benefits expense. Pension and other postretirement benefit expenses for the electric utilities increased $4.9 million over the same period in 2004 due in part to a 25 basis points lower discount rate at December 31, 2004. Maintenance expense increased by 18% due to higher production maintenance expense (primarily due to higher steam generation station maintenance and more generating unit overhauls) and higher transmission and distribution maintenance expense (due in part to higher substation maintenance and higher vegetation management). Higher depreciation expense was attributable to additions to plant in service in 2004 (including HELCO’s CT-4 and CT-5 and HECO’s Waiau fuel oil pipeline), offset in part by lower depreciation expense resulting from the PUC’s approval in September 2004 of changes in the depreciation rates and accounting methodology applicable to HECO’s depreciable assets on Oahu.
The trend of increased operation and maintenance expenses is expected to continue in 2005 as the electric utilities anticipate: (1) higher demand-side management expenses (that are passed on to customers through a surcharge and therefore do not impact net income) and integrated resource planning expenses, (2) higher employee benefits expenses, primarily for retirement benefits and (3) higher production expenses, primarily to meet higher demand levels and load growth set in 2004 and sustained in 2005. The timing and amount of these expenses can vary as circumstances change. For example, recent overhauls have been more expensive than in the past due to the larger scope of work necessary to maintain the aging equipment, which has experienced heavier usage as demand has increased. In October 2004, one of HECO’s two CTs, Waiau Unit 9, experienced a sudden and accidental breakage of a blade that subsequently caused a catastrophic failure of the entire turbine. Greater customer demand resulting in higher usage of Waiau Unit 9 contributed to the failure. While partially covered by insurance, the repair costs are significant additional expenses necessary for service reliability. HECO completed the overhaul of Waiau Unit 9 in April 2005 and preventive overhaul work on its other CT, Waiau Unit 10 (with a capability of 49.9 MW), has been deferred for a few months to work on another unit. These Oahu peaking units have been used more frequently to meet increased customer demand for extended periods. Although it will not be known until the overhaul is fully underway, it is possible that the maintenance costs for Waiau Unit 10 will be higher than originally planned. Increased operation and maintenance expenses was one of the reasons HECO filed a request with the PUC in November 2004 to increase base rates. In September 2005, HECO received interim rate relief (see “Most recent rate request”).
Competition
Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration.
In 1996, the PUC issued an order instituting a proceeding to identify and examine the issues surrounding electric competition and to determine the impact of competition on the electric utility infrastructure in Hawaii. In October 2003, the PUC closed the competition proceeding and 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 current parties/participants in the competitive bidding proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative, the County of Kauai and a renewable energy organization. The issues to be addressed in the proceeding include the benefits and impacts of competitive bidding, whether a competitive bidding system should be developed for acquiring or building new generation, and revisions that should be made to integrated resource planning. If it is determined that a competitive bidding system should be developed, issues include how a fair system can be developed that “ensures that competitive benefits result from the system and ratepayers are not placed at undue risk”, what the guidelines and requirements for prospective bidders should be, and how such a system can encourage broad participation. Statements of Position by, information requests to, and responses by the parties/participants were filed in March through June 2005. Final statements of position were filed in August 2005. The PUC has indicated that panel hearings will be held in December 2005. Management cannot predict the ultimate outcome of this proceeding or its effect on the ability of the electric utilities to acquire or build additional generating capacity in the future. The PUC stated it would consider related matters on a case-by-case basis pending completion of the competitive bidding and DG proceedings.
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Distributed generation proceeding. The number of customer self-generation projects that are being proposed or installed in Hawaii, particularly those involving CHP systems, is growing. CHP systems are a form of DG, and produce electricity and thermal energy, which is generally used in Hawaii to heat water and, through an absorption chiller, drive an air conditioning system. The electric energy generated by these systems is usually lower in output than the customer’s load, which results in the customer’s continued connection to the utility grid to make up the difference in electricity demand and to provide back up electricity.
Over the last several years, the electric utilities have been exploring the possibility of utility-owned, customer sited CHP systems. Incremental generation from such customer-sited CHP systems, and other DG, is expected to complement traditional central station power, as part of the electric utilities’ plans to meet their forecast load growth.
In July 2003, three vendors of DG/CHP equipment and services requested, in an informal complaint, that the PUC investigate the electric utilities’ provision of CHP services and their teaming agreement with another vendor (which teaming agreement has since been cancelled), and issue rules or orders to govern the terms and conditions under which the electric utilities will be permitted to engage in utility-owned, customer sited DG.
In October 2003, the PUC opened the DG proceeding to determine the potential benefits and impact of DG on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii. The parties and participants to the proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative, the Counties of Maui and Kauai, a renewable energy organization, a vendor of DG equipment and services and an environmental organization.
In April 2004, the PUC issued an order in the DG proceeding defining issues related to planning (forms of DG, who should own and operate projects, and the roles of the electric utilities and PUC), impacts (the impacts, if any, on the transmission and distribution systems and market, power quality and reliability, the use of fossil fuels, utility costs and external costs and benefits) and implementation (matters to be considered to allow a DG facility to interconnect with the utility’s grid, appropriate rate design and cost allocation issues, revisions that should be made to the integrated resource planning process, and revisions that should be made to PUC and utility rules and practices). In the proceeding, the parties and participants also were allowed to address issues raised in the informal complaint, but not specific claims made against any parties named in the complaint. Hearings were held in December 2004. A decision from the PUC is expected in the fourth quarter of 2005. Management cannot predict the ultimate outcome of this proceeding.
Prior to opening of the investigative DG proceeding, the electric utilities filed an application for approval of CHP tariffs, under which they would own, operate and maintain customer-sited, packaged CHP systems (and certain ancillary equipment) pursuant to standard form contracts with eligible commercial customers. Pending approval of the proposed CHP tariffs, HECO and HELCO each requested in the fourth quarter of 2004 PUC approval of an agreement with a customer for a utility CHP project. The PUC suspended the applications for approval of the CHP tariffs and CHP project agreements until, at a minimum, the matters in the investigative DG proceeding have been adequately addressed. Subsequently, the HECO customer exercised its right to terminate the CHP project agreement and the application for approval of the project was withdrawn. The HELCO CHP agreement remains in suspension. With the continued suspension of HECO’s CHP Program application and the suspension of HECO’s and HELCO’s applications for individual CHP projects, management cannot predict if or when the benefits of utility CHP can begin to be realized.
Most recent rate request
The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs (e.g., higher energy conservation and efficiency program costs and higher purchased power capacity charges) and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of October 31, 2005, the return on average common equity (ROACE) found by the PUC to be reasonable in the most recent final rate decision for each utility was 11.40% for HECO (D&O issued on December 11, 1995, based on a 1995 test year), 11.50% 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). For the 12 months ended June 30, 2005, the simple average ROACEs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.92%, 6.97% and 9.68%, respectively.
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HELCO’s ROACE will continue to be negatively impacted by CT-4 and CT-5 as electric rates will not change for the unit additions until HELCO files a rate increase application and the PUC grants HELCO rate relief. HECO’s actual ROACE is significantly lower than its allowed ROACE primarily because of increased operation and maintenance (O&M) expenses, which are expected to continue. The PUC has granted HECO interim rate relief, effective September 28, 2005 (see below), which is based in part on increased costs of operating and maintaining its system.
As of October 31, 2005, the return on average rate base (ROR) found by the PUC to be reasonable in the most recent final rate decision for each utility was 9.16% for HECO, 9.14% for HELCO and 8.83% for MECO (D&Os noted above). For the 12 months ended June 30, 2005, the simple average RORs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.29%, 6.64% and 8.45% (after reduction of MECO’s revenues from shareholder incentives and lost margins in December 2004), respectively.
The ROACE and ROR used in determining HECO’s revenue requirements in the latest Interim D&O were 10.7% and 8.66%, respectively (see below).
If required to record significant charges to accumulated other comprehensive income (AOCI) related to a minimum liability for retirement benefits, the electric utilities’ RORs could increase and exceed the PUC authorized RORs, which may ultimately result in reduced revenues and lower earnings.
Hawaiian Electric Company, Inc. The final D&O for the last rate case for HECO on Oahu was issued in 1995.
In November 2004, HECO filed a request with the PUC to increase base rates 9.9%, or $98.6 million in annual base revenues, based on a 2005 test year, a 9.11% return on rate base and an 11.5% return on average common equity. As a result of PUC-approved stipulations in 2001, as modified in 2002, HECO requested approval of its proposed new energy efficiency (EE) DSM programs (Enhanced EE DSM programs), and associated utility incentive mechanism, in its rate case application, and included the related costs in its proposed rate increase. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. Excluding this surcharge transfer amount, the requested net increase to customers was 7.3%, or $74.2 million, largely for (1) the costs of new DSM programs, (2) the costs of capital improvement projects completed since the last rate case, (3) the proposed purchase of up to an additional 29 MW of firm capacity and energy from Kalaeloa Partners, L.P., (4) other measures taken to address peak load increases arising out of economic growth and increasing electricity use, and (5) increased O&M expenses. The PUC held a public hearing in January 2005. In addition to HECO, the parties include the Consumer Advocate and the DOD.
In March 2005, the PUC issued a bifurcation order separating HECO’s requests for approval and/or modification of its existing and proposed DSM programs from the rate case proceeding into a new docket. The preliminary issues identified by the PUC for the new EE DSM Docket include (1) whether, and if so, what, energy efficiency goals should be established, (2) whether the proposed and/or other DSM programs will achieve the established energy efficiency goals and be implemented in a cost-effective manner, (3) what market structures are most appropriate for providing these or other DSM programs, and (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate. The original parties/participants in this docket included HECO, the Consumer Advocate, the Department of Defense, the County of Maui, two renewable energy organizations, an energy efficiency organization, and an environmental organization. In June 2005, however, the PUC, on its own initiative, included HELCO, MECO, Kauai Island Utility Cooperative and The Gas Company as parties to the docket, provided their participation is limited solely to the issues dealing with statewide energy policies. A schedule for the EE DSM Docket has not yet been established.
As a result of the bifurcation order, HECO is continuing its existing DSM programs and cost recovery mechanisms (under which program costs, shareholder incentives, and lost margins between rate cases, are covered through a DSM surcharge). Relevant provisions of the stipulations under which the existing DSM programs have been extended continue to apply, including an agreement to cap the recovery of lost margins and shareholder incentives, if such recovery would cause HECO to exceed its current “authorized” ROR (i.e., the ROR found by the PUC to be reasonable in the most recent rate case for HECO, which, as a result of the Interim D&O discussed below, is currently 8.66%). An estimated $32 million in revenue requirements for DSM program costs related to both the Enhanced EE DSM programs and to the existing DSM programs, to the extent recovered through the DSM surcharge, were thus removed from HECO’s rate increase request.
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The base rate increase included in HECO’s rebuttal testimonies and exhibits filed in the proceeding in August 2005 was $63 million, or 5.2%, rather than $98.6 million, or 9.9%. The reduced request reflected removal of the revenue requirements for existing DSM program costs recovered through a surcharge and the cost of the proposed Enhanced EE DSM programs, slightly higher estimated sales due to lower DSM program impacts as the enhanced DSM proposals are now to be considered in the EE DSM Docket, changes in certain O&M expenses and rate base components for the 2005 test year based on updated information and actual year-end 2004 balances, and a lower proposed ROACE and ROR of 11% and 8.83%, respectively.
The revised and updated $63 million increase requested in August 2005 included the transfer to base rates of certain costs related to existing energy efficiency programs from a surcharge line item on electric bills. Excluding this surcharge transfer amount, the revised requested net increase to customers is 4.1%, or $50.9 million. (The costs to be transferred from a surcharge to base electric rates are primarily for lost margins. HECO currently is allowed to recover lost margins (i.e., lost revenues net of variable costs) due to the impact of its existing energy efficiency DSM programs on sales between rate cases. In rate cases, the impact of DSM programs on test year sales can be directly taken into account and incorporated into the calculation of base rates. Only future lost margins will be recovered through the surcharge after new rates are set, and the continued recovery of lost margins will be reviewed in the EE DSM Docket.)
In its testimonies and exhibits filed at the end of June 2005, the Consumer Advocate had proposed a rate increase of $23.5 million, based on its proposed ROR of 7.85% and a ROACE ranging between 8.50% and 10.0%. The remaining party, the DOD, in testimony and exhibits filed in June and July 2005, had proposed a rate increase of $19.3 million, based on its proposed ROR of 7.71% and ROACE of 9%. These proposals also excluded revenue requirements for DSM program costs. The HECO, Consumer Advocate and DOD RORs are based on rate bases of $1.109 billion, $1.065 billion and $1.062 billion, respectively.
In September 2005, HECO, the Consumer Advocate and the DOD reached agreement among themselves on most of the issues in the rate case proceeding, subject to PUC approval. Under the agreement, HECO’s revised request was lowered from the $63 million requested in August 2005 to $54 million, or 4.4% ($42 million, or 3.4%, excluding the surcharge transfer amount). The remaining significant issue among the parties is the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes. An evidentiary hearing on this issue, with a rate increase impact of approximately $7 million, was held in September 2005. For purposes of the Interim D&O (described below), the PUC included HECO s prepaid pension asset in rate base in determining HECO’s revenue requirements.
In a rate case, the PUC may grant an interim rate increase (subject to refund with interest pending the final outcome of the case) if the PUC believes that the public utility is probably entitled to an increase in its rates. On September 27, 2005, the PUC issued an Interim D&O granting an increase of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the surcharge transfer amount). The tariff changes implementing the interim rate increase were effective September 28, 2005. If the amount collected pursuant to this interim rate increase exceeds the amount of the increase approved in the final D&O, then the excess must be refunded to HECO’s ratepayers, with interest. The interim rate increase is based on a ROACE of 10.7%, a ROR of 8.66% and rate base of $1.109 billion. However, the adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and ROR) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.
Hawaii Electric Light Company, Inc. The timing of a future HELCO rate increase request to recover costs, including cost for the installation of two combustion turbines (CT-4 and CT-5) at Keahole, will depend on future circumstances. See “HELCO power situation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
The PUC has broad discretion in the regulation of the rates charged by the electric utilities and other matters. Any adverse D&O by the PUC concerning the level or method of determining electric utility rates, the authorized returns on equity, or other matters, or any prolonged delay in rendering a D&O in a rate or other proceeding could have a material adverse affect on the Company’s and HECO’s consolidated results of operations and financial condition. Management cannot predict with certainty when D&O’s in the current HECO rate case or in future rate cases will be rendered or the amount of any interim or final rate increase that may be granted.
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Depreciation rates and accounting
In October 2002, HECO filed an application with the PUC for approval to change its depreciation rates based on a study of depreciation expense for 2000 and to change to vintage amortization accounting for selected plant accounts. In March 2004, HECO and the Consumer Advocate reached an agreement, which the PUC approved in September 2004. In accordance with the agreement, HECO changed its depreciation rates and changed to vintage amortization accounting for selected plant accounts effective September 1, 2004, resulting in slightly lower depreciation than would have been recorded under the previous rates and method.
Integrated resource planning and requirements for additional generating capacity
In August 2000, pursuant to a stipulation filed by the electric utilities and the parties in the IRP cost proceedings, the PUC issued an order allowing the electric utilities to begin recovering the 1995 through 1999 incremental IRP costs, subject to refund with interest, pending the PUC’s final D&O approving recovery of each respective year’s incremental IRP costs. Incremental IRP costs are deferred until approved for recovery, at which time they are amortized to expense. Procedural schedules for the IRP cost proceedings have been established with respect to the 2000-2004 IRP costs, such that the electric utilities can begin recovering incremental IRP costs in the month after the filing of the actual costs incurred for the year, subject to refund with interest, pending the PUC’s final D&O approving recovery of the costs. HECO completed recovery of its 2004 incremental IRP costs in August 2005 and MECO is scheduled to complete recovery of its 2004 costs in June 2006. The Consumer Advocate has objected to the recovery of $3.2 million (before interest) of the $11.8 million of incremental IRP costs incurred during the 1995-2004 period, and the PUC’s decision is pending on this matter.
In September 2003, the PUC opened a docket to commence HECO’s third Integrated Resource Plan (IRP-3), which HECO was ordered by the PUC to file by October 31, 2005. On October 28, 2005, HECO filed its 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 central station generation. IRP-3 included a potential wind energy project above HECO’s Kahe power plant. However, HECO currently plans to review other potential sites due to the Mayor of Honolulu’s opposition to the project site.
In June 2005, HECO filed with the PUC an application for approval of funds to build a new nominal 100 MW simple cycle combustion turbine generating unit at Campbell Industrial Park on Oahu, the site of three other existing power plants, each owned and operated by an IPP (AES Hawaii, Kalaeloa and H-POWER). Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, operating mainly between the weekday peak electricity demand periods or during times when other generating units are not available. The air permit application for the unit, filed in October 2003 and currently under review by the DOH, requests approval to burn naphtha or diesel and specifies that the unit will have the ability to convert to using biofuels, such as ethanol, when they are commercially available. HECO is currently in the process of reviewing proposals received in May 2005 for the combustion turbine from three vendors through a competitive bidding process. Selection of the combustion turbine will be made through an evaluation of pricing, performance and commercial terms. Management expects to execute a contract with the selected vendor prior to year-end, with the right to terminate the contract at a specified payment amount if necessary CT project approvals are not obtained.
The generating unit application also requests approval to build an additional 138 kV transmission line approximately two miles long, within and adjacent to Campbell Industrial Park, to more reliably transmit power from the new and existing generating units within the industrial park to the Oahu electric grid. Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $134 million. As of September 30, 2005 accumulated project costs for planning, engineering, permitting and AFUDC amounted to $1.9 million. HECO is now preparing an Environmental Impact Statement for the proposed project.
In a related application filed with the PUC in June 2005, HECO requested approval for an approximately $11.5 million package of community benefit measures to mitigate the impact of the new generating unit on communities near the proposed generating unit site. These measures include a base electric rate discount for those who live near the proposed generation site, additional air-quality monitoring stations, a fish monitoring program and the use of recycled instead of potable water in Kahe power plant’s operations.
In July 2005, the Consumer Advocate filed Preliminary Statements of Position on HECO’s Campbell Industrial Park generating unit and transmission line additions application and community benefits application. Also in
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July 2005, HECO filed memoranda in response opposing the Consumer Advocate’s recommendations to suspend the two applications, suspend the start of the procedural schedule for both applications until after the filing of the IRP-3 (which was filed on October 28, 2005), and consolidate the applications.
In September 2005, the PUC suspended HECO’s Campbell Industrial Park generating unit and transmission line additions application until further order of the PUC to allow more time to review the application. Also in September 2005, the PUC ordered HECO and the Consumer Advocate to submit a stipulated prehearing order for the community benefits application within 30 days following the filing of HECO’s IRP-3 (i.e., by November 28, 2005).
Avoided cost generic docket
In May 1992, the PUC instituted a generic investigation, including all of Hawaii’s electric utilities, 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/sell power from/to the electric utility. The parties to the 1992 docket include the electric utilities, Consumer Advocate, Department of Defense, and representatives of existing or potential IPPs. In March 1994, the parties entered into and filed a Stipulation to Resolve Proceedings, which is subject to PUC approval. The parties could not reach agreement with respect to certain of the issues, which are addressed in Statements of Position filed in March 1994. No further action was taken in the docket until July 2004 when the PUC ordered the parties to review and update, if necessary, the agreements, information and data contained in the stipulation and file such information and stated that further action will follow. In October 2005, the PUC approved a request from the parties for an extension until November 30, 2005 to review and update the stipulation.
Legislation
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. The incentives include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. The Act’s primary impact on HECO and its subsidiaries will 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. Management continues to analyze the Act for further impacts.
Renewable Portfolio Standard
The 2001 Hawaii Legislature adopted a law that required the utilities to meet a renewable portfolio standard (RPS). The 2004 Hawaii Legislature amended the RPS law to require electric utilities to meet a renewable portfolio standard of 8% by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. The PUC has to determine if an electric utility is not able to meet the standard in a cost-effective manner or due to circumstances beyond its control. If such a determination is made, the utility is relieved of its responsibility to achieve the standard for that period of time. The PUC also may provide incentives to encourage electric utility companies to exceed their RPS or to meet their RPS ahead of time, or both.
The RPS law also directs the PUC, by December 31, 2006, to develop and implement a utility ratemaking structure, which may include, but is not limited to, performance-based ratemaking (PBR), 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.
On November 1, 2004 the PUC transmitted an Initial Concept Paper, entitled “Electric Utility Rate Design in Hawaii,” describing the PUC’s intended methodology for fulfilling the legislative mandate. The overall process envisioned by the PUC is the conduct of three sets of workshops, and the creation of a document that forms the basis of a set of rules to be adopted in a conventional rulemaking process to follow, providing input to the PUC’s decisions on electric utility ratemaking. Management cannot predict the outcome of this process.
The goal of the first workshop was to describe and gather comments on the PUC’s methodology as a whole. The goal of the second workshop was to describe and gather comments on the key factors driving successful RPS
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schemes and PBR regimes as well as on their use as inputs to the design of electric utility rates in Hawaii. The goal of the third workshop is to describe and gather comments on the simulation of the power market in Hawaii incorporating, as discussed in the prior workshops, the lessons learned on electric utility rate design under various RPS schemes and PBR regimes, as well as on its use as a tool for electric utility rate design in Hawaii.
The first set of workshops was held in November 2004. On July 26, 2005, the PUC transmitted a Second Concept Paper (SCP) authored by Economists Incorporated (EI), entitled “Proposals for Implementing Renewable Portfolio Standards in Hawaii.” The paper identified and described a number of incentive regulation (IR) mechanisms, including renewable energy credit trading, alternative compliance fees, penalties and positive incentives. On September 23, 2005, the PUC transmitted EI’s technical paper entitled “Planned Computer Simulations Facilitating the Analysis of Proposals for Implementing the Renewable Portfolio Standards Provision in Hawaii.” The second set of workshops was held in October 2005. The PUC received comments from HECO and other participants on the papers prior to, during and after the workshops, and other IR mechanisms were proposed. The PUC plans to hold the third set of workshops in January 2006.
The electric utilities and its unregulated subsidiary, Renewable Hawaii, Inc. continue to pursue a three-pronged renewable energy strategy: a) promote the development of cost-effective, commercially viable renewable energy projects, b) facilitate the integration of intermittent renewable energy resources, and c) encourage renewable energy research, development, and demonstration projects (e.g., photovoltaic energy and an electronic shock absorber for wind generation). They are also conducting integrated resource planning to evaluate the increased use of renewables within the electric utilities’ service territories.
Among the various ways that the electric utilities support renewable energy are solar water heating and heat pump programs and the negotiation and execution of purchased power contracts with nonutility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric and wind turbine generating systems).
HECO filed and received a patent in February 2005 for an electronic shock absorber (ESA) that addresses power fluctuations from wind resources. An ESA demonstration system is expected to be installed later this year and tested into 2006. HECO has sought protection of intellectual property rights in its ESA technology, including a portfolio of U.S. and international patents and patent filings. HECO has an intellectual property license agreement with the party constructing the ESA demonstration system. Management cannot predict the amount of royalties from the sale of ESAs in the future.
See “Collective bargaining agreements” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
Other developments
To evaluate the technical feasibility of the “Broadband over Power Line” (BPL) technology and its applications, HECO completed a small-scale trial of the BPL technology. Based on the favorable results of the trial, HECO will be proceeding with a pilot in an expanded residential/commercial area in Honolulu. BPL-enabled utility applications being evaluated include distribution system line monitoring, advanced remote metering, residential direct load control and monitoring of distribution substation equipment. Although its evaluation will be focused primarily on utility applications of BPL, HECO will also be evaluating broadband information services that might potentially be provided by other service providers. The pilot commenced in June 2005 and is expected to run through at least the second quarter of 2006.
In October 2004, the Federal Communications Commission (FCC) released a Report and Order that amended and adopted new rules for Access Broadband over Power Line systems (Access BPL) and stated that an FCC goal in developing the rules for Access BPL “are therefore to provide a framework that will both facilitate the rapid introduction and development of BPL systems and protect licensed radio services from harmful interference.” Currently, there are no PUC regulations for electric utility applications of BPL systems.
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See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
See Note 7 of HECO’s “Notes to Consolidated Financial Statements.”
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 other borrowings, 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:
Long-term debt
Preferred stock
As of October 31, 2005, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:
Revenue bonds (senior unsecured, insured)
HECO-obligated preferred securities of trust subsidiaries
Cumulative preferred stock (selected series)
The above 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+/Negative/A-2.
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 April 2005, S&P affirmed its corporate credit ratings of HECO, but revised its outlook from stable to negative, citing HECO’s need for a rate increase, rising operating expenses and yet to be recovered investments. 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).” In response to the PUC’s interim rate decision for HECO, S&P stated “a final order that closely mirrors the interim ruling appears to be sufficient to lift key financial metrics to levels that are marginally suitable for Standard & Poor’s guideposts for the ‘BBB’ rating category.” However, S&P will maintain its negative outlook until the PUC issues its final order. Moody’s maintains a stable outlook on HECO. In May 2005, S&P revised HECO’s business profile from “6” to “5”. S&P ranks business profiles from “1” (strong) to “10” (weak).
HECO periodically 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. HECO had an average outstanding balance of commercial paper for the first nine months of 2005 of $95 million and had $112 million of commercial paper outstanding at September 30, 2005. HECO had $13 million of short-term borrowings from HEI at September 30, 2005. Management believes that if HECO’s commercial paper ratings were to be downgraded, they might not be able to sell commercial paper under current market conditions.
At September 30, 2005, HECO maintained bank lines of credit totaling $180 million with six different banks (all expiring in 2006). These lines of credit are principally maintained by HECO to support the issuance of commercial
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paper, but also may be drawn for general corporate purposes. Accordingly, the lines of credit are available for short-term liquidity in the event a rating agency downgrade were to reduce or eliminate access to the commercial paper markets. None of HECO’s line of credit agreements contain clauses that would affect access to the lines by reason of a ratings downgrade, nor do they have broad “material adverse change” clauses that could affect access to the lines in the event of any material adverse event so long as any such event is timely disclosed. However, access to some or all of the lines could be restricted, or defaults under the lines could occur, if representations and warranties in the agreements, as permitted to be updated, are not true and correct at the time an advance is requested or if HECO is not in compliance with the covenants in such agreements. Management believes that it is not likely that any such restriction or default will occur. At September 30, 2005, the lines were undrawn. To the extent deemed necessary, HECO anticipates arranging similar lines of credit as existing lines of credit expire.
Operating activities provided $125 million in net cash during the first nine months of 2005. Investing activities during the same period used net cash of $131 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the period provided net cash of $8 million, primarily due to the $48 million net increase in short term borrowings and long-term debt, partly offset by the payment of $35 million in common and preferred dividends.
As of September 30, 2005, approximately $1 million of proceeds from the sale by the Department of Budget and Finance of the State of Hawaii of Series 2002A Special Purpose Revenue Bonds (SPRBs) issued for the benefit of HECO remain undrawn. In May 2005, up to $160 million of SPRBs ($100 million for HECO, $40 million for HELCO and $20 million for MECO) were authorized by the Hawaii legislature for issuance through June 30, 2010 to finance the electric utilities’ capital improvement projects.
In January 2005, the Department of Budget and Finance of the State of Hawaii issued, at par, Refunding Series 2005A SPRBs in the aggregate principal amount of $47 million (with a maturity of January 1, 2025 and a fixed coupon interest rate of 4.80%) and loaned the proceeds from the sale to HECO, HELCO and MECO. Proceeds from the sale, along with additional funds, were applied to redeem at a 1% premium a like principal amount of SPRBs bearing a higher interest coupon (HECO’s, HELCO’s, and MECO’s aggregate $47 million of 6.60% Series 1995A SPRBs with an original stated maturity of January 1, 2025) in February 2005.
BANK
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ASB’s results of operations for the second quarter of 2004 include a net charge of $24 million due to an adverse tax ruling as discussed in Note 4 of HEI’s “Notes to Consolidated Financial Statements” under “ASB Realty Corporation.” The $24 million net charge included a net $21 million of cumulative bank franchise taxes through March 31, 2004, plus a net $3 million of interest (or gross interest of $5 million, which is included in general and administrative expenses). The following table presents a reconciliation of ASB’s net income to net income excluding the $24 million charge and including additional bank franchise taxes in prior periods as if ASB had not taken a dividends received deduction on income from its REIT subsidiary. Management believes the adjusted information below presents ASB’s net income on a more comparable basis for the periods shown. However, net income, including these adjustments, is not a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in HEI’s consolidated financial statements.
Cumulative franchise tax and interest, net
Net income - as adjusted
Taking into account the adjustments in the table above, ASB’s net income would have decreased 1% for the nine months ended September 30, 2005, compared to the same period last year (see discussion below).
Interest rate spread
Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on interest-earning assets and interest paid on interest-bearing liabilities. 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. At September 30, 2005, ASB’s net loan portfolio mix consisted of 75% residential loans, 7% commercial real estate loans, 11% business loans and 7% consumer loans. At December 31, 2004, ASB’s net loan portfolio mix consisted of 74% residential loans, 9% commercial real estate loans, 10% business 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.
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Deposits continue to be the largest source of funds 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. At September 30, 2005, ASB’s costing liabilities consisted of 51% core deposits, 22% term certificates and 27% FHLB advances and other borrowings. At December 31, 2004, ASB’s costing liabilities consisted of 51% core deposits, 20% term certificates and 29% FHLB advances and other borrowings.
($ in thousands)
Loans receivable
Average balances 1
Interest income 2
Weighted-average yield (%)
Mortgage-related securities
Average balances
Interest income
Investments 3
Interest and dividend income
Total earning assets
Interest expense
Weighted-average rate (%)
Borrowings
Total costing liabilities
Net average balance, net interest income and interest rate spread
Net average balance
Interest rate spread (%)
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Net interest income for the third quarter of 2005 increased by $4.3 million, or 9%, from the same period in 2004. Interest rate spread increased from 3.09% for the third quarter of 2004 to 3.26% for the third quarter of 2005 as ASB’s yield on earning assets increased faster than the increase in the rate on costing liabilities, primarily as a result of an increase in the yield on loans and mortgage-related securities. Interest income on loans receivable increased due to increased loan production and higher weighted-average yields on the loan portfolio. The residential and commercial real estate loan portfolios grew as a result of continued strength in the Hawaii real estate market and the commercial loan portfolio grew as businesses in Hawaii have resumed borrowing to expand and make capital investments. Interest income on mortgage-related securities was about the same despite a $131 million drop in average balances primarily due to the upward adjustment to the amortized cost of the mortgage-related securities portfolio based on updated prepayment expectations resulting from higher interest rates at September 30, 2005 compared to June 30, 2005. The decrease in average balances was the result of ASB’s focus on its core lending businesses and less reliance on wholesale business. Interest income on investments decreased as a result of no dividends on stock in the FHLB of Seattle for the quarter compared to dividends on such stock of $0.8 million in the same quarter of last year. Interest expense on deposit liabilities increased primarily due to a $195 million increase in average core deposits and $167 million increase in average term certificates. The increase in average deposit balances was due to the growth of the Hawaii deposit market and ASB’s execution of its strategic initiatives to transform to a full-service community bank. Interest expense on other borrowings increased due to the upward repricing of adjustable rate borrowings, partly offset by a decrease in the outstanding average balance resulting from ASB’s focus on its deposit business and less reliance on wholesale business.
As of September 30, 2005, delinquent and nonaccrual loans to total loans continued to trend downward to 0.22% (from 0.41% at December 31, 2004), a level well below historical norms. During the third quarter of 2005, the need to provision for additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality. This compares with a reversal of allowance for loan losses of $3.8 million for the third quarter of 2004.
Other income for the third quarter of 2005 increased by $0.3 million or 2%, compared to the same period in 2004.
General and administrative expenses for the third quarter of 2005 increased by $1.4 million, or 4%, from the same period in 2004. Expenses for compensation increased $1.2 million as a result of SOX compliance and strategic initiatives.
In the third quarter of 2005, ASB paid $1.4 million less preferred stock dividends primarily due to the redemption of $75 million of its preferred stock in December 2004. HEIDI concurrently reinvested the redemption proceeds as a capital contribution to ASB.
Net interest income for the first nine months of 2005 increased by $11.5 million, or 8%, from the same period in 2004. Interest rate spread increased from 3.07% for the nine months ended September 30, 2004 to 3.18% for the nine months ended September 30, 2005 as ASB’s yield on earning assets increased faster than the rate on costing liabilities. Interest income on loans receivable increased primarily due to the larger residential and commercial real estate loan portfolios as a result of continued strength in the Hawaii real estate market. Interest income on mortgage-related securities increased due to prior year growth in the mortgage-related securities portfolio and the net upward adjustments to the amortized cost of the portfolio based on updated prepayment expectations. Interest income on investments decreased due to the reinvestment of excess liquidity into loans rather than short-term investments and lower dividends on stock in the FHLB of Seattle. Interest expense on deposit liabilities increased primarily due to a $232 million increase in average core deposits and $115 million in term certificates. Interest expense on other borrowings increased due to the upward repricing of adjustable rate borrowings, partly offset by a decrease in the outstanding average balance.
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ASB recognized a $3.1 million reversal of allowance for loan losses during the first nine months of 2005 primarily due to the reversal of a specific loan loss reserve on a large commercial loan, which was repaid on April 1, 2005. This compares with a reversal of allowance for loan losses of $8.4 million for the same period in the previous year. As of September 30, 2005, ASB’s allowance for loan losses was 0.91% of average loans outstanding, compared to 1.08% at December 31, 2004 and 1.11% at September 30, 2004.
Allowance for loan losses, January 1
Net charge-offs
Allowance for loan losses, September 30
Other income for the nine months ended September 30, 2005 decreased by $1.0 million or 2%, compared to the same period in 2004 as a result of lower annuity sales and fee income on deposit liabilities and gain on sale of loans, partly offset by an increase in debit card income.
General and administrative expenses for the nine months ended September 30, 2005 increased by $3.7 million, or 3%, from the same period in 2004 as a result of several factors, including increased compensation and services expenses and a reserve for interest related to income taxes as a result of a recent Internal Revenue Service examination, partly offset by prior year’s $5 million of interest accrued on cumulative bank franchise taxes through March 31, 2004 as a result of an adverse tax ruling.
In the first nine months of 2005, ASB paid $4.1 million less preferred stock dividends due to the redemption of $75 million of its preferred stock in December 2004. HEIDI concurrently reinvested the redemption proceeds as a capital contribution to ASB.
Charge to accumulated other comprehensive income (AOCI)
Since December 31, 2004, the yield curve flattened as a result of higher short-term interest rates and lower long-term interest rates. The net impact of this flattening was to reduce the market value of mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI. This reduction in the market value of mortgage-related securities did not result in a charge to net income as the impairments in the value of the securities were deemed to be temporary. At September 30, 2005, June 30, 2005, March 31, 2005 and December 31, 2004, the unrealized loss, net of tax benefits, on available-for-sale mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $27 million, $11 million, $36 million and $7 million, respectively.
FHLB of Seattle business and capital plan
In December 2004, the FHLB of Seattle signed an agreement with its regulator, the Federal Housing Finance Board (Finance Board), to adopt a business and capital plan to strengthen its risk management, capital structure and governance. As of September 30, 2005, ASB had an investment in FHLB of Seattle stock of $98 million. In the first nine months of 2005, ASB received a stock dividend with a par value of $0.4 million on its investment in FHLB of Seattle stock, compared to a stock dividend with a par value of $2.7 million in the first nine months of 2004 and nil in the fourth quarter of 2004.
In April 2005, the FHLB of Seattle delivered a proposed three-year business plan and capital management plan to the Finance Board, and issued a press release stating that it anticipates minimal to no dividends in the next few years while it implements its new business model. No dividends were received by ASB from the FHLB of Seattle during the second or third quarters of 2005. Member access to the FHLB of Seattle funding and liquidity is expected to continue unimpeded during implementation of the three-year plan.
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Total assets
Investment in FHLB of Seattle stock
As of September 30, 2005, ASB was the third largest financial institution in Hawaii based on assets of $6.9 billion and deposits of $4.6 billion.
At September 30, 2005, ASB’s unused FHLB borrowing capacity was approximately $1.4 billion. At September 30, 2005, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 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 nine months of 2005, net cash provided by ASB’s operating activities was $24 million. Net cash used by ASB’s investing activities was $75 million, due to a net increase in loans receivable, partly offset by repayments and sales of mortgage-related securities, net of purchases. Net cash provided by financing activities was $114 million due to net increases of $256 million in deposit liabilities and $20 million in advances from the FHLB of Seattle, partly offset by a net decrease of $131 million in securities sold under agreements to repurchase and the payment of $27 million in common stock dividends.
As of September 30, 2005, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.2% (5.0%), a Tier-1 risk-based capital ratio of 14.2% (6.0%) and a total risk-based capital ratio of 15.0% (10.0%).
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION
The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond its control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 77 to 85 of HEI’s 2004 Form 10-K.
Additional factors that may affect future results and financial condition are described on page iv under “Cautionary Statements and Risk Factors that May Affect Future Results.”
MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES
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 policies, see pages 85 to 89 of HEI’s 2004 Form 10-K.
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. In determining that HECO is not the primary beneficiary of Kalaeloa under the provisions of FIN 46R (see Notes 2 and 7 of HECO’s “Notes to Consolidated Financial Statements”), management used estimates in computing Kalaeloa’s expected cash flows. Estimates used in the analysis, for example with respect to the variability of fuel usage and pricing and operational levels and costs, are particularly susceptible to change. Management used its best efforts to determine the expected cash flows based on historical experience, financial information provided by Kalaeloa and on various other assumptions that were believed to be reasonable under the circumstances, the results of which formed the basis for the estimated cash flows. Actual results of Kalaeloa could differ significantly from those estimations.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 90 to 93 of HEI’s 2004 Form 10-K.
ASB’s interest-rate risk sensitivity measures as of September 30, 2005 and December 31, 2004 were as follows:
Change in
net interest
income (NII)
Net
portfolio
value
(NPV)
ratio
NPV ratiosensitivity
(change frombase case in
basis points)
Change
in NII
Change in interest rates (basis points)
+300
+200
+100
Base
-100
Management believes that ASB’s interest rate risk position at September 30, 2005 represents a reasonable level of risk. The bank’s NII profile as of September 30, 2005 is slightly more sensitive to changes in interest rates compared to the NII profile on December 31, 2004. This change is primarily due to smaller changes in prepayment estimates for the mortgage assets and mortgage-related securities in the alternate interest rate scenarios as of September 30, 2005.
ASB’s base NPV ratio as of September 30, 2005 was higher compared to December 31, 2004. Growth in deposits during the period contributed to the increase, as ASB was able to replace higher-cost wholesale borrowings with deposits. Core deposits are the lowest cost funding source available to ASB, so increasing the level of core deposits, relative to wholesale liabilities, causes the NPV ratio to increase.
ASB’s NPV ratio sensitivity measures as of September 30, 2005 were lower than the sensitivity measures as of December 31, 2004. The decrease was due to several factors including the increase in deposit balances as well as the faster overall level of expected prepayment speeds, and correspondingly shorter expected average lives, for the mortgage assets and mortgage-related securities.
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 or future results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. These analyses constitute “forward-looking” statements and 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, as well as management’s responses to the changes in interest rates. The NII simulation model does not reflect the income impact of any changes in the book value of the investment securities due to the application of the level yield methodology for amortizing premiums or discounts.
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Item 4. Controls and Procedures
HEI: Robert F. Clarke, HEI Chief Executive Officer, and Eric K. Yeaman, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of September 30, 2005. Based on their evaluations, as of September 30, 2005, 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) are effective.
HECO: T. Michael May, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2005. Based on their evaluations, as of September 30, 2005, 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) are effective.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
There are no significant developments in pending legal proceedings except as set forth in HEI’s and HECO’s “Notes to Consolidated Financial Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 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.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases of HEI common shares were made as follows:
ISSUER PURCHASES OF EQUITY SECURITIES
Period*
(a)
Total Number ofSharesPurchased **
(b)
Average
Price Paid
per Share **
(c)
Total Number ofShares Purchased asPart of PubliclyAnnounced Plans orPrograms **
(d)
Maximum Number (orApproximate Dollar Value) ofShares that May Yet BePurchased Under the Plansor Programs
July 1 to 31, 2005
August 1 to 31, 2005
September 1 to 30, 2005
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Item 5. Other Information
A. Ratio of earnings to fixed charges.
HEI and Subsidiaries
HECO and Subsidiaries
See HEI Exhibit 12.1 and HECO Exhibit 12.2.
B. Renewable Hawaii, Inc. (RHI)
In December 2002, HECO formed an unregulated subsidiary, RHI, with initial approval to invest up to $10 million in selected renewable energy projects. RHI is seeking to stimulate renewable energy initiatives by prospecting for new projects and sites and taking a passive, minority interest in third party renewable energy projects greater than 1 MW in Hawaii. Since 2003, RHI has periodically solicited competitive proposals for investment opportunities in qualified projects. To date, RHI has signed conditional investment agreements for a municipal solid waste-to-energy project and a small-scale landfill gas-to-energy project, both on Oahu. A number of new proposals are currently being evaluated. Project investments by RHI will generally be made only after developers secure the necessary approvals and permits and independently execute a PPA with HECO, HELCO or MECO, approved by the PUC.
C. Potential HECO wind energy project
In July 2005, HECO held a series of community meetings to get feedback on a potential wind energy project on the mountain ridges above its Kahe power plant. In September 2005, after considering community feedback and opposition to the location of the project by the Mayor of the City and County of Honolulu, who declared that the wind farm would not receive the City permits necessary to operate, HECO decided not to pursue the project. HECO plans to review other potential sites for a wind energy project.
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Item 6. Exhibits
Computation of ratio of earnings to fixed charges, nine months ended September 30, 2005 and 2004 and years ended December 31, 2004, 2003, 2002, 2001 and 2000
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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.
/s/ Robert F. Clarke
/s/ T. Michael May
Chairman, President and Chief Executive Officer
(Principal Executive Officer of HEI)
President and Chief Executive Officer
(Principal Executive Officer of HECO)
/s/ Eric K. Yeaman
/s/ Tayne S. Y. Sekimura
Financial Vice President, Treasurer and
Chief Financial Officer
(Principal Financial Officer of HEI)
Financial Vice President
(Principal Financial Officer of HECO)
/s/ Curtis Y. Harada
/s/ Patsy H. Nanbu
Controller
(Chief Accounting Officer of HEI)
(Chief Accounting Officer of HECO)
Date: November 9, 2005
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