UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
| x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2006March 31, 2007
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Exact Name of Registrant as Specified in Its Charter | Commission File Number | I.R.S. Employer Identification No. | ||
| HAWAIIAN ELECTRIC INDUSTRIES, INC. | 1-8503 | 99-0208097 | ||
| and Principal Subsidiary | ||||
| HAWAIIAN ELECTRIC COMPANY, INC. | 1-4955 | 99-0040500 | ||
State of Hawaii
(State or other jurisdiction of incorporation or organization)
900 Richards Street, Honolulu, Hawaii 96813
(Address of principal executive offices and zip code)
Hawaiian Electric Industries, Inc. —----- (808) 543-5662
Hawaiian Electric Company, Inc. —------- (808) 543-7771
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer 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 ¨ NoNo 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 ¨ NoNo 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 | |||
Hawaiian Electric Industries, Inc. (Without Par Value) | ||||
Hawaiian Electric Company, Inc. ($6-2/3 Par Value) | 12,805,843 Shares (not publicly traded) |
Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended September 30, 2006March 31, 2007
| Page No. | ||||
| ii | ||||
| iv |
| PART I. FINANCIAL INFORMATION | ||||||
Item 1. | ||||||
| Hawaiian Electric Industries, Inc. and Subsidiaries | ||||||
| ||||||
| ||||||
| 1 | ||||||
| Consolidated Balance Sheets (unaudited) - March 31, 2007 and | 2 | |||||
| 3 | ||||||
| 4 | ||||||
| 5 | ||||||
Hawaiian Electric Company, Inc. and Subsidiaries | ||||||
| ||||||
| 15 | ||||||
| 16 | ||||||
| 17 | ||||||
| Consolidated Statements of Cash Flows (unaudited) - | ||||||
| 18 | ||||||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||
| 36 | ||||||
| 36 | ||||||
| 40 | ||||||
| ||||||
| 57 | ||||||
Item 3. | ||||||
| 61 | ||||||
Item 4. | ||||||
| PART II. OTHER INFORMATION | ||||||
Item 1. | ||||||
| 62 | ||||||
Item 1A. | ||||||
| 63 | ||||||
Item 2. | ||||||
| 63 | ||||||
Item 5. | ||||||
| 63 | ||||||
Item 6. | ||||||
| 64 | ||||||
| 65 | ||||||
i
Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended September 30, 2006March 31, 2007
Glossary of TermsGLOSSARY OF TERMS
Terms | Definitions | |
AFUDC | Allowance for funds used during construction | |
AOCI | Accumulated other comprehensive income | |
ASB | American Savings Bank, F.S.B., a wholly-owned subsidiary of HEI Diversified, Inc. and parent company of American Savings Investment Services Corp. (and its subsidiary, Bishop Insurance Agency of Hawaii, Inc.) and AdCommunications, Inc. | |
|
| |
CHP | Combined heat and power | |
Company | Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc., | |
| dissolved subsidiaries. | ||
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 | |
DRIP | HEI Dividend Reinvestment and Stock Purchase Plan | |
DSM | Demand-side management | |
EPA | Environmental Protection Agency — federal | |
Exchange Act | Securities Exchange Act of 1934 | |
FASB | Financial Accounting Standards Board | |
Federal | U.S. Government | |
FHLB | Federal Home Loan Bank | |
FIN | Financial Accounting Standards Board Interpretation | |
| No. | ||
GAAP | U.S. generally accepted accounting principles | |
HECO | Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Maui Electric Company, Limited, Hawaii Electric Light Company, Inc., HECO Capital Trust III (unconsolidated subsidiary) and Renewable Hawaii, Inc. | |
ii
Glossary of Terms,GLOSSARY OF TERMS, continued
Terms | Definitions | |
HEI | Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., HEI Diversified, Inc., Pacific Energy Conservation Services, Inc., HEI Properties, Inc., HEI Investments, Inc., Hycap Management, Inc. (in dissolution), Hawaiian Electric Industries Capital Trust | |
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 formerly wholly owned subsidiary of Hawaiian Electric Industries, Inc., and the former parent company of numerous subsidiaries, the majority of which were dissolved or otherwise wound up since 2002, 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 | |
|
| |
| Hawaiian Electric Industries Retirement Savings Plan | |
HELCO | Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc. | |
HPOWER | City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant | |
IPP | Independent power producer | |
IRP | Integrated resource plan | |
|
| |
|
| |
|
| |
| 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 | |
|
| |
| 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 | |
SOIP | 1987 Stock Option and Incentive Plan, as amended | |
SOX | Sarbanes-Oxley Act of 2002 | |
SPRBs | Special Purpose Revenue Bonds | |
TOOTS | The Old Oahu Tug Service, a wholly owned subsidiary of Hawaiian Electric Industries, Inc. | |
VIE | Variable interest entity | |
iii
Forward-Looking StatementsFORWARD-LOOKING STATEMENTS
This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects and possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things.These forward-looking statements are not guarantees of future performance.
Risks, uncertainties and other important factors that could cause actual results to differ materially from those in forward-looking statements and from historical results include, but are not limited to, the following:
the effects of international, national and local economic conditions, including the state of the Hawaii tourist and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value of collateral underlying loans and mortgage-related securities) and decisions concerning the extent of the presence of the federal government and military in Hawaii;
the effects of weather and natural disasters, such as hurricanes, earthquakes, tsunamis and tsunamis;the potential effects of global warming;
global developments, including the effects of terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan, potential conflict or crisis with North Korea and in the Middle East, North Korea’s and Iran’s nuclear activities and potential avian flu pandemic;
the timing and extent of changes in interest rates and the shape of the yield curve;
the risks inherent in changes in the value of and market for securities available for sale and pension and other retirement plan assets;
changes in assumptions used to calculate retirement benefits costs and changes in funding requirements;
increasing competition in the electric utility and banking industries (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and increased price competition for deposits, or an outflow of deposits to alternative investments, may have an adverse impact on American Savings Bank, F.S.B.’s (ASB’s) cost of funds);
capacity and supply constraints or difficulties, especially if generating units (utility-owned or independent power producer (IPP)-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), combined heat and power (CHP) or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;
increased risk to generation reliability as generation peak reserve margins on Oahu continuedcontinue to be strained;
fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses;clauses (ECACs);
the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);
the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;
new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB and its subsidiaries) or their competitors;
federal, state and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (including changes in taxation, environmental laws and regulations, the potential regulation of greenhouse gas emissions and governmental fees and assessments); decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases (including decisions on ECACs) and other proceedings and by other agencies and courts on land use, environmental and other permitting issues; required corrective actions, restrictions and penalties (that may arise, for example, with respect to environmental conditions, renewable portfolio standards (RPS), capital adequacy and business practices);
increasing operations and maintenance expenses for the electric utilities and the possibility of more frequent rate cases;
the risks associated with the geographic concentration of HEI’s businesses;
the effects of changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the adoption of new accounting principles (such as the effects of Statement of Financial Accounting Standards (SFAS) No. 158 regarding employers’ accounting for defined benefit pension and other postretirement plans), continued regulatory accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” to power purchase arrangementsPPAs with independent power producers;
the effects of changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;
faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicing rights of ASB;
changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses;
changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;
the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;
the ability of consolidated HEI to generate capital gains and utilize capital loss carryforwards on future tax returns;
the risks of suffering losses and incurring liabilities that are uninsured; and
other risks or uncertainties described elsewhere in this report and in other periodic reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).
Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and itstheir subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
iv
PART I - FINANCIAL INFORMATION
| I | Financial Statements |
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Balance SheetsStatements of Income (unaudited)
(dollars in thousands) | September 30, 2006 | December 31, 2005 | ||||||
Assets | ||||||||
Cash and equivalents | $ | 146,917 | $ | 151,513 | ||||
Federal funds sold | 44,667 | 57,434 | ||||||
Accounts receivable and unbilled revenues, net | 271,203 | 249,473 | ||||||
Available-for-sale investment and mortgage-related securities | 2,357,012 | 2,629,351 | ||||||
Investment in stock of Federal Home Loan Bank of Seattle, at cost | 97,764 | 97,764 | ||||||
Loans receivable, net | 3,763,823 | 3,566,834 | ||||||
Property, plant and equipment, net of accumulated depreciation of $1,624,126 and $1,538,836 | 2,605,392 | 2,542,776 | ||||||
Regulatory assets | 110,335 | 110,718 | ||||||
Other | 424,712 | 456,134 | ||||||
Goodwill and other intangibles, net | 88,011 | 89,580 | ||||||
| $ | 9,909,836 | $ | 9,951,577 | |||||
Liabilities and stockholders’ equity | ||||||||
Liabilities | ||||||||
Accounts payable | $ | 178,132 | $ | 183,336 | ||||
Deposit liabilities | 4,540,124 | 4,557,419 | ||||||
Short-term borrowings—other than bank | 194,211 | 141,758 | ||||||
Other bank borrowings | 1,511,956 | 1,622,294 | ||||||
Long-term debt, net—other than bank | 1,133,137 | 1,142,993 | ||||||
Deferred income taxes | 197,800 | 207,997 | ||||||
Regulatory liabilities | 235,480 | 219,204 | ||||||
Contributions in aid of construction | 265,739 | 256,263 | ||||||
Other | 380,957 | 369,390 | ||||||
| 8,637,536 | 8,700,654 | |||||||
Minority interests | ||||||||
Preferred stock of subsidiaries - not subject to mandatory redemption | 34,293 | 34,293 | ||||||
Stockholders’ equity | ||||||||
Preferred stock, no par value, authorized 10,000,000 shares; issued: none | — | — | ||||||
Common stock, no par value, authorized 100,000,000 shares; issued and outstanding: 81,349,570 shares and 80,983,326 shares | 1,025,312 | 1,018,966 | ||||||
Retained earnings | 251,768 | 235,394 | ||||||
Accumulated other comprehensive loss, net of tax benefits | (39,073 | ) | (37,730 | ) | ||||
| 1,238,007 | 1,216,630 | |||||||
| $ | 9,909,836 | $ | 9,951,577 | |||||
Three months ended March 31 | 2007 | 2006 | ||||||
| (in thousands, except per share amounts and ratio of earnings to fixed charges) | ||||||||
Revenues | ||||||||
Electric utility | $ | 447,678 | $ | 475,056 | ||||
Bank | 104,460 | 100,004 | ||||||
Other | 1,885 | (98 | ) | |||||
| 554,023 | 574,962 | |||||||
Expenses | ||||||||
Electric utility | 434,686 | 429,476 | ||||||
Bank | 86,032 | 72,989 | ||||||
Other | 4,764 | 3,346 | ||||||
| 525,482 | 505,811 | |||||||
Operating income (loss) | ||||||||
Electric utility | 12,992 | 45,580 | ||||||
Bank | 18,428 | 27,015 | ||||||
Other | (2,879 | ) | (3,444 | ) | ||||
| 28,541 | 69,151 | |||||||
Interest expense–other than on deposit liabilities and other bank borrowings | (20,511 | ) | (19,117 | ) | ||||
Allowance for borrowed funds used during construction | 598 | 702 | ||||||
Preferred stock dividends of subsidiaries | (473 | ) | (473 | ) | ||||
Allowance for equity funds used during construction | 1,232 | 1,548 | ||||||
Income before income taxes | 9,387 | 51,811 | ||||||
Income taxes | 2,623 | 19,474 | ||||||
Net income | $ | 6,764 | $ | 32,337 | ||||
Basic earnings per common share | $ | 0.08 | $ | 0.40 | ||||
Diluted earnings per common share | $ | 0.08 | $ | 0.40 | ||||
Dividends per common share | $ | 0.31 | $ | 0.31 | ||||
Weighted-average number of common shares outstanding | 81,448 | 80,981 | ||||||
Dilutive effect of stock-based compensation | 265 | 382 | ||||||
Adjusted weighted-average shares | 81,713 | 81,363 | ||||||
Ratio of earnings to fixed charges (SEC method) | ||||||||
Excluding interest on ASB deposits | 1.22 | 2.33 | ||||||
Including interest on ASB deposits | 1.14 | 1.95 | ||||||
See accompanying “Notes to Consolidated Financial Statements” for HEI.
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of IncomeBalance Sheets (unaudited)
(in thousands, except per share amounts and ratio of earnings to fixed charges) | Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
Revenues | ||||||||||||||||
Electric utility | $ | 569,838 | $ | 491,339 | $ | 1,548,861 | $ | 1,295,844 | ||||||||
Bank | 103,338 | 97,431 | 305,898 | 286,601 | ||||||||||||
Other | 718 | 7,145 | (934 | ) | 8,360 | |||||||||||
| 673,894 | 595,915 | 1,853,825 | 1,590,805 | |||||||||||||
Expenses | ||||||||||||||||
Electric utility | 521,187 | 443,806 | 1,414,784 | 1,174,058 | ||||||||||||
Bank | 82,760 | 71,493 | 232,146 | 209,508 | ||||||||||||
Other | 3,591 | 3,377 | 10,659 | 11,880 | ||||||||||||
| 607,538 | 518,676 | 1,657,589 | 1,395,446 | |||||||||||||
Operating income (loss) | ||||||||||||||||
Electric utility | 48,651 | 47,533 | 134,077 | 121,786 | ||||||||||||
Bank | 20,578 | 25,938 | 73,752 | 77,093 | ||||||||||||
Other | (2,873 | ) | 3,768 | (11,593 | ) | (3,520 | ) | |||||||||
| 66,356 | 77,239 | 196,236 | 195,359 | |||||||||||||
Interest expense—other than bank | (18,275 | ) | (18,990 | ) | (56,526 | ) | (56,955 | ) | ||||||||
Allowance for borrowed funds used during construction | 838 | 558 | 2,259 | 1,460 | ||||||||||||
Preferred stock dividends of subsidiaries | (471 | ) | (471 | ) | (1,417 | ) | (1,421 | ) | ||||||||
Allowance for equity funds used during construction | 1,838 | 1,406 | 4,974 | 3,675 | ||||||||||||
Income from continuing operations before income taxes | 50,286 | 59,742 | 145,526 | 142,118 | ||||||||||||
Income taxes | 17,963 | 22,252 | 53,642 | 52,198 | ||||||||||||
Income from continuing operations | 32,323 | 37,490 | 91,884 | 89,920 | ||||||||||||
Discontinued operations-loss on disposal, net of income taxes | — | — | — | (755 | ) | |||||||||||
Net income | $ | 32,323 | $ | 37,490 | $ | 91,884 | $ | 89,165 | ||||||||
Basic earnings (loss) per common share | ||||||||||||||||
Continuing operations | $ | 0.40 | $ | 0.46 | $ | 1.13 | $ | 1.11 | ||||||||
Discontinued operations | — | — | — | (0.01 | ) | |||||||||||
| $ | 0.40 | $ | 0.46 | $ | 1.13 | $ | 1.10 | |||||||||
Diluted earnings (loss) per common share | ||||||||||||||||
Continuing operations | $ | 0.40 | $ | 0.46 | $ | 1.13 | $ | 1.11 | ||||||||
Discontinued operations | — | — | — | (0.01 | ) | |||||||||||
| $ | 0.40 | $ | 0.46 | $ | 1.13 | $ | 1.10 | |||||||||
Dividends per common share | $ | 0.31 | $ | 0.31 | $ | 0.93 | $ | 0.93 | ||||||||
Weighted-average number of common shares outstanding | 81,213 | 80,903 | 81,099 | 80,795 | ||||||||||||
Dilutive effect of stock options and dividend equivalents | 343 | 444 | 284 | 389 | ||||||||||||
Adjusted weighted-average shares | 81,556 | 81,347 | 81,383 | 81,184 | ||||||||||||
Ratio of earnings to fixed charges (SEC method) | ||||||||||||||||
Excluding interest on ASB deposits | 2.23 | 2.23 | ||||||||||||||
Including interest on ASB deposits | 1.85 | 1.93 | ||||||||||||||
(dollars in thousands) | March 31, 2007 | December 31, 2006 | ||||||
Assets | ||||||||
Cash and equivalents | $ | 156,093 | $ | 177,630 | ||||
Federal funds sold | 84,804 | 79,671 | ||||||
Accounts receivable and unbilled revenues, net | 220,894 | 248,639 | ||||||
Available-for-sale investment and mortgage-related securities | 2,405,250 | 2,367,427 | ||||||
Investment in stock of Federal Home Loan Bank of Seattle, at cost | 97,764 | 97,764 | ||||||
Loans receivable, net | 3,816,387 | 3,780,461 | ||||||
Property, plant and equipment, net of accumulated depreciation of $1,675,912 and $1,651,088 | 2,641,227 | 2,647,490 | ||||||
Regulatory assets | 117,078 | 112,349 | ||||||
Other | 296,434 | 292,638 | ||||||
Goodwill and other intangibles, net | 86,645 | 87,140 | ||||||
| $ | 9,922,576 | $ | 9,891,209 | |||||
Liabilities and stockholders’ equity | ||||||||
Liabilities | ||||||||
Accounts payable | $ | 172,554 | $ | 165,505 | ||||
Deposit liabilities | 4,577,073 | 4,575,548 | ||||||
Short-term borrowings—other than bank | 123,414 | 176,272 | ||||||
Other bank borrowings | 1,590,563 | 1,568,585 | ||||||
Long-term debt, net—other than bank | 1,225,144 | 1,133,185 | ||||||
Deferred income taxes | 96,374 | 106,780 | ||||||
Regulatory liabilities | 245,440 | 240,619 | ||||||
Contributions in aid of construction | 277,499 | 276,728 | ||||||
Other | 483,654 | 518,454 | ||||||
| 8,791,715 | 8,761,676 | |||||||
Minority interests | ||||||||
Preferred stock of subsidiaries - not subject to mandatory redemption | 34,293 | 34,293 | ||||||
Stockholders’ equity | ||||||||
Preferred stock, no par value, authorized 10,000,000 shares; issued: none | — | — | ||||||
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 81,823,550 shares and 81,461,409 shares | 1,036,249 | 1,028,101 | ||||||
Retained earnings | 223,946 | 242,667 | ||||||
Accumulated other comprehensive loss, net of tax benefits | (163,627 | ) | (175,528 | ) | ||||
| 1,096,568 | 1,095,240 | |||||||
| $ | 9,922,576 | $ | 9,891,209 | |||||
See accompanying “Notes to Consolidated Financial Statements” for HEI.
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (unaudited)
| Common stock | Retained earnings | Accumulated other comprehensive loss | Total | ||||||||||||||
(in thousands, except per share amounts) | Shares | Amount | |||||||||||||||
Balance, December 31, 2005 | 80,983 | $ | 1,018,966 | $ | 235,394 | $ | (37,730 | ) | $ | 1,216,630 | |||||||
Comprehensive income: | |||||||||||||||||
Net income | — | — | 91,884 | — | 91,884 | ||||||||||||
Net unrealized losses on securities: | |||||||||||||||||
Net unrealized losses arising during the period, net of income tax benefits of $164 | — | — | — | (250 | ) | (250 | ) | ||||||||||
Less: reclassification adjustment for net realized gains included in net income, net of income taxes of $690 | (1,045 | ) | (1,045 | ) | |||||||||||||
Minimum pension liability adjustment, net of income tax benefits of $30 | — | — | — | (48 | ) | (48 | ) | ||||||||||
Comprehensive income (loss) | — | — | 91,884 | (1,343 | ) | 90,541 | |||||||||||
Issuance of common stock, net | 367 | 6,346 | — | — | 6,346 | ||||||||||||
Common stock dividends ($0.93 per share) | — | — | (75,510 | ) | — | (75,510 | ) | ||||||||||
Balance, September 30, 2006 | 81,350 | $ | 1,025,312 | $ | 251,768 | $ | (39,073 | ) | $ | 1,238,007 | |||||||
Balance, December 31, 2004 | 80,687 | $ | 1,010,090 | $ | 208,998 | $ | (8,143 | ) | $ | 1,210,945 | |||||||
Comprehensive income: | |||||||||||||||||
Net income | — | — | 89,165 | — | 89,165 | ||||||||||||
Net unrealized losses on securities: | |||||||||||||||||
Net unrealized losses on securities arising during the period, net of income tax benefits of $15,459 | — | — | — | (19,532 | ) | (19,532 | ) | ||||||||||
Less: reclassification adjustment for net realized gains included in net income, net of income taxes of $70 | — | — | — | (106 | ) | (106 | ) | ||||||||||
Comprehensive income (loss) | — | — | 89,165 | (19,638 | ) | 69,527 | |||||||||||
Issuance of common stock, net | 269 | 8,080 | — | — | 8,080 | ||||||||||||
Common stock dividends ($0.93 per share) | — | — | (75,194 | ) | — | (75,194 | ) | ||||||||||
Balance, September 30, 2005 | 80,956 | $ | 1,018,170 | $ | 222,969 | $ | (27,781 | ) | $ | 1,213,358 | |||||||
(in thousands, except per share amounts) | Common stock | Retained earnings | Accumulated loss | Total | |||||||||||||
| Shares | Amount | ||||||||||||||||
Balance, December 31, 2006 | 81,461 | $ | 1,028,101 | $ | 242,667 | $ | (175,528 | ) | $ | 1,095,240 | |||||||
Comprehensive income: | |||||||||||||||||
Net income | — | — | 6,764 | — | 6,764 | ||||||||||||
Net unrealized gains on securities arising during the period, net of taxes of $6,406 | — | — | — | 9,701 | 9,701 | ||||||||||||
Defined benefit pension plans - amortization of net loss, prior service cost and transition obligation included in net periodic pension cost, net of taxes of $1,400 | — | — | — | 2,200 | 2,200 | ||||||||||||
Comprehensive income | — | — | 6,764 | 11,901 | 18,665 | ||||||||||||
Adjustment to initially apply FIN 48 | — | — | (228 | ) | — | (228 | ) | ||||||||||
Issuance of common stock, net | 363 | 8,148 | — | — | 8,148 | ||||||||||||
Common stock dividends ($0.31 per share) | — | — | (25,257 | ) | — | (25,257 | ) | ||||||||||
Balance, March 31, 2007 | 81,824 | $ | 1,036,249 | $ | 223,946 | $ | (163,627 | ) | $ | 1,096,568 | |||||||
Balance, December 31, 2005 | 80,983 | $ | 1,018,966 | $ | 235,394 | $ | (37,730 | ) | $ | 1,216,630 | |||||||
Comprehensive income: | |||||||||||||||||
Net income | — | — | 32,337 | — | 32,337 | ||||||||||||
Net unrealized losses on securities arising during the period, net of tax benefits of $8,890 | — | — | — | (13,466 | ) | (13,466 | ) | ||||||||||
Minimum pension liability adjustment, net of tax benefits of $30 | — | — | — | (48 | ) | (48 | ) | ||||||||||
Comprehensive income (loss) | — | — | 32,337 | (13,514 | ) | 18,823 | |||||||||||
Issuance of common stock, net | 77 | 1,195 | — | — | 1,195 | ||||||||||||
Common stock dividends ($0.31 per share) | — | — | (25,126 | ) | — | (25,126 | ) | ||||||||||
Balance, March 31, 2006 | 81,060 | $ | 1,020,161 | $ | 242,605 | $ | (51,244 | ) | $ | 1,211,522 | |||||||
See accompanying “Notes to Consolidated Financial Statements” for HEI.
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (unaudited)
Nine months ended September 30 | 2006 | 2005 | ||||||||||||||
Three months ended March 31 | 2007 | 2006 | ||||||||||||||
| (in thousands) | ||||||||||||||||
Cash flows from operating activities | ||||||||||||||||
Net income | $ | 91,884 | $ | 89,920 | $ | 6,764 | $ | 32,337 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||||||
Depreciation of property, plant and equipment | 105,862 | 100,391 | 36,856 | 35,261 | ||||||||||||
Other amortization | 7,790 | 7,565 | 2,680 | 2,196 | ||||||||||||
Reversal of allowance for loan losses | — | (3,100 | ) | |||||||||||||
Writedown of utility plant | 11,701 | — | ||||||||||||||
Deferred income taxes | (8,961 | ) | 19,843 | (5,908 | ) | (2,839 | ) | |||||||||
Allowance for equity funds used during construction | (4,974 | ) | (3,675 | ) | (1,232 | ) | (1,548 | ) | ||||||||
Excess tax benefits from share-based payment arrangements | (697 | ) | — | (233 | ) | (316 | ) | |||||||||
Changes in assets and liabilities, net of effects from the disposal of businesses | ||||||||||||||||
Increase in accounts receivable and unbilled revenues, net | (21,730 | ) | (30,600 | ) | ||||||||||||
Decrease (increase) in federal tax deposit | 30,000 | (30,000 | ) | |||||||||||||
Increase (decrease) in accounts payable | (5,204 | ) | 28,527 | |||||||||||||
Decrease in accounts receivable and unbilled revenues, net | 27,745 | 20,702 | ||||||||||||||
Decrease in federal tax deposit | — | 30,000 | ||||||||||||||
Increase in accounts payable | 7,049 | 516 | ||||||||||||||
Decrease in taxes accrued | (34,828 | ) | (36,217 | ) | ||||||||||||
Changes in other assets and liabilities | 9,412 | (22,492 | ) | 307 | (8,780 | ) | ||||||||||
Net cash provided by operating activities | 203,382 | 156,379 | 50,901 | 71,312 | ||||||||||||
Cash flows from investing activities | ||||||||||||||||
Available-for-sale investment and mortgage-related securities purchased | (175,000 | ) | (411,811 | ) | (132,195 | ) | (125,000 | ) | ||||||||
Principal repayments on available-for-sale mortgage-related securities | 381,960 | 555,640 | 108,556 | 121,632 | ||||||||||||
Proceeds from sale of available-for-sale mortgage-related securities | 61,131 | 28,039 | ||||||||||||||
Net increase in loans held for investment | (196,795 | ) | (243,452 | ) | (41,232 | ) | (58,078 | ) | ||||||||
Net proceeds from sale of investments | 2,536 | — | ||||||||||||||
Capital expenditures | (146,982 | ) | (146,696 | ) | (35,521 | ) | (45,317 | ) | ||||||||
Contributions in aid of construction | 13,227 | 10,274 | 2,495 | 6,623 | ||||||||||||
Other | 2,043 | 1,197 | 1 | 1,177 | ||||||||||||
Net cash used in investing activities | (60,416 | ) | (206,809 | ) | (95,360 | ) | (98,963 | ) | ||||||||
Cash flows from financing activities | ||||||||||||||||
Net increase (decrease) in deposit liabilities | (17,295 | ) | 255,665 | |||||||||||||
Net increase in short-term borrowings with original maturities of three months or less | 53,153 | 44,031 | ||||||||||||||
Net increase in deposit liabilities | 1,525 | 52,980 | ||||||||||||||
Net increase (decrease) in short-term borrowings with original maturities of three months or less | (65,866 | ) | 40,826 | |||||||||||||
Proceeds from short-term borrowings with original maturities of greater than three months | 44,890 | — | 13,008 | — | ||||||||||||
Repayment of short-term borrowings with original maturities of greater than three months | (45,590 | ) | — | |||||||||||||
Net increase in retail repurchase agreements | 45,577 | 17,717 | 23,370 | 7,864 | ||||||||||||
Proceeds from other bank borrowings | 1,050,907 | 847,056 | 238,988 | 206,490 | ||||||||||||
Repayments of other bank borrowings | (1,206,828 | ) | (975,981 | ) | (238,813 | ) | (214,300 | ) | ||||||||
Proceeds from issuance of long-term debt | 100,000 | 58,525 | 215,679 | — | ||||||||||||
Repayment of long-term debt | (110,000 | ) | (53,000 | ) | (126,000 | ) | (10,000 | ) | ||||||||
Excess tax benefits from share-based payment arrangements | 697 | — | 233 | 316 | ||||||||||||
Net proceeds from issuance of common stock | 3,392 | 3,232 | 2,411 | 103 | ||||||||||||
Common stock dividends | (75,469 | ) | (75,153 | ) | (20,166 | ) | (25,112 | ) | ||||||||
Decrease in cash overdraft | (11,280 | ) | (6,460 | ) | ||||||||||||
Other | (10,953 | ) | (10,354 | ) | (5,034 | ) | (347 | ) | ||||||||
Net cash provided by (used in) financing activities | (167,519 | ) | 111,738 | |||||||||||||
Net cash provided by financing activities | 28,055 | 52,360 | ||||||||||||||
Cash flows from discontinued operations-net cash provided by (used in) operating activities (revised see Note 8) | 7,190 | (2,462 | ) | |||||||||||||
Cash flows from discontinued operations-net cash provided by operating activities | — | 6,958 | ||||||||||||||
Net increase (decrease) in cash and equivalents and federal funds sold | (17,363 | ) | 58,846 | (16,404 | ) | 31,667 | ||||||||||
Cash and equivalents and federal funds sold, beginning of period | 208,947 | 173,629 | 257,301 | 208,947 | ||||||||||||
Cash and equivalents and federal funds sold, end of period | $ | 191,584 | $ | 232,475 | $ | 240,897 | $ | 240,614 | ||||||||
See accompanying “Notes to Consolidated Financial Statements” for HEI.
Hawaiian Electric Industries, Inc. and Subsidiaries
Notes To Consolidated Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of presentation
| (1) | Basis of presentation |
The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S–X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HEI’s Form 10-K for the year ended December 31, 2005 and the unaudited consolidated financial statements and the notes thereto included in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
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, 2006March 31, 2007 and December 31, 2005,2006 and the results of its operations for the three and nine months ended September 30, 2006 and 2005 and its cash flows for the ninethree months ended September 30, 2006March 31, 2007 and 2005.2006. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10–Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.
(2) Segment financial information
(in thousands) | Electric Utility | Bank | Other | Total | |||||||||
Three months ended September 30, 2006 | |||||||||||||
Revenues from external customers | $ | 569,768 | $ | 103,338 | $ | 788 | $ | 673,894 | |||||
Intersegment revenues (eliminations) | 70 | — | (70 | ) | — | ||||||||
Revenues | 569,838 | 103,338 | 718 | 673,894 | |||||||||
Profit (loss)* | 38,202 | 20,578 | (8,494 | ) | 50,286 | ||||||||
Income taxes (benefit) | 14,536 | 7,108 | (3,681 | ) | 17,963 | ||||||||
Income (loss) from continuing operations | 23,666 | 13,470 | (4,813 | ) | 32,323 | ||||||||
Nine months ended September 30, 2006 | |||||||||||||
Revenues from external customers | 1,548,651 | 305,898 | (724 | ) | 1,853,825 | ||||||||
Intersegment revenues (eliminations) | 210 | — | (210 | ) | — | ||||||||
Revenues | 1,548,861 | 305,898 | (934 | ) | 1,853,825 | ||||||||
Profit (loss)* | 100,408 | 73,752 | (28,634 | ) | 145,526 | ||||||||
Income taxes (benefit) | 38,468 | 27,237 | (12,063 | ) | 53,642 | ||||||||
Income (loss) from continuing operations | 61,940 | 46,515 | (16,571 | ) | 91,884 | ||||||||
Assets (at September 30, 2006, including net assets of discontinued operations) | 3,165,272 | 6,714,395 | 30,169 | 9,909,836 | |||||||||
Three months ended September 30, 2005 | |||||||||||||
Revenues from external customers | $ | 491,263 | $ | 97,431 | $ | 7,221 | $ | 595,915 | |||||
Intersegment revenues (eliminations) | 76 | — | (76 | ) | — | ||||||||
Revenues | 491,339 | 97,431 | 7,145 | 595,915 | |||||||||
Profit (loss)* | 36,315 | 25,938 | (2,511 | ) | 59,742 | ||||||||
Income taxes (benefit) | 13,728 | 10,027 | (1,503 | ) | 22,252 | ||||||||
Income (loss) from continuing operations | 22,587 | 15,911 | (1,008 | ) | 37,490 | ||||||||
Nine months ended September 30, 2005 | |||||||||||||
Revenues from external customers | 1,295,721 | 286,601 | 8,483 | 1,590,805 | |||||||||
Intersegment revenues (eliminations) | 123 | — | (123 | ) | — | ||||||||
Revenues | 1,295,844 | 286,601 | 8,360 | 1,590,805 | |||||||||
Profit (loss)* | 88,288 | 77,044 | (23,214 | ) | 142,118 | ||||||||
Income taxes (benefit) | 33,672 | 29,820 | (11,294 | ) | 52,198 | ||||||||
Income (loss) from continuing operations | 54,616 | 47,224 | (11,920 | ) | 89,920 | ||||||||
Assets (at September 30, 2005, including net assets of discontinued operations) | 2,998,745 | 6,901,465 | 75,308 | 9,975,518 | |||||||||
| (2) | Segment financial information |
(in thousands) | Electric Utility | Bank | Other | Total | ||||||||||
Three months ended March 31, 2007 | ||||||||||||||
Revenues from external customers | $ | 447,608 | $ | 104,460 | $ | 1,955 | $ | 554,023 | ||||||
Intersegment revenues (eliminations) | 70 | — | (70 | ) | — | |||||||||
Revenues | 447,678 | 104,460 | 1,885 | 554,023 | ||||||||||
Profit (loss)* | 140 | 18,399 | (9,152 | ) | 9,387 | |||||||||
Income taxes (benefit) | (313 | ) | 6,803 | (3,867 | ) | 2,623 | ||||||||
Net income (loss) | 453 | 11,596 | (5,285 | ) | 6,764 | |||||||||
Assets (at March 31, 2007, including net assets of discontinued operations) | 3,050,554 | 6,845,576 | 26,446 | 9,922,576 | ||||||||||
Three months ended March 31, 2006 | ||||||||||||||
Revenues from external customers | $ | 474,986 | $ | 100,004 | $ | (28 | ) | $ | 574,962 | |||||
Intersegment revenues (eliminations) | 70 | — | (70 | ) | — | |||||||||
Revenues | 475,056 | 100,004 | (98 | ) | 574,962 | |||||||||
Profit (loss)* | 34,097 | 27,015 | (9,301 | ) | 51,811 | |||||||||
Income taxes (benefit) | 13,109 | 10,188 | (3,823 | ) | 19,474 | |||||||||
Net income (loss) | 20,988 | 16,827 | (5,478 | ) | 32,337 | |||||||||
Assets (at March 31, 2006, including net assets of discontinued operations) | 3,076,673 | 6,864,915 | 38,120 | 9,979,708 | ||||||||||
| * | Income (loss) before income taxes. |
Intercompany electric sales of consolidated HECO to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income.
Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income.
(3) Electric utility subsidiary
| (3) | Electric utility subsidiary |
For HECO’s consolidated financial information, including its commitments and contingencies, see pages 1715 through 37.35.
(4) Bank subsidiary
| (4) | Bank subsidiary |
Selected financial information
American Savings Bank, F.S.B. and Subsidiaries
Consolidated Balance Sheet Data (unaudited)
(in thousands) | September 30, 2006 | December 31, 2005 | ||||||
Assets | ||||||||
Cash and equivalents | $ | 140,090 | $ | 150,130 | ||||
Federal funds sold | 44,667 | 57,434 | ||||||
Available-for-sale investment and mortgage-related securities | 2,357,012 | 2,629,351 | ||||||
Investment in stock of Federal Home Loan Bank of Seattle, at cost | 97,764 | 97,764 | ||||||
Loans receivable, net | 3,763,823 | 3,566,834 | ||||||
Other | 223,151 | 244,443 | ||||||
Goodwill and other intangibles, net | 87,888 | 89,379 | ||||||
| $ | 6,714,395 | $ | 6,835,335 | |||||
Liabilities and stockholder’s equity | ||||||||
Deposit liabilities–noninterest-bearing | $ | 645,608 | $ | 624,497 | ||||
Deposit liabilities–interest-bearing | 3,894,516 | 3,932,922 | ||||||
Other borrowings | 1,511,956 | 1,622,294 | ||||||
Other | 93,237 | 98,189 | ||||||
| 6,145,317 | 6,277,902 | |||||||
Common stock | 322,809 | 321,538 | ||||||
Retained earnings | 284,249 | 272,545 | ||||||
Accumulated other comprehensive loss, net of tax benefits | (37,980 | ) | (36,650 | ) | ||||
| 569,078 | 557,433 | |||||||
| $ | 6,714,395 | $ | 6,835,335 | |||||
American Savings Bank, F.S.B. and Subsidiaries
Consolidated Statements of Income Data (unaudited)
Three months ended September 30 | Nine months ended September 30 | ||||||||||||||||||
Three months ended March 31 | 2007 | 2006 | |||||||||||||||||
(in thousands) | 2006 | 2005 | 2006 | 2005 | |||||||||||||||
Interest and dividend income | |||||||||||||||||||
Interest and fees on loans | $ | 59,417 | $ | 52,649 | $ | 171,893 | $ | 151,819 | $ | 60,281 | $ | 55,153 | |||||||
Interest and dividends on investment and mortgage-related securities | 28,368 | 30,889 | 89,315 | 93,275 | 28,165 | 30,077 | |||||||||||||
| 87,785 | 83,538 | 261,208 | 245,094 | 88,446 | 85,230 | ||||||||||||||
Interest expense | |||||||||||||||||||
Interest on deposit liabilities | 19,701 | 13,355 | 52,095 | 37,832 | 20,738 | 15,393 | |||||||||||||
Interest on other borrowings | 18,891 | 17,278 | 54,361 | 51,919 | 18,406 | 17,162 | |||||||||||||
| 38,592 | 30,633 | 106,456 | 89,751 | 39,144 | 32,555 | ||||||||||||||
Net interest income | 49,193 | 52,905 | 154,752 | 155,343 | 49,302 | 52,675 | |||||||||||||
Reversal of allowance for loan losses | — | — | — | (3,100 | ) | ||||||||||||||
Provision for loan losses | — | — | |||||||||||||||||
Net interest income after reversal of allowance for loan losses | 49,193 | 52,905 | 154,752 | 158,443 | |||||||||||||||
Net interest income after provision for loan losses | 49,302 | 52,675 | |||||||||||||||||
Noninterest income | |||||||||||||||||||
Fees from other financial services | 6,548 | 6,512 | 19,730 | 18,708 | 6,501 | 6,440 | |||||||||||||
Fee income on deposit liabilities | 4,653 | 4,311 | 13,218 | 12,574 | 6,055 | 4,189 | |||||||||||||
Fee income on other financial products | 1,739 | 2,191 | 6,308 | 6,780 | 2,012 | 2,437 | |||||||||||||
Gain on sale of securities | 1,735 | — | 1,735 | 175 | |||||||||||||||
Other income | 878 | 879 | 3,699 | 3,270 | 1,446 | 1,708 | |||||||||||||
| 15,553 | 13,893 | 44,690 | 41,507 | 16,014 | 14,774 | ||||||||||||||
Noninterest expense | |||||||||||||||||||
Compensation and employee benefits | 17,398 | 17,275 | 52,711 | 51,343 | 18,396 | 17,837 | |||||||||||||
Occupancy | 4,942 | 4,356 | 13,895 | 12,462 | 4,948 | 4,463 | |||||||||||||
Equipment | 3,768 | 3,413 | 10,900 | 10,114 | 3,478 | 3,496 | |||||||||||||
Services | 5,600 | 3,986 | 13,441 | 11,594 | 8,358 | 3,717 | |||||||||||||
Data processing | 2,534 | 2,491 | 7,541 | 8,039 | 2,557 | 2,460 | |||||||||||||
Other expenses | 9,926 | 9,339 | 27,202 | 29,305 | |||||||||||||||
Other expense | 9,180 | 8,461 | |||||||||||||||||
| 44,168 | 40,860 | 125,690 | 122,857 | 46,917 | 40,434 | ||||||||||||||
Income before minority interests and income taxes | 20,578 | 25,938 | 73,752 | 77,093 | |||||||||||||||
Minority interests | — | — | — | 45 | |||||||||||||||
Income before income taxes | 18,399 | 27,015 | |||||||||||||||||
Income taxes | 7,108 | 10,027 | 27,237 | 29,820 | 6,803 | 10,188 | |||||||||||||
Income before preferred stock dividends | 13,470 | 15,911 | 46,515 | 47,228 | |||||||||||||||
Preferred stock dividends | — | — | — | 4 | |||||||||||||||
Net income for common stock | $ | 13,470 | $ | 15,911 | $ | 46,515 | $ | 47,224 | $ | 11,596 | $ | 16,827 | |||||||
American Savings Bank, F.S.B. and Subsidiaries
Consolidated Balance Sheet Data (unaudited)
(in thousands) | March 31, 2007 | December 31, 2006 | ||||||
Assets | ||||||||
Cash and equivalents | $ | 141,975 | $ | 172,370 | ||||
Federal funds sold | 84,804 | 79,671 | ||||||
Available-for-sale investment and mortgage-related securities | 2,405,250 | 2,367,427 | ||||||
Investment in stock of Federal Home Loan Bank of Seattle, at cost | 97,764 | 97,764 | ||||||
Loans receivable, net | 3,816,387 | 3,780,461 | ||||||
Other | 212,751 | 223,666 | ||||||
Goodwill and other intangibles, net | 86,645 | 87,140 | ||||||
| $ | 6,845,576 | $ | 6,808,499 | |||||
Liabilities and stockholder’s equity | ||||||||
Deposit liabilities–noninterest-bearing | $ | 654,538 | $ | 648,915 | ||||
Deposit liabilities–interest-bearing | 3,922,535 | 3,926,633 | ||||||
Other borrowings | 1,590,563 | 1,568,585 | ||||||
Other | 105,650 | 104,470 | ||||||
| 6,273,286 | 6,248,603 | |||||||
Common stock | 323,649 | 323,154 | ||||||
Retained earnings | 282,108 | 280,046 | ||||||
Accumulated other comprehensive loss, net of tax benefits | (33,467 | ) | (43,304 | ) | ||||
| 572,290 | 559,896 | |||||||
| $ | 6,845,576 | $ | 6,808,499 | |||||
Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $739$811 million and $773$780 million, respectively, as of September 30, 2006March 31, 2007 and $687$730 million and $935$839 million, respectively, as of December 31, 2005.2006.
As of September 30, 2006,March 31, 2007, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.1 billion. As of September 30, 2006, ASB had commitments to sell nonresidential loans of $20.4 million.
In
| (5) | Retirement benefits |
For the first quarter of 2005, ASB recorded a $22007, HECO paid $0.3 million reserve, net of taxes, for interest on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends (see Note 10).
(5) Retirement benefits
For the first nine months of 2006, ASB paid $2 million and HECO paid $8$0.9 million in contributions to their respective retirement benefit plans, compared to $6$2.7 million and $8$0.8 million, respectively, in the first nine monthsquarter of 2005.2006. The Company’s current estimate of contributions to its retirement benefit plans in 20062007 is $14$17.0 million (including $13.4 million by HECO, $3.5 million by ASB and $0.1 million by HEI), compared to contributions of $25$12.9 million in 2005.2006. In addition, the Company expects to pay directly $1.7 million of benefits in 2007 compared to $1.2 million paid in 2006.
The components of net periodic benefit cost were as follows:
| Three months ended September 30 | Nine months ended September 30 | Pension benefits | Other benefits | |||||||||||||||||||||||||||||||||||||||||||||
| Pension benefits | Other benefits | Pension benefits | Other benefits | |||||||||||||||||||||||||||||||||||||||||||||
Three months ended March 31 | 2007 | 2006 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||||||||||||||||||||||||||||||||||||
Service cost | $ | 8,200 | $ | 7,354 | $ | 1,277 | $ | 1,316 | $ | 24,454 | $ | 22,027 | $ | 3,822 | $ | 3,934 | $ | 7,753 | $ | 8,091 | $ | 1,231 | $ | 1,271 | ||||||||||||||||||||||||
Interest cost | 13,603 | 13,001 | 2,616 | 2,759 | 40,639 | 39,090 | 8,003 | 8,311 | 14,420 | 13,476 | 2,860 | 2,732 | ||||||||||||||||||||||||||||||||||||
Expected return on plan assets | (18,005 | ) | (18,569 | ) | (2,486 | ) | (2,465 | ) | (53,679 | ) | (55,478 | ) | (7,432 | ) | (7,390 | ) | (17,102 | ) | (17,753 | ) | (2,298 | ) | (2,466 | ) | ||||||||||||||||||||||||
Amortization of unrecognized transition obligation | 1 | 1 | 785 | 785 | 4 | 3 | 2,353 | 2,354 | 1 | 1 | 785 | 784 | ||||||||||||||||||||||||||||||||||||
Amortization of prior service cost (gain) | (29 | ) | (156 | ) | 3 | — | (256 | ) | (467 | ) | 10 | — | (49 | ) | (156 | ) | 3 | 3 | ||||||||||||||||||||||||||||||
Recognized actuarial loss | 2,965 | 1,447 | 43 | 101 | 9,090 | 4,443 | 369 | 332 | 2,855 | 3,111 | — | 224 | ||||||||||||||||||||||||||||||||||||
Net periodic benefit cost | $ | 6,735 | $ | 3,078 | $ | 2,238 | $ | 2,496 | $ | 20,252 | $ | 9,618 | $ | 7,125 | $ | 7,541 | $ | 7,878 | $ | 6,770 | $ | 2,581 | $ | 2,548 | ||||||||||||||||||||||||
Of the net periodic benefit costs, the Company recorded expense of $21$8 million and $14$7 million in the first nine monthsquarters of 20062007 and 2005,2006, respectively, and charged the remaining amounts primarily to electric utility plant.
(6) Share-based compensationAlso, see Note 4, “Retirement benefits,” of HECO’s Notes to Consolidated Financial Statements.
| (6) | Share-based compensation |
Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), HEI may issue an aggregate of 9.3 million shares of common stock (5,096,494(4,900,783 shares available for issuance under outstanding and future grants and awards as of September 30, 2006)March 31, 2007) to officers and key employees as incentive stock options, nonqualified stock options (NQSOs), restricted stock, stock appreciation rights (SARs), stock payments or dividend equivalents. HEI has issued new shares for NQSOs, restricted stock, SARs and dividend equivalents under the SOIP. All information presented has been adjusted for the 2-for-1 stock split in June 2004.
For the NQSOs and SARs, the exercise price of each NQSO or SAR generally equaled the fair market value of HEI’s stock on or near the date of grant. NQSOs, SARs and related dividend equivalents issued in the form of stock awarded prior to and through 2004 generally become exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. The 2005 SARs awards, which have a ten year exercise life, generally become exercisable at the end of four years (i.e., cliff vesting) with the related dividend equivalents issued in the form of stock on an annual basis. Accelerated vesting is provided in the event of a change-in-control or upon retirement. NQSOs and SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.
Restricted stock grants generally become unrestricted three to five years after the date of grant and restricted stock compensation expense has been recognized in accordance with the fair value basedvalue-based measurement method of accounting.
The Company recorded share-based compensation expense in the first nine monthsquarters of 2007 and 2006 and 2005 of $1.3$0.3 million and $3.3$0.6 million, respectively. In each of the third quarters of 2006 and 2005, the Company recorded share-based compensation expense of $0.4 million. The Company recorded related income tax benefit (including a valuation allowance due to limits on the deductibility of executive compensation) on share-based compensation expense in the first nine monthsquarters of 2007 and 2006 and 2005 of $0.6$0.1 million and $1.0$0.2 million, respectively. In each of the third quarters of 2006 and 2005, the Company recorded related income tax benefits of $0.1 million. The Company has not capitalized any share-based compensation cost.
In place of a SARs grant for 2006, the Company instead awarded restricted stock, as described under “Restricted stock.” For all share-based compensation, the estimated forfeiture rate is 1.4%.
Nonqualified stock options
Information about HEI’s NQSOs is summarized as follows:
| September 30, 2006 | Outstanding | Exercisable | ||||||||||||||||||||||||||||||||
| March 31, 2007 | March 31, 2007 | Outstanding | Exercisable | |||||||||||||||||||||||||||||||
Year of grant | Range of exercise prices | Number of options | Weighted- average remaining contractual | Weighted- average exercise price | Number of options | Weighted- average remaining contractual | Weighted- average exercise price | Range of exercise prices | Number of options | Weighted- average remaining contractual life | Weighted- average exercise price | Number of options | Weighted- average remaining contractual life | Weighted- average exercise price | ||||||||||||||||||||
| 1998 | $ | 20.50 | 6,000 | 1.5 | $ | 20.50 | 6,000 | 1.5 | $ | 20.50 | $ | 20.50 | 6,000 | 1.1 | $ | 20.50 | 6,000 | 1.1 | $ | 20.50 | ||||||||||||||
| 1999 | 17.61 - 17.63 | 65,000 | 2.8 | 17.62 | 65,000 | 2.8 | 17.62 | 17.61 - 17.63 | 65,000 | 2.3 | 17.62 | 65,000 | 2.3 | 17.62 | ||||||||||||||||||||
| 2000 | 14.74 | 52,000 | 3.6 | 14.74 | 52,000 | 3.6 | 14.74 | 14.74 | 52,000 | 3.1 | 14.74 | 52,000 | 3.1 | 14.74 | ||||||||||||||||||||
| 2001 | 17.96 | 89,500 | 4.4 | 17.96 | 89,500 | 4.4 | 17.96 | 17.96 | 89,000 | 4.0 | 17.96 | 89,000 | 4.0 | 17.96 | ||||||||||||||||||||
| 2002 | 21.68 | 150,000 | 5.4 | 21.68 | 150,000 | 5.4 | 21.68 | 21.68 | 134,000 | 4.9 | 21.68 | 134,000 | 4.9 | 21.68 | ||||||||||||||||||||
| 2003 | 20.49 | 399,500 | 5.5 | 20.49 | 320,500 | 5.2 | 20.49 | 20.49 | 294,500 | 6.0 | 20.49 | 217,000 | 6.0 | 20.49 | ||||||||||||||||||||
| $ | 14.74 –21.68 | 762,000 | 4.9 | $ | 19.79 | 683,000 | 4.8 | $ | 19.71 | $ | 14.74 – 21.68 | 640,500 | 4.8 | $ | 19.63 | 563,000 | 4.7 | $ | 19.51 | |||||||||||||||
As of December 31, 2005,2006, NQSOs outstanding totaled 929,000,660,000, with a weighted-average exercise price of $19.88.$19.68. As of September 30, 2006,March 31, 2007, NQSO shares outstanding and NQSO exercisable had an aggregate intrinsic value (including dividend equivalents) of $9.1$6.7 million and $8.3$6.1 million, respectively.
NQSO activity and statistics are summarized as follows:
| Three months ended September 30 | Nine months ended September 30 | |||||||||||||||||
Three months ended March 31 | 2007 | 2006 | ||||||||||||||||
($ in thousands, except prices) | 2006 | 2005 | 2006 | 2005 | ||||||||||||||
Shares granted | — | — | — | — | — | — | ||||||||||||
Shares forfeited | — | — | — | — | — | — | ||||||||||||
Shares expired | — | — | — | — | — | — | ||||||||||||
Shares vested | 1,000 | — | 198,500 | 277,000 | 1,500 | — | ||||||||||||
Aggregate fair value of vested shares | $ | 4 | — | $ | 916 | $ | 1,215 | $ | 7 | — | ||||||||
Shares exercised | 50,500 | 17,500 | 167,000 | 171,000 | 19,500 | 6,000 | ||||||||||||
Weighted-average exercise price | $ | 18.04 | $ | 17.93 | $ | 20.32 | $ | 18.90 | $ | 21.47 | $ | 17.31 | ||||||
Cash received from exercise | $ | 911 | $ | 314 | $ | 3,393 | $ | 3,232 | $ | 419 | $ | 104 | ||||||
Intrinsic value of shares exercised1 | $ | 758 | $ | 275 | $ | 1,931 | $ | 2,106 | $ | 142 | $ | 109 | ||||||
Tax benefit realized for the deduction of exercises | $ | 295 | $ | 119 | $ | 751 | $ | 494 | $ | 55 | $ | 42 | ||||||
Dividend equivalent shares distributed under Section 409A | 52 | — | 43,265 | — | 21,892 | 40,309 | ||||||||||||
Weighted-average Section 409A distribution price | $ | 27.72 | — | $ | 26.27 | — | $ | 26.15 | $ | 26.24 | ||||||||
Intrinsic value of shares distributed under Section 409A | $ | 1 | — | $ | 1,137 | — | $ | 572 | $ | 1,058 | ||||||||
Tax benefit realized for Section 409A distributions | $ | 1 | — | $ | 442 | — | $ | 223 | $ | 412 | ||||||||
1 | Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option. |
As of September 30, 2006,March 31, 2007, there was $0.1$0.02 million of total unrecognized compensation cost related to nonvested NQSOs and that cost is expected to be recognized over a weighted average period of seven months.in April 2007.
Stock appreciation rights
Information about HEI’s SARs is summarized as follows:
| September 30, 2006 | Outstanding | Exercisable | ||||||||||||||||||||||||||||||||
| March 31, 2007 | March 31, 2007 | Outstanding | Exercisable | |||||||||||||||||||||||||||||||
Year of grant | Range of exercise prices | Number of shares | Weighted- average remaining contractual life | Weighted- average exercise price | Number of shares SARs | Weighted- average remaining contractual life | Weighted- average exercise price | Range of exercise prices | Number of shares | Weighted- average remaining contractual life | Weighted- average exercise price | Number of shares SARs | Weighted- average remaining contractual life | Weighted- average exercise price | ||||||||||||||||||||
| 2004 | $ | 26.02 | 325,000 | 5.4 | $ | 26.02 | 235,000 | 4.5 | $ | 26.02 | $ | 26.02 | 325,000 | 4.9 | $ | 26.02 | 235,000 | 4.1 | $ | 26.02 | ||||||||||||||
| 2005 | 26.18 | 554,000 | 6.8 | 26.18 | 164,000 | 2.7 | 26.18 | 26.18 | 550,000 | 6.3 | 26.18 | 166,000 | 2.2 | 26.18 | ||||||||||||||||||||
| $ | 26.02 –26.18 | 879,000 | 6.3 | $ | 26.12 | 399,000 | 3.8 | $ | 26.09 | $ | 26.02 – 26.18 | 875,000 | 5.8 | $ | 26.12 | 401,000 | 3.3 | $ | 26.09 | |||||||||||||||
As of December 31, 2005,2006, the shares underlying SARs outstanding totaled 879,000, with a weighted-average exercise price of $26.12. As of September 30, 2006,March 31, 2007, the SARs outstanding and the SARs exercisable had an aggregate intrinsic value (including dividend equivalents) of $1.9$0.6 million and $0.7$0.2 million, respectively.
SARs activity and statistics are summarized as follows:
| Three months ended September 30 | Nine months ended September 30 | ||||||||||||||||
Three months ended March 31 | 2007 | 2006 | |||||||||||||||
($ in thousands, except prices) | 2006 | 2005 | 2006 | 2005 | |||||||||||||
Shares granted | — | — | — | 554,000 | — | — | |||||||||||
Shares forfeited | — | — | — | — | — | — | |||||||||||
Shares expired | — | — | — | — | — | — | |||||||||||
Shares vested | 4,000 | — | 317,750 | 105,250 | 6,000 | — | |||||||||||
Aggregate fair value of vested shares | $ | 24 | — | $ | 1,773 | $ | 537 | $ | 36 | — | |||||||
Shares exercised | — | — | — | 24,000 | 4,000 | — | |||||||||||
Weighted-average exercise price | — | — | — | $ | 26.02 | $ | 26.18 | — | |||||||||
Cash received from exercise | — | — | — | — | — | — | |||||||||||
Intrinsic value of shares exercised1 | — | — | — | $ | 10 | $ | 3 | — | |||||||||
Tax benefit realized for the deduction of exercises | — | — | — | $ | 4 | $ | 1 | — | |||||||||
Dividend equivalent shares distributed under Section 409A | 94 | — | 28,600 | — | 23,760 | 21,173 | |||||||||||
Weighted-average Section 409A distribution price | $ | 27.72 | — | $ | 26.37 | — | $ | 26.15 | $ | 26.24 | |||||||
Intrinsic value of shares distributed under Section 409A | $ | 3 | — | $ | 754 | — | $ | 621 | $ | 556 | |||||||
Tax benefit realized for Section 409A distributions | $ | 1 | — | $ | 293 | — | $ | 242 | $ | 216 | |||||||
1 | Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option. |
As of September 30, 2006,March 31, 2007, there was $1.2$0.9 million of total unrecognized compensation cost related to SARs and that cost is expected to be recognized over a weighted average period of 2.41.9 years.
The weighted-average fair value of each of the SARs granted during 2005 was $5.82 (at grant date). For 2005, the weighted-average assumptions used to estimate fair value include: risk-free interest rate of 4.1%, expected volatility of 18.1%, expected dividend yield of 5.9%, term of 10 years and expected life of 4.5 years. The weighted-average fair value of the SARs grant is estimated on the date of grant using a Binomial Option Pricing Model. See below for discussion of 2005 grant modification. The expected volatility is based on historical price fluctuations. The Company believes that historical volatility is appropriate based upon the Company’s business model and strategies.
Section 409A modification
As a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A), for the ninethree months ended September 30,March 31, 2007 and 2006 a total of 71,86545,652 and 61,482 dividend equivalent shares for NQSO and SAR grants were distributed to SOIP participants, including those that retired during 2006.respectively. Section 409A, which amended the rules on deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally dividend equivalents subject to Section 409A wouldwill be paid within 2 1/2 months after the end of the calendar year.
However, upon Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement rather thanor at the end of the calendar year.
As noted above, in December 2005, to comply with Section 409A, HEI modified certain provisions pertaining to the dividend equivalent rights attributable to the outstanding grants of NQSOs and SARs held by 40 employees under the 1987 HEI Stock Option and Incentive Plan, as amended. The modifications apply to the NQSOs granted in 2001, 2002, and 2003 and the SARs granted in 2004 and 2005 and in general accelerate the distribution of dividend equivalent shares earned after 2004. When a share-based award is modified, the Company recognizes the incremental compensation cost, which is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before its terms are modified.
The assumptions used to estimate fair value at the time of the Section 409A modification for the 2005 SARs include: risk-free interest rate of 4.4%, expected volatility of 14.9%, original term of 10 years and expected dividend yield of 4.6%. The expected life used at the time of modification was 4.2 years for 2005. As of December 7, 2005, the fair value of modified 2005 SARs, the fair value of original 2005 SARs and the additional compensation cost to be recognized per grant was $5.07, $4.95 and $0.12, respectively. The additional compensation cost for the Section 409A modification was not material.
Restricted stock
As of December 31, 2005, restricted stock shares outstanding totaled 41,000, with a weighted-average grant date fair value of $23.50. As of September 30, 2006, restricted stock shares outstanding totaled 91,800, with a weighted-average grant date fair value of $25.68. As of March 31, 2007, restricted stock shares outstanding totaled 100,500, with a weighted-average grant date fair value of $25.81. The grant date fair value of a grant of a restricted stock share is the closing price of HEI common stock on the date of grant.
During the first nine monthsquarter of 2006, 60,8002007, 8,700 shares of restricted stock with a fair market value of $1.6 million were granted, 10,000 shares of restricted stock with agrant date fair market value of $0.2 million were granted. No shares of restricted stock vested and no restricted stock shares were forfeited. During the first nine months of 2005, 9,000 shares of restricted stock with a fair market value of $0.2 million were granted and no restricted stock shares vested or were forfeited. During the third quarter of 2006, no restricted stock shares were granted, or forfeited and 10,000 shares of restricted stock with a fair market value of $0.2 million vested (with a realized tax benefit for tax deductions of $0.1 million). During the third quarter of 2005, no restricted stock shares of restricted stock were granted, vested or were forfeited. The tax benefit realized for the tax deductions from restricted stock dividends were immaterial for the first nine monthsquarters of 20062007 and 2005.2006.
As of September 30, 2006,March 31, 2007, there was $1.7$1.6 million of total unrecognized compensation cost related to nonvested restricted stock. The cost is expected to be recognized over a weighted-average period of 3.52.7 years.
(7) CommitmentsIn April 2007, 57,700 shares of restricted stock were granted to officers and contingencieskey employees with a grant date fair market value of $1.5 million.
| (7) | Commitments and contingencies |
See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”
(8) Cash flows
| (8) | Cash flows |
Supplemental disclosures of cash flow information
For the ninethree months ended September 30,March 31, 2007 and 2006, and 2005, the Company paid interest to non-affiliates amounting to $144$56 million and $127$39 million, respectively.
For the ninethree months ended September 30,March 31, 2007 and 2006, and 2005, the Company paid income taxes amounting to $30$3 million and $21$2 million, respectively. The difference is primarily due to the federal estimated income taxes paid in the first nine months of 2006 versus none paid in the same period of 2005 (as a result of an overpayment credit from the 2004 tax return applied to the 2005 estimated federal income taxes). This difference was partly offset, however, by additional payments made in the first nine months of 2005 for bank franchise taxes and federal income taxes for a settlement of prior year taxes.
Supplemental disclosures of noncash activities
Noncash increases in common stock for director and officer compensatory plans of the Company were $2.3$0.5 million and $4.6$0.8 million for the ninethree months ended September 30,March 31, 2007 and 2006, and 2005, respectively.
InUnder the third quarter ofHEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $5 million and nil for the three months ended March 31, 2007 and 2006, respectively. From March 23, 2004 to March 5, 2007, HEI satisfied the Company completed the settlement of net taxes and interest due to the IRS for tax years 1994 through 2002. In a non-cash transaction in the third quarter of 2006, a $30 million deposit made by
the Company in 2005 with the IRS was applied to the net liabilities of $10 million for tax years 1994 through 2002 and $18 million for tax year 2005 with an immaterial net income impact. The remaining $2 millionrequirements of the 2005 deposit was refunded to the Company.
Revised cash flows from discontinued operations
From December 31, 2005, the Company will separately disclose the operating, investing and financing portions of the cash flows attributable to its discontinued operations, which were previously reported on a combined basis as a single amount. For the first nine months of 2006 and 2005, there were no cash flows from investing and financing activities from the Company’s discontinued operations.
(9) Recent accounting pronouncements and interpretations
For a discussion of a recent accounting pronouncement regarding variable interest entities (VIEs), see Note 7 of HECO’s “Notes to Consolidated Financial Statements.”
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. 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 adopted the provisions of SFAS No. 123 (revised 2004) using a modified prospective applicationHEI DRIP and the guidance in SAB No. 107 on January 1, 2006 andHawaiian Electric Industries Retirement Savings Plan (HEIRSP) by acquiring for cash its common shares through open market purchases rather than the net income impactissuance of adoption was immaterial. Sinceadditional shares. On March 6, 2007, it began satisfying those requirements by the Company adopted the recognition provisionsissuance of SFAS No. 123 as of January 1, 2002, the only expense recognition change the Company made upon adoption of SFAS No. 123 (revised 2004) was how it accounts for forfeitures. The average annual forfeiture rate for 1996 through 2005 was 1.4% and historically has not been significant. In accordance with SFAS No. 123 (revised 2004), expanded disclosures are included in Note 6.additional shares.
| (9) | Recent accounting pronouncements and interpretations |
Accounting for certain hybrid financial instruments
In March 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. The Company will adoptadopted SFAS No. 155 on January 1, 2007. Because2007, as required, and the adoption had no impact on the Company’s results of adopting SFAS No. 155 will be dependent on future events and circumstances, management cannot predict such impact.operations, financial condition or liquidity.
Accounting for servicing of financial assets
In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 156 requires an entity to recognize, in certain situations, a servicing asset or servicing liability when it undertakes an obligation to service a financial asset, requires all separately recognized servicing assets and liabilities to be initially measured at fair value (if practicable), permits alternative subsequent measurement methods for each class of servicing assets and liabilities, permits a limited one-time reclassification of available-for-sale securities to trading securities at adoption, requires separate presentation of servicing assets and liabilities subsequently measured at fair value in the balance sheet and requires additional disclosures. SFAS No. 156 must be adopted by the beginning of the first fiscal year that begins after September 15, 2006. The Company will adoptadopted SFAS No. 156 on January 1, 2007. Management does not expect that2007, as required, continuing to use the amortization method, and the adoption had no impact of adoption will be material toon the Company’s results of operations, financial statements.condition or liquidity.
Accounting for uncertainty in income taxes
In June 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate resolution with tax authorities) for the financial statement recognition and measurement of aan income tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006.2006, and, accordingly, the Company adopted FIN 48 in the first quarter of 2007. The impact to the Company will adopt FIN No. 48 onwas a reclassification of certain deferred tax
liabilities to a liability for tax uncertainties and a charge of $0.2 million to retained earnings as of January 1, 2007. Management has not yet determined2007 for the impactcumulative effect of adoption on the Company’s results of operations, financial condition or liquidity.FIN 48. Also see Note 10.
Cash flows relating to income taxes generated by a leveraged lease transaction
In July 2006, the FASB issued FASB Staff Position (FSP) No. 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” which requires a recalculation of the rate of return and the allocation of income to positive investment years from the inception of the lease if there is a change or projected change in the timing of cash flows relating to income taxes generated by the leveraged lease. The amounts comprising the net leveraged lease investment would be adjusted to the recalculated amounts, and the change in the net investment would be recognized as a gain or loss in the year in which the projected cash flows and/or assumptions change. FSP No. 13-2 is effective for fiscal years beginning after December 15, 2006. The Company will adoptadopted FSP No. 13-2 on January 1, 2007. Based on current circumstances,2007 and the adoption of FSP No. 13-2 will havehad no effectimpact on the Company’s results of operations, financial statements.condition or liquidity.
Fair value measurements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies to fair value measurements that are already required or permitted under existing accounting pronouncements with some exceptions. SFAS No. 157 retains the exchange price notion in defining fair value and clarifies that the exchange price is the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability. It emphasizes that fair value is a market-based, not an entity-specific, measurement based upon the assumptions that market participants would use in pricing an asset or liability. As a basis for considering assumptions in fair value measurements, SFAS No. 157 establishes a hierarchy that gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). SFAS No. 157 expands disclosures about the use of fair value, including disclosure of the level within the hierarchy in which the fair value measurements fall and the effect of the measurements on earnings (or changes in net assets) for the period. SFAS No. 157 must be adopted by the first quarter of the fiscal year beginning after November 15, 2007. The Company plans to adopt SFAS No. 157 on January 1, 2008. Management has not yet determined thewhat impact, of adoption, if any, the adoption of SFAS No. 157 will have on the Company’s results of operations, financial condition or liquidity.
Effects of prior year misstatements
In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” which provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. In order to evaluate whether an error is material based on all relevant quantitative and qualitative factors, SAB No. 108 requires the quantification of misstatements using both the income-statement (rollover) and balance sheet (iron curtain) approaches. If the Company does not elect to restate its financial statements for the material misstatements that arise in connection with application of the guidance in SAB No. 108, then for fiscal years ending after November 15, 2006, it must recognize the cumulative effect of applying SAB No. 108 in the current year beginning balances of the affected assets and liabilities with a corresponding adjustment to the current year opening balance in retained earnings. The Company will adopt SAB No. 108 in the
fourth quarter of 2006. Management expects that the impact of adoption, if any, will be immaterial to the Company’s results of operations, financial condition or liquidity.statements.
Planned major maintenance activities
In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which eliminates the accrue-in-advance method of accounting for planned major maintenance activities. As a result of the elimination, three methods are currently permitted: (1) direct expensing, (2) built-in overhaul, and (3) deferral. FSP AUG AIR-1 must be adopted by the first fiscal year beginning after December 15, 2006. The Company will adoptadopted FSP AUG AIR-1 on January 1, 2007. Because2007 and the Company uses the direct expensing method for planned major maintenance activities, management does not expect anyadoption had no impact of adoption on the Company’s results of operations, financial condition or liquidity.liquidity because the Company has used and continues to use the direct expensing method.
Defined benefit pensionThe fair value option for financial assets and other postretirement plansfinancial liabilities
In September 2006,February 2007, the FASB issued SFAS No. 158, “Employers’ Accounting159, “The Fair Value Option for Defined Benefit PensionFinancial Assets and Other Postretirement Plans,Financial Liabilities, Including an amendment of FASB StatementsStatement No. 87, 88, 106,115.” SFAS No. 159 permits entities to choose to measure many financial instruments and 132(R),”certain other items at fair value, which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans. Employers will recognize actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS Nos. 87 and 106 when recognizing a plan’s funded status,should improve financial reporting by providing entities with the offsetopportunity to accumulated other comprehensive income (AOCI)mitigate volatility in stockholders’ equity.reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 158159 must be adopted in fiscal years ending after December 15, 2006. Accordingly, theby January 1, 2008. The Company willplans to adopt SFAS No. 158159 on December 31, 2006.January 1, 2008. Management has not yet determined what impact, if any, the adoption of SFAS No. 159 will have on the Company’s financial statements.
The Company sponsors defined benefit plans (with fiscal year-end measurement dates) and expects
| (10) | Income taxes |
In general, prior to report increased liabilities at year end, with corresponding charges to AOCI. The actual amount recorded will be dependent on numerous factors, including the year-end discount rate assumption, asset returns experienced in 2006, any changes to actuarial assumptions or plan provisions, and contributions made byJanuary 1, 2007, the Company to the plans during 2006.
If SFAS No. 158 were applied as of December 31, 2005, the Company would have had to recognize additional pension(except for ASB) recorded known interest and penalties on income taxes in “Interest expense – other than bank” (in “Interest and other postretirement benefit obligationscharges” in HECO’s consolidated statements of approximately $184 million and write off $122 million of pension-related intangible and prepaid assets as of December 31, 2005. The Company would also have been required to record a deferred tax benefit associated with the temporary differences between the liabilities recognized for book and tax purposes. The net charge to AOCI would have been $187 million ($4 million, $170 million and $13 million for HEI corporate, consolidated HECOincome) and ASB respectively) asrecorded known interest and penalties on income taxes in “Expenses—Bank” (in “Other expense” in ASB’s consolidated statements of December 31, 2005.
The electric utilities plan to update their application inincome). Since the AOCI Docket to take into account SFAS No. 158 in seeking PUC approval to record as a regulatory asset the amount that would otherwise be charged against stockholders’ equity. If their request is granted, the utilities would seek to include the regulatory asset in their rate bases in their rate cases. To the extentadoption of FIN 48, the electric utilities determine that it is probable that the additional liabilities will be recoverable through rates they charge, a regulatory asset would be recorded and there would be no material impact of adopting SFAS No. 158ASB record all (potential and known) interest and penalties on stockholders’ equity or net income. If the PUC were not to grant regulatory asset treatmentincome taxes in the AOCI Docket as updated for SFAS No. 158, there could be a material negative impact to stockholders’ equity. Although there would not be an immediate impact on net income due to the non-regulatory asset treatment, if the electric utilities are required to record substantial charges against stockholders’ equity, their reported returns on rate base“Interest and returns on average common equity could increase, which could impact the rates they are allowed to chargeother charges” and ultimately result in reduced revenues and lower earnings. Further potential negative impacts include the fact that the consolidated adjusted debt to capitalization and interest coverage ratios of“Other expense,” respectively, but the Company records such amounts in “Interest expense – other than on deposit liabilities and the electric utilities may deteriorate, which could result in security ratings downgrades and difficulty or greater expense in obtaining future financing. If the electric utilities are not allowed regulatory asset treatment for the amounts that would be charged to AOCI, however, they still would seek a return on their prepaid pension assets (by inclusion in rate base) in their respective rate cases.
(10) Income taxes
Inother bank borrowings.” For the first quarter of 2005,2006, interest accrued on income taxes was insignificant. For the Company recorded a $2 million reserve, net of taxes, for interest the Company might incur on the potential taxes related to the disputed timing of dividend income recognition because of a change in ASB’s 2000 and 2001 tax year-ends. In the secondfirst quarter of 2005, the Company made a $302007, $0.3 million deposit primarily to stop the further accrual of interest on income taxes was reflected in “Interest expense – other than on deposit liabilities and bank borrowings.”
As of January 1, 2007, the potential taxestotal amount of accrued interest and penalties related to uncertain tax positions and recognized on the disputed timingbalance sheet was $1.6 million.
As of dividend income recognition. Also inJanuary 1, 2007, the second quartertotal amount of 2005, $1unrecognized tax benefits was $11.3 million, and of income taxes and interest payable, net of taxes, were reversedthis amount, $0.6 million, if recognized, would affect the Company’s effective tax rate. Management concluded that it is reasonably possible that the unrecognized tax benefits will significantly decrease within the next 12 months due to the resolution of other audit issues withunder examination by the IRS. InInternal Revenue Service. Management cannot estimate the fourth quarterrange of 2005, additional IRS audit issues were resolved, resulting in the reversal of $1 million of interest, net of taxes.reasonably possible change.
As of September 30,January 1, 2007, the tax years 2003 to 2006 remain subject to examination by the Company had reserved $1 million, netInternal Revenue Service and Department of tax effects, for potential tax issues and related interest. Although not probable, adverse developments on potential tax issues could resultTaxation of the State of Hawaii. HEIII, which owns leveraged lease investments in additional chargesother states, is also subject to net income in the future. Based on information currently available, the Company believes it has adequately provided for potential income tax issues with federal andexamination by those state tax authorities for tax years 2003 to 2006.
The Company’s effective tax rate for the first quarter of 2007 was 28%, compared to an effective tax rate for the first quarter of 2006 of 38%. The lower effective tax rate was primarily due to the impact of state tax credits recognized against a smaller income tax expense base and related interest,the acceleration of the state tax credits associated with the write-off of a portion of CT-4 and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.CT-5 costs.
(11) Investment in Hoku Scientific, Inc.
| (11) | Sale of shares in Hoku Scientific, Inc. |
As of September 30, 2006, HEI Properties, Inc. (HEIPI) held shares of Hoku Scientific, Inc. (Hoku), a materials science company focused on clean energy technologies. Prior to August 5, 2005, the investment had been accounted for under the cost method. Hoku went public and sharesShares of Hoku began trading on the Nasdaq Stock Market on August 5, 2005. Since August 5, 2005 Hoku shares have been considered marketable and since then HEIPI hashad classified theits Hoku shares as trading securities, carried at fair value with changes in fair value recorded in earnings. HEIPI began selling Hoku stock in February 2006 when its lock-up agreement expired. In the three and nine months ended September 30,first quarter of 2006, HEIPI recognized a $0.4 million gain and a $1.3 million loss (unrealized and realized, net of taxes), respectively, on theits Hoku shares. As of September 30,December 31, 2006, HEIPI had sold 27% of its Hoku shares and carried its remaining investment in Hoku shares at $2$1.2 million. In January 2007, HEIPI sold its remaining Hoku shares for a net after-tax gain of $0.9 million.
(12) Credit agreements
| (12) | Credit agreement |
Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Any draws on the facility bear interest, at the option of HEI, at either the “Adjusted LIBO Rate” plus 50 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on undrawn commitments areThe annual fee is 10 basis points.points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Senior Debt Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2.5 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1) would result in a commitment fee decrease of 2 basis points and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions which must be met in order to draw on it, such as the credit facility, including the continued accuracy of HEI’scertain of its representations at the time of a draw and compliance with its covenants.covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s
failure to maintain its nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less and “Consolidated Net Worth” of $850 million,financial ratio, as defined in itsthe agreement, or meet other requirements will result in an event of default.
Also effective April 3, 2006, For example, under the agreement, it is an event of default if HEI entered intofails to maintain a $75nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 27% as of March 31, 2007, as calculated under the agreement) and “Consolidated Net Worth” of $850 million bilateral revolving unsecured credit agreement with Merrill Lynch Bank USA, which was subsequently terminated effective August 11, 2006.
The(Net Worth of $1.3 billion as of March 31, 2007, as calculated under the agreement), if there is a “Change in Control” of HEI, if any event or condition occurs that results in any “Material Indebtedness” of HEI being subject to acceleration prior to its scheduled maturity, if any “Material Subsidiary Indebtedness” actually becomes due prior to its scheduled maturity, or if ASB fails to remain well capitalized and to maintain specified minimum capital ratios. HEI’s syndicated credit facility is maintained to support the issuance of commercial paper, but may also may be drawn to make investments in and advances to its subsidiaries, and for the Company’s working capital and general corporate purposes. The facility contains provisions for revised pricing in the event of a ratings change and replaced HEI’s four bilateral bank lines of credit totaling $80 million, which were terminated concurrently with the effectiveness of the new facility. The Company used the April 3, 2006 facilities to support the issuance of commercial paper to temporarily refinance $100 million of its Series C medium-term notes, which matured on April 10, 2006. On August 8, 2006, HEI completed the sale of $100 million of 6.141% Medium-Term Notes, Series D due August 15, 2011, the proceeds of which were ultimately used to reduce HEI’s outstanding commercial paper as it matured. As of October 31, 2006,May 1, 2007, the $100 million credit facility remained undrawn.
See Note 910 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of HECO’s credit facility.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Balance Sheets (unaudited)
(in thousands, except par value) | September 30, 2006 | December 31, 2005 | ||||||
Assets | ||||||||
Utility plant, at cost | ||||||||
Land | $ | 35,035 | $ | 33,034 | ||||
Plant and equipment | 3,874,525 | 3,749,386 | ||||||
Less accumulated depreciation | (1,534,682 | ) | (1,456,537 | ) | ||||
Plant acquisition adjustment, net | 106 | 145 | ||||||
Construction in progress | 160,300 | 147,756 | ||||||
Net utility plant | 2,535,284 | 2,473,784 | ||||||
Current assets | ||||||||
Cash and equivalents | 4,418 | 143 | ||||||
Customer accounts receivable, net | 139,808 | 123,895 | ||||||
Accrued unbilled revenues, net | 98,689 | 91,321 | ||||||
Other accounts receivable, net | 6,037 | 14,761 | ||||||
Fuel oil stock, at average cost | 95,970 | 85,450 | ||||||
Materials and supplies, at average cost | 30,297 | 26,974 | ||||||
Prepaid pension benefit cost | 91,292 | 106,318 | ||||||
Other | 9,890 | 8,584 | ||||||
Total current assets | 476,401 | 457,446 | ||||||
Other long-term assets | ||||||||
Regulatory assets | 110,335 | 110,718 | ||||||
Unamortized debt expense | 13,896 | 14,361 | ||||||
Other | 29,356 | 25,152 | ||||||
Total other long-term assets | 153,587 | 150,231 | ||||||
| $ | 3,165,272 | $ | 3,081,461 | |||||
Capitalization and liabilities | ||||||||
Capitalization | ||||||||
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares | $ | 85,387 | $ | 85,387 | ||||
Premium on capital stock | 299,186 | 299,186 | ||||||
Retained earnings | 687,245 | 654,686 | ||||||
Common stock equity | 1,071,818 | 1,039,259 | ||||||
Cumulative preferred stock – not subject to mandatory redemption | 34,293 | 34,293 | ||||||
Long-term debt, net | 766,137 | 765,993 | ||||||
Total capitalization | 1,872,248 | 1,839,545 | ||||||
Current liabilities | ||||||||
Short-term borrowings–nonaffiliates | 145,080 | 136,165 | ||||||
Accounts payable | 107,348 | 122,201 | ||||||
Interest and preferred dividends payable | 15,905 | 9,990 | ||||||
Taxes accrued | 163,896 | 133,583 | ||||||
Other | 36,610 | 37,132 | ||||||
Total current liabilities | 468,839 | 439,071 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes | 200,523 | 208,374 | ||||||
Regulatory liabilities | 235,480 | 219,204 | ||||||
Unamortized tax credits | 57,373 | 55,327 | ||||||
Other | 65,070 | 63,677 | ||||||
Total deferred credits and other liabilities | 558,446 | 546,582 | ||||||
Contributions in aid of construction | 265,739 | 256,263 | ||||||
| $ | 3,165,272 | $ | 3,081,461 | |||||
See accompanying “Notes to Consolidated Financial Statements” for HECO.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Income (unaudited)
Three months ended September 30 | Nine months ended September 30 | |||||||||||||||
(in thousands, except for ratio of earnings to fixed charges) | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Operating revenues | $ | 568,236 | $ | 489,877 | $ | 1,545,557 | $ | 1,292,374 | ||||||||
Operating expenses | ||||||||||||||||
Fuel oil | 227,288 | 182,663 | 594,940 | 447,064 | ||||||||||||
Purchased power | 138,758 | 122,086 | 378,916 | 329,671 | ||||||||||||
Other operation | 46,612 | 41,974 | 136,565 | 125,084 | ||||||||||||
Maintenance | 23,653 | 21,141 | 63,087 | 58,916 | ||||||||||||
Depreciation | 32,539 | 30,655 | 97,614 | 92,297 | ||||||||||||
Taxes, other than income taxes | 51,985 | 44,990 | 142,726 | 120,254 | ||||||||||||
Income taxes | 14,665 | 13,754 | 38,909 | 33,785 | ||||||||||||
| 535,500 | 457,263 | 1,452,757 | 1,207,071 | |||||||||||||
Operating income | 32,736 | 32,614 | 92,800 | 85,303 | ||||||||||||
Other income | ||||||||||||||||
Allowance for equity funds used during construction | 1,838 | 1,406 | 4,974 | 3,675 | ||||||||||||
Other, net | 1,379 | 1,191 | 2,809 | 2,811 | ||||||||||||
| 3,217 | 2,597 | 7,783 | 6,486 | |||||||||||||
Income before interest and other charges | 35,953 | 35,211 | 100,583 | 91,789 | ||||||||||||
Interest and other charges | ||||||||||||||||
Interest on long-term debt | 10,777 | 10,731 | 32,331 | 32,296 | ||||||||||||
Amortization of net bond premium and expense | 565 | 545 | 1,651 | 1,658 | ||||||||||||
Other interest charges | 1,285 | 1,408 | 5,424 | 3,183 | ||||||||||||
Allowance for borrowed funds used during construction | (838 | ) | (558 | ) | (2,259 | ) | (1,460 | ) | ||||||||
Preferred stock dividends of subsidiaries | 228 | 228 | 686 | 686 | ||||||||||||
| 12,017 | 12,354 | 37,833 | 36,363 | |||||||||||||
Income before preferred stock dividends of HECO | 23,936 | 22,857 | 62,750 | 55,426 | ||||||||||||
Preferred stock dividends of HECO | 270 | 270 | 810 | 810 | ||||||||||||
Net income for common stock | $ | 23,666 | $ | 22,587 | $ | 61,940 | $ | 54,616 | ||||||||
Ratio of earnings to fixed charges (SEC method) | 3.36 | 3.24 | ||||||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Retained Earnings (unaudited)
Three months ended September 30 | Nine months ended September 30 | ||||||||||||||
(in thousands) | 2006 | 2005 | 2006 | 2005 | |||||||||||
Retained earnings, beginning of period | $ | 663,579 | $ | 645,586 | $ | 654,686 | $ | 632,779 | |||||||
Net income for common stock | 23,666 | 22,587 | 61,940 | 54,616 | |||||||||||
Common stock dividends | — | (14,733 | ) | (29,381 | ) | (33,955 | ) | ||||||||
Retained earnings, end of period | $ | 687,245 | $ | 653,440 | $ | 687,245 | $ | 653,440 | |||||||
Three months ended March 31 | 2007 | 2006 | ||||||
| (in thousands, except ratio of earnings to fixed charges) | ||||||||
Operating revenues | $ | 446,797 | $ | 473,971 | ||||
Operating expenses | ||||||||
Fuel oil | 159,929 | 175,338 | ||||||
Purchased power | 111,516 | 117,720 | ||||||
Other operation | 47,193 | 42,019 | ||||||
Maintenance | 27,336 | 17,052 | ||||||
Depreciation | 34,267 | 32,533 | ||||||
Taxes, other than income taxes | 42,547 | 44,523 | ||||||
Income taxes | 4,506 | 13,224 | ||||||
| 427,294 | 442,409 | |||||||
Operating income | 19,503 | 31,562 | ||||||
Other income (loss) | ||||||||
Allowance for equity funds used during construction | 1,232 | 1,548 | ||||||
Other, net | (6,198 | ) | 909 | |||||
| (4,966 | ) | 2,457 | ||||||
Income before interest and other charges | 14,537 | 34,019 | ||||||
Interest and other charges | ||||||||
Interest on long-term debt | 11,496 | 10,778 | ||||||
Amortization of net bond premium and expense | 546 | 543 | ||||||
Other interest charges | 2,141 | 1,913 | ||||||
Allowance for borrowed funds used during construction | (598 | ) | (702 | ) | ||||
Preferred stock dividends of subsidiaries | 229 | 229 | ||||||
| 13,814 | 12,761 | |||||||
Income before preferred stock dividends of HECO | 723 | 21,258 | ||||||
Preferred stock dividends of HECO | 270 | 270 | ||||||
Net income for common stock | $ | 453 | $ | 20,988 | ||||
Ratio of earnings to fixed charges (SEC method) | .99 | 3.38 | ||||||
HEI owns all the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO isare not meaningful.
See accompanying “Notes to Consolidated Financial Statements” for HECO.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Cash FlowsBalance Sheets (unaudited)
Nine months ended September 30 | 2006 | 2005 | ||||||
| (in thousands) | ||||||||
Cash flows from operating activities | ||||||||
Income before preferred stock dividends of HECO | $ | 62,750 | $ | 55,426 | ||||
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities | ||||||||
Depreciation of property, plant and equipment | 97,614 | 92,297 | ||||||
Other amortization | 5,907 | 6,675 | ||||||
Deferred income taxes | (7,851 | ) | 17,935 | |||||
Tax credits, net | 2,990 | 1,800 | ||||||
Allowance for equity funds used during construction | (4,974 | ) | (3,675 | ) | ||||
Changes in assets and liabilities | ||||||||
Increase in accounts receivable | (7,189 | ) | (14,938 | ) | ||||
Increase in accrued unbilled revenues | (7,368 | ) | (11,153 | ) | ||||
Increase in fuel oil stock | (10,520 | ) | (19,208 | ) | ||||
Increase in materials and supplies | (3,323 | ) | (3,121 | ) | ||||
Decrease in prepaid pension benefit cost | 15,026 | 5,400 | ||||||
Increase in regulatory assets | (2,296 | ) | (2,815 | ) | ||||
Decrease in accounts payable | (14,853 | ) | (970 | ) | ||||
Increase in taxes accrued | 30,313 | 10,616 | ||||||
Changes in other assets and liabilities | (2,719 | ) | (9,138 | ) | ||||
Net cash provided by operating activities | 153,507 | 125,131 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (137,345 | ) | (142,573 | ) | ||||
Contributions in aid of construction | 13,227 | 10,274 | ||||||
Other | 407 | 1,476 | ||||||
Net cash used in investing activities | (123,711 | ) | (130,823 | ) | ||||
Cash flows from financing activities | ||||||||
Common stock dividends | (29,381 | ) | (33,955 | ) | ||||
Preferred stock dividends | (810 | ) | (810 | ) | ||||
Proceeds from issuance of long-term debt | — | 58,525 | ||||||
Repayment of long-term debt | — | (47,000 | ) | |||||
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less | 8,915 | 36,433 | ||||||
Other | (4,245 | ) | (4,925 | ) | ||||
Net cash provided by (used in) financing activities | (25,521 | ) | 8,268 | |||||
Net increase in cash and equivalents | 4,275 | 2,576 | ||||||
Cash and equivalents, beginning of period | 143 | 327 | ||||||
Cash and equivalents, end of period | $ | 4,418 | $ | 2,903 | ||||
(in thousands, except par value) | March 31, 2007 | December 31, 2006 | ||||||
Assets | ||||||||
Utility plant, at cost | ||||||||
Land | $ | 35,288 | $ | 35,242 | ||||
Plant and equipment | 4,009,677 | 4,002,929 | ||||||
Less accumulated depreciation | (1,581,161 | ) | (1,558,913 | ) | ||||
Plant acquisition adjustment, net | 80 | 93 | ||||||
Construction in progress | 106,396 | 95,619 | ||||||
Net utility plant | 2,570,280 | 2,574,970 | ||||||
Current assets | ||||||||
Cash and equivalents | 12,414 | 3,859 | ||||||
Customer accounts receivable, net | 110,656 | 125,524 | ||||||
Accrued unbilled revenues, net | 77,215 | 92,195 | ||||||
Other accounts receivable, net | 7,173 | 4,423 | ||||||
Fuel oil stock, at average cost | 66,715 | 64,312 | ||||||
Materials and supplies, at average cost | 32,466 | 30,540 | ||||||
Other | 9,274 | 9,695 | ||||||
Total current assets | 315,913 | 330,548 | ||||||
Other long-term assets | ||||||||
Regulatory assets | 117,078 | 112,349 | ||||||
Unamortized debt expense | 16,044 | 13,722 | ||||||
Other | 31,239 | 31,545 | ||||||
Total other long-term assets | 164,361 | 157,616 | ||||||
| $ | 3,050,554 | $ | 3,063,134 | |||||
Capitalization and liabilities | ||||||||
Capitalization | ||||||||
Common stock, $6 2/3 par value, authorized 50,000 shares; outstanding 12,806 shares | $ | 85,387 | $ | 85,387 | ||||
Premium on capital stock | 299,214 | 299,214 | ||||||
Retained earnings | 700,085 | 700,252 | ||||||
Accumulated other comprehensive loss, net of income tax benefits | (124,689 | ) | (126,650 | ) | ||||
Common stock equity | 959,997 | 958,203 | ||||||
Cumulative preferred stock – not subject to mandatory redemption | 34,293 | 34,293 | ||||||
Long-term debt, net | 858,144 | 766,185 | ||||||
Total capitalization | 1,852,434 | 1,758,681 | ||||||
Current liabilities | ||||||||
Short-term borrowings–nonaffiliates | 47,242 | 113,107 | ||||||
Accounts payable | 100,037 | 102,512 | ||||||
Interest and preferred dividends payable | 14,219 | 10,645 | ||||||
Taxes accrued | 115,221 | 152,182 | ||||||
Other | 33,286 | 43,120 | ||||||
Total current liabilities | 310,005 | 421,566 | ||||||
Deferred credits and other liabilities | ||||||||
Deferred income taxes | 106,418 | 118,055 | ||||||
Regulatory liabilities | 245,440 | 240,619 | ||||||
Unamortized tax credits | 57,743 | 57,879 | ||||||
Other | 201,015 | 189,606 | ||||||
Total deferred credits and other liabilities | 610,616 | 606,159 | ||||||
Contributions in aid of construction | 277,499 | 276,728 | ||||||
| $ | 3,050,554 | $ | 3,063,134 | |||||
See accompanying “Notes to Consolidated Financial Statements” for HECO.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholder’s Equity (unaudited)
Notes
| Common stock | Premium on capital stock | Retained earnings | Accumulated loss | Total | ||||||||||||||||
(in thousands, except per share amounts) | Shares | Amount | ||||||||||||||||||
Balance, December 31, 2006 | 12,806 | $ | 85,387 | $ | 299,214 | $ | 700,252 | $ | (126,650 | ) | $ | 958,203 | ||||||||
Comprehensive income: | ||||||||||||||||||||
Net income | — | — | — | 453 | — | 453 | ||||||||||||||
Defined benefit pension plans - amortization | — | — | — | — | 1,961 | 1,961 | ||||||||||||||
Comprehensive income | — | — | — | 453 | 1,961 | 2,414 | ||||||||||||||
Adjustment to initially apply FIN 48 | — | — | — | (620 | ) | —�� | (620 | ) | ||||||||||||
Balance, March 31, 2007 | 12,806 | $ | 85,387 | $ | 299,214 | $ | 700,085 | $ | (124,689 | ) | $ | 959,997 | ||||||||
Balance, December 31, 2005 | 12,806 | $ | 85,387 | $ | 299,214 | $ | 654,686 | $ | (28 | ) | $ | 1,039,259 | ||||||||
Net income | — | — | — | 20,988 | — | 20,988 | ||||||||||||||
Common stock dividends | — | — | — | (13,640 | ) | — | (13,640 | ) | ||||||||||||
Balance, March 31, 2006 | 12,806 | $ | 85,387 | $ | 299,214 | $ | 662,034 | $ | (28 | ) | $ | 1,046,607 | ||||||||
See accompanying “Notes to Consolidated Financial Statements” for HECO.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (unaudited)
Three months ended March 31 | 2007 | 2006 | ||||||
| (in thousands) | ||||||||
Cash flows from operating activities | ||||||||
Income before preferred stock dividends of HECO | $ | 723 | $ | 21,258 | ||||
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities | ||||||||
Depreciation of property, plant and equipment | 34,267 | 32,533 | ||||||
Other amortization | 1,306 | 1,678 | ||||||
Writedown of utility plant | 11,701 | — | ||||||
Deferred income taxes | (8,166 | ) | (4,390 | ) | ||||
Tax credits, net | 583 | 1,229 | ||||||
Allowance for equity funds used during construction | (1,232 | ) | (1,548 | ) | ||||
Changes in assets and liabilities | ||||||||
Decrease in accounts receivable | 12,118 | 16,330 | ||||||
Decrease in accrued unbilled revenues | 14,980 | 9,913 | ||||||
Increase in fuel oil stock | (2,403 | ) | (7,833 | ) | ||||
Increase in materials and supplies | (1,926 | ) | (1,821 | ) | ||||
Increase in regulatory assets | (1,603 | ) | (1,119 | ) | ||||
Decrease in accounts payable | (2,475 | ) | (6,736 | ) | ||||
Decrease in taxes accrued | (36,961 | ) | (19,472 | ) | ||||
Changes in other assets and liabilities | 7,706 | 9,445 | ||||||
Net cash provided by operating activities | 28,618 | 49,467 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (34,822 | ) | (43,079 | ) | ||||
Contributions in aid of construction | 2,495 | 6,623 | ||||||
Other | — | 108 | ||||||
Net cash used in investing activities | (32,327 | ) | (36,348 | ) | ||||
Cash flows from financing activities | ||||||||
Common stock dividends | — | (13,640 | ) | |||||
Preferred stock dividends | (270 | ) | (270 | ) | ||||
Proceeds from issuance of long-term debt | 215,679 | — | ||||||
Repayment of long-term debt | (126,000 | ) | — | |||||
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less | (65,865 | ) | 8,992 | |||||
Decrease in cash overdraft | (11,280 | ) | (6,460 | ) | ||||
Net cash provided by (used in) financing activities | 12,264 | (11,378 | ) | |||||
Net increase in cash and equivalents | 8,555 | 1,741 | ||||||
Cash and equivalents, beginning of period | 3,859 | 143 | ||||||
Cash and equivalents, end of period | $ | 12,414 | $ | 1,884 | ||||
See accompanying “Notes to Consolidated Financial Statements” for HECO.
Hawaiian Electric Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of presentation
| (1) | Basis of presentation |
The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2005, and the unaudited consolidated financial statements and the notes thereto included in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
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, 2006March 31, 2007 and December 31, 2005,2006 and the results of their operations for the three and nine months ended September 30, 2006 and 2005 and their cash flows for the ninethree months ended September 30, 2006March 31, 2007 and 2005.2006. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.
(2) Unconsolidated variable interest entities
| (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 Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) in the respective principal amounts of $10 million, (iii) making distributions on the trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are redeemable at the issuer’s option without premium beginning on March 18, 2009. The 2004 Debentures, together with the obligations of HECO, MECOHELCO and HELCOMECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECOHELCO and HELCOMECO under their respective debentures, are the sole assets of Trust III. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with FIN 46R, “Consolidation of Variable Interest Entities.” Trust III’s balance sheets as of September 30, 2006March 31, 2007 and December 31, 20052006 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for ninethree months ended September 30,March 31, 2007 and 2006 and 2005 each consisted of $2.5$0.8 million of interest income received from the 2004 Debentures; $2.4$0.8 million of distributions to holders of the Trust Preferred Securities; and $0.1 million$25,000 of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment
of interest on any of their 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.
Purchase power agreements
As of September 30, 2006,March 31, 2007, HECO and its subsidiaries had six purchase power agreements (PPAs)PPAs for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller IPPsindependent power producers (IPPs) and Schedule Q providers that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the ninethree months ended September 30, 2006March 31, 2007 totaled $379$112 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $98$35 million, $137$35 million, $52$15 million and $32$8 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.
Under FIN 46R, an enterprise with an interest in a VIEvariable interest entity (VIE) or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.
HECO has reviewed its significant PPAs and determined in 2004 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 to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPOWER) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of FIN 46R, and HECO was unable to apply FIN 46R to these IPPs.
As required under FIN 46R, HECO has continued after 2004 its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006 and 2006,2007, 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, except that Kalaeloa (see below) and Kaheawa Wind Power, LLC (KWP) have now provided their information (see below).information. Management has concluded that MECO does not have to consolidate KWP (which began selling power to MECO in June 2006 from its 30 MW windfarm) as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.
If the requested information is ultimately received from the other IPPs, a possible outcome of future analysis is the consolidation of an IPPone or more of such IPPs in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities, and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”
Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, 2) a fuel additives cost component and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to 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 Qualifying Facility under the Public Utility Regulatory Policies Act of 1978 (PURPA).
Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not absorb the majority of Kalealoa’s expected losses nor receive a majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor which affectedaffecting the level of expected losses HECO would absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s energy cost adjustment clauseECAC to the extent the fuel and fuel relatedfuel-related energy payments are not included in base energy rates.
Kaheawa Wind Power, LLC. In December 2004, MECO executed a new PPA with KWP, which completed the installation of a 30 MW windfarm on Maui and began selling power to MECO in June 2006. Management concluded that MECO does not have to consolidate KWP as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.
Apollo Energy Corporation.. In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total allowed capacity of 20.5 MW. The PUC approved the restated and amended PPA on March 10, 2005 and it became effective in April 2005. Apollo has informed HELCO that it can meet the April 2007 targetMW (targeted for commercial operation. The restatedoperation in the second quarter of 2007). In December 2005, Apollo assigned the PPA to a subsidiary, which voluntarily, unilaterally and amendedirrevocably waived and relinquished its right and benefit under the PPA requires Apollo to provide information necessary to (1) determine if HELCO must consolidate Apollo under FIN 46R, (2) consolidate Apollo, if necessary, under FIN 46R, and (3) comply with Section 404collect the floor rate for the entire term of the Sarbanes-Oxley Act of 2002 (SOX). Management is in the process of obtaining the information necessary to complete its determination of whether Apollo is a VIE and, if so, whether HELCO is the primary beneficiary.PPA. Based on information available, at this time, management currently believes the impact on consolidated HECO’s financial statements of the consolidation of Apollo, if necessary, wouldconcluded that HELCO does not be material. However, depending on the magnitude of the capital additions contemplated in the restated and amended PPA, the impact of a required consolidation of Apollo could be material. If HELCO determines it is requiredhave to consolidate Apollo as HELCO does not have a variable interest in Apollo because the financial statementsPPA does not require HELCO to absorb any variability of Apollo and such consolidation has a material effect, HECO would retrospectively apply FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”Apollo.
(3) Revenue taxes
| (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 ninethree months ended September 30,March 31, 2007 and 2006, and 2005, HECO and its subsidiaries included approximately $137$40 million and $114$42 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.
| (4) | Retirement benefits |
(4) Retirement benefits
In each ofFor the first nine monthsquarters of 20062007 and 2005,2006, HECO and its subsidiaries paid contributions of $8$0.3 million and $2.7 million, respectively, to their retirement benefit plans. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 20062007 is $10$13.4 million, compared to contributions of $18$9.8 million in 2005.2006. In addition, HECO and its subsidiaries expect to pay directly $0.5 million of benefits in 2007 compared to $0.6 million paid in 2006.
The components of net periodic benefit cost were as follows:
| Three months ended September 30 | Nine months ended September 30 | Pension benefits | Other benefits | |||||||||||||||||||||||||||||||||||||||||||||
| Pension benefits | Other benefits | Pension benefits | Other benefits | |||||||||||||||||||||||||||||||||||||||||||||
Three months ended March 31 | 2007 | 2006 | 2007 | 2006 | ||||||||||||||||||||||||||||||||||||||||||||
(in thousands) | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | ||||||||||||||||||||||||||||||||||||||||
Service cost | $ | 6,749 | $ | 5,969 | $ | 1,244 | $ | 1,280 | $ | 19,970 | $ | 17,873 | $ | 3,721 | $ | 3,824 | $ | 6,331 | $ | 6,540 | $ | 1,200 | $ | 1,235 | ||||||||||||||||||||||||
Interest cost | 12,111 | 11,675 | 2,547 | 2,694 | 36,237 | 35,113 | 7,790 | 8,114 | 12,822 | 12,039 | 2,787 | 2,659 | ||||||||||||||||||||||||||||||||||||
Expected return on plan assets | (16,208 | ) | (16,847 | ) | (2,445 | ) | (2,428 | ) | (48,257 | ) | (50,309 | ) | (7,312 | ) | (7,278 | ) | (15,224 | ) | (15,932 | ) | (2,257 | ) | (2,427 | ) | ||||||||||||||||||||||||
Amortization of unrecognized transition obligation | 1 | 1 | 782 | 782 | 2 | 2 | 2,347 | 2,347 | — | 1 | 782 | 782 | ||||||||||||||||||||||||||||||||||||
Amortization of prior service gain | (193 | ) | (192 | ) | — | — | (578 | ) | (577 | ) | — | — | (190 | ) | (193 | ) | — | — | ||||||||||||||||||||||||||||||
Recognized actuarial loss | 2,655 | 1,150 | 39 | 90 | 8,043 | 3,552 | 349 | 296 | 2,616 | 2,714 | — | 213 | ||||||||||||||||||||||||||||||||||||
Net periodic benefit cost | $ | 5,115 | $ | 1,756 | $ | 2,167 | $ | 2,418 | $ | 15,417 | $ | 5,654 | $ | 6,895 | $ | 7,303 | $ | 6,355 | $ | 5,169 | $ | 2,512 | $ | 2,462 | ||||||||||||||||||||||||
Of the net periodic benefit costs, HECO and its subsidiaries recorded expense of $16$7 million and $10$6 million in the first nine monthsquarters of 20062007 and 2005,2006, respectively, and charged the remaining amounts primarily to electric utility plant.
In an April 4, 2007 interim Decision and (5) Commitmentscontingencies
| (5) | Commitments and contingencies |
Interim increases
On September 27, 2005, the PUC issued an Interim Decision and Order (D&O)D&O in HECO’s 2005 test year rate case 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, which was implemented on September 28, 2005.
On April 4, 2007, the PUC issued an interim D&O in HELCO’s 2006 test year rate case granting a general rate increase on the island of Hawaii of 7.58%, or $24.6 million, which was implemented on April 5, 2007.
As of September 30, 2006,March 31, 2007, HECO and its subsidiaries had recognized $71$91 million of revenues with respect to interim orders ($1914 million related to interim orders regarding certain integrated resource planning costs and $52$77 million related to thean interim order with respect to Oahu’s general rate increase request based on a 2005 test year described above)year), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.
Energy cost adjustment clausesclauses.
On June 19, 2006, the PUC issued an order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the public utility and its customers, (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means, such as through fuel hedging contracts, (4) preserve, to the extent reasonably possible, the public utility’s financial integrity, and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already reviewsreviewed the automatic fuel rate adjustment clause in rate cases, Act 162 requiresrequired that these five specific factors be addressed in the record. The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s energy cost adjustment clause (ECAC)ECAC that are raised by Act 162. The parties in the rate case proceeding are HECO, the Division of Consumer Advocate,Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate), and the federal Department of Defense (DOD).
On June 30, 2006, HECO and the Consumer Advocate filed a stipulation requesting that the PUC not review the Act 162 ECAC issues in the pending rate case based on a 2005 test year since HECO’s application was filed and the
record in the proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in the rate case (subject to PUC approval) included a provision allowing the existing ECAC to be continued. On August 7, 2006, an amended stipulation was filed in substantially the same form as the June 30, 2006 stipulation, but also included the DOD. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the amended stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162 or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case based on a 2005 test year.year rate case.
The ECAC provisions of Act 162 will bewere reviewed in the HELCO rate case based on a 2006 test year as well asand will be reviewed in future rate casesthe HECO and MECO intend to file.rate cases based on 2007 test years. In the HELCO 2006 test year rate case, the filed testimony of the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. On April 4, 2007 the PUC issued an interim D&O in the HELCO 2006 test year rate case which reflected the continuation of HELCO’s ECAC, consistent with a settlement agreement reached between HELCO and the Consumer Advocate.
Management cannot predict the ultimate outcome or the effect of thesethe required Act 162 issuesanalysis on the operationcontinuation of the ECAC as it relates to the electric utilities.utilities’ existing ECACs.
HELCO power situation
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 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time these units would be converted to a 56 MW (net) dual traindual-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.” As a result of the final resolution of thevarious proceedings, described below, CT-4 and CT-5 are nowbecame operational in mid-2004, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. In May 2006, HELCO filed a rate increase application basedNoise mitigation equipment has been installed on a 2006 test year seeking to recover, among other things, CT-4 and CT-5 costs.and additional noise mitigation work is ongoing to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate the generating units at Keahole as required to meet its system needs.
Historical context.Settlement Agreement; ST-7 costs incurredInstallation 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. However, in.In 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposed 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, HELCO installed CT-4 and CT-5 and put them into limited commercial operation in May and June 2004, respectively. HELCO met the Board of Land and Natural Resources’ (BLNR’s) construction deadline of July 31, 2005. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work is planned to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate the generating units at Keahole as required to meet its system needs.
Waimana filed four appeals to the Hawaii Supreme Court from judgments of the Third Circuit Court involving (i) vacating a November 2002 Final Judgment which had halted construction, (ii) upholding the BLNR 2003 construction period extension, (iii) upholding the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the primary source of water for operating the Keahole plant and (iv) upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water.
The Hawaii Supreme Court has issued favorable decisions on all four of these appeals. In the first appeal, on May 18, 2006, the Hawaii Supreme Court affirmed the Third Circuit Court’s decision vacating the November 2002 Final Judgment which had halted construction. (As a result of the Third Circuit’s decision, construction recommenced in November 2003.) In the second and third appeals, on May 25, 2006, the Hawaii Supreme Court affirmed the Third Circuit Court’s decision on the construction period extension and dismissed the appeal of the Third Circuit’s judgment upholding the grant of the brackish water revocable permit as moot. In the fourth appeal, on September 21, 2006, the Hawaii Supreme Court affirmed the Third Circuit Court’s decision upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water.
In addition to the Supreme Court appeals, one Circuit Court matter had remained open, but it was inactive after the mediation that resulted in the Settlement Agreement. With all appeals resolved, the stipulation to dismiss this case was filed on October 5, 2006 and the case was dismissed with prejudice on October 6, 2006. Full implementation of the Settlement Agreement was conditioned on obtaining final dispositions, which have now been obtained, of all litigation pending at the time of the Settlement Agreement.
The Settlement Agreement required HELCO to undertake a number of actions 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). ManyOther than required payments to other parties to the settlement agreement, which were timely made, many of these actions had commenced well before all of the litigation was resolved.are ongoing.
HELCO’s plans for ST-7 are progressing. 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 of Hawaii Land Use Commission, which boundary amendment was approved in October 2005. In May 2006, HELCO obtained the County of Hawaii rezoning to a “General Industrial” classification, and in June 2006, received approval for a covered source permit amendment to include selective catalytic reduction with the installation of ST-7. Management believes that any other required permits will be obtained and anticipates an in-service date for ST-7 in late 2009. HELCO will now commencehas commenced engineering, design and certain construction work for ST-7. HELCO’s current cost estimate for ST-7 construction work.is approximately $92 million, of which approximately $1.2 million has been incurred through March 31, 2007.
Costs incurred; management’s evaluationCT-4 and CT-5 costs incurred. As of September 30, 2006, 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 $110 million, including $43 million for equipment and material purchases, $47 million for planning, engineering, permitting, site development and other costs and $20 million for allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date HELCO has not accrued AFUDC.million. The $110 million of costs was reclassified from construction in progress to plant and equipment in 2004 ($103 million) and 2005 ($7 million) and depreciated beginning January 1, 2005 and 2006, respectively, and HELCO sought recovery of these costs as part of its 2006 test year rate case.
In March 2007, HELCO and the Consumer Advocate reached a settlement of the year followingissues in the reclassification.
HELCO’s electric rates will not change as a resultHELCO 2006 rate case proceeding, subject to PUC approval. Under the settlement, HELCO agreed to write-off approximately $12 million of includingplant-in-service costs, net of average accumulated depreciation, relating to CT-4 and CT-5, resulting in plant and equipment unless and untilan after-tax charge to net income in the first quarter of 2007 of approximately $7 million (included in “Other, net” under “Other income (loss)” on HECO’s consolidated statement of income).
In April 2007, the PUC grants rate reliefissued an interim D&O granting HELCO a 7.58% increase in rates, which reflects the settlement agreement reached between HELCO rate case based onand the Consumer Advocate, including the agreement to write-off a 2006 test year in part to recoverportion of CT-4 and CT-5 costs. Management believes that no adjustmentHowever, the interim order does not commit the PUC to costs incurred to put CT-4 and CT-5 into service is required asaccept any of September 30, 2006. However, ifthe amounts in the interim increase in its final order. If it becomes probable that the PUC, in its final order, will disallow some or all of theadditional costs incurred costsfor CT-4 and CT-5 for rate-making purposes, HELCO maywill be required to write off a material portion of these costs.record an additional write-off.
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 kilovolt (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. However, in June 2002, an application for a permit which would have allowed construction in the originally planned route through conservation district lands was denied.
HECO continuescontinued to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. Inwas needed and, in December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $60$63 million; see costs incurred below) for a revised EOTP using a 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 for the revised EOTP has beenwas completed and the PUC issued a Finding of No Significant Impact in April 2005. Subject to obtaining PUC approval and other construction permits, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases. The first phase is currently projected to be completed in 2008, and the completion date of the second phase is being evaluated.
As of September 30, 2006, the accumulated costs recorded for the EOTP amounted to $29 million, including (i) $12 million of planning and permitting costs incurred prior to the denial in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $12 million for AFUDC. In written testimony filed in June 2005, the consultant for the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate)Advocate contended that HECO should always have planned for a project using only the 46 kV system and recommended that HECO be required to expense the $12 million incurred before 2003,prior to the denial in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, and the related AFUDCallowance for funds used during construction (AFUDC) of $5 million. 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 held an evidentiary hearing on HECO’s application in November 2005, and post-hearing briefing was completed in March 2006.
Just prior to the November 2005 evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate providing that (i) this proceeding should determine whether HECO should be given approval to expend funds for the EOTP, but with the understanding 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 (ii) 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) in which HECO seeks approval to recover the EOTP costs.
Subject to obtaining PUC approval and other construction permits, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases. The first phase is currently projected to be completed in 2009, subject to the timing of PUC approval, and the completion date of the second phase is being evaluated.
As of March 31, 2007, the accumulated costs recorded for the EOTP amounted to $31 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $14 million for AFUDC. Management believes no adjustment to project costs is required as of September 30, 2006.March 31, 2007. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.
Environmental regulation
HEI and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances.
HECO, HELCO and MECO, like other utilities, periodically identify petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of
responding to its subsidiaries’ releases identified to date will not have a material adverse effect, individually or in the aggregate, on the Company’s or consolidated HECO’s financial statements.
Additionally, current environmental laws may require HEI and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.
Honolulu Harbor investigation.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 to 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 Remedial Alternatives Analyses for the sites comprising the Iwilei Unit, which analyses will identify and recommend remedial approaches for consideration by the DOH.
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 $0.7$0.8 million has been incurredexpended through September 30,March 31, 2007). 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 the DOH.
In 2003, HECO and other Participating Parties with active operations in the Iwilei area investigated their operations to evaluate whether their facilities were active sources of petroleum contamination in the area. HECO’s investigation concluded that its facilities were not then releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently releasing petroleum.
During 2006 and the beginning of 2007, the PRPs developed analyses of various remedial alternatives for two of the four remedial subunits of the Iwilei Unit. The DOH will use the analyses to make a final determination of which remedial alternatives the PRPs will be required to implement. The DOH is scheduled to complete the final remediation determinations for all remedial subunits of the Iwilei Unit by the end of 2007 or first quarter of 2008. HECO management developed an estimate of HECO’s share of the costs associated with implementing the PRP recommended remedial approaches for the two subunits covered by the analyses of approximately $1.2 million, (which was expensed in 2006).
As of March 31, 2007, the accrual (amounts expensed less amounts expended) related to the Honolulu Harbor investigation was $1.5 million. Because (1) the full scope and extent of additional investigative work, remedial activities and monitoring are unknown at this time,remain to be determined, (2) the final cost allocation method among the PRPs has not yet been determinedestablished and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei Unit (such as its Honolulu power plant, which is located in the “Downtown” unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.
In 2003, HECO and other members of the IDPP with active operations in the Iwilei area investigated their operations to evaluate whether their facilities were active sources of petroleum in the area. HECO’s investigation concluded that its facilities were not releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently releasing petroleum.
Regional Haze Rule amendments.amendments. In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States must develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, HECO, HELCO and MECO will evaluate itsthe plan’s impacts, if any, on them. If any of the utilities’ generating units are ultimately required to install post-combustion control technologies to meet BART emission limits, the resulting capital and operations and maintenance costs could be significant.
Clean Water Act.Act. Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. Effective September 9, 2004, the EPA issued a new rule, which establishesestablished location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards applyapplied to HECO’s Kahe, Waiau and Honolulu generating stations, unless the utility cancould demonstrate that at each facility implementation of these standards willwould result in costs either significantly higher than projected costs the EPA considered in establishing the standards for the facility (cost-cost test) or significantly greater than the benefits of meeting the standards.standards (cost-benefit test). In either case, the EPA willwould then make a case-by-case determination of an appropriate performance standard. The regulation also would have allowed restoration of aquatic organism populations in lieu of meeting the standards. The rule required covered facilities to demonstrate compliance by March 2008. HECO has until March 2008 to make this showing or demonstrate compliance. HECO hashad retained a consultant to developthat was developing a cost effective compliance strategy and a preliminary assessment of technologies and operational measures. HECO is currently collecting datameasures under the rule.
On January 25, 2007, the U.S. Circuit Court for the Second Circuit issued a decision in Riverkeeper, Inc. v. EPA that remanded for further consideration and proceedings significant portions of the rule and found other portions of the rule to be impermissible. In particular, the court determined that restoration and the cost-benefit test were impermissible under the Clean Water Act. It also remanded the best technology available determination to permit the EPA to provide a reasoned explanation for its decision or a new determination. It remanded the cost-cost test for the EPA’s further consideration based on the best technology available determination and to afford adequate notice. Although the EPA has not announced its plans, it has obtained an extension of time to request a rehearing or to file an appeal to the U.S. Supreme Court. If the decision stands, the Court of Appeals ruling reduces the compliance options available to HECO. In addition, the EPA has not issued a schedule for rulemaking, which would be necessary to preparecomply with the comprehensive demonstration studycourt’s decision. On March 20, 2007, the EPA announced it had “suspended” the rule pending appeal or additional rulemaking. In the announcement, the EPA provided guidance to federal and state permit writers that will evaluatethey should use their “best professional judgment” in determining permit conditions regarding cooling water intake requirements at existing power plants. Currently, this guidance does not affect the HECO facilities subject to the cooling water intake requirements because none of the facilities are subject to permit renewal until mid-2009. Due to the uncertainties raised by the court’s decision as well as the need for further rulemaking by the EPA, management is unable to predict which compliance options, are available for the Company, some of which could entail significant capital expenditures to implement.implement, will be applicable to its facilities.
Collective bargaining agreements
ApproximatelyAs of March 31, 2007, approximately 58% 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 provideprovided 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). Negotiations for new agreements are expected to begin in the third quarter of 2007.
(6) Cash flows
| (6) | Cash flows |
Supplemental disclosures of cash flow information
For each of the ninethree months ended September 30,March 31, 2007 and 2006, and 2005, HECO and its subsidiaries paid interest amounting to $30 million.$11.0 million and $7.6 million, respectively.
For the ninethree months ended September 30,March 31, 2007 and 2006, and 2005, HECO and its subsidiaries paid income taxes amounting to $17$5.5 million and $5$4.9 million, respectively. The difference is primarily due to the federal estimated income taxes paid in the first nine months of 2006 versus none paid in the same period of 2005 (as a result of an overpayment credit from the 2004 tax return applied to the 2005 estimated federal income taxes).
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 $5.0$1.2 million and $3.7$1.5 million for the ninethree months ended September 30,March 31, 2007 and 2006, and 2005, respectively.
(7) Recent accounting pronouncements and interpretations
| (7) | Recent accounting pronouncements and interpretations |
For a discussion of recent accounting pronouncements and interpretations, regarding the accounting treatment of uncertainty in income taxes, fair value measurements, effects of prior year misstatements, planned major maintenance activities and balance sheet recognition of the funded status of defined benefit pension and other postretirement benefit plans, see Note 9 of HEI’s “Notes to Consolidated Financial Statements.”
Determining
| (8) | Income taxes |
The electric utilities record interest and penalties on income taxes in “Interest and other charges.” Interest accrued on income taxes was insignificant in the variabilityfirst quarter of 2006 and $0.1 million in the first quarter of 2007.
As of January 1, 2007, the total amount of accrued interest and penalties related to be considered in applying FIN 46Runcertain tax positions and recognized on the balance sheet was $0.6 million.
In April 2006,As of January 1, 2007, the FASB issued FSP FIN 46R-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R).” This FSP provides guidance in applying FIN 46R, “Consolidationtotal amount of Variable Interest Entities.” The variability that is considered canunrecognized tax benefits was $4.7 million, and of this amount, $0.2 million, if recognized, would affect the determinationelectric utilities’ effective tax rate. Management concluded that it is reasonably possible that the unrecognized tax benefits will significantly decrease within the next 12 months due to the resolution of whether an entity is a VIE; which party, if any, isissues under examination by the primary beneficiaryInternal Revenue Service. Management cannot estimate the range of the VIE;reasonably possible change.
As of January 1, 2007, the tax years 2003 to 2006 remain subject to examination by the Internal Revenue Service and calculationsDepartment of expected losses and expected residual returns. A company is required to applyTaxation of the guidanceState of Hawaii.
The electric utilities had a $0.3 million tax benefit in the FSP prospectivelyfirst quarter of 2007 (compared to all entities (including newly created entities) with which that company first becomes involved and to all entities previously required to be analyzed under FIN 46R when a “reconsideration event” has occurred beginningan effective tax rate for the first dayquarter of 2006 of 38%), primarily due to the low pre-tax income and the impact of state tax credits, including the acceleration of the first reporting period beginning after June 15, 2006. HECOstate tax credits associated with the write off of a portion of CT-4 and its subsidiaries adopted FSP FIN 46R-6 on July 1, 2006, and the adoption had no effect on HECO and its subsidiaries’ financial statements.
(8) Reconciliation of electric utility operating income per HEI and HECO consolidated statements of incomeCT-5 costs.
Three months ended September 30 | Nine months ended September 30 | |||||||||||||||
(in thousands) | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income) | $ | 48,651 | $ | 47,533 | $ | 134,077 | $ | 121,786 | ||||||||
Deduct: | ||||||||||||||||
Income taxes on regulated activities | (14,665 | ) | (13,754 | ) | (38,909 | ) | (33,785 | ) | ||||||||
Revenues from nonregulated activities | (1,602 | ) | (1,462 | ) | (3,304 | ) | (3,470 | ) | ||||||||
Add: Expenses from nonregulated activities | 352 | 297 | 936 | 772 | ||||||||||||
Operating income from regulated activities after income taxes (per HECO consolidated statements of income) | $ | 32,736 | $ | 32,614 | $ | 92,800 | $ | 85,303 | ||||||||
| (9) | Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income |
(9) Credit agreement
Three months ended March 31 | 2007 | 2006 | ||||||
| (in thousands) | ||||||||
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income) | $ | 12,992 | $ | 45,580 | ||||
Deduct: | ||||||||
Income taxes on regulated activities | (4,506 | ) | (13,224 | ) | ||||
Revenues from nonregulated activities | (881 | ) | (1,085 | ) | ||||
Add: | ||||||||
Expenses from nonregulated activities | 11,898 | 291 | ||||||
Operating income from regulated activities after income taxes (per HECO consolidated statements of income) | $ | 19,503 | $ | 31,562 | ||||
| (10) | Credit agreement |
Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement haswas for an initial term which expiresexpiring on March 29, 2007. On2007, but the term was subject to an automatic extension to March 31, 2011 upon approval by the PUC. In August 30, 2006, HECO filed an application with therequested PUC requesting approval to maintain the $175 million credit facility for five years, which, if approved byyears. On March 14, 2007 the PUC will automatically extend the termination date ofissued a D&O approving HECO’s request to maintain the credit facility for five years, to borrow under the credit facility with maturities in excess of 364 days, to use the proceeds from March 29, 2007any borrowings with maturities in excess of 364 days to March 31, 2011. finance capital expenditures and/or to repay short-term or other borrowings used to finance or refinance capital expenditures and to use an expedited approval process to obtain PUC approval to increase the facility amount, renew the facility, refinance the facility or change other terms of the facility if such changes are required or desirable.
Any draws on the facility bear interest, at the option of HECO, at either the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual feesThe annual fee is 8 basis points on the undrawn commitments are 8 basis points.commitment amount. The agreement contains provisions for revised pricing in the event of a ratings changechange. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not
contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions that must be met in order to draw on it, includingsuch as the continued accuracy of HECO’scertain of its representations at the time of a draw and compliance with several covenants.its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting HECO’s ability, as well as the ability of any of its subsidiaries, to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratios of 49% for HELCO and 43% for MECO as of March 31, 2007, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default would result if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 54% as of March 31, 2007, as calculated under the agreement), as definedif HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in its agreement, if HECO’sany “Material Indebtedness” of HECO or any of its subsidiaries’ guarantee of additional indebtedness of thesignificant subsidiaries would cause the subsidiary’s Consolidated Subsidiary Funded Debtbeing subject to Capitalization Ratioacceleration prior to exceed 65%, as defined in its agreement, or if HECO fails to meet other requirements.
Thisscheduled maturity. HECO’s syndicated credit facility is maintained to support the issuance of commercial paper, but it may also may be drawn for capital expenditures and general corporate purposes. This facility replaced HECO’s six bilateral bank lines of credit totaling $175 million, which were terminated concurrently with the effectiveness of the new syndicated facility.purposes and capital expenditures. As of October 31, 2006,May 1, 2007, the $175 million of credit facilitiesfacility remained undrawn.
| (11) | Special Purpose Revenue Bonds (SPRBs) |
On March 27, 2007, the Department of Budget and Finance of the State of Hawaii (the Department) issued (pursuant to a 2005 Legislative authorization), at par, Series 2007A SPRBs in the aggregate principal amount of $140 million, with a maturity of March 1, 2037 and a fixed coupon interest rate of 4.65%, and loaned the proceeds to HECO ($100 million), HELCO ($20 million) and MECO ($20 million). Payment of the principal and interest on the SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company. Proceeds will be used to finance capital expenditures, including reimbursements to the electric utilities for previously incurred capital expenditures which, in turn, will be used primarily to repay short-term borrowings. As of March 31, 2007, approximately $49 million of proceeds from the Series 2007A SPRBs had not yet been drawn and were held by the construction fund trustee. HECO’s long-term debt will increase from time to time as these remaining proceeds are drawn down.
On March 27, 2007, the Department issued, at par, Refunding Series 2007B SPRBs in the aggregate principal amount of $125 million, with a maturity of May 1, 2026 and a fixed coupon interest rate of 4.60%, and loaned the proceeds to HECO ($62 million), HELCO ($8 million) and MECO ($55 million). Proceeds from the sale were applied, together with other funds provided by the electric utilities, to the redemption at par on May 1, 2007 of the $75 million aggregate principal amount of 6.20% Series 1996A SPRBs (which had an original maturity of May 1, 2026) and to the redemption at a 2% premium on April 27, 2007 of the $50 million aggregate principal amount of 5 7/8% Series 1996B SPRBs (which had an original maturity of December 1, 2026). Payment of the principal and interest on the refunding SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company.
(10) Consolidating financial information
| (12) | Consolidating financial information |
HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated.
HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) relating to the trust preferred securities of Trust III. Also, see Note 2. HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance SheetStatement of Income (unaudited)
September 30, 2006Three months ended March 31, 2007
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | |||||||||||||
Assets | |||||||||||||||||||
Utility plant, at cost | |||||||||||||||||||
Land | $ | 25,779 | 4,910 | 4,346 | — | — | $ | 35,035 | |||||||||||
Plant and equipment | 2,392,147 | 785,228 | 697,150 | — | — | 3,874,525 | |||||||||||||
Less accumulated depreciation | (938,647 | ) | (294,662 | ) | (301,373 | ) | — | — | (1,534,682 | ) | |||||||||
Plant acquisition adjustment, net | — | — | 106 | — | — | 106 | |||||||||||||
Construction in progress | 82,945 | 17,687 | 59,668 | — | — | 160,300 | |||||||||||||
Net utility plant | 1,562,224 | 513,163 | 459,897 | — | — | 2,535,284 | |||||||||||||
Investment in subsidiaries, at equity | 396,027 | — | — | — | (396,027 | ) | — | ||||||||||||
Current assets | |||||||||||||||||||
Cash and equivalents | 1,946 | 711 | 1,467 | 294 | — | 4,418 | |||||||||||||
Advances to affiliates | 61,650 | — | — | — | (61,650 | ) | — | ||||||||||||
Customer accounts receivable, net | 93,997 | 24,415 | 21,396 | — | — | 139,808 | |||||||||||||
Accrued unbilled revenues, net | 67,237 | 16,507 | 14,945 | — | — | 98,689 | |||||||||||||
Other accounts receivable, net | 4,486 | 677 | 1,180 | — | (306 | ) | 6,037 | ||||||||||||
Fuel oil stock, at average cost | 68,618 | 10,098 | 17,254 | — | — | 95,970 | |||||||||||||
Materials and supplies, at average cost | 14,729 | 4,177 | 11,391 | — | — | 30,297 | |||||||||||||
Prepaid pension benefit cost | 71,833 | 13,464 | 5,995 | — | — | 91,292 | |||||||||||||
Other | 8,185 | 1,480 | 225 | — | — | 9,890 | |||||||||||||
Total current assets | 392,681 | 71,529 | 73,853 | 294 | (61,956 | ) | 476,401 | ||||||||||||
Other long-term assets | |||||||||||||||||||
Regulatory assets | 81,168 | 14,120 | 15,047 | — | — | 110,335 | |||||||||||||
Unamortized debt expense | 9,460 | 2,315 | 2,121 | — | — | 13,896 | |||||||||||||
Other | 21,849 | 3,455 | 4,052 | — | — | 29,356 | |||||||||||||
Total other long-term assets | 112,477 | 19,890 | 21,220 | — | — | 153,587 | |||||||||||||
| $ | 2,463,409 | 604,582 | 554,970 | 294 | (457,983 | ) | $ | 3,165,272 | |||||||||||
Capitalization and liabilities | |||||||||||||||||||
Capitalization | |||||||||||||||||||
Common stock equity | $ | 1,071,818 | 193,885 | 201,858 | 284 | (396,027 | ) | $ | 1,071,818 | ||||||||||
Cumulative preferred stock—not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | — | — | 34,293 | |||||||||||||
Long-term debt, net | 481,213 | 131,036 | 153,888 | — | — | 766,137 | |||||||||||||
Total capitalization | 1,575,324 | 331,921 | 360,746 | 284 | (396,027 | ) | 1,872,248 | ||||||||||||
Current liabilities | |||||||||||||||||||
Short-term borrowings—nonaffiliates | 145,080 | — | — | — | — | 145,080 | |||||||||||||
Short-term borrowings—affiliate | — | 46,900 | 14,750 | — | (61,650 | ) | — | ||||||||||||
Accounts payable | 74,238 | 17,260 | 15,850 | — | — | 107,348 | |||||||||||||
Interest and preferred dividends payable | 10,180 | 2,970 | 3,004 | — | (249 | ) | 15,905 | ||||||||||||
Taxes accrued | 104,660 | 29,477 | 29,759 | — | — | 163,896 | |||||||||||||
Other | 24,749 | 3,690 | 8,218 | 10 | (57 | ) | 36,610 | ||||||||||||
Total current liabilities | 358,907 | 100,297 | 71,581 | 10 | (61,956 | ) | 468,839 | ||||||||||||
Deferred credits and other liabilities | |||||||||||||||||||
Deferred income taxes | 155,422 | 24,626 | 20,475 | — | — | 200,523 | |||||||||||||
Regulatory liabilities | 160,808 | 42,864 | 31,808 | — | — | 235,480 | |||||||||||||
Unamortized tax credits | 32,378 | 12,913 | 12,082 | — | — | 57,373 | |||||||||||||
Other | 21,304 | 35,016 | 8,750 | — | — | 65,070 | |||||||||||||
Total deferred credits and other liabilities | 369,912 | 115,419 | 73,115 | — | — | 558,446 | |||||||||||||
Contributions in aid of construction | 159,266 | 56,945 | 49,528 | — | — | 265,739 | |||||||||||||
| $ | 2,463,409 | 604,582 | 554,970 | 294 | (457,983 | ) | $ | 3,165,272 | |||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance Sheet (unaudited)
December 31, 2005
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consolidated | |||||||||||||
Assets | |||||||||||||||||||
Utility plant, at cost | |||||||||||||||||||
Land | $ | 25,699 | 3,018 | 4,317 | — | — | $ | 33,034 | |||||||||||
Plant and equipment | 2,304,142 | 766,714 | 678,530 | — | — | 3,749,386 | |||||||||||||
Less accumulated depreciation | (898,351 | ) | (275,444 | ) | (282,742 | ) | — | — | (1,456,537 | ) | |||||||||
Plant acquisition adjustment, net | — | — | 145 | — | — | 145 | |||||||||||||
Construction in progress | 108,060 | 11,414 | 28,282 | — | — | 147,756 | |||||||||||||
Net utility plant | 1,539,550 | 505,702 | 428,532 | — | — | 2,473,784 | |||||||||||||
Investment in subsidiaries, at equity | 383,715 | — | — | — | (383,715 | ) | — | ||||||||||||
Current assets | |||||||||||||||||||
Cash and equivalents | 8 | 3 | 4 | 128 | — | 143 | |||||||||||||
Advances to affiliates | 49,700 | — | 5,250 | — | (54,950 | ) | — | ||||||||||||
Customer accounts receivable, net | 81,870 | 21,652 | 20,373 | — | — | 123,895 | |||||||||||||
Accrued unbilled revenues, net | 62,701 | 14,675 | 13,945 | — | — | 91,321 | |||||||||||||
Other accounts receivable, net | 10,212 | 2,772 | 1,185 | — | 592 | 14,761 | |||||||||||||
Fuel oil stock, at average cost | 64,309 | 7,868 | 13,273 | — | — | 85,450 | |||||||||||||
Materials & supplies, at average cost | 14,128 | 3,204 | 9,642 | — | — | 26,974 | |||||||||||||
Prepaid pension benefit cost | 82,497 | 15,388 | 8,433 | — | — | 106,318 | |||||||||||||
Other | 7,485 | 541 | 558 | — | — | 8,584 | |||||||||||||
Total current assets | 372,910 | 66,103 | 72,663 | 128 | (54,358 | ) | 457,446 | ||||||||||||
Other long-term assets | |||||||||||||||||||
Regulatory assets | 81,682 | 14,596 | 14,440 | — | — | 110,718 | |||||||||||||
Unamortized debt expense | 9,778 | 2,362 | 2,221 | — | — | 14,361 | |||||||||||||
Other | 17,816 | 3,696 | 3,640 | — | — | 25,152 | |||||||||||||
Total other long-term assets | 109,276 | 20,654 | 20,301 | — | — | 150,231 | |||||||||||||
| $ | 2,405,451 | 592,459 | 521,496 | 128 | (438,073 | ) | $ | 3,081,461 | |||||||||||
Capitalization and liabilities | |||||||||||||||||||
Capitalization | |||||||||||||||||||
Common stock equity | $ | 1,039,259 | 189,407 | 194,190 | 118 | (383,715 | ) | $ | 1,039,259 | ||||||||||
Cumulative preferred stock–not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | — | — | 34,293 | |||||||||||||
Long-term debt, net | 481,132 | 131,009 | 153,852 | — | — | 765,993 | |||||||||||||
Total capitalization | 1,542,684 | 327,416 | 353,042 | 118 | (383,715 | ) | 1,839,545 | ||||||||||||
Current liabilities | |||||||||||||||||||
Short-term borrowings-nonaffiliates | 136,165 | — | — | — | — | 136,165 | |||||||||||||
Short-term borrowings-affiliate | 5,250 | 49,700 | — | — | (54,950 | ) | — | ||||||||||||
Accounts payable | 86,843 | 19,503 | 15,855 | — | — | 122,201 | |||||||||||||
Interest and preferred dividends payable | 7,217 | 1,311 | 1,664 | — | (202 | ) | 9,990 | ||||||||||||
Taxes accrued | 84,054 | 24,252 | 25,277 | — | — | 133,583 | |||||||||||||
Other | 24,971 | 3,566 | 7,791 | 10 | 794 | 37,132 | |||||||||||||
Total current liabilities | 344,500 | 98,332 | 50,587 | 10 | (54,358 | ) | 439,071 | ||||||||||||
Deferred credits and other liabilities | |||||||||||||||||||
Deferred income taxes | 160,351 | 25,147 | 22,876 | — | — | 208,374 | |||||||||||||
Regulatory liabilities | 148,898 | 40,535 | 29,771 | — | — | 219,204 | |||||||||||||
Unamortized tax credits | 31,209 | 12,693 | 11,425 | — | — | 55,327 | |||||||||||||
Other | 21,522 | 31,781 | 10,374 | — | — | 63,677 | |||||||||||||
Total deferred credits and other liabilities | 361,980 | 110,156 | 74,446 | — | — | 546,582 | |||||||||||||
Contributions in aid of construction | 156,287 | 56,555 | 43,421 | — | — | 256,263 | |||||||||||||
| $ | 2,405,451 | 592,459 | 521,496 | 128 | (438,073 | ) | $ | 3,081,461 | |||||||||||
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Operating revenues | $ | 288,690 | 78,809 | 79,298 | — | — | $ | 446,797 | ||||||||||||
Operating expenses | ||||||||||||||||||||
Fuel oil | 101,062 | 20,038 | 38,829 | — | — | 159,929 | ||||||||||||||
Purchased power | 78,300 | 27,062 | 6,154 | — | — | 111,516 | ||||||||||||||
Other operation | 33,485 | 7,166 | 6,542 | — | — | 47,193 | ||||||||||||||
Maintenance | 16,378 | 5,568 | 5,390 | — | — | 27,336 | ||||||||||||||
Depreciation | 19,739 | 7,524 | 7,004 | — | — | 34,267 | ||||||||||||||
Taxes, other than income taxes | 27,702 | 7,363 | 7,482 | — | — | 42,547 | ||||||||||||||
Income taxes | 1,970 | 538 | 1,998 | — | — | 4,506 | ||||||||||||||
| 278,636 | 75,259 | 73,399 | — | — | 427,294 | |||||||||||||||
Operating income | 10,054 | 3,550 | 5,899 | — | — | 19,503 | ||||||||||||||
Other income | ||||||||||||||||||||
Allowance for equity funds used during construction | 1,087 | 65 | 80 | — | — | 1,232 | ||||||||||||||
Equity in earnings of subsidiaries | (2,937 | ) | — | — | — | 2,937 | — | |||||||||||||
Other, net | 1,485 | (6,863 | ) | 6 | (15 | ) | (811 | ) | (6,198 | ) | ||||||||||
| (365 | ) | (6,798 | ) | 86 | (15 | ) | 2,126 | (4,966 | ) | |||||||||||
Income (loss) before interest and other charges | 9,689 | (3,248 | ) | 5,985 | (15 | ) | 2,126 | 14,537 | ||||||||||||
Interest and other charges | ||||||||||||||||||||
Interest on long-term debt | 7,125 | 1,857 | 2,514 | — | — | 11,496 | ||||||||||||||
Amortization of net bond premium and expense | 348 | 99 | 99 | — | — | 546 | ||||||||||||||
Other interest charges | 2,022 | 757 | 173 | — | (811 | ) | 2,141 | |||||||||||||
Allowance for borrowed funds used during construction | (529 | ) | (31 | ) | (38 | ) | — | — | (598 | ) | ||||||||||
Preferred stock dividends of subsidiaries | — | — | — | — | 229 | 229 | ||||||||||||||
| 8,966 | 2,682 | 2,748 | — | (582 | ) | 13,814 | ||||||||||||||
Income (loss) before preferred stock dividends of HECO | 723 | (5,930 | ) | 3,237 | (15 | ) | 2,708 | 723 | ||||||||||||
Preferred stock dividends of HECO | 270 | 134 | 95 | — | (229 | ) | 270 | |||||||||||||
Net income (loss) for common stock | $ | 453 | (6,064 | ) | 3,142 | (15 | ) | 2,937 | $ | 453 | ||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (unaudited)
Three months ended September 30,March 31, 2006
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||||||||||||||||
Operating revenues | $ | 376,925 | 94,088 | 97,223 | — | — | $ | 568,236 | $ | 318,345 | 79,451 | 76,175 | — | — | $ | 473,971 | ||||||||||||||||||||||||
Operating expenses | ||||||||||||||||||||||||||||||||||||||||
Fuel oil | 150,868 | 24,723 | 51,697 | — | — | 227,288 | 115,735 | 20,102 | 39,501 | — | — | 175,338 | ||||||||||||||||||||||||||||
Purchased power | 96,038 | 33,315 | 9,405 | — | — | 138,758 | 85,454 | 28,046 | 4,220 | — | — | 117,720 | ||||||||||||||||||||||||||||
Other operation | 32,344 | 6,935 | 7,333 | — | — | 46,612 | 28,201 | 7,252 | 6,566 | — | — | 42,019 | ||||||||||||||||||||||||||||
Maintenance | 14,494 | 5,062 | 4,097 | — | — | 23,653 | 10,557 | 3,616 | 2,879 | — | — | 17,052 | ||||||||||||||||||||||||||||
Depreciation | 18,702 | 7,429 | 6,408 | — | — | 32,539 | 18,693 | 7,431 | 6,409 | — | — | 32,533 | ||||||||||||||||||||||||||||
Taxes, other than income taxes | 34,492 | 8,584 | 8,909 | — | — | 51,985 | 29,896 | 7,403 | 7,224 | — | — | 44,523 | ||||||||||||||||||||||||||||
Income taxes | 9,388 | 2,160 | 3,117 | — | — | 14,665 | 9,057 | 1,171 | 2,996 | — | — | 13,224 | ||||||||||||||||||||||||||||
| 356,326 | 88,208 | 90,966 | — | — | 535,500 | 297,593 | 75,021 | 69,795 | — | — | 442,409 | |||||||||||||||||||||||||||||
Operating income | 20,599 | 5,880 | 6,257 | — | — | 32,736 | 20,752 | 4,430 | 6,380 | — | — | 31,562 | ||||||||||||||||||||||||||||
Other income | ||||||||||||||||||||||||||||||||||||||||
Allowance for equity funds used during construction | 1,009 | 63 | 766 | — | — | 1,838 | 1,077 | 40 | 431 | — | — | 1,548 | ||||||||||||||||||||||||||||
Equity in earnings of subsidiaries | 8,375 | — | — | — | (8,375 | ) | — | 6,657 | — | — | — | (6,657 | ) | — | ||||||||||||||||||||||||||
Other, net | 1,630 | 111 | 467 | (32 | ) | (797 | ) | 1,379 | 1,241 | 70 | 227 | (47 | ) | (582 | ) | 909 | ||||||||||||||||||||||||
| 11,014 | 174 | 1,233 | (32 | ) | (9,172 | ) | 3,217 | 8,975 | 110 | 658 | (47 | ) | (7,239 | ) | 2,457 | |||||||||||||||||||||||||
Income (loss) before interest and other charges | 31,613 | 6,054 | 7,490 | (32 | ) | (9,172 | ) | 35,953 | 29,727 | 4,540 | 7,038 | (47 | ) | (7,239 | ) | 34,019 | ||||||||||||||||||||||||
Interest and other charges | ||||||||||||||||||||||||||||||||||||||||
Interest on long-term debt | 6,741 | 1,809 | 2,227 | — | — | 10,777 | 6,743 | 1,808 | 2,227 | — | — | 10,778 | ||||||||||||||||||||||||||||
Amortization of net bond premium and expense | 354 | 108 | 103 | — | — | 565 | 339 | 100 | 104 | — | — | 543 | ||||||||||||||||||||||||||||
Other interest charges | 1,034 | 600 | 448 | — | (797 | ) | 1,285 | 1,870 | 582 | 43 | — | (582 | ) | 1,913 | ||||||||||||||||||||||||||
Allowance for borrowed funds used during construction | (452 | ) | (29 | ) | (357 | ) | — | — | (838 | ) | (483 | ) | (19 | ) | (200 | ) | — | — | (702 | ) | ||||||||||||||||||||
Preferred stock dividends of subsidiaries | — | — | — | — | 228 | 228 | — | — | — | — | 229 | 229 | ||||||||||||||||||||||||||||
| 7,677 | 2,488 | 2,421 | — | (569 | ) | 12,017 | 8,469 | 2,471 | 2,174 | — | (353 | ) | 12,761 | |||||||||||||||||||||||||||
Income (loss) before preferred stock dividends of HECO | 23,936 | 3,566 | 5,069 | (32 | ) | (8,603 | ) | 23,936 | 21,258 | 2,069 | 4,864 | (47 | ) | (6,886 | ) | 21,258 | ||||||||||||||||||||||||
Preferred stock dividends of HECO | 270 | 133 | 95 | — | (228 | ) | 270 | 270 | 134 | 95 | — | (229 | ) | 270 | ||||||||||||||||||||||||||
Net income (loss) for common stock | $ | 23,666 | 3,433 | 4,974 | (32 | ) | (8,375 | ) | $ | 23,666 | $ | 20,988 | 1,935 | 4,769 | (47 | ) | (6,657 | ) | $ | 20,988 | ||||||||||||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Retained EarningsBalance Sheet (unaudited)
Three months ended September 30,March 31, 2007
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | |||||||||||||
Assets | |||||||||||||||||||
Utility plant, at cost | |||||||||||||||||||
Land | $ | 25,960 | 4,982 | 4,346 | — | — | $ | 35,288 | |||||||||||
Plant and equipment | 2,437,586 | 799,880 | 772,211 | — | — | 4,009,677 | |||||||||||||
Less accumulated depreciation | (963,202 | ) | (304,340 | ) | (313,619 | ) | — | — | (1,581,161 | ) | |||||||||
Plant acquisition adjustment, net | — | — | 80 | — | — | 80 | |||||||||||||
Construction in progress | 87,226 | 12,779 | 6,391 | — | — | 106,396 | |||||||||||||
Net utility plant | 1,587,570 | 513,301 | 469,409 | — | — | 2,570,280 | |||||||||||||
Investment in subsidiaries, at equity | 365,066 | — | — | — | (365,066 | ) | — | ||||||||||||
Current assets | |||||||||||||||||||
Cash and equivalents | 9,658 | 2,080 | 413 | 263 | — | 12,414 | |||||||||||||
Advances to affiliates | 45,800 | — | 3,500 | — | (49,300 | ) | — | ||||||||||||
Customer accounts receivable, net | 71,097 | 21,241 | 18,318 | — | — | 110,656 | |||||||||||||
Accrued unbilled revenues, net | 51,072 | 13,742 | 12,401 | — | — | 77,215 | |||||||||||||
Other accounts receivable, net | 2,177 | 1,238 | 4,817 | — | (1,059 | ) | 7,173 | ||||||||||||
Fuel oil stock, at average cost | 43,629 | 7,577 | 15,509 | — | — | 66,715 | |||||||||||||
Materials and supplies, at average cost | 15,185 | 5,148 | 12,133 | — | — | 32,466 | |||||||||||||
Other | 6,856 | 1,769 | 649 | — | — | 9,274 | |||||||||||||
Total current assets | 245,474 | 52,795 | 67,740 | 263 | (50,359 | ) | 315,913 | ||||||||||||
Other long-term assets | |||||||||||||||||||
Regulatory assets | 84,586 | 15,713 | 16,779 | — | — | 117,078 | |||||||||||||
Unamortized debt expense | 10,843 | 2,555 | 2,646 | — | — | 16,044 | |||||||||||||
Other | 23,660 | 3,732 | 3,847 | — | — | 31,239 | |||||||||||||
Total other long-term assets | 119,089 | 22,000 | 23,272 | — | — | 164,361 | |||||||||||||
| $ | 2,317,199 | 588,096 | 560,421 | 263 | (415,425 | ) | $ | 3,050,554 | |||||||||||
Capitalization and liabilities | |||||||||||||||||||
Capitalization | |||||||||||||||||||
Common stock equity | $ | 959,997 | 169,266 | 195,550 | 250 | (365,066 | ) | $ | 959,997 | ||||||||||
Cumulative preferred stock–not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | — | — | 34,293 | |||||||||||||
Long-term debt, net | 550,972 | 143,012 | 164,160 | — | — | 858,144 | |||||||||||||
Total capitalization | 1,533,262 | 319,278 | 364,710 | 250 | (365,066 | ) | 1,852,434 | ||||||||||||
Current liabilities | |||||||||||||||||||
Short-term borrowings–nonaffiliates | 47,242 | — | — | — | — | 47,242 | |||||||||||||
Short-term borrowings–affiliate | 3,500 | 45,800 | — | — | (49,300 | ) | — | ||||||||||||
Accounts payable | 63,182 | 14,155 | 22,700 | — | — | 100,037 | |||||||||||||
Interest and preferred dividends payable | 9,372 | 2,974 | 2,142 | — | (269 | ) | 14,219 | ||||||||||||
Taxes accrued | 69,925 | 21,586 | 23,710 | — | — | 115,221 | |||||||||||||
Other | 20,593 | 5,068 | 8,402 | 13 | (790 | ) | 33,286 | ||||||||||||
Total current liabilities | 213,814 | 89,583 | 56,954 | 13 | (50,359 | ) | 310,005 | ||||||||||||
Deferred credits and other liabilities | |||||||||||||||||||
Deferred income taxes | 87,180 | 8,120 | 11,118 | — | — | 106,418 | |||||||||||||
Regulatory liabilities | 168,498 | 43,802 | 33,140 | — | — | 245,440 | |||||||||||||
Unamortized tax credits | 32,516 | 12,869 | 12,358 | — | — | 57,743 | |||||||||||||
Other | 118,300 | 54,253 | 28,462 | — | — | 201,015 | |||||||||||||
Total deferred credits and other liabilities | 406,494 | 119,044 | 85,078 | — | — | 610,616 | |||||||||||||
Contributions in aid of construction | 163,629 | 60,191 | 53,679 | — | — | 277,499 | |||||||||||||
| $ | 2,317,199 | 588,096 | 560,421 | 263 | (415,425 | ) | $ | 3,050,554 | |||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance Sheet (unaudited)
December 31, 2006
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||
Retained earnings, beginning of period | $ | 663,579 | 89,808 | 101,963 | (465 | ) | (191,306 | ) | $ | 663,579 | ||||||
Net income (loss) for common stock | 23,666 | 3,433 | 4,974 | (32 | ) | (8,375 | ) | 23,666 | ||||||||
Common stock dividends | — | — | — | — | — | — | ||||||||||
Retained earnings, end of period | $ | 687,245 | 93,241 | 106,937 | (497 | ) | (199,681 | ) | $ | 687,245 | ||||||
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consolidated | |||||||||||||
Assets | |||||||||||||||||||
Utility plant, at cost | |||||||||||||||||||
Land | $ | 25,919 | 4,977 | 4,346 | — | — | $ | 35,242 | |||||||||||
Plant and equipment | 2,428,155 | 807,474 | 767,300 | — | — | 4,002,929 | |||||||||||||
Less accumulated depreciation | (953,187 | ) | (298,590 | ) | (307,136 | ) | — | — | (1,558,913 | ) | |||||||||
Plant acquisition adjustment, net | — | — | 93 | — | — | 93 | |||||||||||||
Construction in progress | 80,298 | 9,745 | 5,576 | — | — | 95,619 | |||||||||||||
Net utility plant | 1,581,185 | 523,606 | 470,179 | — | — | 2,574,970 | |||||||||||||
Investment in subsidiaries, at equity | 367,595 | — | — | — | (367,595 | ) | — | ||||||||||||
Current assets | |||||||||||||||||||
Cash and equivalents | 2,328 | 738 | 518 | 275 | — | 3,859 | |||||||||||||
Advances to affiliates | 54,400 | — | — | — | (54,400 | ) | — | ||||||||||||
Customer accounts receivable, net | 81,912 | 24,228 | 19,384 | — | — | 125,524 | |||||||||||||
Accrued unbilled revenues, net | 64,235 | 14,437 | 13,523 | — | — | 92,195 | |||||||||||||
Other accounts receivable, net | 3,210 | 1,097 | 773 | — | (657 | ) | 4,423 | ||||||||||||
Fuel oil stock, at average cost | 40,680 | 9,761 | 13,871 | — | — | 64,312 | |||||||||||||
Materials & supplies, at average cost | 13,959 | 4,892 | 11,689 | — | — | 30,540 | |||||||||||||
Other | 7,537 | 1,463 | 695 | — | — | 9,695 | |||||||||||||
Total current assets | 268,261 | 56,616 | 60,453 | 275 | (55,057 | ) | 330,548 | ||||||||||||
Other long-term assets | |||||||||||||||||||
Regulatory assets | 82,116 | 15,349 | 14,884 | — | — | 112,349 | |||||||||||||
Unamortized debt expense | 9,323 | 2,282 | 2,117 | — | — | 13,722 | |||||||||||||
Other | 23,507 | 4,340 | 3,698 | — | — | 31,545 | |||||||||||||
Total other long-term assets | 114,946 | 21,971 | 20,699 | — | — | 157,616 | |||||||||||||
| $ | 2,331,987 | 602,193 | 551,331 | 275 | (422,652 | ) | $ | 3,063,134 | |||||||||||
Capitalization and liabilities | |||||||||||||||||||
Capitalization | |||||||||||||||||||
Common stock equity | $ | 958,203 | 175,099 | 192,231 | 265 | (367,595 | ) | $ | 958,203 | ||||||||||
Cumulative preferred stock–not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | — | — | 34,293 | |||||||||||||
Long-term debt, net | 481,240 | 131,046 | 153,899 | — | — | 766,185 | |||||||||||||
Total capitalization | 1,461,736 | 313,145 | 351,130 | 265 | (367,595 | ) | 1,758,681 | ||||||||||||
Current liabilities | |||||||||||||||||||
Short-term borrowings-nonaffiliates | 113,107 | — | — | — | — | 113,107 | |||||||||||||
Short-term borrowings-affiliate | — | 49,400 | 5,000 | — | (54,400 | ) | — | ||||||||||||
Accounts payable | 61,672 | 22,572 | 18,268 | — | — | 102,512 | |||||||||||||
Interest and preferred dividends payable | 7,269 | 1,907 | 1,717 | — | (248 | ) | 10,645 | ||||||||||||
Taxes accrued | 96,846 | 26,981 | 28,355 | — | — | 152,182 | |||||||||||||
Other | 27,012 | 5,971 | 10,536 | 10 | (409 | ) | 43,120 | ||||||||||||
Total current liabilities | 305,906 | 106,831 | 63,876 | 10 | (55,057 | ) | 421,566 | ||||||||||||
Deferred credits and other liabilities | |||||||||||||||||||
Deferred income taxes | 92,805 | 13,285 | 11,965 | — | — | 118,055 | |||||||||||||
Regulatory liabilities | 164,617 | 43,596 | 32,406 | — | — | 240,619 | |||||||||||||
Unamortized tax credits | 32,359 | 13,126 | 12,394 | — | — | 57,879 | |||||||||||||
Other | 110,473 | 52,274 | 26,859 | — | — | 189,606 | |||||||||||||
Total deferred credits and other liabilities | 400,254 | 122,281 | 83,624 | — | — | 606,159 | |||||||||||||
Contributions in aid of construction | 164,091 | 59,936 | 52,701 | — | — | 276,728 | |||||||||||||
| $ | 2,331,987 | 602,193 | 551,331 | 275 | (422,652 | ) | $ | 3,063,134 | |||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of IncomeChanges in Stockholder’s Equity (unaudited)
Three months ended September 30, 2005March 31, 2007
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Operating revenues | $ | 330,922 | 79,511 | 79,444 | — | — | $ | 489,877 | ||||||||||||
Operating expenses | ||||||||||||||||||||
Fuel oil | 124,427 | 16,799 | 41,437 | — | — | 182,663 | ||||||||||||||
Purchased power | 89,021 | 29,015 | 4,050 | — | — | 122,086 | ||||||||||||||
Other operation | 28,809 | 6,454 | 6,711 | — | — | 41,974 | ||||||||||||||
Maintenance | 14,157 | 4,250 | 2,734 | — | — | 21,141 | ||||||||||||||
Depreciation | 17,583 | 6,804 | 6,268 | — | — | 30,655 | ||||||||||||||
Taxes, other than income taxes | 30,411 | 7,252 | 7,327 | — | — | 44,990 | ||||||||||||||
Income taxes | 7,962 | 2,413 | 3,379 | — | — | 13,754 | ||||||||||||||
| 312,370 | 72,987 | 71,906 | — | — | 457,263 | |||||||||||||||
Operating income | 18,552 | 6,524 | 7,538 | — | — | 32,614 | ||||||||||||||
Other income | ||||||||||||||||||||
Allowance for equity funds used during construction | 1,051 | 95 | 260 | — | — | 1,406 | ||||||||||||||
Equity in earnings of subsidiaries | 9,768 | — | — | — | (9,768 | ) | — | |||||||||||||
Other, net | 1,436 | 103 | 192 | (50 | ) | (490 | ) | 1,191 | ||||||||||||
| 12,255 | 198 | 452 | (50 | ) | (10,258 | ) | 2,597 | |||||||||||||
Income (loss) before interest and other charges | 30,807 | 6,722 | 7,990 | (50 | ) | (10,258 | ) | 35,211 | ||||||||||||
Interest and other charges | ||||||||||||||||||||
Interest on long-term debt | 6,695 | 1,809 | 2,227 | — | — | 10,731 | ||||||||||||||
Amortization of net bond premium and expense | 343 | 98 | 104 | — | — | 545 | ||||||||||||||
Other interest charges | 1,319 | 475 | 104 | — | (490 | ) | 1,408 | |||||||||||||
Allowance for borrowed funds used during construction | (407 | ) | (38 | ) | (113 | ) | — | — | (558 | ) | ||||||||||
Preferred stock dividends of subsidiaries | — | — | — | — | 228 | 228 | ||||||||||||||
| 7,950 | 2,344 | 2,322 | — | (262 | ) | 12,354 | ||||||||||||||
Income (loss) before preferred stock dividends of HECO | 22,857 | 4,378 | 5,668 | (50 | ) | (9,996 | ) | 22,857 | ||||||||||||
Preferred stock dividends of HECO | 270 | 133 | 95 | — | (228 | ) | 270 | |||||||||||||
Net income (loss) for common stock | $ | 22,587 | 4,245 | 5,573 | (50 | ) | (9,768 | ) | $ | 22,587 | ||||||||||
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Balance, December 31, 2006 | $ | 958,203 | 175,099 | 192,231 | 265 | (367,595 | ) | $ | 958,203 | |||||||||||
Comprehensive income: | ||||||||||||||||||||
Net income | 453 | (6,064 | ) | 3,142 | (15 | ) | 2,937 | 453 | ||||||||||||
Defined benefit pension plans - amortization of net loss, prior service cost and transition obligation included in net periodic pension cost, net of tax benefits | 1,961 | 263 | 219 | — | (482 | ) | 1,961 | |||||||||||||
Comprehensive income (loss) | 2,414 | (5,801 | ) | 3,361 | (15 | ) | 2,455 | 2,414 | ||||||||||||
Adjustment to initially apply FIN 48, net of tax benefits | (620 | ) | (32 | ) | (42 | ) | — | 74 | (620 | ) | ||||||||||
Balance, March 31, 2007 | $ | 959,997 | 169,266 | 195,550 | 250 | (365,066 | ) | $ | 959,997 | |||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Retained EarningsChanges in Stockholder’s Equity (unaudited)
Three months ended September 30, 2005
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Retained earnings, beginning of period | $ | 645,586 | 88,881 | 97,659 | (283 | ) | (186,257 | ) | $ | 645,586 | ||||||||||
Net income (loss) for common stock | 22,587 | 4,245 | 5,573 | (50 | ) | (9,768 | ) | 22,587 | ||||||||||||
Common stock dividends | (14,733 | ) | (3,074 | ) | (3,710 | ) | — | 6,784 | (14,733 | ) | ||||||||||
Retained earnings, end of period | $ | 653,440 | 90,052 | 99,522 | (333 | ) | (189,241 | ) | $ | 653,440 | ||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (unaudited)
Nine months ended September 30,March 31, 2006
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Operating revenues | $ | 1,034,483 | 254,275 | 256,799 | — | — | $ | 1,545,557 | ||||||||||||
Operating expenses | ||||||||||||||||||||
Fuel oil | 397,360 | 62,860 | 134,720 | — | — | 594,940 | ||||||||||||||
Purchased power | 268,019 | 91,479 | 19,418 | — | — | 378,916 | ||||||||||||||
Other operation | 92,754 | 21,947 | 21,864 | — | — | 136,565 | ||||||||||||||
Maintenance | 39,880 | 12,755 | 10,452 | — | — | 63,087 | ||||||||||||||
Depreciation | 56,097 | 22,291 | 19,226 | — | — | 97,614 | ||||||||||||||
Taxes, other than income taxes | 95,464 | 23,527 | 23,735 | — | — | 142,726 | ||||||||||||||
Income taxes | 25,373 | 4,564 | 8,972 | — | — | 38,909 | ||||||||||||||
| 974,947 | 239,423 | 238,387 | — | — | 1,452,757 | |||||||||||||||
Operating income | 59,536 | 14,852 | 18,412 | — | — | 92,800 | ||||||||||||||
Other income | ||||||||||||||||||||
Allowance for equity funds used during construction | 3,002 | 156 | 1,816 | — | — | 4,974 | ||||||||||||||
Equity in earnings of subsidiaries | 21,408 | — | — | — | (21,408 | ) | — | |||||||||||||
Other, net | 3,789 | 239 | 978 | (134 | ) | (2,063 | ) | 2,809 | ||||||||||||
| 28,199 | 395 | 2,794 | (134 | ) | (23,471 | ) | 7,783 | |||||||||||||
Income (loss) before interest and other charges | 87,735 | 15,247 | 21,206 | (134 | ) | (23,471 | ) | 100,583 | ||||||||||||
Interest and other charges | ||||||||||||||||||||
Interest on long-term debt | 20,225 | 5,425 | 6,681 | — | — | 32,331 | ||||||||||||||
Amortization of net bond premium and expense | 1,032 | 309 | 310 | — | — | 1,651 | ||||||||||||||
Other interest charges | 5,072 | 1,832 | 583 | — | (2,063 | ) | 5,424 | |||||||||||||
Allowance for borrowed funds used during construction | (1,344 | ) | (71 | ) | (844 | ) | — | — | (2,259 | ) | ||||||||||
Preferred stock dividends of subsidiaries | — | — | — | — | 686 | 686 | ||||||||||||||
| 24,985 | 7,495 | 6,730 | — | (1,377 | ) | 37,833 | ||||||||||||||
Income (loss) before preferred stock dividends of HECO | 62,750 | 7,752 | 14,476 | (134 | ) | (22,094 | ) | 62,750 | ||||||||||||
Preferred stock dividends of HECO | 810 | 400 | 286 | — | (686 | ) | 810 | |||||||||||||
Net income (loss) for common stock | $ | 61,940 | 7,352 | 14,190 | (134 | ) | (21,408 | ) | $ | 61,940 | ||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Retained Earnings (unaudited)
Nine months ended September 30, 2006
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Retained earnings, beginning of period | $ | 654,686 | 88,763 | 99,269 | (363 | ) | (187,669 | ) | $ | 654,686 | ||||||||||
Net income (loss) for common stock | 61,940 | 7,352 | 14,190 | (134 | ) | (21,408 | ) | 61,940 | ||||||||||||
Common stock dividends | (29,381 | ) | (2,874 | ) | (6,522 | ) | — | 9,396 | (29,381 | ) | ||||||||||
Retained earnings, end of period | $ | 687,245 | 93,241 | 106,937 | (497 | ) | (199,681 | ) | $ | 687,245 | ||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (unaudited)
Nine months ended September 30, 2005
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Operating revenues | $ | 864,123 | 211,860 | 216,391 | — | — | $ | 1,292,374 | ||||||||||||
Operating expenses | ||||||||||||||||||||
Fuel oil | 294,266 | 45,784 | 107,014 | — | — | 447,064 | ||||||||||||||
Purchased power | 246,622 | 72,110 | 10,939 | — | — | 329,671 | ||||||||||||||
Other operation | 84,992 | 19,052 | 21,040 | — | — | 125,084 | ||||||||||||||
Maintenance | 39,254 | 10,991 | 8,671 | — | — | 58,916 | ||||||||||||||
Depreciation | 53,076 | 20,413 | 18,808 | — | — | 92,297 | ||||||||||||||
Taxes, other than income taxes | 80,530 | 19,626 | 20,098 | — | — | 120,254 | ||||||||||||||
Income taxes | 18,368 | 6,520 | 8,897 | — | — | 33,785 | ||||||||||||||
| 817,108 | 194,496 | 195,467 | — | — | 1,207,071 | |||||||||||||||
Operating income | 47,015 | 17,364 | 20,924 | — | — | 85,303 | ||||||||||||||
Other income | ||||||||||||||||||||
Allowance for equity funds used during construction | 2,891 | 197 | 587 | — | — | 3,675 | ||||||||||||||
Equity in earnings of subsidiaries | 25,158 | — | — | — | (25,158 | ) | — | |||||||||||||
Other, net | 3,446 | 251 | 393 | (146 | ) | (1,133 | ) | 2,811 | ||||||||||||
| 31,495 | 448 | 980 | (146 | ) | (26,291 | ) | 6,486 | |||||||||||||
Income (loss) before interest and other charges | 78,510 | 17,812 | 21,904 | (146 | ) | (26,291 | ) | 91,789 | ||||||||||||
Interest and other charges | ||||||||||||||||||||
Interest on long-term debt | 20,146 | 5,456 | 6,694 | — | — | 32,296 | ||||||||||||||
Amortization of net bond premium and expense | 1,041 | 301 | 316 | — | — | 1,658 | ||||||||||||||
Other interest charges | 3,027 | 1,004 | 285 | — | (1,133 | ) | 3,183 | |||||||||||||
Allowance for borrowed funds used during construction | (1,130 | ) | (75 | ) | (255 | ) | — | — | (1,460 | ) | ||||||||||
Preferred stock dividends of subsidiaries | — | — | — | — | 686 | 686 | ||||||||||||||
| 23,084 | 6,686 | 7,040 | — | (447 | ) | 36,363 | ||||||||||||||
Income (loss) before preferred stock dividends of HECO | 55,426 | 11,126 | 14,864 | (146 | ) | (25,844 | ) | 55,426 | ||||||||||||
Preferred stock dividends of HECO | 810 | 400 | 286 | — | (686 | ) | 810 | |||||||||||||
Net income (loss) for common stock | $ | 54,616 | 10,726 | 14,578 | (146 | ) | (25,158 | ) | $ | 54,616 | ||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Retained Earnings (unaudited)
Nine months ended September 30, 2005
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Retained earnings, beginning of period | $ | 632,779 | 85,861 | 94,492 | (187 | ) | (180,166 | ) | $ | 632,779 | ||||||||||
Net income (loss) for common stock | 54,616 | 10,726 | 14,578 | (146 | ) | (25,158 | ) | 54,616 | ||||||||||||
Common stock dividends | (33,955 | ) | (6,535 | ) | (9,548 | ) | — | 16,083 | (33,955 | ) | ||||||||||
Retained earnings, end of period | $ | 653,440 | 90,052 | 99,522 | (333 | ) | (189,241 | ) | $ | 653,440 | ||||||||||
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||
Balance, December 31, 2005 | $ | 1,039,259 | 189,407 | 194,190 | 118 | (383,715 | ) | $ | 1,039,259 | |||||||||||
Net income | 20,988 | 1,935 | 4,769 | (47 | ) | (6,657 | ) | 20,988 | ||||||||||||
Common stock dividends | (13,640 | ) | (1,423 | ) | (2,945 | ) | — | 4,368 | (13,640 | ) | ||||||||||
Balance, March 31, 2006 | $ | 1,046,607 | 189,919 | 196,014 | 71 | (386,004 | ) | $ | 1,046,607 | |||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Cash Flows (unaudited)
NineThree months ended September 30, 2006March 31, 2007
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||||||||||||||||||||||
Income (loss) before preferred stock dividends of HECO | $ | 62,750 | 7,752 | 14,476 | (134 | ) | (22,094 | ) | $ | 62,750 | $ | 723 | (5,930 | ) | 3,237 | (15 | ) | 2,708 | $ | 723 | ||||||||||||||||||||
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities | ||||||||||||||||||||||||||||||||||||||||
Equity in earnings | (21,483 | ) | — | — | — | 21,408 | (75 | ) | ||||||||||||||||||||||||||||||||
Equity in (earnings) loss | 2,912 | — | — | — | (2,937 | ) | (25 | ) | ||||||||||||||||||||||||||||||||
Common stock dividends received from subsidiaries | 9,471 | — | — | — | (9,396 | ) | 75 | 25 | — | — | — | — | 25 | |||||||||||||||||||||||||||
Depreciation of property, plant and equipment | 56,097 | 22,291 | 19,226 | — | — | 97,614 | 19,739 | 7,524 | 7,004 | — | — | 34,267 | ||||||||||||||||||||||||||||
Other amortization | 3,032 | 409 | 2,466 | — | — | 5,907 | 875 | (312 | ) | 743 | — | — | 1,306 | |||||||||||||||||||||||||||
Writedown of utility plant | — | 11,701 | — | — | — | 11,701 | ||||||||||||||||||||||||||||||||||
Deferred income taxes | (4,929 | ) | (521 | ) | (2,401 | ) | — | — | (7,851 | ) | (2,929 | ) | (4,845 | ) | (392 | ) | — | — | (8,166 | ) | ||||||||||||||||||||
Tax credits, net | 1,805 | 360 | 825 | — | — | 2,990 | 348 | 217 | 18 | — | — | 583 | ||||||||||||||||||||||||||||
Allowance for equity funds used during construction | (3,002 | ) | (156 | ) | (1,816 | ) | — | — | (4,974 | ) | (1,087 | ) | (65 | ) | (80 | ) | — | — | (1,232 | ) | ||||||||||||||||||||
Changes in assets and liabilities | ||||||||||||||||||||||||||||||||||||||||
Increase in accounts receivable | (6,401 | ) | (668 | ) | (1,018 | ) | — | 898 | (7,189 | ) | ||||||||||||||||||||||||||||||
Increase in accrued unbilled revenues | (4,536 | ) | (1,832 | ) | (1,000 | ) | — | — | (7,368 | ) | ||||||||||||||||||||||||||||||
Increase in fuel oil stock | (4,309 | ) | (2,230 | ) | (3,981 | ) | — | — | (10,520 | ) | ||||||||||||||||||||||||||||||
Decrease (increase) in accounts receivable | 11,848 | 2,846 | (2,978 | ) | — | 402 | 12,118 | |||||||||||||||||||||||||||||||||
Decrease in accrued unbilled revenues | 13,163 | 695 | 1,122 | — | — | 14,980 | ||||||||||||||||||||||||||||||||||
Decrease (increase) in fuel oil stock | (2,949 | ) | 2,184 | (1,638 | ) | — | — | (2,403 | ) | |||||||||||||||||||||||||||||||
Increase in materials and supplies | (601 | ) | (973 | ) | (1,749 | ) | — | — | (3,323 | ) | (1,226 | ) | (256 | ) | (444 | ) | — | — | (1,926 | ) | ||||||||||||||||||||
Decrease in prepaid pension benefit cost | 10,664 | 1,924 | 2,438 | — | — | 15,026 | ||||||||||||||||||||||||||||||||||
Decrease (increase) in regulatory assets | (218 | ) | 32 | (2,110 | ) | — | — | (2,296 | ) | |||||||||||||||||||||||||||||||
Decrease in accounts payable | (12,605 | ) | (2,243 | ) | (5 | ) | — | — | (14,853 | ) | ||||||||||||||||||||||||||||||
Increase in taxes accrued | 20,606 | 5,225 | 4,482 | — | — | 30,313 | ||||||||||||||||||||||||||||||||||
Increase in regulatory assets | (632 | ) | (183 | ) | (788 | ) | — | — | (1,603 | ) | ||||||||||||||||||||||||||||||
Increase (decrease) in accounts payable | 1,510 | (8,417 | ) | 4,432 | — | — | (2,475 | ) | ||||||||||||||||||||||||||||||||
Decrease in taxes accrued | (26,921 | ) | (5,395 | ) | (4,645 | ) | — | — | (36,961 | ) | ||||||||||||||||||||||||||||||
Changes in other assets and liabilities | (5,941 | ) | 5,624 | (1,504 | ) | — | (898 | ) | (2,719 | ) | 6,766 | 3,259 | (1,920 | ) | 3 | (402 | ) | 7,706 | ||||||||||||||||||||||
Net cash provided by (used in) operating activities | 100,400 | 34,994 | 28,329 | (134 | ) | (10,082 | ) | 153,507 | 22,165 | 3,023 | 3,671 | (12 | ) | (229 | ) | 28,618 | ||||||||||||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||||||||||||||||||||||
Capital expenditures | (65,033 | ) | (29,032 | ) | (43,280 | ) | — | — | (137,345 | ) | (21,284 | ) | (8,727 | ) | (4,811 | ) | — | — | (34,822 | ) | ||||||||||||||||||||
Contributions in aid of construction | 8,235 | 1,770 | 3,222 | — | — | 13,227 | 1,334 | 655 | 506 | — | — | 2,495 | ||||||||||||||||||||||||||||
Advances from (to) affiliates | (11,950 | ) | — | 5,250 | — | 6,700 | — | |||||||||||||||||||||||||||||||||
Other | 107 | — | — | — | 300 | 407 | ||||||||||||||||||||||||||||||||||
Advances to affiliates | 8,600 | — | (3,500 | ) | — | (5,100 | ) | — | ||||||||||||||||||||||||||||||||
Net cash used in investing activities | (68,641 | ) | (27,262 | ) | (34,808 | ) | — | 7,000 | (123,711 | ) | (11,350 | ) | (8,072 | ) | (7,805 | ) | — | (5,100 | ) | (32,327 | ) | |||||||||||||||||||
Cash flows from financing activities | ||||||||||||||||||||||||||||||||||||||||
Common stock dividends | (29,381 | ) | (2,874 | ) | (6,522 | ) | — | 9,396 | (29,381 | ) | ||||||||||||||||||||||||||||||
Preferred stock dividends | (810 | ) | (400 | ) | (286 | ) | — | 686 | (810 | ) | (270 | ) | (134 | ) | (95 | ) | — | 229 | (270 | ) | ||||||||||||||||||||
Proceeds from issuance of long-term debt | 130,959 | 19,850 | 64,870 | — | — | 215,679 | ||||||||||||||||||||||||||||||||||
Repayment of long-term debt | (62,280 | ) | (8,020 | ) | (55,700 | ) | — | — | (126,000 | ) | ||||||||||||||||||||||||||||||
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less | 3,665 | (2,800 | ) | 14,750 | — | (6,700 | ) | 8,915 | (62,365 | ) | (3,600 | ) | (5,000 | ) | — | 5,100 | (65,865 | ) | ||||||||||||||||||||||
Other | (3,295 | ) | (950 | ) | — | 300 | (300 | ) | (4,245 | ) | ||||||||||||||||||||||||||||||
Decrease in cash overdraft | (9,529 | ) | (1,705 | ) | (46 | ) | — | — | (11,280 | ) | ||||||||||||||||||||||||||||||
Net cash provided by (used in) financing activities | (29,821 | ) | (7,024 | ) | 7,942 | 300 | 3,082 | (25,521 | ) | (3,485 | ) | 6,391 | 4,029 | — | 5,329 | 12,264 | ||||||||||||||||||||||||
Net increase in cash and equivalents | 1,938 | 708 | 1,463 | 166 | — | 4,275 | ||||||||||||||||||||||||||||||||||
Net increase (decrease) in cash and equivalents | 7,330 | 1,342 | (105 | ) | (12 | ) | — | 8,555 | ||||||||||||||||||||||||||||||||
Cash and equivalents, beginning of period | 8 | 3 | 4 | 128 | — | 143 | 2,328 | 738 | 518 | 275 | — | 3,859 | ||||||||||||||||||||||||||||
Cash and equivalents, end of period | $ | 1,946 | 711 | 1,467 | 294 | — | $ | 4,418 | $ | 9,658 | 2,080 | 413 | 263 | — | $ | 12,414 | ||||||||||||||||||||||||
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Cash Flows (unaudited)
NineThree months ended September 30, 2005March 31, 2006
(in thousands) | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | HECO | HELCO | MECO | RHI | Reclassi- and elimina- tions | HECO consoli- dated | ||||||||||||||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||||||||||||||||||||||
Income (loss) before preferred stock dividends of HECO | $ | 55,426 | 11,126 | 14,864 | (146 | ) | (25,844 | ) | $ | 55,426 | $ | 21,258 | 2,069 | 4,864 | (47 | ) | (6,886 | ) | $ | 21,258 | ||||||||||||||||||||
Adjustments to reconcile income (loss) before preferred stock dividends of HECO to net cash provided by (used in) operating activities | ||||||||||||||||||||||||||||||||||||||||
Equity in earnings | (25,233 | ) | — | — | — | 25,158 | (75 | ) | (6,682 | ) | — | — | — | 6,657 | (25 | ) | ||||||||||||||||||||||||
Common stock dividends received from subsidiaries | 16,158 | — | — | — | (16,083 | ) | 75 | 4,393 | — | — | — | (4,368 | ) | 25 | ||||||||||||||||||||||||||
Depreciation of property, plant and equipment | 53,076 | 20,413 | 18,808 | — | — | 92,297 | 18,693 | 7,431 | 6,409 | — | — | 32,533 | ||||||||||||||||||||||||||||
Other amortization | 3,404 | 713 | 2,558 | — | — | 6,675 | 884 | 225 | 569 | — | — | 1,678 | ||||||||||||||||||||||||||||
Deferred income taxes | 11,829 | 2,266 | 3,840 | — | — | 17,935 | (1,993 | ) | (597 | ) | (1,800 | ) | — | — | (4,390 | ) | ||||||||||||||||||||||||
Tax credits, net | 1,100 | 604 | 96 | — | — | 1,800 | 720 | 142 | 367 | — | — | 1,229 | ||||||||||||||||||||||||||||
Allowance for equity funds used during construction | (2,891 | ) | (197 | ) | (587 | ) | — | — | (3,675 | ) | (1,077 | ) | (40 | ) | (431 | ) | — | — | (1,548 | ) | ||||||||||||||||||||
Changes in assets and liabilities | ||||||||||||||||||||||||||||||||||||||||
Increase in accounts receivable | (9,810 | ) | (3,658 | ) | (2,752 | ) | — | 1,282 | (14,938 | ) | ||||||||||||||||||||||||||||||
Increase in accrued unbilled revenues | (9,091 | ) | (959 | ) | (1,103 | ) | — | — | (11,153 | ) | ||||||||||||||||||||||||||||||
Decrease (increase) in fuel oil stock | (15,010 | ) | 522 | (4,720 | ) | — | — | (19,208 | ) | |||||||||||||||||||||||||||||||
Decrease in accounts receivable | 6,973 | 3,969 | 4,411 | — | 977 | 16,330 | ||||||||||||||||||||||||||||||||||
Decrease in accrued unbilled revenues | 6,841 | 1,176 | 1,896 | — | — | 9,913 | ||||||||||||||||||||||||||||||||||
Increase in fuel oil stock | (6,621 | ) | (689 | ) | (523 | ) | — | — | (7,833 | ) | ||||||||||||||||||||||||||||||
Increase in materials and supplies | (2,226 | ) | (761 | ) | (134 | ) | — | — | (3,121 | ) | �� | (579 | ) | (341 | ) | (901 | ) | — | — | (1,821 | ) | |||||||||||||||||||
Decrease in prepaid pension benefit cost | 3,441 | 650 | 1,309 | — | — | 5,400 | ||||||||||||||||||||||||||||||||||
Decrease (increase) in regulatory assets | (1,270 | ) | 459 | (2,004 | ) | — | — | (2,815 | ) | (673 | ) | 195 | (641 | ) | — | — | (1,119 | ) | ||||||||||||||||||||||
Increase (decrease) in accounts payable | (2,530 | ) | 974 | 586 | — | — | (970 | ) | ||||||||||||||||||||||||||||||||
Increase in taxes accrued | 3,750 | 4,450 | 2,416 | — | — | 10,616 | ||||||||||||||||||||||||||||||||||
Decrease in accounts payable | (1,657 | ) | (1,777 | ) | (3,302 | ) | — | — | (6,736 | ) | ||||||||||||||||||||||||||||||
Decrease in taxes accrued | (13,935 | ) | (3,849 | ) | (1,688 | ) | — | — | (19,472 | ) | ||||||||||||||||||||||||||||||
Changes in other assets and liabilities | (6,947 | ) | (296 | ) | (621 | ) | 8 | (1,282 | ) | (9,138 | ) | 6,269 | 2,979 | 1,168 | 6 | (977 | ) | 9,445 | ||||||||||||||||||||||
Net cash provided by (used in) operating activities | 73,176 | 36,306 | 32,556 | (138 | ) | (16,769 | ) | 125,131 | 32,814 | 10,893 | 10,398 | (41 | ) | (4,597 | ) | 49,467 | ||||||||||||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||||||||||||||||||||||
Capital expenditures | (84,606 | ) | (36,693 | ) | (21,274 | ) | — | — | (142,573 | ) | (22,109 | ) | (9,554 | ) | (11,416 | ) | — | — | (43,079 | ) | ||||||||||||||||||||
Contributions in aid of construction | 5,191 | 1,909 | 3,174 | — | — | 10,274 | 5,837 | 429 | 357 | — | — | 6,623 | ||||||||||||||||||||||||||||
Advances to affiliates | (6,350 | ) | — | (3,250 | ) | — | 9,600 | — | 100 | — | 4,500 | — | (4,600 | ) | — | |||||||||||||||||||||||||
Other | 1,476 | — | — | — | — | 1,476 | 108 | — | — | — | — | 108 | ||||||||||||||||||||||||||||
Net cash used in investing activities | (84,289 | ) | (34,784 | ) | (21,350 | ) | — | 9,600 | (130,823 | ) | (16,064 | ) | (9,125 | ) | (6,559 | ) | — | (4,600 | ) | (36,348 | ) | |||||||||||||||||||
Cash flows from financing activities | ||||||||||||||||||||||||||||||||||||||||
Common stock dividends | (33,955 | ) | (6,535 | ) | (9,548 | ) | — | 16,083 | (33,955 | ) | (13,640 | ) | (1,423 | ) | (2,945 | ) | — | 4,368 | (13,640 | ) | ||||||||||||||||||||
Preferred stock dividends | (810 | ) | (400 | ) | (286 | ) | — | 686 | (810 | ) | (270 | ) | (134 | ) | (95 | ) | — | 229 | (270 | ) | ||||||||||||||||||||
Proceeds from issuance of long-term debt | 51,525 | 5,000 | 2,000 | — | — | 58,525 | ||||||||||||||||||||||||||||||||||
Repayment of long-term debt | (40,000 | ) | (5,000 | ) | (2,000 | ) | — | — | (47,000 | ) | ||||||||||||||||||||||||||||||
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less | 39,683 | 6,350 | — | — | (9,600 | ) | 36,433 | |||||||||||||||||||||||||||||||||
Other | (4,873 | ) | (52 | ) | — | — | — | (4,925 | ) | |||||||||||||||||||||||||||||||
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less | 4,492 | (100 | ) | — | — | 4,600 | 8,992 | |||||||||||||||||||||||||||||||||
Decrease in cash overdraft | (5,836 | ) | (111 | ) | (513 | ) | — | — | (6,460 | ) | ||||||||||||||||||||||||||||||
Net cash provided by (used in) financing activities | 11,570 | (637 | ) | (9,834 | ) | — | 7,169 | 8,268 | ||||||||||||||||||||||||||||||||
Net cash used in financing activities | (15,254 | ) | (1,768 | ) | (3,553 | ) | — | 9,197 | (11,378 | ) | ||||||||||||||||||||||||||||||
Net increase (decrease) in cash and equivalents | 457 | 885 | 1,372 | (138 | ) | — | 2,576 | 1,496 | — | 286 | (41 | ) | — | 1,741 | ||||||||||||||||||||||||||
Cash and equivalents, beginning of period | 9 | 3 | 17 | 298 | — | 327 | 8 | 3 | 4 | 128 | — | 143 | ||||||||||||||||||||||||||||
Cash and equivalents, end of period | $ | 466 | 888 | 1,389 | 160 | — | $ | 2,903 | $ | 1,504 | 3 | 290 | 87 | — | $ | 1,884 | ||||||||||||||||||||||||
| Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in HEI’s and HECO’s 20052006 Form 10-K and Forms 10-Q for the quarters ended March 31 and June 30, 2006 and should be read in conjunction with the annual (as of and for the year ended December 31, 2005)2006) and quarterly (as of and for the three months ended March 31, 2006 and as of and for the three and six months ended June 30, 2006)2007) consolidated financial statements of HEI and HECO and accompanying notes.
RESULTS OF OPERATIONS
(in thousands, except per share amounts) | Three months ended September 30 | % change | Primary reason(s) for significant change* | ||||||||
| 2006 | 2005 | ||||||||||
Revenues | $ | 673,894 | $ | 595,915 | 13 | Increases for the electric utility and bank segments, partly offset by a decrease for the “other” segment | |||||
Operating income | 66,356 | 77,239 | (14 | ) | Decreases for the bank and the “other” segments, slightly offset by an increase for the electric utility segment | ||||||
Net income | 32,323 | 37,490 | (14 | ) | Lower operating income, partly offset by lower “interest expense–other than bank” and higher AFUDC | ||||||
Basic earnings per common share | $ | 0.40 | $ | 0.46 | (13 | ) | See explanation for net income above and weighted-average number of common shares outstanding below | ||||
Weighted-average number of common shares outstanding | 81,213 | 80,903 | — | Issuances of shares under stock option and non-employee director plans | |||||||
(in thousands, except per share amounts) Nine months ended September 30 % change Primary reason(s) for significant change* Revenues Operating income Income (loss) from: Continuing operations Discontinued operations Net income Basic earnings (loss) per common share–Continuing operations Discontinued operations Weighted-average number of common shares outstanding 2006 2005 $ 1,853,825 $ 1,590,805 17 Increases for the electric utility and bank segments, slightly offset by a decrease for the “other” segment 196,236 195,359 — Increase for the electric utility segment, largely offset by decreases for the bank and the “other” segments $ 91,884 $ 89,920 2 Higher operating income and higher AFUDC — (755 ) NM Increase in reserve in the second quarter of 2005 for higher arbitration costs relating to HEIPC $ 91,884 $ 89,165 3 $ 1.13 $ 1.11 2 — (0.01 ) NM $ 1.13 $ 1.10 3 See explanation for income (loss) above and weighted-average number of common shares outstanding below 81,099 80,795 — Issuances of shares under stock option and non-employee director plans
NM Not meaningful.
(in thousands, except per share amounts) | Three months ended March 31, | % change | Primary reason(s) for significant change* | ||||||||
| 2007 | 2006 | ||||||||||
Revenues | $ | 554,023 | $ | 574,962 | (4 | ) | Decrease for the electric utility segment, slightly offset by increases for the bank and “other” segments | ||||
Operating income | 28,541 | 69,151 | (59 | ) | Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment | ||||||
Net income | 6,764 | 32,337 | (79 | ) | Lower operating income and AFUDC and higher “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by lower taxes resulting from lower income before taxes and a lower effective income tax rate ** | ||||||
Basic earnings per common share | $ | 0.08 | $ | 0.40 | (80 | ) | Lower net income | ||||
Weighted-average number of common shares outstanding | 81,448 | 80,981 | 1 | Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans | |||||||
| * | Also, see segment discussions |
| ** | The Company’s effective tax rate for the first quarter of 2007 was 28%, compared to an effective tax rate for the first quarter of 2006 of 38% (see Note 10 in HEI’s “Notes to Consolidated Financial Statements”). |
Dividends
On October 31, 2006,May 3, 2007, HEI’s Board of Directors maintained the quarterly dividend of $0.31 per common share. The payout ratios for 20052006 and the first nine monthsquarter of 20062007 were 79%93% and 82% (payout ratios388%, respectively. Historically low net income for the first quarter of 78%2007 resulted in a dividend payout nearly four times greater than net income. Net income for the first quarter of 2007 was affected by a number of factors, including higher operations and 82% based on income from continuing operations), respectively.maintenance expenses and a $7 million (net of taxes) write-off of plant at the electric utilities and higher legal and litigation expenses at ASB (see “Results of Operations” in the “Electric Utilities” and “Bank” sections below). HEI’s Board and management continues to believe that theyHEI should not considerachieve a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level until HEI improves its payout ratio to 65% on a sustainable basis and has sufficient cash flows to support an increase.level.
Economic conditions
Note: The statistical data in this section is from public third party sources (e.g., State of Hawaii Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).
Because HEI’s core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – tourism and the federal government, – was 3.4% in 2005. State economists forecast growth ofestimated at 2.7% for 2006.2006 and is forecast by DBEDT to further moderate to 2.6% for 2007.
According to the latest available data, Hawaii ranked fifth among the states in its receipt of federal government expenditures per capita. For the federal fiscal year ended September 30, 2004 (latest available data), total federal
government expenditures in Hawaii, including military expenditures, were $12.2 billion or $9,651 per capita, increasing 8% and 7%, respectively, over fiscal year 2003. Military spending, which is 39% of federal expenditures in Hawaii, increased 6% in fiscal year 2004 compared to fiscal year 2003.
Tourism is widely acknowledged as a significant component of Hawaii’s economy. 2005 wasIn 2006, visitor expenditures reached a record year for tourism in Hawaii, with visitor days exceeding the 2004 record by 7.7%. Visitor expenditures were $11.9$12.3 billion, in 2005, which was a 9.6%3% increase over 2004. For the first eight months of2005. 2006 visitor days were relatively flatslightly lower by 0.3% compared to the 2005 record-high level. State economists currently expect marginal visitor growth in 2007 due to capacity constraints with projected increases of 1.5% in visitor days and 4.8% in visitor expenditures. Although visitor days year-to-date through February 2007 were down 3.7% compared to the same period for 2005, buta year ago, visitor expenditures were up 4.5%1.2%. State economists expect continued growth in tourism in 2006 with projected increases of 2.8% in visitor days and 7.1% in visitor expenditures.
The real estate and construction industries in Hawaii also influence HEI’s core businesses. The Oahu housing market is slowingcontinuing to stabilize with sales volumes decliningprices down from their 2006 record high levels and inventory is returning to historicalmore normal levels. The number of sales for the first nine months of 2006 decreased by 11.9% compared to the same period last year. Although sales are slowing, Oahu median prices continue to stablilize. The median home price on Oahu was $620,000$643,500 in September 2006,March 2007 compared to the median price of $615,000$650,000 in September 2005.March 2006. Total sales of single-family homes in the first quarter of 2007 decreased 15.8% compared to the first quarter of 2006, in line with a stabilizing market.
The construction industry continues to beremain healthy, indicated by a 26%7.7% increase in building permits for the first nine months of 2006year-to-date through February 2007 compared with the same period last year. Local economists continue to expect a gradual slowing of growth in residential construction as rising costs meet flattening demand. However, it is expectedover the next few years, and that increased military and commercial construction will continue to be stabilizing factors.
Overall, the outlook for Hawaii’s economy remains positive. However, economic growth is affected by the expansion rate of expansion in the mainland U.S. and Japan economies and the growth in military spending, and is vulnerable to uncertainties in the world’s geopolitical environment. The projected real gross domestic product (GDP) growth for the U.S. and Japan in 2007 are 2.7% and 2.1%, respectively.
Management also monitors (1) oil prices, because of their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates, because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Crude oil prices remained highwere around $60 per barrel during the thirdfirst quarter of 2006 but recently have come off their high levels due2007, compared to a slowing U.S. economy and lessening concerns about Iran continuing its nuclear program. Thean average fuel oil costprice of $70.28 per barrel forin 2006, and are expected to stabilize in the electric utilities increased 24% and 31% for$60-$70 range.
Long-term interest rates were flat in the three and nine months ended September 30, 2006, respectively, compared tofirst quarter of 2007 with the same periods in 2005. On October 27, 2006, crude oil futures closed at $60.78 per barrel.
The 10-year Treasury yield was 4.64% astrading in the 4.5%-4.9% range. At the end of September 29, 2006 comparedMarch 2007, while still considered to 5.15% as of June 30, 2006.be flat, the yield curve began to slope upward which may signal concern for future inflation. The spread between the 10-year and 2-year Treasuries was (0.08)% as of October 27, 2006, compared to spreads of (0.07)% as of September 29, 2006, (0.01)% as of June 30, 2006, 0.04%0.07% as of March 31, 20062007, and (0.02)0.01% as of May 1, 2007, compared to a spread of (0.10)% as of December 31, 2005.2006.
Pension and other postretirement benefits
See Note 5 and Note 4 of HEI’s and HECO’s “Notes to Consolidated Financial Statements,” respectively, for information concerning retirement benefit plan contributions and net periodic benefit costs and expenses. Retirement benefits expense and cash funding requirements could increase in future years depending on numerous factors, including the performance of the equity markets and changes in interest rates.
For the first nine months of 2006, the retirement benefit plan assets generated a total return of 6.5%, resulting in realized and unrealized net gains of approximately $59 million, compared to a 9% annual expected return on plan
assets assumption and a total return of 7.2% for 2005. The market value of the retirement benefit plans’ assets as of September 30, 2006 was $960 million.
In part, the Company benchmarks its discount rate assumption to the Moody’s Daily Long-Term Corporate Bond Aa Yield Average, which was 5.66% at September 30, 2006 compared to 5.41% at December 31, 2005. The discount rate used at December 31, 2005 was 5.75%. The Company projects the discount rate at December 31, 2006 will be between 5.75% and 6.25%.
Consolidated HEI’s, consolidated HECO’s and ASB’s net periodic pension and other postretirement benefits expenses, net of amounts capitalized and tax benefits, are estimated to be $17 million, $13 million and $3 million, respectively, for 2006, compared to $11 million, $8 million and $2 million, respectively, for 2005.
Based on the market value of the pension plans’ assets as of December 31, 2005, a 9% return on plan asset assumption, contributions of $14 million in 2006, a range of 5.75% to 6.25% for the discount rate at December 31, 2006, and no further changes in assumptions or pension plan provisions, consolidated HEI’s, consolidated HECO’s and ASB’s 2007 retirement benefit expenses, net of amounts capitalized and tax benefits, are estimated to be:
Retirement benefit expense, net of amounts capitalized and tax benefits“Other” segment
| Discount rate | ||||||
($ in millions) | 5.75% | 6.25% | ||||
Consolidated HEI | $ | 19 | $ | 16 | ||
Consolidated HECO | 15 | 13 | ||||
ASB | 3 | 2 | ||||
The electric utilities’ retirement benefit expenses have been allowable expenses for rate-making, and higher retirement benefit expenses, along with other factors, may affect the timing and amount of future electric rate increase requests.
The Company expects to report increased liabilities on its balance sheet to recognize the funded status of pension and other postretirement benefit plans at December 31, 2006 as a result of the Company’s adoption on that date of SFAS No. 158, “Accounting for Defined Benefit Pension and other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” The electric utilities, however, plan to update their application in the AOCI Docket to take into account SFAS No. 158 in seeking PUC approval to record as a regulatory asset the amount that would otherwise be charged against stockholders’ equity. See “Defined benefit pension and other postretirement plans” in Note 9 of HEI’s “Notes to Consolidated Financial Statements” for a discussion of SFAS No. 158, its potential effects, and how these effects may be mitigated if the PUC grants the electric utilities’ request in the AOCI docket, which is planned to be updated for SFAS No. 158, or if the PUC allows a return on the electric utilities’ prepaid pension assets (by inclusion in rate base) in rate cases.
Based on the same assumptions used to estimate 2007 retirement benefits expense above, consolidated HEI’s, consolidated HECO’s and ASB’s AOCI balances, net of tax benefits, related to SFAS No. 158 at December 31, 2006 are estimated to be:
Estimated AOCI balance, net of tax benefits, related to SFAS No. 158
| Discount rate | ||||||
($ in millions) | 5.75% | 6.25% | ||||
Consolidated HEI | $ | 190 | $ | 144 | ||
Consolidated HECO | 173 | 131 | ||||
ASB | 12 | 8 | ||||
The Pension Protection Act of 2006. The Pension Protection Act of 2006 (the 2006 Act) was signed into law on August 17, 2006. The 2006 Act makes significant changes to a wide variety of rules that apply to employee benefit plans, including those dealing with minimum funding requirements of defined benefit pension plans and plan investments of defined contribution pension plans. The 2006 Act also permanently extended the pension law changes made by the Economic Growth and Tax Relief Reconciliation Act of 2001, which had been scheduled to sunset on December 31, 2010. Due to the Company’s pension plans’ funded status and funding policy, the Company
does not expect this new law will have a material impact on the Company’s results of operations, financial condition or liquidity when implemented in 2008.
“Other” segment
| Three months ended September 30 | % change | Primary reason(s) for significant change | |||||||||||
(in thousands) | 2006 | 2005 | |||||||||||
Revenues | $ | 718 | $ | 7,145 | (90 | ) | Net unrealized and realized gain of $0.6 million in 2006 compared to net unrealized gain of $6.6 million in 2005 on Hoku shares (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) | ||||||
Operating income (loss) | (2,873 | ) | 3,768 | NM | See explanation for revenues and higher retirement benefit expense and legal and consulting fees | ||||||||
Net loss | (4,813 | ) | (1,008 | ) | NM | See explanation for operating loss, partly offset by lower interest expense due to temporary refinancing of long-term debt with short-term borrowings | |||||||
Three months ended March 31, | % change | Primary reason(s) for significant change | ||||||||||||||||||||||
| (in thousands) | Nine months ended September 30 | % change | Primary reason(s) for significant change | 2007 | 2006 | |||||||||||||||||||
| 2006 | 2005 | |||||||||||||||||||||||
Revenues | $ | (934 | ) | $ | 8,360 | NM | Net unrealized and realized loss of $2.0 million in 2006 compared to net unrealized gain of $6.6 million in 2005 on Hoku shares (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) | $ | 1,885 | $ | (98 | ) | NM | Gain on the sale of Hoku shares of $1.4 million in the first quarter of 2007 compared to an unrealized and realized loss of $0.6 million in the first quarter of 2006 (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) | ||||||||||
Operating loss | (11,593 | ) | (3,520 | ) | NM | See explanation for revenues and higher retirement benefit expense and legal and consulting fees, partly offset by lower stock-based compensation expense | (2,879 | ) | (3,444 | ) | NM | Gain on the sale of Hoku shares versus prior year unrealized and realized loss, partly offset by higher consulting and other administrative and general expenses | ||||||||||||
Net loss | (16,571 | ) | (11,920 | ) | NM | See explanation for operating loss and lower income tax benefit primarily due to the resolution of audit issues with the Internal Revenue Service in 2005, partly offset by lower interest expense due to temporary refinancing of long-term debt with short-term borrowings and prior year interest on tax issues | (5,285 | ) | (5,478 | ) | NM | See explanation for operating loss, partly offset by higher interest expense primarily due to higher short-term borrowing rates and average balances | ||||||||||||
NM Not meaningful.
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, venture capital investments; Hycap Management, Inc. (which is in dissolution); The Old Oahu Tug Service, Inc., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, which are both holding companies; and eliminations of intercompany transactions.
Commitments and contingencies
See Note 4, “Bank Subsidiary,”7 of HEI’s “Notes to Consolidated Financial Statements” and Note 5, “Commitments“Commitment and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretations
See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”
FINANCIAL CONDITION
Liquidity and capital resources
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, lines of credit and bank borrowings, is adequate to maintain sufficient liquidity to fund the Company’s 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 and ASB’s other borrowings) was as follows as of the dates indicated:
(in millions) | September 30, 2006 | December 31, 2005 | ||||||||||
Short-term borrowings—other than bank | $ | 195 | 7 | % | $ | 142 | 6 | % | ||||
Long-term debt, net—other than bank | 1,133 | 44 | 1,143 | 45 | ||||||||
Preferred stock of subsidiaries | 34 | 1 | 34 | 1 | ||||||||
Common stock equity | 1,238 | 48 | 1,217 | 48 | ||||||||
| $ | 2,600 | 100 | % | $ | 2,536 | 100 | % | |||||
As of October 31, 2006, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:
| ||||
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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 August 2006, S&P affirmed its corporate credit ratings of HEI and maintained its negative outlook. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P indicated that “credit-supportive actions by the company as well as responsive rate treatment would lead to ratings stability.” See “Electric Utilities—Liquidity and capital resources” below. In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). There was no change in August 2006 in HEI’s business profile rank of “6”. Moody’s maintains a stable outlook for HEI.
On August 8, 2006, HEI completed the sale of $100 million of 6.141% Medium-Term Notes, Series D due August 15, 2011, under its registered medium-term note program. The proceeds from the sale were ultimately used to reduce HEI’s outstanding commercial paper as it matured. As of September 30, 2006, $96 million of debt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration and an additional $50 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program.
HEI 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, including the funding of loans by HECO to HELCO and MECO. HEI had an average outstanding balance of commercial paper for the first nine months of 2006 of $74 million and had $49 million outstanding as of September 30, 2006. HEI’s commercial paper outstanding is expected to increase through the remainder of 2006 as a result of HECO’s plans to not declare a dividend to HEI in the fourth quarter of 2006. The decrease in HECO’s dividend is expected to continue to be partly offset by the increase in ASB’s dividend to HEI. See “Electric Utilities—Liquidity and capital resources” and “Bank—Liquidity and capital resources” below. Management believes that if HEI’s commercial paper ratings were to be downgraded, it may be more difficult to sell commercial paper under current market conditions.
Effective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of credit facility of $100 million, with a letter of credit sub-facility, expiring on March 31, 2011, with a syndicate of eight financial institutions. Any draws on the facility bear interest, at the option of HEI, at the “Adjusted LIBO Rate” plus 50 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on undrawn commitments are 10 basis points. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Senior Debt Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2.5 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1) would result in a commitment fee decrease of 2 basis points and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions which must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratio, as defined in its agreement, or meet other requirements will result in an event of default. For example, under its agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 27% as of September 30, 2006) and “Consolidated Net Worth” of $850 million (Net Worth of $1.3 billion as of September 30, 2006), if there is a “Change in Control” of HEI, if any event or condition occurs that results in any “Material Indebtedness” of HEI being subject to acceleration prior to its scheduled maturity, if any “Material Subsidiary Indebtedness” actually becomes due prior to its scheduled maturity, or if ASB fails to remain well capitalized and to maintain specified minimum capital ratios. Also effective April 3, 2006, HEI entered into a $75 million bilateral revolving unsecured credit agreement with Merrill Lynch Bank USA. This bilateral agreement was subsequently terminated in accordance with its terms effective August 11, 2006. See Note 12 of HEI’s “Notes to Consolidated Financial Statements” for additional discussion of the credit facilities.
For the first nine months of 2006, net cash provided by operating activities of consolidated HEI was $203 million. Net cash used in investing activities was $60 million primarily due to the purchases of investment securities and net increase in loans receivable at ASB and HECO’s consolidated capital expenditures, partly offset by repayments and sales of mortgage-related securities. Net cash used in financing activities was $168 million as a result of several factors, including net decreases in deposit liabilities, other bank borrowings and long-term debt and the payment of common stock dividends, partly offset by a net increase in short-term borrowings.
Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.
RESULTS OF OPERATIONS
(dollars in thousands, except per barrel amounts) | Three months ended September 30 | % change | Primary reason(s) for significant change | ||||||||
| 2006 | 2005 | ||||||||||
Revenues | $ | 569,838 | $ | 491,339 | 16 | Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers through energy cost adjustment clauses ($63 million, including related revenue taxes), HECO interim rate relief ($11 million) and higher KWH sales ($3 million) (See “Most recent rate requests-HECO” below for a discussion of the energy cost adjustment clauses.) | |||||
Expenses | |||||||||||
Fuel oil | 227,288 | 182,663 | 24 | Higher fuel oil costs | |||||||
Purchased power | 138,758 | 122,086 | 14 | Higher fuel costs and more KWHs purchased | |||||||
Other | 155,141 | 139,057 | 12 | Higher other operation and maintenance expenses ($7 million), depreciation ($2 million), and taxes, other than income taxes ($7 million) | |||||||
Operating income | 48,651 | 47,533 | 2 | HECO interim rate relief and slightly higher KWH sales, partly offset by higher expenses | |||||||
Net income | 23,666 | 22,587 | 5 | Higher operating income, higher AFUDC and slightly lower interest expense (primarily due to the interest benefit from the resolution of audit issues with the Internal Revenue Service, largely offset by higher short-term borrowings average balance and interest rates) | |||||||
Kilowatthour sales (millions) | 2,678 | 2,672 | — | New load growth, mostly offset by generally cooler, less humid weather and customer conservation | |||||||
Oahu cooling degree days (CDD) | 1,469 | 1,649 | (11 | ) | |||||||
Average fuel oil cost per barrel | $ | 74.35 | $ | 59.74 | 24 | ||||||
(in thousands, except per share amounts) | Three months ended March 31, | % change | Primary reason(s) for significant change* | ||||||||
| 2007 | 2006 | ||||||||||
Revenues | $ | 554,023 | $ | 574,962 | (4 | ) | Decrease for the electric utility segment, slightly offset by increases for the bank and “other” segments | ||||
Operating income | 28,541 | 69,151 | (59 | ) | Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment | ||||||
Net income | 6,764 | 32,337 | (79 | ) | Lower operating income and AFUDC and higher “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by lower taxes resulting from lower income before taxes and a lower effective income tax rate ** | ||||||
Basic earnings per common share | $ | 0.08 | $ | 0.40 | (80 | ) | Lower net income | ||||
Weighted-average number of common shares outstanding | 81,448 | 80,981 | 1 | Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans | |||||||
| * | Also, see segment discussions which follow. |
| ** | The Company’s effective tax rate for the first quarter of 2007 was 28%, compared to an effective tax rate for the first quarter of 2006 of 38% (see Note 10 in HEI’s “Notes to Consolidated Financial Statements”). |
Dividends
(dollars in thousands, except per barrel amounts) Nine months ended September 30 % change Primary reason(s) for significant change Revenues Expenses Fuel oil Purchased power Other Operating income Net income Kilowatthour sales (millions) Oahu cooling degree days (CDD) Average fuel oil cost per barrel 2006 2005 $ 1,548,861 $ 1,295,844 20 Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers through energy cost adjustment clauses ($210 million, including related revenue taxes), HECO interim rate relief ($30 million) and higher KWH sales at HELCO and MECO ($8 million), partly offset by lower KWH sales at HECO ($2 million) and lower DSM lost margins and shareholder incentives ($2M) (See “Most recent rate requests-HECO” below for a discussion of the energy cost adjustment clauses.) 594,940 447,064 33 Higher fuel oil costs and more KWHs generated 378,916 329,671 15 Higher fuel costs, partly offset by less KWHs purchased 440,928 397,323 11 Higher other operation and maintenance expenses ($16 million), depreciation ($5 million), and taxes, other than income taxes ($22 million) 134,077 121,786 10 HECO interim rate relief, partly offset by higher expenses and lower DSM lost margins and shareholder incentives 61,940 54,616 13 Higher operating income and higher AFUDC, partly offset by higher interest expense (due to higher short-term borrowings average balance and interest rates, partly offset by the interest benefit from the resolution of audit issues with the Internal Revenue Service) 7,528 7,538 — Generally cooler, less humid weather and customer conservation, partly offset by new load growth 3,323 3,900 (15 ) $ 69.09 $ 52.85 31
See “Economic conditions”On May 3, 2007, HEI’s Board of Directors maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2006 and the first quarter of 2007 were 93% and 388%, respectively. Historically low net income for the first quarter of 2007 resulted in a dividend payout nearly four times greater than net income. Net income for the first quarter of 2007 was affected by a number of factors, including higher operations and maintenance expenses and a $7 million (net of taxes) write-off of plant at the electric utilities and higher legal and litigation expenses at ASB (see “Results of Operations” in the “HEI Consolidated”“Electric Utilities” and “Bank” sections below). HEI’s Board and management continues to believe that HEI should achieve a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.
Economic conditions
Note: The statistical data in this section above.is from public third party sources (e.g., State of Hawaii Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).
ResultsBecause HEI’s core businesses provide local electric utility and banking services, HEI’s operating results are significantly influenced by the strength of Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – three monthstourism and the federal government, was estimated at 2.7% for 2006 and is forecast by DBEDT to further moderate to 2.6% for 2007.
According to the latest available data, Hawaii ranked fifth among the states in its receipt of federal government expenditures per capita. For the federal fiscal year ended September 30, 20062004 (latest available data), total federal
government expenditures in Hawaii, including military expenditures, were $12.2 billion or $9,651 per capita, increasing 8% and 7%, respectively, over fiscal year 2003. Military spending, which is 39% of federal expenditures in Hawaii, increased 6% in 2004 compared to 2003.
Operating income forTourism is widely acknowledged as a significant component of Hawaii’s economy. In 2006, visitor expenditures reached a record $12.3 billion, a 3% increase over 2005. 2006 visitor days were slightly lower by 0.3% compared to the third quarter2005 record-high level. State economists currently expect marginal visitor growth in 2007 due to capacity constraints with projected increases of 2006 increased 2% when1.5% in visitor days and 4.8% in visitor expenditures. Although visitor days year-to-date through February 2007 were down 3.7% compared to the same period a year ago, visitor expenditures were up 1.2%.
The real estate and construction industries in 2005 due primarilyHawaii also influence HEI’s core businesses. The Oahu housing market is continuing to interim rate relief granted bystabilize with sales prices down from their 2006 record levels and inventory returning to more normal levels. The median home price on Oahu was $643,500 in March 2007 compared to the PUC to HECOmedian of $650,000 in late September 2005, partly offset by higher expenses. KWHMarch 2006. Total sales of single-family homes in the thirdfirst quarter of 2007 decreased 15.8% compared to the first quarter of 2006, were relatively flat whenin line with a stabilizing market.
The construction industry continues to remain healthy, indicated by a 7.7% increase in building permits year-to-date through February 2007 compared towith the same period last year. Local economists continue to expect slowing of growth in 2005, primarily due to generally cooler, less humid weather and customer conservation partially in response to the higher cost per KWH due to higher fuel prices, more than offset by new load growth (i.e., increase in number of customers and new construction). The electric utilities expect the conservation trend to continue as fuel prices remain high. Other operation expense increased 11% primarily due to higher retirement benefits expense, higher production operations expense (including lease rent and operating expenses for distributed generation units on Oahu) and higher demand-side management expenses. Pension and other postretirement benefit expenses for the electric utilities increased $2.2 millionresidential construction over the same period in 2005. Maintenance expense increased by 12% due to higher production maintenance expense (primarily due to the greater scope of generating unit overhauls)next few years, and higher substation maintenance expense. Other operationsthat military and maintenance expenses also include increased staffing and other costs
to support the increased level of peak demand that has occurred over the past five years, reliability, customer service and energy efficiency programs. Higher depreciation expense was attributable to additions to plant in service in 2005 (including HECO’s New Kuahua Substation, Mokuone Substation 46kV and 12kV line extensions, an office building air conditioning replacement and HELCO’s Keahole power plant noise mitigation measures).
Results – nine months ended September 30, 2006
Operating income for the first nine months of 2006 increased 10% over the same period in 2005 due primarily to interim rate relief granted by the PUC to HECO in late September 2005 and lower purchase power capacity charges due primarily to lower availability caused by scheduled major maintenance by an IPP, which was not performed in 2005, partly offset by higher expenses and lower DSM lost margins and shareholder incentives. KWH sales in the first nine months of 2006 were relatively flat when compared to the same period in 2005, primarily due to generally cooler, less humid weather and customer conservation partially in response to the higher cost per KWH, partly offset by new load growth (i.e., increase in number of customers and new construction). The electric utilities expect their full-year 2006 KWH sales to be down by 0.3% compared with 2005. In 2007 and 2008, the electric utilities are currently estimating KWH sales to be moderately higher over the prior year by 1.2% and 1.6%, respectively. Other operation expense increased 9% primarily due to higher retirement benefits expense, higher production operations expense (including expenses incurred to sustain or increase generating unit availability and lease rent and operating expenses for distributed generation units on Oahu) and higher demand-side management expenses. Pension and other postretirement benefit expenses for the electric utilities increased $6.7 million over the same period in 2005. Maintenance expense increased by 7% due to higher production maintenance expense (primarily due to higher steam generation station maintenance expense and greater scope of generating unit overhauls). Higher depreciation expense was attributable to additions to plant in service in 2005 as described above.
The trend of increased operation and maintenance (O&M) expenses is expected to continue as the electric utilities expect (1) higher demand-side management expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved pursuant to an interim decision and order in an energy efficiency DSM Docket), (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to support the increased level of peak demand that has occurred over the past five years. Also, since May 26, 2006, HECO and, since September 26, 2006, HELCO and MECO have discontinued their recovery of lost margins and shareholder incentives for their DSM programs until further order by the PUC, which has resulted in reduced revenues.
In the fourth quarter of 2006, the electric utilities expect O&M expenses to increase significantly. Repairs and maintenance scheduled for earlier in 2006 were delayed and are now expected to occur in the fourth quarter of 2006. Changes in overhaul schedules affected the timing of repairs and maintenance. Also, rainy weather has resulted in increased vegetation management expenses. Another factor anticipated to impact O&M expense in the fourth quarter of 2006 is costs related to two earthquakes on October 15, 2006, which led to outages (see “Recent outages” below).
As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. Generation reserve margins on Oahu and Maui during peak periods continued to be strained. The electric utilities on Oahu and Maui have taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation at some substations and encouraging energy conservation. The marginal costs of supplying energy to meet growing demand, however, are increasing because of the decreasing reserve margin situation, and the trend of cost increases is not likely to ease. Increased O&M expense was one of the reasons HECO and HELCO filed requests with the PUC in November 2004 and May 2005, respectively, to increase base rates and HECO and MECO filed in September 2006 notices of intent to request increased base rates. See “Most recent rate requests.”
Competition
Although competition in the generation sector in Hawaii has been moderated by the scarcity of generation sites, various permitting processes and lack of interconnections to other electric utilities, HECO and its subsidiaries face competition from IPPs and customer self-generation, with or without cogeneration.
In October 2003, the PUC opened investigative proceedings on two specific issues (competitive bidding and DG) to move toward a more competitive electric industry environment under cost-based regulation.
Competitive bidding proceeding. The stated purpose of this proceeding is to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii.
The current parties in the proceeding include the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC) and Hawaii Renewable Energy Alliance (HREA), a renewable energy organization. The issues addressed in the proceeding included whether a competitive bidding system should be developed for acquiring or building new generation and, if so, 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 were filed in March through August 2005. The PUC held panel hearings in December 2005. In May 2006, all of the parties, except HREA, jointly filed a proposed competitive bidding framework incorporating areas of agreement in on-going settlement discussions. In June 2006, briefs addressing any areas of disagreement and post-hearing questions posed by the PUC were filed and oral arguments were presented.
On June 30, 2006, the PUC issued a D&O in this proceeding, which included a proposed framework to govern competitive bidding. The D&O contained modifications to the framework proposed by the stipulating parties and stated (1) a utility is required to use competitive bidding to acquire future generation resources or blocks of generation resources, unless the PUC finds bidding to be unsuitable pursuant to a waiver request, (2) the final decision on whether to use competitive bidding for a particular project will be made by the PUC during its review of the utility’s integrated resource plan (IRP), (3) exemption from the framework would be granted for cooperatively-owned utilities, for three pending projects (HECO’s CT-1, HELCO’s ST-7 and MECO’s M-18 projects), and specifically identified offers to sell energy on an as-available basis by non-fossil fuel producers that are under review by an electric utility at the time this framework is adopted, (4) waivers will be granted where bidding will be unproductive or will conflict with the utility’s obligation to bring resources on-line in a timely manner and at reasonable cost, (5) the parties are required to submit briefs that address issues regarding Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA), (6) the utility is required to submit a report on the cost of parallel planning upon the PUC’s request and the utility must submit a code of conduct to the PUC for approval prior to the commencement of any competitive bid process under this framework, (7) the utility is required to consider the effects on competitive bidding of not allowing site access to bidders and present reasons for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (8) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its Request for Proposal or when the PUC otherwise determines, (9) in evaluating the utility’s bid, the independent observer is required to address the probability that later costs will exceed the utility’s original bid, (10) the utility may consider a bid from its affiliate if the PUC determines, prior to commencement of the competitive bidding process, that the affiliate has no advantage due to its past or present relationship to the utility, or the affiliate is a qualifying facility exercising its mandatory sales rights under PURPA, and (11) the utility is required to submit a proposed tariff containing procedures for interconnection and transmission upgrades within 90 days after the issuance of the framework. On September 11, 2006, HECO, HELCO and MECO, the Consumer Advocate and HREA each submitted comments on the proposed framework and responded to the PURPA issues in the D&O. KIUC submitted a letter stating that it had no comments on the proposed framework. Management cannot currently predict the ultimate effect of this proceeding on the ability of the electric utilities to acquire or build additional generating capacity in the future.
Distributed generation proceeding. In October 2003, the PUC opened a DG proceeding to determine DG’s potential benefits to and impact on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii.
On January 27, 2006, the PUC issued its D&O in the DG proceeding. In the D&O, the PUC indicated that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost,
DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system.
With regard to DG ownership, the D&O affirmed the ability of the electric utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. In weighing the general advantages and disadvantages of allowing a utility to provide DG services on a customer’s site, the PUC found that the “disadvantages outweigh the advantages.” However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the electric utilities from providing DG services at this early stage of DG market development.
Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.
On March 1, 2006, the electric utilities filed a Motion for Clarification and/or Partial Reconsideration (DG Motion), requesting that the PUC clarify how the three conditions under which electric utilities are allowed to provide regulated DG services at customer-owned sites will be administered, in order to better determine the impacts the conditions may have on the electric utilities’ DG plans. On April 6, 2006, the PUC issued its decision on the electric utilities’ DG Motion. The PUC provided clarification to the conditions under which the electric utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework), and affirmed that the electric utility has the responsibility to demonstrate that it meets all applicable criteria included in the D&O in its application for PUC approval to proceed with a specific DG project.
The electric utilities are currently evaluating several potential DG and CHP (a form of DG) projects. If a decision is made to pursue a specific project, an application requesting project approval will be filed with the PUC. In July 2006, MECO filed an application for approval of an agreement for the installation of a CHP system on the island of Lanai. On September 11, 2006, the PUC issued a Schedule of Proceedings for its consideration of this CHP project, establishing completion of all filings in the docket by February 8, 2007.
The D&O also required the electric utilities to file tariffs, establish reliability and safety requirements for DG, establish a non-discriminatory DG interconnection policy, develop a standardized interconnection agreement to streamline the DG application review process, establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services), and establish detailed affiliate requirements should the utility choose to sell DG through an affiliate. The electric utilities filed their proposed modifications to existing DG interconnection tariffs and their proposed unbundled standby rates for PUC approval in the third quarter of 2006. The Consumer Advocate stated that it did not object to implementation of the interconnection and standby rate tariffs at the present time, but reserved the right to review the reasonableness of both tariffs in rate proceedings for each of the utilities.
Most recent rate requests
The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. As of October 31, 2006, 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). However, the ROACE used for purposes of the interim rate increase in HECO’s rate case based on a 2005 test year was 10.70%.
For the 12 months ended June 30, 2006, the simple average ROACEs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 8.09%, 5.44% and 9.74%, respectively.
HECO’s actual ROACE is significantly lower than its allowed ROACE primarily because of increased O&M expenses, which are expected to continue and are likely to result in HECO seeking rate relief more often than in the past. The interim rate relief granted to HECO by the PUC in September 2005 (see below) was based in part on increased costs of operating and maintaining HECO’s system. HELCO’s ROACEcommercial construction will continue to be negatively impactedstabilizing factors.
Overall, the outlook for Hawaii’s economy remains positive. However, economic growth is affected by CT-4the rate of expansion in the mainland U.S. and CT-5 as electric rates will not changeJapan economies and the growth in military spending, and is vulnerable to uncertainties in the world’s geopolitical environment. The projected real gross domestic product (GDP) growth for the unit additions until the PUC grants rate reliefU.S. and Japan in the HELCO rate case based on a 2006 test year (see below).
As of October 31, 2006, the 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 HELCO2007 are 2.7% and 8.83% for MECO (D&Os noted above). However, the ROR used for purposes of the interim D&O in the HECO rate case based on a 2005 test year was 8.66%. For the 12 months ended June 30, 2006, the simple average RORs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.84%, 5.59% and 7.91%2.1%, respectively.
AsManagement also monitors (1) oil prices, because of December 31,their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates, because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Crude oil prices were around $60 per barrel during the first quarter of 2007, compared to an average price of $70.28 per barrel in 2006, when the utilitiesand are expected to record significant charges to accumulated other comprehensive income (AOCI) related tostabilize in the funded status$60-$70 range.
Long-term interest rates were flat in the first quarter of their retirement benefit plans, the electric utilities’ RORs could increase and could impact the rates the electric utilities are allowed to charge, which may ultimately result in reduced revenues and lower earnings. In December 2005, the electric utilities submitted a request to the PUC for approval to record as a regulatory asset and include in rate base the amount that would otherwise be charged to AOCI and reduce stockholder’s equity related to a minimum liability for retirement benefits. Subsequently in September 2006, the FASB issued SFAS No. 158, “Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of retirement benefit plans. The electric utilities plan to update their application to the PUC to take into account SFAS No. 158. If their request is granted, the electric utilities expect that their ROACEs, RORs and financial ratios would not be adversely affected. See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”
HECO. In November 2004, HECO filed a request2007 with the PUC to increase base rates 9.9%, or $99 million in annual base revenues, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. HECO also requested approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. Excluding the surcharge transfer amount, the requested net increase to customers was 7.3%, or $74 million.
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 (EE DSM Docket). The issues for the 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, (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate, (5) whether, and if so, what incentive mechanisms are appropriate to encourage the implementation of DSM programs, and (6) which DSM programs should be approved, modified, or rejected. The parties/participants for all issues include HECO, the Consumer Advocate, the DOD, the County of Maui, two renewable energy organizations, an energy efficiency organization, and an environmental organization. HELCO, MECO, Kauai Island Utility Cooperative, The Gas Company and the County of Kauai are parties/participants solely for issues dealing with statewide energy policies. The EPA and its consultants also have been involved in an advisory capacity to the PUC, and have submitted comments on the proposed DSM programs and the issues in this proceeding. See “Other regulatory matters—Demand-side management programs” below for additional information on this docket and a discussion of the PUC’s Interim D&O issued on April 26, 2006
In September 2005, HECO, the Consumer Advocate and the DOD reached agreement (subject to PUC approval) among themselves on most of the issues10-year Treasury yield trading in the rate case proceeding, excluding the portion of the original rate case bifurcated into the EE DSM Docket. The remaining significant issue not resolved among the parties was the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes.
Later in September 2005, the PUC issued its interim D&O (with tariff changes effective September 28, 2005 and amounts collected refundable, with interest, to ratepayers to the extent they exceed the amount approved in the final D&O). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with an annual rate increase impact of approximately $7 million).
The following amounts were included in HECO’s rebuttal, the Consumer Advocate’s and the DOD’s testimonies and exhibits (as adjusted to exclude the transferred surcharge amount of $12 million); the settlement agreement with the Consumer Advocate and the DOD; and the PUC’s interim D&O:
| Pre-Settlement | |||||||||||||||
(dollars in millions) | HECO rebuttal | Consumer Advocate | Department of Defense | HECO (per | Interim increase1 | ||||||||||
Net additional revenues2 | $ | 51 | $ | 11 | $ | 7 | $ | 42 | $ | 41 | |||||
ROACE (%) | 11 | 8.5-10 | 9 | 10.7 | 10.7 | ||||||||||
ROR (%) | 8.83 | 7.85 | 7.71 | 8.66 | 8.66 | ||||||||||
Average rate base | $ | 1,109 | $ | 1,065 | $ | 1,062 | $ | 1,109 | $ | 1,109 | |||||
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.
On June 19, 2006, the PUC issued an order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. See “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.” The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s ECAC that are raised by Act 162. The parties in the rate case proceeding are HECO, the Consumer Advocate, and the DOD.
On June 30, 2006, HECO and the Consumer Advocate filed a stipulation requesting the PUC not to review the Act 162 ECAC issues in this rate case based on a 2005 test year since HECO’s application was filed and the record of this proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in this rate case included a provision allowing the existing ECAC to be continued. On August 7, 2006, an amended stipulation was filed in substantially the same form as the June 30, 2006 stipulation, but also included the DOD as a party. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the amended stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162, the ultimate outcome of these issues, the effect of these issues on the operation of the ECAC as it relates to the electric utilities or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case based on a 2005 test year.
In September 2006, HECO filed a notice with the PUC that it intends to file an application for a general rate increase based on a 2007 test year. HECO has not yet determined the amount of the rate increase it will be requesting.
HELCO. In May 2006, HELCO filed a request with the PUC to increase base rates by $30 million, or 9.24% in annual base revenues, based on a 2006 test year, an 8.65% ROR, an 11.25% ROACE and a $369 million average rate base. HELCO’s application includes a proposed new tiered rate structure, which would enable most residential users to see smaller increases in the range of 3% to 8%. The tiered rate structure is designed to minimize the increase for residential customers using less electricity and is expected to encourage customers to take advantage of solar water
heating programs and other energy management options. In addition, HELCO’s application proposes new time-of-use service rates for residential and commercial customers. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution line improvements and the two generating units at the Keahole power plant (CT-4 and CT-5), and increased O&M expenses. The application requests the continuation of HELCO’s ECAC.
The PUC held public hearings on HELCO’s application in June 2006. The PUC granted Keahole Defense Coalition’s motion to participate in this proceeding, and denied Rocky Mountain Institute’s motion to intervene, but granted it participant status. The ECAC provisions of Act 162 will be addressed in this rate case. Evidentiary hearings are scheduled for May 2007. The earliest that any increase, if granted, may go into effect is expected to be in the second quarter of 2007.
MECO. In September 2006, MECO filed a notice with the PUC that it intends to file an application for a general rate increase based on a 2007 test year. MECO has not yet determined the amount of the rate increase it will be requesting.
Other regulatory matters
Avoided cost docket. For information about the “Avoided cost generic docket,” see page 67 of HEI’s and HECO’s 2005 Form 10-K. Subsequently, the parties requested and in June 2006 were granted an extension until November 30, 2006 to file the required information with the PUC.
Demand-side management programs. The following updates the “Demand-side management programs” discussions on pages 66 to 67 of HEI’s and HECO’s 2005 Form 10-K.
In October 2001, HECO and the Consumer Advocate finalized agreements, subject to PUC approval, for the continuation of HECO’s three commercial and industrial DSM programs and two residential DSM programs until HECO’s next rate case. These agreements were in lieu of HECO continuing to seek approval of new 5-year DSM programs and provided that DSM programs to be in place after HECO’s next rate case would be determined as part of the case. Under the agreements, HECO agreed to cap the recovery of lost margins and shareholder incentives if such recovery would cause HECO to exceed its current “authorized return on rate base” (i.e. the rate of return on rate base found by the PUC to be reasonable in the most recent rate case for HECO). HECO also agreed it would not pursue the continuation of lost margins recovery and shareholder incentives through a surcharge mechanism in future rate cases.4.5%-4.9% range. At the time of the agreement, HECO indicated to the Consumer Advocate that it planned to seek alternative incentive mechanisms for DSM programs in its rate case. In November 2001, the PUC issued orders that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HECO’s five existing DSM programs until HECO’s next rate case.
In November 2004, HECO filed a request for a rate increase based on a 2005 test year and approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. 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 based on a 2005 test year into a new EE DSM docket. The bifurcation order allowed HECO to temporarily continue, in the manner currently employed, its existing three commercial and industrial DSM programs and two residential DSM programs, until further order by the PUC.
As a result of the bifurcation order in HECO’s rate case, HECO has been continuing its existing DSM programs and cost recovery mechanisms, including the recovery of incremental program costs for its energy efficiency DSM programs through a surcharge mechanism, pending the resolution of the EE DSM Docket. HECO also continued to accrue shareholder incentives and lost margins until May 26, 2006.
In December 2005 in the EE DSM Docket, HECO requested PUC approval, on an interim basis, for certain modifications to its existing energy efficiency DSM programs and a new interim DSM program (Interim DSM Proposals). HECO did not request shareholder incentives and lost margins for its proposed new interim DSM program, but did so for the modifications to its existing energy efficiency programs. In January 2006, the Consumer Advocate filed comments on HECO’s Interim DSM Proposals, which generally supported the proposals, but objected
to the continued recovery of shareholder incentives and lost margins for the existing energy efficiency DSM programs, as well as for the modifications.
In April 2006, the PUC issued an Interim Decision and Order (Interim D&O) approving HECO’s requests to modify its existing DSM programs and implement its proposed interim DSM program. However, the PUC also ordered that HECO’s recovery of lost margins and shareholder incentives for its DSM programs be discontinued within 30 days of the Interim D&O (i.e., by May 26, 2006), until further order by the PUC. Lost margins and shareholder incentives are estimated and recorded in the year earned, and collected from ratepayers in the current year (lost margins) or the following year (shareholder incentives). Revenues that HECO had previously expected to accrue for lost margins and shareholder incentives from May 26, 2006 through the end of 2006 were estimated at $2.1 million, or $1.2 million in after-tax net income. HECO filed a motion to reconsider that part of the Interim D&O that required HECO to discontinue the accrual of lost margins and shareholder incentives for its existing DSM programs, but the motion was denied in October 2006.
Following the submission of simultaneous statements of position by the parties/participants, comments by the EPA, and responses to the EPA comments, hearings were held in the EE DSM Docket in August 2006. The parties/participants have filed opening briefs and are scheduled to file reply briefs by November 15, 2006. Following the filing of reply briefs, the EE DSM Docket will be ready for PUC decision making.
In October 2001, HELCO and MECO had reached similar agreements with the Consumer Advocate regarding the continuation of their DSM programs and filed requests to continue their four existing DSM programs. In November 2001, the PUC issued orders (one of which was later amended) that, subject to certain reporting requirements and other conditions, approved the agreements regarding the temporary continuation of HELCO’s and MECO’s DSM programs until one year after the PUC makes a revenue requirements determination in HECO’s next rate case. Under the orders, however, HELCO and MECO were allowed to recover only lost margins and shareholder incentives accrued through the date that interim rates are established in HECO’s next rate case, but were permitted in the orders to request to extend the time of such accrual and recovery for up to one additional year.
Based on the Interim D&O in the EE DSM docket, on May 25, 2006, HELCO and MECO filed a request for a one-year extension for the recovery of HELCO and MECO’s lost margins and shareholder incentives or until final resolution of the EE DSM Docket. On September 19, 2006, the Consumer Advocate opposed an extension beyond September 26, 2006 (i.e., one year beyond the interim rate increase in the HECO rate case). On October 4 and 5, 2006, the PUC issued orders that allowed HELCO and MECO to accrue lost margins and shareholder incentives only up to September 26, 2006. Revenues that HELCO and MECO had previously expected to accrue for lost margins and shareholder incentives from September 27, 2006 through the end of 2006 were estimated at $1.6 million, or $0.9 million in after-tax net income.
Integrated resource planning, requirements for additional generating capacity and adequacy of supply. The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop IRPs. The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. The utilities’ proposed IRPs are planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the PUC’s IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed.
The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities can begin recovering their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery of the costs. HELCO and HECO now recover IRP costs through base rates.
However, the Consumer Advocate has objected to the recovery of $3.6 million (before interest) of the $12.9 million of incremental IRP costs incurred by the utilities during the 1995-2005 period, and the PUC’s decision is
pending on this matter. As of September 30, 2006, the amount of revenues, including interest and revenue taxes, that the electric utilities recorded for IRP cost recoveries, subject to refund with interest, amounted to $19 million.
HECO’s IRP.In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation (including a combustion turbine generating unit in 2009 and a possible 180 MW coal unit in 2022). In addition, HECO currently plans for all existing generating units to remain in operation (future environmental considerations permitting) beyond the 20-year IRP planning period (2006-2025). In June 2006, the PUC granted an environmental group’s motion to intervene in the proceeding and ordered the parties to determine the issues, procedures and schedule for the docket and to file a stipulated procedural order. In September 2006, the parties to the IRP-3 docket filed for PUC approval a stipulation for the parties to meet informally to address IRP-3 process issues and to attempt to reach a follow-up stipulation that will allow for the disposition of the IRP-3 docket without a final D&O approving the IRP-3 plan and action plan. If the parties are unable to reach a follow-up stipulation, then the parties will file a stipulated procedural order setting forth the issues, procedures and schedule for the docket, or if the parties are unable to reach agreement on a stipulated procedural order, then the parties will submit separate proposed procedural orders for PUC consideration.
In June 2005, HECO filed with the PUC an application for approval of funds to build a new 110 MW simple cycle combustion turbine generating unit at Campbell Industrial Park and an additional 138 kilovolt transmission line to transmit power from the new unit and existing generating units at Campbell Industrial Park to the Oahu electric grid. Plans are for the combustion turbineMarch 2007, while still considered to be run primarilyflat, the yield curve began to slope upward which may signal concern for future inflation. The spread between the 10-year and 2-year Treasuries was 0.07% as of March 31, 2007, and 0.01% as of May 1, 2007, compared to a “peaking” unit beginning in 2009, and to burn naphtha or diesel, but will be capablespread of using biofuels, such(0.10)% as ethanol. On December 15, 2005, HECO signed a contract with Siemens for the right to purchase up to two 110 MW combustion turbine units. The contract allows HECO to terminate the contract at a specified payment amount if necessary combustion turbine (CT) project approvals are not obtained. In April 2006, HECO issued Solicitation of Interest letters to prospective suppliers of ethanol, asking them to indicate their ability to provide ethanol to specifications such as chemical composition and heat generating capacity, for use in a blend of ethanol and naphtha in the new generating unit. After reviewing the responses received, HECO, in consultation with the PUC and the Consumer Advocate, may issue a more detailed request for proposals or enter into direct negotiations with potential providers. The PUC would need to approve any ethanol fuel contract. HECO is in the process of purchasing land for the new generating unit.
Preliminary costs for the new generating unit and transmission line, as well as related substation improvements, are estimated at $137 million. As of September 30, 2006, accumulated project costs for planning, engineering, permitting and AFUDC amounted to $3.6 million. HECO’s Final Environmental Impact Statement for the generating unit and transmission line was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006.
In a related application filed with the PUC in June 2005, HECO requested approval for a package of community benefit measures, which is currently estimated at $13.8 million, 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.
The PUC granted an environmental group’s motion to intervene and a neighboring business entity’s motion to participate in the generating unit and transmission line application. The procedural schedule for the proceeding includes hearings in December 2006. For the community benefits application, the only party to the proceeding is the Consumer Advocate, and hearings are scheduled for November 2006.
HELCO’s IRP.In September 1998, HELCO filed its second IRP with the PUC, and updated it in 1999 and 2004. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. The near-term additions included installing two 20 MW CTs at its Keahole power plant site (which were put into limited commercial operation in May and June 2004) and a PPA with Hamakua Energy Partners, L.P. (HEP) for a 60 MW (net) facility (which was completed in December 2000). HELCO has deferred the retirements of some of its older generating units until the 2030 timeframe, and periodically assesses the cost-effectiveness of the continued operation of those units. HELCO’s current plans are to install an 18 MW heat recovery steam generator (ST-7) in 2009
or earlier. After the installation of ST-7, the target date in HELCO’s updated second IRP for the next firm capacity addition is the 2020 timeframe.
HELCO’s third IRP is required to be filed with the PUC by December 31, 2006.
MECO’s IRP“Other” segment.MECO filed its second IRP with the PUC
Three months ended March 31, | % change | Primary reason(s) for significant change | ||||||||||
(in thousands) | 2007 | 2006 | ||||||||||
Revenues | $ | 1,885 | $ | (98 | ) | NM | Gain on the sale of Hoku shares of $1.4 million in the first quarter of 2007 compared to an unrealized and realized loss of $0.6 million in the first quarter of 2006 (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) | |||||
Operating loss | (2,879 | ) | (3,444 | ) | NM | Gain on the sale of Hoku shares versus prior year unrealized and realized loss, partly offset by higher consulting and other administrative and general expenses | ||||||
Net loss | (5,285 | ) | (5,478 | ) | NM | See explanation for operating loss, partly offset by higher interest expense primarily due to higher short-term borrowing rates and average balances | ||||||
NM Not meaningful.
The “other” business segment includes results of operations of HEI Investments, Inc. (HEIII), a company primarily holding investments in May 2000,leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and updated it in 2004 and 2005. On the supply side, MECO’s second IRP focused on the planning for the installation of approximately 150 MW of additional generation through the year 2020 on the island of Maui, including 38 MW of generation at its Maalaea power plant site in increments from 2000-2005, 100 MW at its new Waena site in increments from 2007-2018, beginning withmaintenance services to an affiliated electric utility; HEI Properties, Inc.
(HEIPI), a 20 MW combustion turbine in 2007 (currently not planned to be added until 2011)company holding passive, venture capital investments; The Old Oahu Tug Service, Inc., and 10 MW from the acquisition of a wind resource in 2003 (but with MECO actually beginning to purchase 30 MW of wind energy in 2006 from Kaheawa Wind Power, LLC). Approximately 4 MW of additional generation through the year 2020 were included for each of the islands of Lanai and Molokai. MECO completed the installation of a 20 MW increment (the second) at Maalaea in September 2000, and the final increment of 18 MW, which was originally expected to be installedpreviously a maritime freight transportation company that ceased operations in 2005, went into commercial operation in October 2006.
MECO’s third IRP is required to be filed with the PUC by April 30, 2007.
Adequacy of supply.
HECO. As a result of load growth1999 and other factors, HECO’s 2005 Adequacy of Supply letter, filed in March 2005, concluded that generation reserve margins, although substantial, continued to be strained on Oahu under the circumstances, and that there was an increased risk to generation reliability. The letter also stated that the risk of having generation-related customer outages would be higher if the peak reduction impacts of planned energy efficiency DSM programs, load management programs or CHP installations fall short of achieving their forecasted benefits. This situation is expected to continue if the peak demand continues to grow as forecasted, at least until 2009, which is the earliest HECO expects to be able to install its planned combustion turbine. The letter also indicated that HECO was working on plans to implement a number of potential interim mitigation measures, such as installing portable, leased, distributed 1.6 MW generating units at substations or other sites (nine units totaling 14.8 MW were installed in the fourth quarter of 2005) and initiating a customer demand response program to supplement its load management programs (for which HECO plans to request PUC approval in the fourth quarter of 2006). HECO did not experience actual generation shortfalls causing customer load shedding in 2005, in part because peak loads were lower than forecast for the second half of 2005.
HECO’s 2006 Adequacy of Supply letter filed in March 2006 indicates that HECO’s latest analysis estimates the reserve capacity shortfall to be between 170 MW and 200 MW in the 2006 to 2009 period, which is significantly larger than the 50 to 70 MW shortfall projected in the 2005 Adequacy of Supply letter. The increase in projected reserve capacity shortfallnow is largely due to the lower projected availabilityinactive; HEI and HEIDI, holding companies; and eliminations of existing generating units, and a reduction in the projected impacts from planned peak reduction measures. Generating units may be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes. While the availability rates for generating units on Oahu have been better than those of comparable units on the U.S. mainland, the availability rates declined in 2002 through 2005. Based on this experience, the manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects this situation to continue in the near-term and is forecasting lower availability rates than were used in the 2005 analyses.
HECO’s rebuttal testimony in the Campbell Industrial Park generating unit proceeding, filed September 2006, estimated the reserve capacity shortfall to be approximately 120 MW by 2009, which is significantly less than the 170 to 200 MW shortfall projected in the 2006 Adequacy of Supply letter. The decrease in the projected reserve capacity shortfall is largely due to a lower sales and peak forecast that was issued in August 2006 and the planned installation of additional distributed generators in late 2006 and early 2007.
To mitigate the projected reserve capacity shortfalls and to increase generating unit availability going forward, HECO is continuing to plan and implement mitigation measures, such as installing distributed generators at substations or other sites, seeking approval for additional load management and other demand reduction measures,
and pursuing efforts to improve the availability of generating units. HECO will operate at lower than desired reliability levels and take steps to mitigate the reserve capacity shortfall situation until the next generating unit is installed. Until sufficient generating capacity can be added to the system, HECO will experience a higher risk of generation related customer outages. Given the magnitude of the projected reserve capacity shortfall, HECO will also evaluate the need to file an application with the PUC for approval to add more firm capacity (over and above the PUC application filed in June 2005 for a 110 MW simple-cycle combustion turbine at Campbell Industrial Park).
On June 1, 2006, due to the unanticipated loss of three generating units from an IPP and two HECO generating units, HECO shed 29,300 customers in various parts of the island. Power was restored to all customers within four hours. HECO’s system peak loads generally occur in the fourth quarter of the year, and the possibility remains for generation shortfall events in the future.
Also, see “Recent outages” below.
HELCO. HELCO’s 2006 Adequacy of Supply letter filed in February 2006 indicated that HELCO’s generation capacity for the next three years, 2006 through 2008, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.
Also, see “Recent outages” below.
MECO. In December 2005, MECO’s Maalaea Unit 13, a 12.34 MW diesel generator suffered an equipment failure and the unit is not expected to be available for service until approximately June 2007. In March 2006, MECO filed its 2006 Adequacy of Supply letter, which indicated that MECO’s Maui island system should generally have sufficient installed capacity to meet the forecasted loads. However, in the event of an unexpected outage of the largest unit, the Maui island system may not have sufficient capacity until Maalaea Unit 13 returns to service. To overcome insufficient reserve capacity situations, MECO plans to implement appropriate mitigation measures, such as optimizing its unit overhaul schedule to minimize load capability shortfalls, coordinating the delivery of supplemental power, as needed, from an IPP and modifying its combined-cycle unit overhaul procedure to allow for the possible operation of the combustion turbine in simple-cycle mode. In October 2006, MECO placed into commercial operation an additional 18 MW of capacity at its Maalaea power plant site.
On April 3, 2006, MECO experienced lower than normal generation capacity due to the unexpected temporary loss of several of its generating units, and issued a request for the public to voluntarily conserve electricity.
Also, see “Recent outages” below.
Recent outages. On Sunday, October 15, 2006, shortly after 7 a.m., two earthquakes centered on the island of Hawaii with magnitudes of 6.7 and 6.0 triggered power outages throughout most of the state and disrupted air traffic on all major islands. Management is currently evaluating what impact the earthquakes and outages may have on the utilities (e.g., property damage, lost revenues, labor costs and claims). The electric utilities’ tariffs (approved and adopted by the PUC) state that “[t]he Company will not be liable for interruption or insufficiency of supply or any loss, cost, damage or expense of any nature whatsoever, occasioned thereby if caused by accident, storm, fire, strikes, riots, war or any cause not within the Company’s control through the exercise of reasonable diligence and care.” Customers have 30 days to file claims.
On Oahu, following the impact of the earthquakes, a series of protective actions and automatic systems operated to successively shut down all generators to protect them from potential damage. As a result, no significant damage has been observed on any of HECO’s generators, or transmission and distribution systems.
Following the island-wide outage, HECO restored power to customers in a careful, methodical manner to further protect its system, and as a result power was restored to over 99% of its customers over a period of time ranging from approximately 4 1/2 to 18 hours. Management believes the shutdown and methodical restoration of power were necessary to prevent severe damage to HECO’s generating equipment and power grid and to avoid a more prolonged blackout.
HELCO’s and MECO’s smaller electric systems also experienced sustained outages; however, their systems were for the most part back online by mid to late afternoon.
As is the electric utilities’ practice with all major system emergencies, management immediately committed to investigating the outage, including bringing in an outside industry expert to help identify any potential improvements
to procedures or systems, and also made arrangements for a preliminary briefing of the PUC. The PUC briefings took place on October 19 and 20, 2006. HECO also conducted a public briefing on October 23, 2006. HECO has made it clear that in addition to any investigation it undertakes, it will cooperate fully with any other reviews conducted by its regulators.
Following requests by members of a state Senate energy subcommittee and the Consumer Advocate that the PUC investigate the power failure, to which investigation HECO stated it did not object, the PUC issued an order on October 27, 2006 opening an investigative proceeding on the outages at HECO, HELCO and MECO on October 15 and 16, 2006. The preliminary issues identified by the PUC to be addressed in the proceeding include (1) aside from the earthquake, are there any underlying causes that contributed or may have contributed to the power outages, (2) were the activities and performances of the HECO Companies prior to and during the power outages reasonable and in the public interest, and were the power restoration processes and communication regarding the outages reasonable and timely under the circumstances, (3) could the island-wide power outages on Oahu and Maui have been avoided, and what are the necessary steps to minimize and improve the response to such occurrences in the future, and (4) what penalties, if any, should be imposed on the HECO Companies. Pursuant to the PUC’s order, HECO’s 2006 Outage Report must be filed by December 31, 2006, and the outage reports of HELCO and MECO must be filed by March 30, 2007. Management cannot predict what the outcomes of the investigation may be.
Collective bargaining agreements
See “Collective bargaining agreements” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
Legislation and regulation
Congress and the State of Hawaii Legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers. For information about legislation and regulation impacting HECO and its subsidiaries, see pages 70 to 72 of HEI’s and HECO’s 2005 Form 10-K and “Legislation and Regulation” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in HEI’s and HECO’s Forms 10-Q for the quarters ended March 31, 2006 and June 30, 2006. The following updates the Company’s discussion of legislation and regulation. Also, see “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of Act 162.
2006 Hawaii State Legislature energy measures. The 2006 Hawaii State Legislature passed energy measures, which were signed into law by the Governor of Hawaii, including the following (in addition to the ECAC provisions of Act 162 discussed above):
Renewable Portfolio Standards (RPS) law. The State RPS law was amended to provide that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources, such as wind or solar, versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The amendment also added provisions for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control. The amendment extends to December 31, 2007 the date by which the PUC must develop and implement a utility rate making structure to provide incentives to encourage electric utilities to use cost effective renewable energy resources.
DSM programs. The PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds currently collected by the utilities and included in their revenues through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. If the fund is established, the PUC is required to appoint a fund administrator (other than an electric utility or utility affiliate), to operate and manage the programs established under the fund.
Non-fossil fuel purchased power contracts. In connection with the PUC’s determination of just and reasonable rates in purchased power contracts, the PUC will be required to establish a methodology that removes or significantly reduces any linkage between the price paid for non-fossil-fuel-generated electricity under future power purchase contracts and the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation.
Net energy metering. Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly). The law provides a cap of 0.5% of the electric utility’s peak demand on the total generating capacity produced by eligible customer-generators. The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the maximum size of eligible net metered systems from 10 kilowatts (kw) to 50 kw and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less.
In 2005, the Legislature amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kw and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative, a renewable energy organization and a solar vendor organization. The PUC has approved a procedural schedule with panel hearings scheduled for October 2007. Depending on their magnitude, changes made by the PUC by rule or order could have a negative effect on electric utility sales. Management cannot predict the outcome of the investigative proceeding.
Other developments
Electronic shock absorber (ESA). HECO received a U.S. patent in February 2005 for an ESA that addresses power fluctuations from wind resources. An ESA demonstration system was installed and tested at HELCO’s Lalamilo wind farm. HECO has an intellectual property license agreement with S&C Electric Company (S&C), the party constructing the ESA demonstration system. S&C has the right to seek international patents for the design. Management cannot predict the amount of royalties HECO may receive from the sale of ESAs in the future.
On October 16, 2006, the ESA demonstration system sustained structural and fire damage, which is currently being assessed but is expected to have an immaterial impact to the electric utilities’ financial statements.
Advanced Meter Infrastructure (AMI) HECO is evaluating the feasibility of utility applications using power line and wireless technologies for two-way communication.
HECO completed a small-scale trial of the “Broadband over Power Line” (BPL) technology in 2005. Based on the favorable results of the trial, HECO has proceeded with a small-scale pilot in an expanded residential/commercial area in Honolulu, which is expected to run through the fourth quarter of 2006. The effort is primarily focused on automatic meter reading, which is aimed at enabling time of use rates for residential and commercial customers. Other BPL-enabled utility applications being evaluated include distribution system line monitoring, residential direct load control and monitoring of distribution substation equipment. HECO is also evaluating broadband information services that might potentially be provided by other service providers.
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.
EarthLink, an internet service-provider, and the City and County of Honolulu will partner in a test to provide free, wireless, broadband access in Chinatown in downtown Honolulu. As part of that Chinatown Pilot project, EarthLink and HECO are negotiating a separate non-binding collaborative agreement to develop and demonstrate a variety of utility applications using WiFi technology, including advanced electric metering and energy conservation initiatives. This utility applications pilot project is expected to continue for approximately one year, subject to the execution of the City and County of Honolulu and EarthLink Chinatown Pilot Agreement.intercompany transactions.
Commitments and contingencies
See Note 7 of HEI’s “Notes to Consolidated Financial Statements” and Note 5, “Commitment and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretations
See Note 79 of HECO’sHEI’s “Notes to Consolidated Financial Statements.”
FINANCIAL CONDITION
Liquidity and capital resources
HECO believes that its ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper, lines of credit and bank 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 as of the dates indicated:
(in millions) | September 30, 2006 | December 31, 2005 | ||||||||||
Short-term borrowings | $ | 145 | 7 | % | $ | 136 | 7 | % | ||||
Long-term debt | 766 | 38 | 766 | 38 | ||||||||
Preferred stock | 34 | 2 | 34 | 2 | ||||||||
Common stock equity | 1,072 | 53 | 1,039 | 53 | ||||||||
| $ | 2,017 | 100 | % | $ | 1,975 | 100 | % | |||||
As of October 31, 2006, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:
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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 May 2006, S&P affirmed its corporate credit ratings of HECO and its negative outlook. 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, and also reiterated in August 2006, 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.” S&P has stated that it will reconsider its negative outlook when the PUC issues its final order. In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). There was no change in HECO’s business profile rank of “5” in August 2006. Moody’s maintains a stable outlook for HECO.
HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. At September 30, 2006, HELCO and MECO had $47 million and $15 million, respectively, of short-term borrowings from HECO. HECO had an average
outstanding balance of commercial paper for the first nine months of 2006 of $145 million and had $145 million of commercial paper outstanding as of September 30, 2006. Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult for HECO to sell commercial paper under current market conditions.
Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement has an initial term which expires on March 29, 2007, but will automatically extend to March 31, 2011 if the longer-term agreement is approved by the PUC. An application seeking such approval was filed with the PUC on August 30, 2006. Any draws on the facility bear interest, at the option of HECO, at the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. Annual fees on the undrawn commitments are 8 basis points. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions that must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratios of 47% for HELCO and 45% for MECO as of September 30, 2006)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 53% as of September 30, 2006), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity. See Note 9 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the $175 million credit facility.
Operating activities provided $154 million in net cash during the first nine months of 2006. Investing activities used net cash of $124 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities used net cash of $26 million, primarily due to the payment of $30 million in common and preferred dividends, partly offset by a $9 million net increase in short term borrowings. In order to strengthen HECO’s balance sheet and support its investment in its reliability program, HECO does not plan to pay any dividends to HEI in the second half of 2006.
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 in February 2005 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 May 2005, the Hawaii legislature authorized the issuance prior to June 30, 2010, of up to $160 million of Special Purpose Revenue Bonds (SPRBs) ($100 million for HECO, $40 million for HELCO and $20 million for MECO), subject to PUC approval of the projects to be financed, to finance the electric utilities’ capital improvement projects. As of October 31, 2006, no SPRBs had been issued under this authorization.
In December 2005, an application was filed with the PUC requesting approval to issue up to a total of $165 million in taxable unsecured notes for HECO, MECO and HELCO (up to $100 million for HECO, up to $50 million for HELCO and up to $15 million for MECO). On January 20, 2006, a Registration Statement on Form S-3 was filed with the SEC covering $100 million, $50 million and $15 million aggregate principal amount, respectively, of
long-term, unsecured taxable notes to be issued by HECO, HELCO and MECO, with the obligations of HELCO and MECO to be fully and unconditionally guaranteed by HECO. It was anticipated that the proceeds from the sale of the notes would be used for capital expenditures and/or to repay short-term borrowings (including borrowings from affiliates) incurred for capital expenditures or to refinance short-term borrowings used for capital expenditures. However, on October 27, 2006, the electric utilities amended the PUC application, in accordance with a stipulation between the utilities and the Consumer Advocate, to seek approval for the issuance of up to $160 million of SPRBs (allocated as indicated above) instead of issuing the taxable unsecured notes. Accordingly, the electric utilities have filed with the SEC an application to withdraw the Registration Statement on Form S-3 filed on January 20, 2006.
RESULTS OF OPERATIONS
| Three months ended September 30 | % change | Primary reason(s) for significant change | |||||||||
(in thousands) | 2006 | 2005 | |||||||||
Revenues | $ | 103,338 | $ | 97,431 | 6 | Higher interest income (resulting from higher average balances and yields on loans and higher yields on investment and mortgage-related securities, partly offset by lower average investment and mortgage-related securities balances) and higher noninterest income | |||||
Operating income | 20,578 | 25,938 | (21 | ) | Lower net interest income and higher noninterest expense, partly offset by higher noninterest income | ||||||
Net income | 13,470 | 15,911 | (15 | ) | Lower operating income, partly offset by a lower effective tax rate | ||||||
Nine months ended September 30 | % | Primary reason(s) for significant change | |||||||||
(in thousands) | 2006 | 2005 | |||||||||
Revenues | $ | 305,898 | $ | 286,601 | 7 | Higher interest income (resulting from higher average balances and yields on loans and higher yields on investment and mortgage-related securities, partly offset by lower average investment and mortgage-related securities balances) and higher noninterest income | |||||
Operating income | 73,752 | 77,093 | (4 | ) | Lower net interest income, higher noninterest expense and reversal in first quarter of 2005 of allowance for loan losses, partly offset by higher noninterest income | ||||||
Net income | 46,515 | 47,224 | (2 | ) | Lower operating income, partly offset by a lower effective tax rate | ||||||
See “Economic conditions” in the “HEI Consolidated” section above.
Net interest margin
Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. As a result of a prolonged, flat or inverted yield curve environment, margin compression remains an issue for ASB.
ASB���s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. As of September 30, 2006, ASB’s loan portfolio mix, net, consisted of 72% residential loans, 12% commercial loans, 9% commercial real estate loans and 7% consumer loans. As of December 31, 2005, ASB’s loan portfolio mix, net, consisted of 74% residential loans, 11% commercial loans, 8% commercial real estate loans and 7% consumer loans. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand. In the third quarter of 2006, commercial real estate loans grew by 17%. While the outlook for the Hawaii economy remains positive, management does not expect the growth rate in this portfolio to remain at this level for the remainder of 2006. Expected repayments and slower growth in the fourth quarter of 2006 may cause commercial loan and commercial real estate loan balances to remain relatively flat. Originating mortgages has been more difficult with the Hawaii real estate market beginning to stabilize. While real estate prices remain high, the number of sales transactions has declined, impacting ASB’s mortgage origination levels. Management believes this trend in real estate sales volumes will continue.
Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds. As of September 30, 2006, ASB’s costing liabilities consisted of 75% deposits and 25% other borrowings. As of December 31, 2005, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings. The shift in mix was due to the paydown of maturing other borrowings during the third quarter of 2006. The deposit liabilities balance as of September 30, 2006 was 0.1% lower than the balance as of June 30, 2006 and 0.4% lower than the balance as of December 31, 2005. The shift in deposit mix from lower cost savings and checking accounts to higher cost time deposits, along with the repricing of deposits, has contributed to increased funding costs. ASB believes that, with the federal funds rate increases, the difference between rates on its deposit accounts and the rates on alternative investments became significant enough to cause more customers to move deposits in search of higher yields. Because of this, and ASB’s outlook for a prolonged flat or inverted yield curve environment, management made tactical shifts in order to retain deposits, including more aggressive repricing of certain deposit accounts, increased promotions and accelerating product launches. While ASB tries to control its overall deposit costs by selectively repricing certain deposit accounts, rather than the entire deposit base, the move to more aggressive repricing of selected accounts caused deposit costs to increase faster than they have in the past, and could continue to negatively impact ASB’s future net interest margin.
The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for all categories of earning assets and costing liabilities for the three and nine months ended September 30, 2006 and 2005.
| Three months ended September 30 | Nine months ended September 30 | |||||||||||||||||||
($ in thousands) | 2006 | 2005 | Change | 2006 | 2005 | Change | ||||||||||||||
Loans receivable | ||||||||||||||||||||
Average balances1 | $ | 3,745,138 | $ | 3,461,873 | $ | 283,265 | $ | 3,665,279 | $ | 3,374,255 | $ | 291,024 | ||||||||
Interest income2 | 59,417 | 52,649 | 6,768 | 171,893 | 151,819 | 20,074 | ||||||||||||||
Weighted-average yield (%) | 6.33 | 6.08 | 0.25 | 6.26 | 6.00 | 0.26 | ||||||||||||||
Investment and mortgage-related securities | ||||||||||||||||||||
Average balances | $ | 2,462,058 | $ | 2,728,094 | $ | (266,036 | ) | $ | 2,550,028 | $ | 2,805,377 | $ | (255,349 | ) | ||||||
Interest income | 27,477 | 29,956 | (2,479 | ) | 86,704 | 90,911 | (4,207 | ) | ||||||||||||
Weighted-average yield (%) | 4.46 | 4.39 | 0.07 | 4.53 | 4.32 | 0.21 | ||||||||||||||
Other investments3 | ||||||||||||||||||||
Average balances | $ | 165,515 | $ | 206,954 | $ | (41,439 | ) | $ | 170,372 | $ | 186,142 | $ | (15,770 | ) | ||||||
Interest and dividend income | 891 | 933 | (42 | ) | 2,611 | 2,364 | 247 | |||||||||||||
Weighted-average yield (%) | 2.11 | 1.76 | 0.35 | 2.02 | 1.68 | 0.34 | ||||||||||||||
Total earning assets | ||||||||||||||||||||
Average balances | $ | 6,372,711 | $ | 6,396,921 | $ | (24,210 | ) | $ | 6,385,679 | $ | 6,365,774 | $ | 19,905 | |||||||
Interest and dividend income | 87,785 | 83,538 | 4,247 | 261,208 | 245,094 | 16,114 | ||||||||||||||
Weighted-average yield (%) | 5.50 | 5.22 | 0.28 | 5.46 | 5.13 | 0.33 | ||||||||||||||
Deposit liabilities | ||||||||||||||||||||
Average balances | $ | 4,530,796 | $ | 4,498,500 | $ | 32,296 | $ | 4,547,874 | $ | 4,420,693 | $ | 127,181 | ||||||||
Interest expense | 19,701 | 13,355 | 6,346 | 52,095 | 37,832 | 14,263 | ||||||||||||||
Weighted-average rate (%) | 1.73 | 1.18 | 0.55 | 1.53 | 1.14 | 0.39 | ||||||||||||||
Other borrowings | ||||||||||||||||||||
Average balances | $ | 1,629,002 | $ | 1,681,329 | $ | (52,327 | ) | $ | 1,629,809 | $ | 1,722,799 | $ | (92,990 | ) | ||||||
Interest expense | 18,891 | 17,278 | 1,613 | 54,361 | 51,919 | 2,442 | ||||||||||||||
Weighted-average rate (%) | 4.59 | 4.07 | 0.52 | 4.45 | 4.02 | 0.43 | ||||||||||||||
Total costing liabilities | ||||||||||||||||||||
Average balances | $ | 6,159,798 | $ | 6,179,829 | $ | (20,031 | ) | $ | 6,177,683 | $ | 6,143,492 | $ | 34,191 | |||||||
Interest expense | 38,592 | 30,633 | 7,959 | 106,456 | 89,751 | 16,705 | ||||||||||||||
Weighted-average rate (%) | 2.48 | 1.96 | 0.52 | 2.30 | 1.95 | 0.35 | ||||||||||||||
Net average balance | $ | 212,913 | $ | 217,092 | $ | (4,179 | ) | $ | 207,996 | $ | 222,282 | $ | (14,286 | ) | ||||||
Net interest income | 49,193 | 52,905 | (3,712 | ) | 154,752 | 155,343 | (591 | ) | ||||||||||||
Interest rate spread (%) | 3.02 | 3.26 | (0.24 | ) | 3.16 | 3.18 | (0.02 | ) | ||||||||||||
Net interest margin (%) | 3.10 | 3.33 | (0.23 | ) | 3.23 | 3.25 | (0.02 | ) | ||||||||||||
(in thousands, except per share amounts) | Three months ended March 31, | % change | Primary reason(s) for significant change* | ||||||||
| 2007 | 2006 | ||||||||||
Revenues | $ | 554,023 | $ | 574,962 | (4 | ) | Decrease for the electric utility segment, slightly offset by increases for the bank and “other” segments | ||||
Operating income | 28,541 | 69,151 | (59 | ) | Decrease for the electric utility and the bank segments, slightly offset by a reduction in losses for the “other” segment | ||||||
Net income | 6,764 | 32,337 | (79 | ) | Lower operating income and AFUDC and higher “interest expense—other than on deposit liabilities and other bank borrowings,” partly offset by lower taxes resulting from lower income before taxes and a lower effective income tax rate ** | ||||||
Basic earnings per common share | $ | 0.08 | $ | 0.40 | (80 | ) | Lower net income | ||||
Weighted-average number of common shares outstanding | 81,448 | 80,981 | 1 | Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and other Company plans | |||||||
Other factorsDividends
OtherOn May 3, 2007, HEI’s Board of Directors maintained the quarterly dividend of $0.31 per common share. The payout ratios for 2006 and the first quarter of 2007 were 93% and 388%, respectively. Historically low net income for the first quarter of 2007 resulted in a dividend payout nearly four times greater than net income. Net income for the first quarter of 2007 was affected by a number of factors, primarily affecting ASB’sincluding higher operations and maintenance expenses and a $7 million (net of taxes) write-off of plant at the electric utilities and higher legal and litigation expenses at ASB (see “Results of Operations” in the “Electric Utilities” and “Bank” sections below). HEI’s Board and management continues to believe that HEI should achieve a payout ratio of 65% or lower on a sustainable basis and that cash flows should support an increase before it considers increasing the common stock dividend above its current level.
Economic conditions
Note: The statistical data in this section is from public third party sources (e.g., State of Hawaii Department of Business, Economic Development and Tourism (DBEDT), U.S. Census Bureau and Bloomberg).
Because HEI’s core businesses provide local electric utility and banking services, HEI’s operating results include fee income, provision (or reversalare significantly influenced by the strength of allowance)Hawaii’s economy. The state’s economic growth, which is fueled by the two largest components of Hawaii’s economy – tourism and the federal government, was estimated at 2.7% for loan losses, gains or losses on sales of securities available for sale and expenses from operations.
Although higher long-term interest rates could reduce the market value of available-for-sale investment and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investment and mortgage-related securities would not result in an immediate charge to net
income in the absence of an “other-than-temporary” impairment in the value of the securities. As of September 30, 2006 and December 31, 2005,is forecast by DBEDT to further moderate to 2.6% for 2007.
According to the unrealized losses, netlatest available data, Hawaii ranked fifth among the states in its receipt of tax benefits, on available-for-sale investment and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $38 million and $36 million, respectively. See “Quantitative and qualitative disclosures about market risk” forfederal government expenditures per capita. For the impact of higher interest rates on ASB’s net portfolio value (NPV) ratio.
Results – three monthsfederal fiscal year ended September 30, 20062004 (latest available data), total federal
Net interest income for the three months ended September 30, 2006 decreased by $3.7 million,
government expenditures in Hawaii, including military expenditures, were $12.2 billion or $9,651 per capita, increasing 8% and 7%, whenrespectively, over fiscal year 2003. Military spending, which is 39% of federal expenditures in Hawaii, increased 6% in 2004 compared to 2003.
Tourism is widely acknowledged as a significant component of Hawaii’s economy. In 2006, visitor expenditures reached a record $12.3 billion, a 3% increase over 2005. 2006 visitor days were slightly lower by 0.3% compared to the 2005 record-high level. State economists currently expect marginal visitor growth in 2007 due to capacity constraints with projected increases of 1.5% in visitor days and 4.8% in visitor expenditures. Although visitor days year-to-date through February 2007 were down 3.7% compared to the same period in 2005. ASB continued to increase its loan portfolio, however, margin compression continued as a result of the prolonged flat or inverted yield curve environment. Increasing short-term rates continued to put upward pressure on deposit costs and contributed to increased funding costs. Net interest margin decreased from 3.33% in the third quarter of 2005 to 3.10% in the third quarter of 2006 as the impact of growth in the loan portfolio as well as higher yields on loans, investments and mortgage-related securitiesyear ago, visitor expenditures were more than offset by the impact of lower investment and mortgage-related securities balances and higher funding costs. up 1.2%.
The increase in the average loan portfolio balance was partly due to the continued strength of the Hawaii economy, the high-priced real estate and construction industries in Hawaii also influence HEI’s core businesses. The Oahu housing market is continuing to stabilize with sales prices down from their 2006 record levels and growthinventory returning to more normal levels. The median home price on Oahu was $643,500 in the commercial loan portfolio as a result of the bank’s strategy to transform from a thrift to a community bank. The decrease in the average investment and mortgage-related securities portfolio was due to the reinvestment of proceeds from the repayment or sale of mortgage-related securities into loans. The average deposit balance was $32 million higher in the third quarter of 2006 than in the third quarter of 2005.
Noninterest income for the third quarter of 2006 increased by $1.7 million, or 12%, whenMarch 2007 compared to the third quartermedian of 2005, primarily due to gains on$650,000 in March 2006. Total sales of securities in 2006.
Noninterest expense for the third quarter of 2006 increased by $3.3 million, or 8%, when compared to the third quarter of 2005, due to higher litigation and other legal expenses, some of which may be recoverable through insurance in the future, increased marketing cost related to new deposit promotions and new combined rewards program (under which customers can combine reward points for credit and debit card purchases) and higher occupancy and equipment expenses.
Results – nine months ended September 30, 2006
Net interest income before reversal of allowance for loan losses for the nine months ended September 30, 2006 decreased by $0.6 million, or 0.4%, when compared to the same period in 2005. ASB continued to increase its loan portfolio, but margin compression continued as a result of the prolonged flat or inverted yield curve environment. Increasing short-term rates continued to put upward pressure on deposit costs and contributed to increased funding costs. Net interest margin decreased from 3.25%single-family homes in the first nine monthsquarter of 2005 to 3.23% in the first nine months of 2006 as the impact of growth in the loan portfolio and higher yields on loans and investment and mortgage-related securities were more than offset by the impact of lower investment and mortgage-related securities balances and higher funding costs. The increase in the average loan portfolio balance was partly due to the continued strength of the Hawaii economy, the high-priced real estate market and growth in the commercial loan portfolio as a result of the bank’s transformation from a thrift to a community bank. The decrease in the average investment and mortgage-related securities portfolio was due to the reinvestment of proceeds from the repayment or sale of mortgage-related securities into loans. The increase in yields on the investment and mortgage-related securities portfolio was due to increasing short-term rates. The average deposit balance was $127 million higher in the first nine months of 20062007 decreased 15.8% compared to the first nine monthsquarter of 2005.
The construction industry continues to remain healthy, indicated by a 7.7% increase in building permits year-to-date through February 2007 compared with the same period last year. Local economists continue to expect slowing of growth in residential construction over the next few years, and that military and commercial construction will continue to be stabilizing factors.
DuringOverall, the outlook for Hawaii’s economy remains positive. However, economic growth is affected by the rate of expansion in the mainland U.S. and Japan economies and the growth in military spending, and is vulnerable to uncertainties in the world’s geopolitical environment. The projected real gross domestic product (GDP) growth for the U.S. and Japan in 2007 are 2.7% and 2.1%, respectively.
Management also monitors (1) oil prices, because of their impact on the rates the utilities charge for electricity and the potential effect of increased prices of electricity on usage, and (2) interest rates, because of their potential impact on ASB’s earnings, HEI’s and HECO’s cost of capital, pension costs and HEI’s stock price. Crude oil prices were around $60 per barrel during the first nine monthsquarter of 2007, compared to an average price of $70.28 per barrel in 2006, and are expected to stabilize in the need$60-$70 range.
Long-term interest rates were flat in the first quarter of 2007 with the 10-year Treasury yield trading in the 4.5%-4.9% range. At the end of March 2007, while still considered to providebe flat, the yield curve began to slope upward which may signal concern for loan lossesfuture inflation. The spread between the 10-year and 2-year Treasuries was 0.07% as a result of additional loan growth was fully offset by the releaseMarch 31, 2007, and 0.01% as of reserves on existing loans due to strong asset quality. This comparesMay 1, 2007, compared to a reversalspread of allowance for loan losses of $3.1 million ($1.9 million, net of tax) for the first nine months of 2005. As of September 30, 2006, ASB’s allowance for loan losses was 0.82% of average loans outstanding, compared to 0.90%(0.10)% as of December 31, 2005 and 0.91% as of September 30, 2005.2006.
“Other” segment
Nine months ended September 30 | 2006 | 2005 | ||||||
| (in thousands) | ||||||||
Allowance for loan losses, January 1 | $ | 30,595 | $ | 33,857 | ||||
Reversal of allowance for loan losses | — | (3,100 | ) | |||||
Net recoveries (charge-offs) | (571 | ) | (58 | ) | ||||
Allowance for loan losses, September 30 | $ | 30,024 | $ | 30,699 | ||||
Three months ended March 31, | % change | Primary reason(s) for significant change | ||||||||||
(in thousands) | 2007 | 2006 | ||||||||||
Revenues | $ | 1,885 | $ | (98 | ) | NM | Gain on the sale of Hoku shares of $1.4 million in the first quarter of 2007 compared to an unrealized and realized loss of $0.6 million in the first quarter of 2006 (see Note 11 of HEI’s “Notes to Consolidated Financial Statements”) | |||||
Operating loss | (2,879 | ) | (3,444 | ) | NM | Gain on the sale of Hoku shares versus prior year unrealized and realized loss, partly offset by higher consulting and other administrative and general expenses | ||||||
Net loss | (5,285 | ) | (5,478 | ) | NM | See explanation for operating loss, partly offset by higher interest expense primarily due to higher short-term borrowing rates and average balances | ||||||
Noninterest income for the first nine monthsNM Not meaningful.
The “other” business segment includes results of 2006 increased by $3.2 million, or 8%operations of HEI Investments, Inc. (HEIII), when compareda company primarily holding investments in leveraged leases; Pacific Energy Conservation Services, Inc., a contract services company primarily providing windfarm operational and maintenance services to the first nine monthsan affiliated electric utility; HEI Properties, Inc.
(HEIPI), a company holding passive, venture capital investments; The Old Oahu Tug Service, Inc., which was previously a maritime freight transportation company that ceased operations in 1999 and now is largely inactive; HEI and HEIDI, holding companies; and eliminations of 2005, primarily due to higher gains on sales of securities and higher fee income on ATM and debit cards.
Noninterest expense for the first nine months of 2006 increased by $2.8 million, or 2%, when compared to the first nine months of 2005, primarily due to higher compensation and employee benefits, occupancy, equipment and litigation and other legal expenses, some of which may be recoverable through insurance in the future, partially offset by lower interest accruals on income taxes.intercompany transactions.
FHLBCommitments and contingencies
See Note 7 of Seattle businessHEI’s “Notes to Consolidated Financial Statements” and capital planNote 5, “Commitment and contingencies,” of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretations
In December 2004, the FHLBSee Note 9 of Seattle signed an agreement with its regulator, the Federal Housing Finance Board (Finance Board),HEI’s “Notes to adopt a business and capital plan to strengthen its risk management, capital structure and governance. 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. Subject to the impact of legislation being considered by Congress, member access to the FHLB of Seattle funding and liquidity is expected to continue unimpeded during implementation of the three-year plan.
As of September 30, 2006, ASB had an investment in FHLB of Seattle stock of $98 million. No dividends have been received by ASB from the FHLB of Seattle since the first quarter of 2005.Consolidated Financial Statements.”
FINANCIAL CONDITION
Selected contractual obligations and commitments
Deferred tax liabilities ($96.4 million as of March 31, 2007 and $106.8 million as of December 31, 2006), FIN 48 liabilities ($11.3 million as of March 31, 2007) and accrued interest and penalties related to uncertain tax positions ($1.8 million as of March 31, 2007) have not and are not expected to be included in HEI’s consolidated table of “Selected contractual obligations and commitments” in HEI’s Form 10-K because the Company cannot reliably estimate when, and to what extent, cash settlement of these liabilities will occur.
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, lines of credit and bank borrowings, is adequate to maintain sufficient liquidity to fund the Company’s 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 and other borrowings) was as follows as of the dates indicated:
(in millions) | September 30, 2006 | December 31, 2005 | % change | ||||||
Total assets | $ | 6,714 | $ | 6,835 | (2 | ) | |||
Available-for-sale investment and mortgage-related securities | 2,357 | 2,629 | (10 | ) | |||||
Investment in FHLB of Seattle stock | 98 | 98 | — | ||||||
Loans receivable, net | 3,764 | 3,567 | 6 | ||||||
Deposit liabilities | 4,540 | 4,557 | — | ||||||
Other bank borrowings | 1,512 | 1,622 | (7 | ) | |||||
(in millions) | March 31, 2007 | December 31, 2006 | ||||||||||
Short-term borrowings—other than bank | $ | 123 | 5 | % | $ | 177 | 7 | % | ||||
Long-term debt, net—other than bank | 1,225 | 50 | 1,133 | 47 | ||||||||
Preferred stock of subsidiaries | 34 | 1 | 34 | 1 | ||||||||
Common stock equity | 1,097 | 44 | 1,095 | 45 | ||||||||
| $ | 2,479 | 100 | % | $ | 2,439 | 100 | % | |||||
As of September 30, 2006, ASB wasMay 1, 2007, the third largest financial institution in Hawaii based on assetsStandard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of $6.7 billion and deposits of $4.5 billion.HEI securities were as follows:
ASB’s S&P long-term/short-term counterparty credit ratings are BBB-/A-3. In April 2006, S&P affirmed its counterparty credit ratings on ASB and revised its outlook from stable to positive, acknowledging the promising potential of ASB’s community banking strategy, its still modest credit risk profile, and its solid capital base. These
| S&P | Moody’s | |||
Commercial paper | A-2 | P-2 | ||
Medium-term notes | BBB | Baa2 |
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 S&P;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 March 2007, S&P affirmed its corporate credit ratings of HEI and maintained its negative outlook. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P indicated:
Failure to strengthen key financial parameters, especially cash flow coverage of debt, a slump in the Hawaiian economy, a final rate order that differs from the PUC’s interim decision with regard to HECO’s 2005 rate case, and, although not expected, a major erosion in American Savings Bank’s creditworthiness could lead to lower ratings. Conversely, credit- supportive actions by the company as well as responsive rate treatment would lead to ratings stability.
In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). In March 2007, S&P did not change HEI’s business profile rank of “6”.
In December 2006, Moody’s confirmed its issuer ratings and stable outlook for HEI. Moody’s stated, “The rating could be downgraded should weaker than expected regulatory support emerge at HECO, including the continuation of regulatory lag, which ultimately causes earnings and sustainable cash flow to suffer.”
As of September 30, 2006, ASB’s unused FHLB borrowing capacity was approximately $1.6 billion. AsMarch 31, 2007, $96 million of September 30, 2006, ASB had commitmentsdebt, equity and/or other securities were available for offering by HEI under an omnibus shelf registration and an additional $50 million principal amount of Series D notes were available for offering by HEI under its registered medium-term note program.
HEI utilizes short-term debt, principally commercial paper, to borrowerssupport normal operations and 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 itother temporary requirements. HEI also periodically makes short-term loans to HECO to meet these obligations while maintaining liquidity at satisfactory levels.
ForHECO’s cash requirements, including the funding of loans by HECO to HELCO and MECO. HEI had an average outstanding balance of commercial paper for the first ninethree months of 2006, net cash provided by ASB’s operating activities was $81 million. Net cash provided by ASB’s investing activities was $622007 of $66 million primarily dueand had $76 million outstanding as of March 31, 2007. HEI’s commercial paper is expected to repayments and salesincrease during 2007 as a result of mortgage-related securitiesHECO’s plans to not declare a dividend to HEI during the first half of $443 million, which repayments were2007. The decrease in HECO’s dividend is expected to continue to be partly offset by purchases of investment securities of $175 million and a net increase in loans receivable of $197 million. Net cash used by financing activities was $166 million primarily due to net decreases of $110 million in other borrowings and $17 million in deposit liabilities and the payment of $35 million in common stock dividends. The ASB Board of Directors approved aASB’s dividend of all100% of ASB’s third quarterits net income, subjectincome. Management believes that if HEI’s commercial paper ratings were to receiving an OTS non-objection letter.be downgraded, it might not be able to sell commercial paper under current market conditions.
AsEffective April 3, 2006, HEI entered into a revolving unsecured credit agreement establishing a line of September 30, 2006, ASB was well-capitalized (ratio requirements noted in parentheses)credit facility of $100 million, with a leverage ratioletter of 7.8% (5.0%),credit sub-facility, expiring on March 31, 2011, with a Tier-1 risk-based capital ratiosyndicate of 14.3% (6.0%) and a total risk-based capital ratio of 15.2% (10.0%).
Under SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” there will be a reduction in ASB’s equity beginning December 31, 2006.eight financial institutions. See Note 912 of HEI’s “Notes to Consolidated Financial Statements.” This reduction will haveStatements” for a negative impact on its regulatory capital ratiosdescription of the $100 million credit facility. As of May 1, 2007, the line was undrawn. In the future, the Company may seek to enter into new lines of credit and may reducealso seek to increase the amount of dividends it ultimately pays.credit available under such lines as management deems appropriate.
For the first three months of 2007, net cash provided by operating activities of consolidated HEI was $51 million. Net cash used in investing activities for the same period was $95 million primarily due to net increases in investment and mortgage-related securities and loans receivable at ASB however, believes it will remain “well-capitalized” afterand HECO’s consolidated capital expenditures. Net cash provided by financing activities during this period was $28 million as a result of several factors, including net increases in deposit liabilities, other bank borrowings and long-term debt and proceeds from the adoptionissuance of SFAS No. 158.common stock under HEI plans, partly offset by net decreases in short-term borrowings and cash overdrafts and the payment of common stock dividends.
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION
The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 8082 to 8689 of HEI’s and HECO’s 20052006 Form 10-K.
Additional factors that may affect future results and financial condition are described on page iv under “Forward-Looking Statements” and under “Risk Factors” in this Quarterly Report and on pages 36 to 44 of HEI’s and HECO’s 2005 Form 10-K.Statements.”
MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES
In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s financial condition and results of operations, and currently require management’s most difficult, subjective or complex judgments.
For information about these material estimates and critical accounting policies, see pages 8690 to 8993 of HEI’s and HECO’s 20052006 Form 10-K.
Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.
RESULTS OF OPERATIONS
(dollars in thousands, except per barrel amounts) | Three months ended March 31, | % change | Primary reason(s) for significant change | ||||||||
| 2007 | 2006 | ||||||||||
Revenues | $ | 447,678 | $ | 475,056 | (6 | ) | Lower fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers ($28 million), and discontinuation of DSM lost margin and shareholder incentives ($2M), partly offset by 0.6% higher KWH sales ($4 million) | ||||
Expenses | |||||||||||
Fuel oil | 159,929 | 175,338 | (9 | ) | Lower fuel oil costs, partly offset by more KWHs generated | ||||||
Purchased power | 111,516 | 117,720 | (5 | ) | Lower fuel costs and less KWHs purchased, partly offset by higher capacity and non-fuel charges | ||||||
Other | 163,241 | 136,418 | 20 | Higher other operation and maintenance (O&M) ($15 million) and depreciation expenses ($2 million), and write-off of HELCO plant in service ($12 million), partly offset by lower taxes, other than income taxes ($2 million) | |||||||
Operating income | 12,992 | 45,580 | (71 | ) | Higher expenses, write-off of plant in service and discontinuation of DSM lost margin and shareholder incentives, partly offset by higher KWH sales | ||||||
Net income | 453 | 20,988 | (98 | ) | Lower operating income and AFUDC and higher interest expense due primarily to the accrual of interest for the Series 1996A and 1996B SPRBs to the redemption dates (see Note 11 of HECO’s “Notes to Consolidated Financial Statements”) and higher short-term interest rates, partly offset by tax benefits in 2007 versus tax expense in 2006 * | ||||||
Kilowatthour sales (millions) | 2,404 | 2,390 | 1 | Load growth | |||||||
Oahu cooling degree days | 845 | 771 | 10 | ||||||||
Fuel oil cost per barrel | $ | 58.19 | $ | 63.59 | (8 | ) | |||||
| * | The electric utilities had a $0.3 million tax benefit in the first quarter of 2007, compared to an effective tax rate for the first quarter of 2006 of 38% (see Note 8 in HECO’s “Notes to Consolidated Financial Statements”). |
See “Economic conditions” in the “HEI Consolidated” section above.
Results – three months ended March 31, 2007
Operating income for the first quarter of 2007 decreased 71% from the same period in 2006 due primarily to higher O&M expenses, a write-off of a portion of plant-in-service costs related to CT-4 and CT-5 (see “Most recent rate cases”) and the discontinuation of DSM lost margin and shareholder incentives, partly offset by slightly higher KWH sales. KWH sales in the first three months of 2007 increased 0.6% from the same period in 2006, primarily due to new load growth (i.e., increase in number of customers and new construction). Other operation expenses increased 12% primarily due to higher administrative and general expenses, including employee retirement benefits
expense. Pension and other postretirement benefit expenses for the electric utilities increased $1.0 million over the same period in 2006 primarily due to the adoption of a 50 basis points lower asset return rate assumption as of December 31, 2006 by the HEI Pension Investment Committee. Maintenance expenses increased by 60% due to higher production maintenance expenses (primarily due to $7.2 million of costs related to an increase in the number and greater scope of generating unit overhauls) and transmission and distribution maintenance expenses (primarily due to $1.2 million and $0.8 million of costs related to higher substation and vegetation management expenses, respectively). Higher depreciation expense was attributable to additions to plant in service in 2006 (including HECO’s New Dispatch Center and Ford Island Substation, and MECO’s M18 generating unit).
The trend of increased O&M expenses is expected to continue in 2007 as the electric utilities expect (1) higher DSM expenses (that are generally passed on to customers through a surcharge, including additional expenses for programs that have been approved in an energy efficiency DSM Docket) and integrated resource planning expenses, (2) higher employee benefit expenses, primarily for retirement benefits, and (3) higher production expenses, primarily to support the increased level of peak demand that has occurred over the last five years.
As a result of load growth on Oahu and other factors, there currently is an increased risk to generation reliability. Existing units are running harder, resulting in more frequent and more extensive maintenance, at times requiring temporary shut downs of these units. Generation reserve margins on Oahu during peak periods continued to be strained. HECO has taken a number of steps to mitigate the risk of outages, including securing additional purchased power, adding distributed generation (DG) at some substations and encouraging energy conservation. The marginal costs of supplying growing demand, however, are increasing because of the decreasing reserve margin situation, and the trend of cost increases is not likely to ease.
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 preparing financial statements, managementMarch 2000, the PUC approved a standard form contract for customer retention that allows HELCO to provide a rate option for customers who would otherwise reduce their energy use from HELCO’s system by using energy from a nonutility generator. Based on HELCO’s current rates, the standard form contract provides a 10% discount on base energy rates for qualifying “Large Power” and “General Service Demand” customers. In November 2006, HELCO entered into three-year standard form contracts with two of its hotel customers.
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 stated purpose of this proceeding was to evaluate competitive bidding as a mechanism for acquiring or building new generating capacity in Hawaii.
The parties in the proceeding included the Consumer Advocate, HECO, HELCO, MECO, Kauai Island Utility Cooperative (KIUC) and Hawaii Renewable Energy Alliance (HREA), a renewable energy organization. The issues addressed in the proceeding included whether a competitive bidding system should be developed for acquiring or building new generation and, if so, 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.
On June 30, 2006, the PUC issued a decision in this proceeding, which included a proposed framework to govern competitive bidding as a mechanism for acquiring or building new generation in Hawaii and required the parties to submit comments on the proposed framework. On December 8, 2006, the PUC issued a decision which reviewed the parties’ comments and revised the competitive bidding framework, which became effective upon issuance of the decision. The final framework states, among other things, that: (1) a utility is required to make estimatesuse competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable, (2) the determination of whether to use competitive bidding for a future generation resource or a block of generation resources will be made by the PUC during its review of the utility’s IRP, (3) an exemption
from the framework is granted for cooperatively-owned utilities, (4) the framework does not apply to two pending projects (HECO’s CIP-1 and assumptionsHELCO’s ST-7), MECO’s M-18 project (which went into commercial operation in October 2006), specifically identified offers to sell energy on an as-available basis or to sell firm energy and/or capacity by non-fossil fuel producers that affectwere under review by an electric utility at the reported amountstime this framework was adopted (provided that negotiations with the non-fossil producers are completed no later than December 31, 2007), and certain other situations identified in the framework, (5) waivers from competitive bidding for certain circumstances will be considered by the PUC and granted when considered appropriate, (6) for each project that is subject to competitive bidding, the utility is required to submit a report on the cost of assetsparallel planning upon the PUC’s request, (7) the utility is required to consider the effects on competitive bidding of not allowing bidders access to utility-owned or controlled sites, and liabilities,to present reasons to the disclosurePUC for not allowing site access to bidders when the utility has not chosen to offer a site to a third party, (8) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders) in response to a need that is addressed by its Request for Proposal (RFP) or when the PUC otherwise determines, (9) the evaluation of contingent assetsthe utility’s bid should account for the possibility that the capital or running costs actually incurred, and liabilitiesrecovered from ratepayers, over the plant’s lifetime, will vary from the levels assumed in the utility’s bid, (10) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP and (11) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC. In accordance with the decision, the utilities filed in March 2007 proposed tariffs containing procedures for Interconnection and transmission upgrades and proposed Codes of Conduct are expected to be filed by June 6, 2007.
Management cannot currently predict the ultimate effect of this decision on the ability of the electric utilities to acquire or build additional generating capacity in the future.
DG proceeding. In October 2003, the PUC opened a DG proceeding to determine DG’s potential benefits to and impact on Hawaii’s electric distribution systems and markets and to develop policies and a framework for DG projects deployed in Hawaii.
On January 27, 2006, the PUC issued its D&O in the DG proceeding. In the D&O, the PUC indicated that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system.
With regard to DG ownership, the D&O affirmed the ability of the electric utilities to procure and operate DG for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. In weighing the general advantages and disadvantages of allowing a utility to provide DG services on a customer’s site, the PUC found that the “disadvantages outweigh the advantages.” However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the electric utilities from providing DG services at this early stage of DG market development. Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost alternative to meet that need, and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.
On March 1, 2006, the electric utilities filed a Motion for Clarification and/or Partial Reconsideration (DG Motion). On April 6, 2006, the PUC issued its decision on the electric utilities’ DG Motion and provided clarification to the conditions under which the electric utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systems and other supply-side and demand-side options—to support a finding that utility-owned customer-sited DG projects fulfill a legitimate system need, and the economic standard of “least cost” in the order means “lowest reasonable cost” consistent with the standard in the IRP framework), and affirmed that the electric utility has the responsibility to demonstrate that it meets all applicable criteria included in the D&O in its application for PUC approval to proceed with a specific DG project.
The electric utilities are currently evaluating several potential DG and combined heat and power (CHP, a form of DG) projects. In July 2006, MECO filed an application for PUC approval of an agreement for the installation of a CHP system at a hotel site on the island of Lanai. On September 11, 2006, the PUC issued a Schedule of Proceedings for its consideration of this CHP project. The Consumer Advocate filed its statement of position in January 2007 and MECO filed its response in February 2007. The Consumer Advocate did not object to approval of MECO’s application with the qualification that no determination be made at this time as to whether the costs associated with installation of the CHP system can be included in MECO’s revenue requirements. MECO’s response, filed in February 2007, explained that the Consumer Advocate’s conditions would not allow MECO to proceed with the project as such a conditional approval would not provide reasonable assurance that MECO will be able to include the associated costs in its revenue requirement. MECO requested that the PUC approve the CHP agreement, approve inclusion of the fuel and transportation costs and associated taxes in MECO’s ECAC and allow MECO to include the costs incurred in its revenue requirement for ratemaking purposes.
The D&O also required the electric utilities to file tariffs, establish reliability and safety requirements for DG, establish a non-discriminatory DG interconnection policy, develop a standardized interconnection agreement to streamline the DG application review process, establish standby rates based on unbundled costs associated with providing each service (i.e., generation, distribution, transmission and ancillary services), and establish detailed affiliate requirements should the utility choose to sell DG through an affiliate. The electric utilities filed their proposed modifications to existing DG interconnection tariffs and their proposed unbundled standby rates for PUC approval in the third quarter of 2006. The Consumer Advocate stated that it did not object to implementation of the interconnection and standby rate tariffs at the present time, but reserved the right to review the reasonableness of both tariffs in rate proceedings for each of the utilities.
Distributed generation tariff proceeding. By order dated December 28, 2006, the PUC opened a new proceeding to investigate the utilities’ proposed DG interconnection tariff modifications and standby rate tariffs. Public hearings were held during February and March 2007. In April 2007, the PUC granted intervenor status to HREA, a group of hotel and resort companies, a group consisting of a CHP vendor, a hotel company and a hospital management company, a senior living community company and the United States Combined Heat and Power Association. As proposed by the electric utilities, the PUC also ordered the electric utilities to hold one or more technical meetings with the parties and directed the parties to submit a stipulation identifying the remaining issues, procedural steps and schedule for the proceeding. The first of the technical meetings is required to begin no later than May 18, 2007 and the stipulated procedural schedule is due by June 22, 2007.
Most recent rate requests
The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of the application, but there is no guarantee of such an interim increase or its amount and amounts collected are refundable, with interest, to the extent they exceed the amount approved in the final D&O. The timing and amount of any final increase is determined in the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the return on average common equity and return on rate base) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.
As of May 1, 2007, 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). The ROACEs used by the PUC for purposes of the interim rate increases in HECO’s and HELCO’s rate cases based on 2005 and 2006 test years, respectively, were both 10.70%.
For 2006, the simple average ROACEs (calculated under the rate-making method and reported amountsto the PUC semi-annually), which calculations include charges to accumulated other comprehensive income (AOCI) due to the application of SFAS No. 158, for HECO, HELCO and MECO were 8.19%, 3.88% and 9.86%, respectively; if the AOCI charges due to SFAS No. 158 were excluded, these ROACEs would have been 7.61%, 3.70% and 9.51%,
respectively. HECO’s actual ROACE continues to be significantly lower than its allowed ROACE primarily because of increased O&M expenses, which are expected to continue and have resulted in HECO seeking rate relief more often than in the past. The interim rate relief granted to HECO by the PUC in September 2005 (see below) was based in part on increased costs of operating and maintaining HECO’s system. HELCO’s ROACE was negatively impacted by CT-4 and CT-5 as its electric rates did not change for the unit additions until the PUC granted interim rate relief in the HELCO 2006 rate case (see below).
As of May 1, 2007, the return on 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). However, the RORs used for purposes of the interim D&Os in the HECO and HELCO rate cases based on 2005 and 2006 test years were 8.66% and 8.33%, respectively. For 2006, the simple average RORs (calculated under the rate-making method and reported to the PUC semi-annually) for HECO, HELCO and MECO were 6.78%, 4.50% and 7.21%, respectively.
By reason of the adoption of SFAS No. 158, HECO and MECO had, and may in the future have, significant charges to AOCI related to the funded status of their retirement benefit plans, which decrease their common stock equity. Absent appropriate regulatory relief in rate cases to adjust for the impact on equity of these AOCI charges, the resulting increase in their RORs and ROACEs could impact the rates they are allowed to charge, which may ultimately result in reduced revenues and expenses. For example,lower earnings. HELCO received an interim D&O in determiningits 2006 test year rate case, which included the reclassification, beginning April 5, 2007, to a regulatory asset of the charge for retirement benefits that HECO is not the primary beneficiary of Kalaeloa under the provisions of FIN 46Rwould otherwise be recorded in AOCI (see Note 24 of HECO’s “Notes to Consolidated Financial Statements”).
HECO.
2005 test year rate case. In November 2004, HECO filed a request with the PUC to increase base rates 9.9%, or $99 million in annual base revenues, based on a 2005 test year, a 9.11% ROR and an 11.5% ROACE. The requested increase included transferring the cost of existing DSM programs from a surcharge line item on electric bills into base electricity charges. HECO also requested approval and/or modification of its existing and proposed DSM programs, and associated utility incentive mechanism. Excluding the surcharge transfer amount, the requested net increase to customers was 7.3%, or $74 million.
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 (EE DSM Docket). The issues for the EE DSM Docket included (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, (4) for utility-incurred costs, what cost recovery mechanisms and cost levels are appropriate, (5) whether, and if so, what incentive mechanisms are appropriate to encourage the implementation of DSM programs, and (6) which DSM programs should be approved, modified, or rejected. See “Other regulatory matters—Demand-side management programs” below for a discussion of the PUC’s D&O issued in the EE DSM Docket on February 13, 2007.
In September 2005, HECO, the Consumer Advocate and the DOD reached agreement (subject to PUC approval) on most of the issues in the rate case proceeding, excluding the portion of the original rate case bifurcated into the EE DSM Docket. The remaining significant issue not resolved among the parties was the appropriateness of including in rate base approximately $50 million related to HECO’s prepaid pension asset, net of deferred income taxes.
Later in September 2005, the PUC issued its interim D&O (with tariff changes implemented on September 28, 2005). For purposes of the interim D&O, the PUC included HECO’s prepaid pension asset in rate base (with an annual rate increase impact of approximately $7 million).
The following amounts were included in HECO’s rebuttal, the Consumer Advocate’s and the DOD’s testimonies and exhibits (as adjusted to exclude the transferred surcharge amount of $12 million); the settlement agreement with the Consumer Advocate and the DOD; and the PUC’s interim D&O:
| Pre-Settlement | |||||||||||||||
(dollars in millions) | HECO rebuttal | Consumer Advocate | Department of Defense | HECO (per settlement) | Interim increase1 | ||||||||||
Net additional revenues2 | $ | 51 | $ | 11 | $ | 7 | $ | 42 | $ | 41 | |||||
ROACE (%) | 11 | 8.5-10 | 9 | 10.7 | 10.7 | ||||||||||
ROR (%) | 8.83 | 7.85 | 7.71 | 8.66 | 8.66 | ||||||||||
Average rate base | $ | 1,109 | $ | 1,065 | $ | 1,062 | $ | 1,109 | $ | 1,109 | |||||
1 | Implemented on September 28, 2005, subject to refund with interest pending the final outcome of the case. |
2 | Excludes $12 million transferred from a surcharge to base rates for existing energy efficiency programs. |
On June 19, 2006, the PUC issued a further order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162. Act 162, which became effective in June 2006, requires the PUC to consider certain specific factors in evaluating fuel adjustment clauses. See “Energy cost adjustment clauses” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.” The parties proposed by stipulation not to reopen the record in the proceeding and address the factors in Act 162 since the record had been completed before Act 162 became law. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed by the parties or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162, the ultimate outcome of these issues, the effect of these issues on the operation of the ECAC as it relates to the electric utilities or the timing of the PUC’s issuance of a final D&O in HECO’s pending 2005 test year rate case.
2007 test year rate case. On December 22, 2006, HECO filed a request with the PUC for a general rate increase of $99.6 million, or 7.1% over the electric rates currently in effect (i.e., including the interim rate increase discussed above of $53 million ($41 million net additional revenues) granted by the PUC in September 2005), based on a 2007 test year, an 8.92% ROR, an 11.25% ROACE and a $1.214 billion average rate base. If the additional revenues from the interim increase were ultimately not included in rates in the final D&O in HECO’s 2005 test year rate case, the total increase requested would be $151.5 million. This rate case excluded DSM surcharge revenues and associated incremental DSM costs because certain DSM issues, including cost recovery, were being addressed in the EE DSM Docket.
HECO’s application includes a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase includes costs incurred to maintain and improve reliability, such as the new Dispatch Center building and associated equipment and the Energy Management System that became operational in 2006, new substations, a new outage management system to be added in the second quarter of 2007 and increased O&M expenses.
The application addresses the ECAC provisions of Act 162 and requests the continuation of HECO’s ECAC. On December 29, 2006, the electric utilities’ Report on Power Cost Adjustments and Hedging Fuel Risks (ECAC Report) prepared by their consultant, National Economic Research Associates, Inc., was filed with the PUC. The testimonies filed in the latest rate cases for HECO, HELCO and MECO included or incorporated the ECAC Report, which concluded that (1) the electric utilities’ ECACs are well-designed, and benefit the electric utilities and their ratepayers and (2) the ECACs comply with the statutory requirements of Act 162. With respect to hedging, the consultants concluded that (1) hedging of oil by HECO would not be expected to reduce fuel and purchased power costs and in fact would be expected to increase the level of such costs and (2) even if rate smoothing is a desired goal, there may be more effective means of meeting the goal, and there is no compelling reason for the electric utilities to use fuel price hedging as the means to achieving the objective of increased rate stability.
HECO’s application requests a return on HECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred taxes) in rate base. In a separate proceeding, the electric utilities requested PUC approval to record as a regulatory asset for financial reporting
purposes, the amounts that would otherwise be charged to AOCI in stockholders’ equity as a result of adopting SFAS No. 158, which request was denied. HECO’s application, filed before that decision was issued, assumed that the amounts that would otherwise be charged to AOCI in stockholder’s equity would be recorded as a regulatory asset for financial reporting purposes (and used estimatesfor ratemaking purposes). HECO’s book equity (financial reporting equity) will be lower than that assumed in computing Kalaeloa’sthe rate increase application because of the charges to AOCI as a result of recording a pension and other postretirement benefits liability after implementing SFAS No. 158 on December 31, 2006. As it did in the HELCO rate case discussed below, HECO will propose in its rebuttal testimony to restore the book equity (financial reporting equity) for the amounts that were charged against equity (i.e., AOCI) in determining the equity balance for ratemaking purposes. The authorized ROACE found to be fair in a rate case is applied to the equity balance in determining the utility’s weighted cost of capital, which is the rate of return applied to the rate base in determining the utility’s revenue requirements and rate increase in a rate case. If the reduction in equity balance resulting from the AOCI charges is not restored for ratemaking purposes, the utility’s position is that a higher ROE will be required.
In April 2007, the PUC granted the DOD’s motion to intervene, but denied an environmental organization’s motion to intervene. Evidentiary hearings are expected cash flows. Estimatesto be held in the week beginning October 29, 2007.
HELCO. In May 2006, HELCO filed a request with the PUC to increase base rates by $29.9 million, or 9.24% in annual base revenues, based on a 2006 test year, an 8.65% ROR, an 11.25% ROACE and a $369 million average rate base. HELCO’s application includes a proposed new tiered rate structure, which would enable most residential users to see smaller increases in the range of 3% to 8%. The tiered rate structure is designed to minimize the increase for residential customers using less electricity and is expected to encourage customers to take advantage of solar water heating programs and other energy management options. In addition, HELCO’s application proposes new time-of-use service rates for residential and commercial customers. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution line improvements and the two generating units at the Keahole power plant (CT-4 and CT-5), and increased O&M expenses. The application requests the continuation of HELCO’s ECAC.
The PUC held public hearings on HELCO’s application in June 2006. The PUC granted Keahole Defense Coalition’s motion to participate in this proceeding. In February 2007, the Consumer Advocate submitted its testimony in the proceeding, recommending a revenue increase of $16.6 million based on its proposed ROR of 7.95%, a ROACE ranging between 9.50% and 10.25% and a proposed average rate base of $345 million. The Consumer Advocate recommended adjustments of $21.5 million to HELCO’s rate base for a portion of CT-4 and CT-5 costs (primarily relating to HELCO’s AFUDC, land use permitting costs, and related litigation expenses). In the filing, the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings.
Keahole Defense Coalition (whose participation in the proceeding is limited) submitted a Position Statement in which it contended that the PUC should exclude from rate base a greater amount of the CT-4 and CT-5 costs than proposed by the Consumer Advocate.
In April 2007, Keahole Defense Coalition filed a position statement in response to HELCO’s rebuttal testimonies. HELCO plans to file a response to this statement of position.
In March and May 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement and rate design issues in the HELCO 2006 rate case proceeding. The PUC may accept or reject the settlement agreements or any part of them. If the PUC does not accept the material terms of the agreements, either (or both) of the parties, may withdraw from the agreements and may pursue their respective positions in the proceeding without prejudice. Under the revenue requirement agreement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, which resulted in an after-tax charge of approximately $7 million in the first quarter of 2007.
On April 4, 2007, the PUC issued an interim D&O, which was implemented on April 5, 2007, granting HELCO an increase of 7.58%, or $24.6 million in annual revenues, over revenues at present rates for a normalized 2006 test year. The interim increase reflects the settlement of the revenue requirement issues reached between HELCO and the Consumer
Advocate and is based on an average rate base of $357 million (which reflects the write-off of a portion of CT-4 and CT-5 costs) and a return on average rate base of 8.33% (incorporating a rate of return on average common equity of 10.7%). In the interim D&O, the PUC also approved on an interim basis the adoption of a pension tracking mechanism and a similar tracking mechanism for postretirement benefits other than pensions (see Note 4 of HECO’s “Notes to Consolidated Financial Statements”).
MECO. In February 2007, MECO filed a request with the PUC to increase base rates by $19.0 million, or 5.3% in annual base revenues, based on a 2007 test year, an 8.98% ROR, an 11.25% ROACE and a $386 million average rate base. MECO’s application includes a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage. The proposed rate increase would pay for improvements to increase reliability, including two new generating units added since MECO’s last rate case (which was based on a 1999 test year) at its Maalaea Power plant (M19, a 20 MW combustion turbine placed in service in 2000 and M18, an 18 MW steam turbine placed in service in October 2006 to complete the installation of a second dual-train combined cycle unit), and transmission and distribution infrastructure improvements. The proposed rate structure also includes continuation of MECO’s ECAC. The application requests a return on MECO’s pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of deferred income taxes) in rate base. The application also proposes to restore book equity (in determining the equity balance for ratemaking purposes) for the amounts that were charged against equity (i.e., to AOCI) as a result of recording a pension and other postretirement benefits liability after implementing SFAS No. 158.
The PUC held public hearings on MECO’s application in April 2007.
Other regulatory matters
Demand-side management programs. On February 13, 2007, the PUC issued its D&O in the EE DSM Docket that had been opened by the PUC to bifurcate the EE DSM issues originally raised in the HECO 2005 test year rate case. In the D&O, the PUC authorized HECO to implement its seven proposed EE DSM programs (which include enhancements to its existing programs), with certain modifications, as well as a proposed Residential Customer Energy Awareness (RCEA) Program. In approving the EE DSM portfolio, the PUC found that: (1) the EE DSM portfolio should achieve Energy Efficiency goals and should be implemented in a cost-effective manner and (2) the EE DSM programs are necessary to help address HECO’s current reserve capacity shortfall. On March 8, 2007, HECO filed a motion for clarification and/or partial reconsideration of the D&O which requested, among other things, clarification of certain energy efficiency goals for 2007 and 2008, reconsideration of HECO’s request for budget flexibility which would allow HECO to increase its DSM program budget within certain limits without PUC approval, and clarification of the calculation of the DSM utility incentive.
In addition, the PUC required that the administration of all EE DSM programs be turned over to a non-utility, third-party administrator, with the transition to the administrator, funded through a public benefits fund surcharge, to become effective around January 2009. The PUC indicated that a new docket will be opened to select a third-party administrator and to refine details of the new market structure. Unlike the EE DSM programs, load management DSM programs (see below) will continue to be administered by the utilities. The utilities also may compete for implementation of the EE DSM programs and the RCEA Program and the PUC did not determine any of the parameters of the eligibility of HECO or its subsidiaries or the selection criteria that will be used in awarding program implementation.
The D&O also provides for HECO’s recovery of DSM program costs and utility incentives. With respect to cost recovery, the analysis,PUC continues to permit recovery of reasonably-incurred DSM implementation costs, under the Integrated Resource Plan (IRP) framework. Specifically, during the transition period under the current utility market structure, labor costs are to be recovered through base rates, while non-labor costs will be recovered via a surcharge. DSM utility incentives will be derived from a graduated performance-based schedule of net system benefits. In order to qualify for examplean incentive, the utility must meet MW and MWh reduction goals for its EE DSM programs in both the commercial and industrial, and residential sectors. The amount of the annual incentive is capped at $4 million for HECO, and may not exceed either 5% of the net system benefits, or utility earnings
opportunities foregone by implementing DSM programs in lieu of supply-side rate based investments. Negative incentives will not be imposed for underperformance.
The PUC further indicated that a new docket will be opened to approve HECO’s periodic DSM program reports and field any of HECO’s requests for DSM program modifications. The issue of decoupling sales from revenues, which had been proposed by one party to the proceeding, was deferred to a future proceeding.
In 2004, HECO and the Consumer Advocate reached agreement on a residential load management program and a commercial and industrial load management program and the PUC approved HECO’s programs. Implementation of these programs began in early 2005. The residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow to be controlled or interrupted by HECO. In addition, if HECO interrupts the load, an incentive is paid on the kilowatthours interrupted.
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, the Consumer Advocate, the DOD, and representatives of existing or potential IPPs. In March 1994, the parties entered into and filed a Stipulation to Resolve Proceeding, which is subject to PUC approval. The parties could not reach agreement with respect to certain of the variabilityissues, which are addressed in Statements of Position filed in March 1994. In July 2004, the PUC ordered the parties to review and update the agreements, information and data contained in the stipulation and file such information. On December 29, 2006, the parties filed an Updated Stipulation to Resolve Proceeding with the PUC. The parties agreed that avoided fuel usagecosts, except for Lanai and pricingMolokai, will be determined using a computer production simulation model and operational levelsagreed on certain parameters that would be used to calculate avoided costs. The parties were not in total agreement on certain other issues which will need to be decided by the PUC. HECO and its subsidiaries, the Consumer Advocate and the DOD filed a joint statement of position that they oppose retroactive compensation to Wailuku River Hydro for transformer losses, as proposed by Mauna Kea Power Company, Inc. and the Hawaii Agriculture Research Center.
Integrated resource planning, requirements for additional generating capacity and adequacy of supply. The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop integrated resource plans (IRPs), which may be approved, rejected or modified by the PUC. The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. The utilities’ proposed IRPs are planning strategies, rather than fixed courses of action, and the resources ultimately added to their systems may differ from those included in their 20-year plans. Under the PUC’s IRP framework, the utilities are required to submit annual evaluations of their plans (including a revised five-year program implementation schedule) and to submit new plans on a three-year cycle, subject to changes approved by the PUC. Prior to proceeding with the DSM programs, separate PUC approval proceedings must be completed.
The utilities are entitled to recover all appropriate and reasonable integrated resource planning and implementation costs, are particularly susceptibleincluding the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities can begin recovering their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to change. Management usedrefund with interest pending the PUC’s final D&O approving recovery in the docket for each year’s costs. HELCO and HECO now recover IRP costs through base rates and MECO continues to recover its best effortscosts through a surcharge. The Consumer Advocate has objected to the recovery of $2.9 million (before interest) of the $8.4 million of incremental IRP costs incurred by the utilities during the 1997-2005 period, and the PUC’s decision is pending on these costs. In addition, MECO incurred approximately $0.7 million of incremental IRP costs for 2006, for which the Consumer Advocate has not yet stated its
position. Also, see Note 5 in HECO’s “Notes to Consolidated Financial Statements” and “Demand-side management programs” above.
HECO’s IRP.In October 2005, HECO filed its third IRP (IRP-3), which proposes multiple solutions to meet Oahu’s future energy needs, including renewable energy resources, energy efficiency, conservation, technology (such as CHP and DG) and central station generation (including a combustion turbine generating unit in 2009 described under “HECO’s 2009 Campbell Industrial Park generating unit” and a possible 180 MW coal unit in 2022). In addition, HECO currently plans for all existing generating units to remain in operation (future environmental considerations permitting) beyond the 20-year IRP planning period (2006-2025). In June 2006, the PUC granted an environmental organization’s motion to intervene in the proceeding and ordered the parties to determine the expected cash flowsissues, procedures and schedule for the docket and to file a stipulated procedural order. In September 2006, the parties to the IRP-3 docket filed for PUC approval a stipulation for the parties to meet informally to address IRP-3 process issues and to attempt to reach a follow-up stipulation that will allow for the disposition of the IRP-3 docket without a final D&O approving the IRP-3 plan and action plan. On March 7, 2007, HECO, the Consumer Advocate and the environmental organization filed the follow-up stipulation with the PUC, which the PUC approved in its D&O issued on March 21, 2007. The D&O requires HECO to (1) file its Evaluation Report for IRP-3 by May 31, 2007, after which the IRP-3 docket will be closed, (2) initiate the development of its IRP-4, beginning with the first Advisory Group meeting in March 2007 and (3) file its IRP-4 Plan and Action Plans by June 30, 2008, unless ordered otherwise by the PUC. On March 29, 2007, the PUC opened a new docket for the IRP-4 plan and, pursuant to the stipulation, the first Advisory Group meeting was held on March 30, 2007.
HELCO’s IRP.In September 1998, HELCO filed its second IRP with the PUC, and updated it in 1999 and 2004. On the supply side, HELCO’s second IRP focused on the planning for generating unit additions after near-term additions. The near-term additions included installing two 20 MW CTs at its Keahole power plant site (which were put into limited commercial operation in May and June 2004) and a PPA with Hamakua Energy Partners, L.P. (HEP) for a 60 MW (net) facility (which was completed in December 2000). HELCO has deferred the retirements of some of its older generating units until the 2030 timeframe, and periodically assesses the cost-effectiveness of the continued operation of those units. HELCO’s current plans are to install an 18 MW heat recovery steam generator (ST-7) in 2009 or earlier. After the installation of ST-7, the target date in HELCO’s updated second IRP for the next firm capacity addition is the 2020 timeframe.
HELCO’s third IRP is required to be filed with the PUC by May 31, 2007.
MECO’s IRP.In April 2007, MECO filed its third IRP, which proposes multiple solutions to meet future energy needs on the islands of Maui, Lanai and Molokai, including renewable energy resources (such as photovoltaics, additional wind, biomass and waste-to-energy), energy efficiency (continuation of existing and addition of new DSM programs), technology (such as CHP and DG) and central station generation (including 20 MW combustion turbines in each of 2011 and 2013 and an 18 MW steam turbine in 2024 which, under the utility baseline plan would all be located at its Waena site, and approximately 2 MW of additional generation through the year 2026 on each of the islands of Lanai and Molokai).
HECO’s 2009 Campbell Industrial Park generating unit. In June 2005, HECO filed with the PUC an application for approval of funds to build a new 110 MW simple cycle combustion turbine (CT) generating unit at Campbell Industrial Park and an additional 138 kilovolt transmission line to transmit power from generating units at Campbell Industrial Park (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). Plans are for the combustion turbine to be run primarily as a “peaking” unit beginning in 2009, fueled by biofuels, but with the capability of using diesel or naphtha. On December 15, 2005, HECO signed a contract with Siemens to purchase a 110 MW combustion turbine unit. The contract allows HECO to terminate the contract at a specified payment amount if necessary CT project approvals are not obtained.
In July 2006, the Honolulu City Council adopted a resolution to amend the Public Infrastructure Map to include the new generating facility at Campbell Industrial Park. HECO’s Final Environmental Impact Statement for the Project was accepted by the Department of Planning & Permitting of the City and County of Honolulu in August 2006. In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100%
biofuels in its new plant and the steps necessary for HECO to reach that goal. After agreeing to use 100% biofuels in its new plant, there were no remaining differences between HECO and the Consumer Advocate regarding the issues in the docket. An environmental organization that had been permitted by the PUC to intervene agreed that there is a need for additional generation on Oahu, but disagreed on the use of the proposed CT unit and the use of biofuels. Hearings were held in December 2006. Opening and Reply Briefs were filed in March 2007 and the matter awaits a PUC decision.
Preliminary costs for the Project are estimated at $138 million. As of March 31, 2007, accumulated Project costs for planning, engineering, permitting and AFUDC amounted to $4.4 million.
In conjunction with the Project, HECO is evaluating bids from potential suppliers of ethanol or biodiesel for the new unit. The PUC would need to approve any resulting ethanol or biodiesel fuel supply contract.
In a related application filed with the PUC in June 2005, HECO requested approval for part of the package of community benefit measures, which is currently estimated at $13.8 million (through the first 10 years of implementation), 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 HECO’s residential customers 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 for industrial water consumption at the Kahe power plant. For the community benefits application, the only party to the proceeding is the Consumer Advocate, and a hearing was held in November 2006. The primary issue during the hearing was whether rate recovery of foregone revenues from the proposed electric rate discount program is just and reasonable. The Consumer Advocate did not object to the remainder of the community benefit package. Briefs were filed in January 2007 and a PUC decision is pending.
Adequacy of supply.
HECO. HECO’s 2007 Adequacy of Supply (AOS) letter, filed in February 2007, indicates that HECO’s analysis estimates its reserve capacity shortfall to be approximately 70 MW in the 2007 to 2008 period (before the addition of the Campbell Industrial Park combustion turbine planned to be installed in 2009). The availability rates for HECO units have generally declined since 2002 and, based on historicalthis experience, financial information provided by Kalaeloathe manner in which the units must be operated when there is a reserve capacity shortfall, and the increasing ages of the units, HECO expects availability rates to remain suppressed in the near-term. Although the availability rates for generating units on various other assumptions that were believedOahu continue to be better than those of comparable units on the U.S. mainland, HECO generating units may continue to be entirely or partially unavailable to serve load during scheduled overhaul periods and other planned maintenance outages, or when they “trip” or are taken out of operation or their output is “de-rated” due to equipment failure or other causes.
To mitigate the projected reserve capacity shortfalls, HECO is continuing to plan and implement mitigation measures, such as installing distributed generators at substations or other sites, implementing additional load management and other demand reduction measures, and pursuing efforts to improve the availability of generating units. HECO will operate at lower than desired reliability levels and take steps to mitigate the reserve capacity shortfall situation until the next generating unit is installed. Until sufficient generating capacity can be added to the system, HECO will experience a higher risk of generation-related customer outages.
After the planned 2009 addition of the Campbell Industrial Park generating unit, and in recognition of the uncertainty underlying key forecasts, HECO anticipates the potential for continued reserve capacity shortfalls, which could range between 20 MW to 110 MW in the 2009 to 2012 period. Any plan to install additional firm capacity is required to proceed under the guidance of the Competitive Bidding Framework issued by the PUC in December 2006.
HECO’s gross peak demand was 1,327 MW in 2004, 1,273 MW in 2005 and 1,315 MW in 2006. Although the gross peak demand in 2005 and 2006 was lower than in 2004, demand for electricity on Oahu is projected to increase. On occasions in 2004, 2005, 2006 and 2007, HECO issued public requests that its customers voluntarily conserve electricity as generating units were out for scheduled maintenance or were unexpectedly unavailable. In addition to making the requests, in 2005, 2006 and 2007, HECO on occasion remotely turned off water heaters for a number of residential customers who participate in its load-control program.
HELCO. HELCO’s 2007 Adequacy of Supply letter filed in January 2007 indicated that HELCO’s generation capacity for the next three years, 2007 through 2009, is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies.
MECO. In December 2005, MECO’s Maalaea Unit 13, a diesel generator, suffered an equipment failure and the unit is not expected to be available for service until approximately July 2007. In February 2007, MECO filed its 2007 Adequacy of Supply letter, which indicated that MECO’s Maui island system should usually have sufficient installed capacity to meet the forecasted loads. However, in the event of an unexpected outage of the largest unit, the Maui island system may not have sufficient capacity until Maalaea Unit 13, with a 12.34 MW capacity, returns to service. To overcome insufficient reserve capacity situations, MECO has been implementing appropriate mitigation measures, such as optimizing its unit overhaul schedule to minimize load capability shortfalls, coordinating the delivery of supplemental power, as needed, from an IPP and modifying its combined-cycle unit overhaul procedure to allow for the possible operation of the combustion turbine in simple-cycle mode. In October 2006, MECO placed into commercial operation an additional 18 MW of capacity at its Maalaea power plant site.
In April and August 2006, MECO experienced lower than normal generation capacity due to the unexpected temporary loss of several of its generating units, and issued a public request that its customers voluntarily conserve electricity.
Recent outages. On June 1, 2006, due to the unanticipated loss of three generating units from an IPP and two HECO generating units, HECO shed power to 29,300 customers in various parts of the island. Power was restored to all customers within four hours.
On Sunday, October 15, 2006, shortly after 7 a.m., two earthquakes centered on the island of Hawaii with magnitudes of 6.7 and 6.0 triggered power outages throughout most of the state and disrupted air traffic on all major islands. On Oahu, following the impact of the earthquakes, a series of protective actions and automatic systems operated to successively shut down all generators to protect them from potential damage. As a result, no significant damage to any of HECO’s generators, or to its transmission and distribution systems, occurred. Following the island-wide outage, HECO restored power to customers in a careful, methodical manner to further protect its system, and as a result power was restored to over 99% of its customers within a period of time ranging from approximately 4 1/2 to 18 hours. Management believes the shutdown and methodical restoration of power were necessary to prevent severe damage to HECO’s generating equipment and power grid and to avoid a more prolonged blackout. HELCO’s and MECO’s smaller electric systems also experienced sustained outages from the earthquakes; however, their systems were for the most part back online by mid to late afternoon.
As is the electric utilities’ practice with all major system emergencies, management immediately committed to investigating the outage caused by the earthquakes, including bringing in an outside industry expert to help identify any potential improvements to procedures or systems, and also made arrangements for a preliminary briefing of the PUC. The PUC briefings took place on October 19 and 20, 2006. HECO also conducted a public briefing on October 23, 2006. HECO has made it clear that in addition to any investigation it undertakes, it will cooperate fully with any other reviews conducted by its regulators.
Following requests by members of a state Senate energy subcommittee and the Consumer Advocate that the PUC investigate the power failure, to which investigation HECO stated it did not object, the PUC issued an order on October 27, 2006 opening an investigative proceeding on the outages at HECO, HELCO and MECO. The questions the PUC has asked to be addressed in the proceeding include (1) aside from the earthquake, are there any underlying causes that contributed or may have contributed to the power outages, (2) were the actions of the electric utilities prior to and during the power outages reasonable and in the public interest, and were the power restoration processes and communication regarding the outages reasonable and timely under the circumstances, (3) could the resultsisland-wide power outages on Oahu and Maui have been avoided, and what are the necessary steps to minimize and improve the response to such occurrences in the future, and (4) what penalties, if any, should be imposed on the electric utilities. Pursuant to the PUC’s order, HECO’s 2006 Outage Report was filed in December 2006, and the outage reports of which formedHELCO and MECO were filed in March 2007. The investigation consultants retained by HECO, POWER Engineers, Inc., concluded that, “HECO’s performance prior to and during the outage demonstrated reasonable actions in the public interest” in a “distinctly extraordinary event.”
Power Engineers, Inc. also concluded that HELCO and MECO personnel responded in a “reasonable, responsible, and professional manner.” The consultants also made a number of recommendations, mostly of a technical nature, regarding the operation of the electric system during such an incident. Management cannot predict the outcome of the investigation or its impacts on the utilities. Management currently believes the financial impacts of property damage and claims resulting from the earthquakes and outages are not material, but future findings and developments may change that belief.
Collective bargaining agreements
See “Collective bargaining agreements” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
Legislation and regulation
Congress and the Hawaii legislature periodically consider legislation that could have positive or negative effects on the utilities and their customers.
Energy Policy Act of 2005. On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (the Act). The Act provides $14.5 billion in tax incentives over a 10-year period designed to boost conservation efforts, increase domestic energy production and expand the use of alternative energy sources, such as solar, wind, ethanol, biomass, hydropower and clean coal technology. Ocean energy sources, including wave power, are identified as renewable technologies. Section 355 of the Act authorizes a study by the U.S. Department of Energy of Hawaii’s dependence on oil; however, that provision is subject to appropriation, as is $9 million authorized under Section 208 for a sugar cane ethanol program in Hawaii. Incentives also include tax credits and shorter depreciable lives for many assets associated with energy production and transmission. The Act’s primary direct impact on HECO and its subsidiaries is currently expected to be the reduction in the depreciable tax life, from 20 years to 15 years, of certain electric transmission equipment placed into service after April 11, 2005.
Renewable Portfolio Standard. The 2004 Hawaii Legislature amended an existing renewable portfolio standard (RPS) law to require electric utilities to meet a renewable portfolio standard of 8% of KWH sales by December 31, 2005, 10% by December 31, 2010, 15% by December 31, 2015, and 20% by December 31, 2020. These standards may be met by the electric utilities on an aggregated basis and were met in 2005 when they attained a RPS of 11.7%. It may be difficult, however, for the estimated cash flows. Actual resultselectric utilities to attain the required renewables percentages in the future, and management cannot predict the future consequences of Kalaeloa could differ significantlyfailure to do so (including potential penalties to be established by the PUC).
The RPS law was further amended in 2006 to provide that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources, such as wind or solar, versus from those estimations,the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The amendment also added provisions for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control.
The PUC must, by December 31, 2007, 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 potentially triggernot have been reasonably anticipated or ameliorated.
On January 11, 2007, the PUC opened a reconsiderationnew docket (RPS Docket) to examine Hawaii’s amended RPS law, to establish the appropriate penalties and to determine circumstances under which penalties should be levied. The PUC indicated that the 2006 amendment to the RPS law that added provisions for penalties effectively gives utilities incentive to comply with RPS and therefore the PUC will no longer complete the rulemaking in a process initiated in November 2004, but will instead proceed by way of this RPS Docket to handle any issues related to the utilities meeting renewable portfolio standards. The parties in the proceeding include the electric utilities, the Consumer Advocate, an environmental organization and HREA. The PUC set forth the issues for the proceeding to be (1) the appropriate penalty framework to establish under the RPS law for failure to meet the RPS, (2) the appropriate utility
ratemaking structure to establish and include in the framework to provide incentives that encourage electric utilities to use cost-effective renewable energy resources while allowing for deviations from the standards in the event the standards cannot be met in a cost-effective manner, or as a result of circumstances beyond the control of the electric utility that could not have been reasonably anticipated or ameliorated and (3) should the framework include a provision that provides incentives to encourage utilities to exceed the RPS or to meet their RPS ahead of time or both. The parties filed preliminary position statements in April 2007, and final position statements of the parties are expected to be filed in June 2007. The PUC has a deadline to issue a decision and order by December 31, 2007. Management cannot predict the outcome of this process.
See “Renewable energy strategy” under “Other developments” below.
Net energy metering. Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly). The law provides a cap of 0.5% of the electric utility’s peak demand on the total generating capacity produced by eligible customer-generators. The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the maximum size of eligible net metered systems from 10 kilowatts (kw) to 50 kw and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less.
In 2005, the Legislature again amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kw and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative, a renewable energy organization and a solar vendor organization. The PUC has approved a procedural schedule with panel hearings scheduled for October 2007. Depending on their magnitude, changes made by the PUC by rule or order could have a negative effect on electric utility sales. Management cannot predict the outcome of the investigative proceeding.
DSM programs. In 2006, the PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds currently collected by the utilities and included in their revenues through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC. In February 2007, the PUC issued a D&O requiring that administration of EE DSM programs be turned over to a non-utility third party administrator in 2009, to be funded through such a public benefits surcharge. See “Demand-side management programs” above for a discussion of the D&O.
Non-fossil fuel purchased power contracts. In 2006, the Hawaii State legislature passed a measure which required that the PUC establish a methodology that removes or significantly reduces any linkage between the price paid for non-fossil-fuel-generated electricity under future power purchase contracts and the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation (in connection with the PUC’s determination of just and reasonable rates in purchased power contracts).
Other legislation. A number of bills were introduced in the 2007 Hawaii State legislative session. The majority of the measures contained in the bills are not expected to negatively affect the electric utilities, and the electric utilities supported many of the measures that would encourage the more efficient use of energy and the use of Hawaii’s renewable resources. Various bills also proposed different approaches to addressing the issue of global warming.
On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts v. EPA, that, contrary to EPA’s position, the EPA has the authority to regulate greenhouse gases under the Clean Air Act. Although it is too early to assess the ultimate impact of the ruling, since the decision there have been reports that comprehensive legislation may be introduced in Congress this term to regulate greenhouse gas emissions.
At this time, it is not possible to predict with certainty the outcome of any proposed or new legislation.
Other developments
Advanced Meter Infrastructure (AMI). HECO is evaluating the primary beneficiaryfeasibility of Kalaeloa.utility applications using power line and wireless technologies for two-way communication.
HECO is currently partnering with Sensus Metering Systems to field test an Advanced Metering Infrastructure system that delivers two-way communications to advanced meters, which can enable time-of-use pricing and conservation options for HECO customers. This pilot is expected to include more than 3,000 residential, commercial and industrial customers. Other utility applications being evaluated include distribution system line monitoring, load control for residential and commercial customers and monitoring of distribution substation equipment.
Renewable energy strategy. The electric utilities continue to pursue the following 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 the electronic shock absorber (ESA) for wind generation). They are also conducting integrated resource planning to evaluate the increased use of renewables within the electric utilities’ service territories.
The electric utilities support renewable energy through their 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 received a U.S. patent in February 2005 for an ESA that addresses power fluctuations from wind resources. An ESA demonstration system was installed and tested at HELCO’s Lalamilo wind farm. The demonstration confirmed the viability of the technology on a small-scale wind farm, and management plans to pursue a larger scale project in the future. HECO has an intellectual property license agreement with S&C Electric Company (S&C), the party constructing the ESA demonstration system. S&C has the right to seek international patents for the design. On October 16, 2006, the ESA demonstration system sustained structural and fire damage and is no longer operational. The impact of the loss on the electric utilities’ financial statements is immaterial. Management cannot predict the amount of royalties HECO may receive from the sale of ESAs in the future.
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 a Conditional Investment Agreement for a small-scale landfill gas-to-energy project on Oahu, a Framework Agreement for evaluation of three wind projects and two pumped storage hydroelectric projects and two Project Agreements providing the option to invest in wind projects. 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.
In February 2007, BlueEarth Biofuels LLC (BlueEarth) announced plans for a new biodiesel refining plant to be built on the island of Maui by 2009. The biodiesel plant will be owned by BlueEarth Maui Biofuels LLC (BlueEarth Maui), a planned new venture between BlueEarth and a to-be-formed non-regulated subsidiary of HECO. All of the HECO non-regulated subsidiary’s profits from the project will be directed into a biofuels public trust to be created for the purpose of funding biofuels development in Hawaii. MECO intends to lease to the non-regulated subsidiary of HECO a portion of the land owned by MECO for its future Waena generation station as the site for the biodiesel plant, with lease proceeds to be credited to MECO ratepayers. In addition, MECO plans to negotiate a fuel purchase contract with BlueEarth Maui for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. Both the lease agreement and biodiesel fuel contract will require PUC approval.
Commitments and contingencies
See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretations
See Note 7 of HECO’s “Notes to Consolidated Financial Statements.”
FINANCIAL CONDITION
Liquidity and capital resources
HECO believes that its ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.
HECO’s consolidated capital structure (which includes the impact of the sale of the SPRBs on March 27, 2007 and the application of the proceeds thereof (i) to reimburse the utilities for capital expenditures and their use of the reimbursements to paydown short-term borrowings and (ii) to provide a portion of the funds required to refund two series of SPRBs originally issued in 1996) was as follows as of the dates indicated:
(in millions) | March 31, 2007 | December 31, 2006 | ||||||||||
Short-term borrowings | $ | 47 | 2 | % | $ | 113 | 6 | % | ||||
Long-term debt | 858 | 45 | 766 | 41 | ||||||||
Preferred stock | 34 | 2 | 34 | 2 | ||||||||
Common stock equity | 960 | 51 | 959 | 51 | ||||||||
| $ | 1,899 | 100 | % | $ | 1,872 | 100 | % | |||||
As of May 1, 2007, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HECO securities were as follows:
| S&P | Moody’s | |||
Commercial paper | A-2 | P-2 | ||
Revenue bonds (senior unsecured, insured) | AAA | Aaa | ||
HECO-obligated preferred securities of trust subsidiary | BBB- | Baa2 | ||
Cumulative preferred stock (selected series) | Not rated | Baa3 |
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 March 2007, S&P confirmed its corporate credit ratings of HECO and maintained its negative outlook. S&P’s ratings outlook “assesses the potential direction of a long-term credit rating over the intermediate term (typically six months to two years).” S&P indicated:
Failure to strengthen key financial parameters, especially cash flow coverage of debt, a slump in the Hawaiian economy, a final rate order that differs from the PUC’s interim decision with regard to HECO’s 2005 rate case, . . . could lead to lower ratings. Conversely, credit-supportive actions by the company as well as responsive rate treatment would lead to ratings stability.
In addition, S&P ranks business profiles from “1” (strong) to “10” (weak). In March 2007, S&P did not change HECO’s business profile rank of “5.”
In December 2006, Moody’s confirmed its issuer ratings and stable outlook for HECO. Moody’s stated, “The rating could be downgraded should weaker than expected regulatory support emerge, including the continuation of regulatory lag, which ultimately causes earnings and sustainable cash flow to suffer.”
HECO utilizes short-term debt, principally commercial paper, to support normal operations and for other temporary requirements. HECO also periodically borrows short-term from HEI for itself and on behalf of HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the consolidation of HECO’s financial statements. As of March 31, 2007, HECO had $4 million of short-term borrowings from MECO and HELCO had $46 million of short-term borrowings from HECO. HECO had an average outstanding balance of commercial paper for the first three months of 2007 of $125 million and had $47 million of commercial paper outstanding as of March 31, 2007.
Management believes that if HECO’s commercial paper ratings were to be downgraded, it may be more difficult for HECO to sell commercial paper under current market conditions.
Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement expires on March 31, 2011. See Note 10 of HECO’s “Notes to Consolidated Financial Statements” for a description of the $175 million credit facility. As of May 1, 2007, the line was undrawn. In the future, HECO may seek to modify the credit facility in accordance with the expedited approval process approved by the PUC, including to increase the amount of credit available under the agreement, and/or to enter into new lines of credit, as management deems appropriate.
See Note 11 of HECO’s “Notes to Consolidated Financial Statements” for a discussion of the SPRBs issued in March 2007. An additional $20 million of revenue bonds may be issued by the Department of Budget and Finance of the State of Hawaii for the benefit of HELCO under a 2005 Legislative authorization prior to the end of June 30, 2010 to finance the electric utilities’ capital improvement projects.
The PUC must approve issuances of long-term securities for HECO, HELCO and MECO, including notes or debentures issued by the electric utilities in connection with the issuance of SPRBs, taxable unsecured notes or trust preferred securities.
Operating activities provided $29 million in net cash during the first three months of 2007. Investing activities during the same period used net cash of $32 million primarily for capital expenditures, net of contributions in aid of construction. Financing activities for the same period provided net cash of $12 million, primarily due to the drawdown of $91 million in SPRBs, partly offset by a $66 million net decrease in short-term borrowings.
MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The following updates HECO’s disclosures about material estimates and critical accounting policies on pages 90 to 92 of HECO’s 2006 Form 10-K.
A material estimate was revised in the first quarter of 2007 when HELCO and the Consumer Advocate reached a settlement of the issues in the HELCO 2006 rate case proceeding (see “HELCO power situation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements”). Under the settlement, HELCO agreed to write-off a portion of CT-4 and CT-5 costs, resulting in an after-tax charge to net income of approximately $7 million in the first quarter of 2007. If it becomes probable that the PUC, in its final order, will disallow additional costs incurred for CT-4 and CT-5 for rate-making purposes, HELCO will be required to again revise its CT-4 and CT-5 costs estimated to be recoverable and record an additional write-off.
RESULTS OF OPERATIONS
| Three months ended March 31, | % change | ||||||||||
(in thousands) | 2007 | 2006 | Primary reason(s) for significant change | ||||||||
Revenues | $ | 104,460 | $ | 100,004 | 4 | Higher interest income (resulting from higher average balances and yields on loans, partly offset by lower average balances on investment and mortgage-related securities) and higher noninterest income | |||||
Operating income | 18,428 | 27,015 | (32 | ) | Lower net interest income and higher noninterest expense, partly offset by higher noninterest income | ||||||
Net income | 11,596 | 16,827 | (31 | ) | Lower operating income | ||||||
See “Economic conditions” in the “HEI Consolidated” section above.
Net interest margin
Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. If the current interest rate environment persists, compression of ASB’s net interest margin will continue to be a concern. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. As of March 31, 2007 and December 31, 2006, ASB’s loan portfolio mix, net, consisted of 72% residential loans, 12% commercial loans, 9% commercial real estate loans and 7% consumer loans. ASB’s mortgage-related securities portfolio consists primarily of shorter-duration assets and is affected by market interest rates and demand.
Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be significant sources of funds, but the amount of advances has trended downward over the last few years. As of March 31, 2007 and December 31, 2006, ASB’s costing liabilities consisted of 74% deposits and 26% other borrowings. Higher short-term interest rates and the inverted to flat yield curve have made it challenging to retain deposits and control funding costs. Deposit retention and growth will remain a challenge in the current environment.
Other factors primarily affecting ASB’s operating results include fee income, provision (or reversal of allowance) for loan losses, gains or losses on sales of securities available-for-sale and expenses from operations.
Although higher long-term interest rates could reduce the market value of available-for-sale investment and mortgage-related securities and reduce stockholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities or an “other-than-temporary” impairment in the value of the securities. As of March 31, 2007 and December 31, 2006, the unrealized losses, net of tax benefits, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $26 million and $35 million, respectively. The reduction in unrealized losses was largely due to movement in the general level of interest rates within the first quarter of 2007. See “Quantitative and qualitative disclosures about market risk.”
The following table sets forth average balances, interest and dividend income, interest expense and weighted-average yields earned and rates paid, for certain categories of earning assets and costing liabilities for the three months ended March 31, 2007 and 2006.
Three months ended March 31 | 2007 | 2006 | Change | |||||||
| (dollars in thousands) | ||||||||||
Loans receivable | ||||||||||
Average balances1 | $ | 3,805,122 | $ | 3,585,205 | $ | 219,917 | ||||
Interest income2 | 60,281 | 55,153 | 5,128 | |||||||
Weighted-average yield (%) | 6.36 | 6.17 | 0.19 | |||||||
Investment and mortgage-related securities | ||||||||||
Average balances | $ | 2,382,179 | $ | 2,606,480 | $ | (224,301 | ) | |||
Interest income | 26,706 | 29,173 | (2,467 | ) | ||||||
Weighted-average yield (%) | 4.48 | 4.48 | — | |||||||
Other investments3 | ||||||||||
Average balances | $ | 203,358 | $ | 180,697 | $ | 22,661 | ||||
Interest and dividend income | 1,459 | 904 | 555 | |||||||
Weighted-average yield (%) | 2.87 | 2.00 | 0.87 | |||||||
Total earning assets | ||||||||||
Average balances | $ | 6,390,659 | $ | 6,372,382 | $ | 18,277 | ||||
Interest and dividend income | 88,446 | 85,230 | 3,216 | |||||||
Weighted-average yield (%) | 5.55 | 5.36 | 0.19 | |||||||
Deposit liabilities | ||||||||||
Average balances | $ | 4,531,825 | $ | 4,550,700 | $ | (18,875 | ) | |||
Interest expense | 20,738 | 15,393 | 5,345 | |||||||
Weighted-average rate (%) | 1.86 | 1.37 | 0.49 | |||||||
Borrowings | ||||||||||
Average balances | $ | 1,636,161 | $ | 1,614,099 | $ | 22,062 | ||||
Interest expense | 18,406 | 17,162 | 1,244 | |||||||
Weighted-average rate (%) | 4.55 | 4.30 | 0.25 | |||||||
Total costing liabilities | ||||||||||
Average balances | $ | 6,167,986 | $ | 6,164,799 | $ | 3,187 | ||||
Interest expense | 39,144 | 32,555 | 6,589 | |||||||
Weighted-average rate (%) | 2.57 | 2.14 | 0.43 | |||||||
Net average balance | $ | 222,673 | $ | 207,583 | $ | 15,090 | ||||
Net interest income | 49,302 | 52,675 | (3,373 | ) | ||||||
Interest rate spread (%) | 2.98 | 3.22 | (0.24 | ) | ||||||
Net interest margin (%)4 | 3.07 | 3.29 | (0.22 | ) | ||||||
1 | Includes nonaccrual loans. |
2 | Includes loan fees of $1.2 million and $1.4 million for three months ended March 31, 2007 and 2006, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans. |
3 | Includes federal funds sold and interest bearing deposits and stock in the FHLB of Seattle ($98 million as of March 31, 2007). |
4 | Defined as net interest income as a percentage of average earning assets. |
Results – three months ended March 31, 2007
Net interest income for three months ended March 31, 2007 decreased by $3.4 million, or 6%, when compared to the same period in 2006. ASB continued to grow its loans, but the combination of higher short-term and falling long-term interest rates have made the interest rate environment significantly more challenging than it was during the first quarter of 2006 and caused ASB to experience further margin compression. Net interest margin decreased from 3.29% in the first quarter of 2006 to 3.07% in the first quarter of 2007 as higher balances and yields on loans were more than offset by lower balances on investment and mortgage-related securities and higher funding costs. The increase in the average loan portfolio balance was due, in part, to the continued strength in the Hawaii economy and real estate market. The decrease in the average investment and mortgage-related securities portfolios was due to the use of proceeds from repayments in the portfolio to fund loans. Average deposit balances decreased by $19 million compared to the first quarter of 2006, and increased by $14 million compared to the last quarter of 2006. The shift in deposit mix from lower cost savings and checking accounts to higher cost certificates, along with the repricing of deposits, has contributed to increased funding costs. Net interest margin for the first quarter of 2007 of 3.07% was comparable to the fourth quarter of 2006 of 3.05%. ASB’s net interest income continues to be under pressure given the prolonged inverted to flat yield curve.
During the first quarters of 2007 and 2006, the need to provide for loan losses as a result of additional loan growth was fully offset by the release of reserves on existing loans due to strong asset quality. As of March 31, 2007, ASB’s allowance for loan losses was 0.80% of average loans outstanding, compared to 0.85% at December 31, 2006 and 0.86% at March 31, 2006. As of March 31, 2007, ASB’s nonperforming assets to total assets was 0.06%, compared to 0.03% as of December 31, 2006 and March 31, 2006.
Three months ended March 31 | 2007 | 2006 | |||||
| (in thousands) | |||||||
Allowance for loan losses, January 1 | $ | 31,228 | $ | 30,595 | |||
Net recoveries (charge-offs) | (708 | ) | 66 | ||||
Allowance for loan losses, March 31 | $ | 30,520 | $ | 30,661 | |||
First quarter of 2007 noninterest income increased by $1.2 million, or 8%, when compared to the first quarter of 2006, primarily due to increases in deposit fees and card fees, partly offset by decreases in insurance commission income.
Noninterest expense for the three months ended March 31, 2007 increased by $6.5 million, or 16%, when compared to the first quarter of 2006, primarily due to higher legal and other litigation expenses. While the costs related to litigation and other legal issues may decline in the future as matters are resolved, ASB expects overall noninterest expenses to remain near current levels as ASB strengthens its risk management and compliance infrastructure in 2007 to support its transformation growth.
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 March 31, 2007, ASB had an investment in FHLB of Seattle stock of $98 million. 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. In December 2006 and in January 2007, the Board of Directors of the FHLB of Seattle declared, and ASB received, a cash dividend of $98,000 in December 2006 and February 2007, respectively. In January 2007, the FHLB of Seattle announced that the Finance Board had terminated its agreement with the FHLB of Seattle, attributing the termination to its full compliance with the terms of the agreement and significant progress the FHLB of Seattle has made in implementing its business and capital management plan.
FINANCIAL CONDITION
Liquidity and capital resources
(in millions) | March 31, 2007 | December 31, 2006 | % change | |||||
Total assets | $ | 6,846 | $ | 6,808 | 1 | |||
Available-for-sale investment and mortgage-related securities | 2,405 | 2,367 | 2 | |||||
Investment in stock of FHLB of Seattle | 98 | 98 | — | |||||
Loans receivable, net | 3,816 | 3,780 | 1 | |||||
Deposit liabilities | 4,577 | 4,576 | — | |||||
Other bank borrowings | 1,591 | 1,569 | 1 | |||||
As of March 31, 2007, ASB was the third largest financial institution in Hawaii based on assets of $6.8 billion and deposits of $4.6 billion.
In March 2007, Moody’s raised ASB’s counterparty credit rating to A3 from Baa3. In doing so, Moody’s acknowledged ASB’s high capital ratios, excellent asset quality indicators and prudent liquidity posture. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3. In doing so, S&P acknowledged the improvement in ASB’s interest rate risk and funding profiles from its community banking strategy, its still modest credit risk profile and its solid capital base. These ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
As of March 31, 2007, ASB’s unused FHLB borrowing capacity was approximately $1.6 billion. As of March 31, 2007, 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 three months of 2007, net cash provided by ASB’s operating activities was $29 million. Net cash used during the same period by ASB’s investing activities was $65 million, primarily due to purchases of investment and mortgage-related securities of $132 million and a net increase in loans receivable of $41 million, partly offset by repayments of mortgage-related securities of $109 million. Net cash provided by financing activities during this period was $11 million, primarily due to net increase of $23 million in retail repurchase agreements, partly offset by payment of $9 million in common stock dividends.
As of March 31, 2007, ASB was well-capitalized (ratio requirements noted in parentheses) with a leverage ratio of 7.7% (5.0%), a Tier-1 risk-based capital ratio of 14.1% (6.0%) and a total risk-based capital ratio of 14.9% (10.0%).
| Item 3. | Quantitative and Qualitative Disclosures About Market Risk |
The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 9094 to 9396 of HEI’s and HECO’s 20052006 Form 10-K.
ASB’s interest-rate risk sensitivity measures as of September 30, 2006March 31, 2007 and December 31, 20052006 constitute “forward-looking statements” and were as follows:
| September 30, 2006 | December 31, 2005 | March 31, 2007 | December 31, 2006 | |||||||||||||||||||||||||||||||||
| Change in NII | NPV ratio | NPV ratio sensitivity * | Change in NII | NPV ratio | NPV ratio sensitivity * | Change in NII | NPV ratio | NPV ratio sensitivity * | Change in NII | NPV ratio | NPV ratio sensitivity * | |||||||||||||||||||||||||
Change in interest rates (basis points) | Gradual change | Instantaneous change | Gradual change | Instantaneous change | Gradual change | Instantaneous change | Gradual change | Instantaneous change | ||||||||||||||||||||||||||||
+300 | (2.8 | )% | 8.06 | % | (340 | ) | (2.7 | )% | 8.12 | % | (332 | ) | (3.6 | )% | 7.66 | % | (350 | ) | (3.8 | )% | 7.83 | % | (341 | ) | ||||||||||||
+200 | (1.9 | ) | 9.29 | (217 | ) | (1.8 | ) | 9.34 | (210 | ) | (2.4 | ) | 8.97 | (219 | ) | (2.6 | ) | 9.09 | (215 | ) | ||||||||||||||||
+100 | (1.0 | ) | 10.48 | (98 | ) | (0.9 | ) | 10.49 | (95 | ) | (1.2 | ) | 10.21 | (95 | ) | (1.3 | ) | 10.29 | (95 | ) | ||||||||||||||||
Base | — | 11.46 | — | — | 11.44 | — | — | 11.16 | — | — | 11.24 | — | ||||||||||||||||||||||||
-100 | 1.6 | 11.95 | 49 | 1.5 | 11.91 | 47 | 1.6 | 11.48 | 32 | 2.0 | 11.64 | 40 | ||||||||||||||||||||||||
-200 | 1.2 | 11.70 | 24 | 1.0 | 11.62 | 18 | 1.0 | 11.00 | (16 | ) | 1.8 | 11.27 | 3 | |||||||||||||||||||||||
-300 | (0.5 | ) | 11.12 | (34 | ) | * | * | * | * | * | * | (1.1 | ) | 10.29 | (87 | ) | 0.3 | 10.60 | (64 | ) | ||||||||||||||||
| * | Change from base case in basis points. |
There was little change in ASB’s net interest rate risk measuresincome sensitivity as of September 30, 2006March 31, 2007 is slightly less liability sensitive when compared to the net interest rate risk measuresincome sensitivity as of December 31, 2005.2006. In the declining rate scenarios, changes in net interest income relative to the base case are less positive as of March 31, 2007 than they were at December 31, 2006. The changes are due to lower interest rates as of March 31, 2007, which result in faster prepayment expectations and lower reinvestment rates in the falling rate scenarios, causing interest income to decline faster than interest expenses.
ASB’s base net present value (NPV) ratio as of March 31, 2007 was essentially unchanged compared to December 31, 2006.
ASB’s NPV ratio sensitivity measure as of March 31, 2007 is slightly less liability sensitive when compared to the NPV ratio sensitivity measure as of December 31, 2006. In the falling rate scenarios, changes in the NPV ratio relative to the base case are less favorable as of March 31, 2007 than they were at December 31, 2006. The changes are due to lower interest rates as of March 31, 2007, which result in faster prepayment expectations in the falling rate scenarios.
The computation of the prospective effects of hypothetical interest rate changes on the net interest income (NII) sensitivity, the NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, estimates of loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. (See page 9195 of HEI’s and HECO’s 20052006 Form 10-K for a more detailed description of key modeling assumptions used in the NII sensitivity analysis.) To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.
| Item 4. | Controls and Procedures |
HEI:
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Constance H. Lau, 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, 2006.March 31, 2007. Based on their evaluations, as of September 30, 2006,March 31, 2007, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:
| (1) | is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and |
| (2) | is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. |
Internal Control Over Financial Reporting
During the thirdfirst quarter of 2006,2007, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2006March 31, 2007 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
HECO:
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
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, 2006.March 31, 2007. Based on their evaluations, as of September 30, 2006,March 31, 2007, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:
| (1) | is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and |
| (2) | is accumulated and communicated to HECO management, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. |
Internal Control Over Financial Reporting
During the thirdfirst quarter of 2006,2007, there has been no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of September 30, 2006March 31, 2007 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.
PART II - OTHER INFORMATION
| Item 1. | Legal Proceedings |
There were no significant developments in pendingThe descriptions of legal proceedings during(including judicial proceedings and proceedings before the first nine months of 2006, except as set forthPUC and environmental and other administrative agencies) in HECO’s “Notes to Consolidated Financial Statements”HEI’s Form 10-K (see “Part II. Item 1. Legal Proceedings”) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”Operations” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.
| Item 1A. | Risk Factors |
For information about Risk Factors, see pages 3633 to 4442 of HEI’s and HECO’s 20052006 Form 10-K, and “Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Certain of these risk factors are updated below.
Holding Company and Company-Wide Risks
HEI and HECO and their subsidiaries may incur higher retirement benefits expenses and will likely recognize substantial liabilities for retirement benefits.
Retirement benefits expenses and cash funding requirements could increase in future years depending on numerous factors, including the performance of the U.S. equity markets, trends in interest rates and health care costs, new laws relating to pension funding and changes in accounting principles. Retirement benefits expenses based on net periodic pension and other postretirement benefit costs have been an allowable expense for rate-making, and higher retirement benefits expenses, along with other factors, may affect each electric utilities’ need to request a rate increase.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in stockholders’ equity. If SFAS No. 158 were applied as of December 31, 2005, the Company would have had to recognize additional pension and other postretirement benefit obligations of approximately $184 million and write off $122 million of pension-related intangible and prepaid assets ($106 million of which related to the electric utilities and would have been removed from their rate bases) as of December 31, 2005. The Company would also have been required to record a deferred tax benefit associated with the temporary differences between the liabilities recognized for book and tax purposes. The net charge to AOCI would have been $187 million ($4 million, $170 million and $13 million for HEI corporate, consolidated HECO and ASB, respectively) as of December 31, 2005. The actual amounts recorded at December 31, 2006 and in the future will be dependent on numerous factors, including the year-end discount rate assumption, asset returns experienced, any changes to actuarial assumptions or plan provisions, contributions made by the Company to the plans, and what action the PUC takes, if any, on the AOCI docket (described below) or in future rate cases.
By application filed on December 8, 2005 (AOCI Docket), the electric utilities had requested the PUC to permit them to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and include in rate base, any amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.” The electric utilities plan to update their application in the AOCI Docket to take into account SFAS No. 158, but no assurance can be given concerning how or when the PUC will act on the electric utilities’ updated application. If the PUC were not to grant regulatory asset treatment in the AOCI Docket as updated for SFAS No. 158, there could be a material negative impact to stockholders’ equity. Although there would not be an immediate impact on net income due to the non-regulatory asset treatment, if the electric utilities are required to record substantial charges against stockholders’ equity, their reported returns on rate base and returns on average common equity could increase, which could impact the rates they are allowed to charge and ultimately result in reduced revenues and lower earnings. Further potential negative impacts include the fact that the consolidated adjusted debt to capitalization and
interest coverage ratios of the Company and the electric utilities may deteriorate, which could result in security ratings downgrades and difficulty or greater expense in obtaining future financing. If the electric utilities are not allowed regulatory asset treatment for the amounts that would be charged to AOCI, however, they still would seek a return on their prepaid pension assets (by inclusion in rate base) in their respective rate cases.
Electric Utility Risks
Actions of the PUC are outside the control of the electric utility subsidiaries and could result in inadequate or untimely rate relief, in rate reductions or refunds or in unanticipated delays, expenses or writedowns in connection with the construction of new projects.
The rates the electric utilities are allowed to charge for their services and the timeliness of permitted rate increases, are among the most important items influencing the electric utilities’ financial condition, results of operations and liquidity. The PUC has broad discretion over the rates that the electric utilities charge their customers. HECO currently has a rate case based on a 2005 test year pending before the PUC. Near the end of September 2005, HECO received an interim D&O (granting $53.3 million in annual base revenues) and is awaiting a final D&O. In May 2006, HELCO filed a request for a rate increase based on a 2006 test year intended largely to recover the cost of improvements to its transmission and distribution lines and the two generating units at its Keahole generating plant (CT-4 and CT-5). In addition, HECO and MECO have filed notices that they intend to file applications for a general rate increase based on a 2007 test year. The trend of increased O&M expenses (including increased retirement benefits expenses), which management expects will continue, increased capital expenditures and other factors are likely to result in the electric utilities seeking rate relief more often than in the past. Any adverse decision by the PUC concerning the level or method of determining electric utility rates, the returns on equity or rate base found to be reasonable, the potential consequences of exceeding or not meeting such returns, or any prolonged delay in rendering a decision in a rate or other proceeding, could have a material adverse effect on HECO’s consolidated financial condition, results of operations and liquidity.
The electric utilities could be required to refund to their customers, with interest, revenues received under interim rate orders if and to the extent they exceed the amounts allowed in final rate orders. As of September 30, 2006, the electric utilities had recognized an aggregate of $71 million of revenues with respect to interim orders, including the interim order in the HECO rate case based on a 2005 test year.
Many public utility projects require PUC approval and various permits (e.g., environmental and land use permits) from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits, or any adverse decision or policy made or adopted, or any prolonged delay in rendering a decision, by an agency with respect to such approvals and permits, can result in significantly increased project costs or even cancellation of projects. For example, two major capital improvement projects — HECO’s East Oahu Transmission Project and the expansion of HELCO’s Keahole generating plant — have encountered substantial opposition and consequent delay and increased cost. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of the project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income.
Energy cost adjustment clauses. The rate schedules of each of HEI’s electric utilities include energy cost adjustment clauses under which electric rates charged to customers are automatically adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power. In 2004 PUC decisions approving the electric utilities’ fuel supply contracts, the PUC affirmed the electric utilities’ right to include in their respective energy cost adjustment clauses the stated costs incurred pursuant to their respective new fuel supply contracts, to the extent that these costs are not included in their respective base rates, and restated its intention to examine the need for continued use of energy cost adjustment clauses in rate cases.
On June 19, 2006, the PUC issued an order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the public utility and its customers, (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means, such as through fuel hedging contracts, (4) preserve, to the extent reasonably possible, the public utility’s financial integrity, and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already reviews the automatic fuel rate adjustment clause in rate cases, Act 162 requires that these five specific factors must be addressed in the record. The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s energy cost adjustment clause (ECAC) that are raised by Act 162.
On June 30, 2006, HECO and the Consumer Advocate filed a stipulation requesting that the PUC not review the Act 162 ECAC issues in the pending rate case based on a 2005 test year since HECO’s application was filed and the record in the proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in the rate case included a provision allowing the existing ECAC to be continued. On August 7, 2006, an amended stipulation was filed in substantially the same form as the June 30, 2006 stipulation, but also included the DOD. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the amended stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162 or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case based on a 2005 test year.
The ECAC provisions of Act 162 will be reviewed in the HELCO rate case based on a 2006 test year.
Management cannot predict the ultimate outcome or the effect of these Act 162 issues on the operation of the ECAC as it relates to the electric utilities.
The electric utilities may be adversely affected by new legislation.
Congress and the Hawaii Legislature periodically consider legislation that could have positive or negative effects on the electric utilities and their customers. For example, Congress adopted the Energy Policy Act of 2005, which will provide $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 primary impact of these incentives on the electric utilities 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. In addition to the ECAC provisions of Act 162 discussed above, the Hawaii Legislature adopted a number of measures in 2006, which may affect the electric utilities, as described below.
Renewable Portfolio Standards (RPS) law. The 2001 Hawaii Legislature passed a law establishing renewable portfolio standard (RPS) goals for the electric utilities, on a consolidated basis, of 7% by December 31, 2003, 8% by December 31, 2005 and 9% by December 31, 2010. The law was amended in 2004 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. It may be difficult for the electric utilities to attain the renewables percentages in the future (although they have in the past), and management cannot predict the future consequences of failure to do so.
The RPS law also required the PUC to develop and implement a utility ratemaking structure, which may include performance-based ratemaking, to provide incentives that encourage Hawaii’s electric utilities to use cost-effective renewable energy resources found in Hawaii to meet the RPS goals, while allowing for deviation from the standards in the event that the standards cannot be met in a cost-effective manner or as a result of circumstances beyond the control of the utility which could not have been reasonably anticipated or ameliorated. In November 2004, the PUC initiated a process that is intended to lead to the creation of a document forming the basis of a set of rules to be adopted in a rule-making process relating to electric utility rate design. The electric utilities cannot predict the ultimate outcome of this process.
In 2006, the RPS law was amended to provide that at least 50% of the RPS targets must be met by electrical energy generated using renewable energy sources such as wind or solar versus from the electrical energy savings from renewable energy displacement technologies (such as solar water heating) or from energy efficiency and conservation programs. The amendment also added provisions for penalties to be established by the PUC if the RPS requirements are not met and criteria for waiver of the penalties by the PUC, if the requirements cannot be met due to circumstances beyond the electric utility’s control. And the amendment extends the date to December 31, 2007 for the PUC to develop and implement a utility rate making structure to provide incentives to encourage electric utilities to use cost effective renewable energy resources.
DSM programs. In 2006, the PUC was given the authority, if it deems appropriate, to redirect all or a portion of the funds currently collected by the utilities and included in their revenues through the current utility DSM surcharge into a Public Benefits Fund, for the purpose of supporting customer DSM programs approved by the PUC.
Non-fossil fuel purchased power contracts. In 2006, a law was passed that requires the PUC, in connection with the its determination of just and reasonable rates in purchased power contracts, to establish a methodology that removes or significantly reduces any linkage between the price paid for non-fossil-fuel-generated electricity under future power purchase contracts and the price of fossil fuel, in order to allow utility customers to receive the potential cost savings from non-fossil fuel generation.
Net energy metering. Hawaii has a net energy metering law, which requires that electric utilities offer net energy metering to eligible customer generators (i.e., a customer generator may be a net user or supplier of energy and will make payment to or receive credit from the electric utility accordingly). The law provides a cap of 0.5% of the electric utility’s peak demand on the total generating capacity produced by eligible customer-generators. The 2004 Legislature amended the net energy metering law by expanding the definition of “eligible customer generator” to include government entities, increasing the maximum size of eligible net metered systems from 10 kilowatts (kw) to 50 kw and limiting exemptions from additional requirements for systems meeting safety and performance standards to systems of 10 kw or less.
In 2005, the Legislature amended the net energy metering law by, among other revisions, authorizing the PUC, by rule or order, to increase the maximum size of the eligible net metered systems and to increase the total rated generating capacity available for net energy metering. In April 2006, the PUC initiated an investigative proceeding on whether the PUC should increase (1) the maximum capacity of eligible customer-generators to more than 50 kw and (2) the total rated generating capacity produced by eligible customer-generators to an amount above 0.5% of an electric utility’s system peak demand. The parties to the proceeding include HECO, HELCO, MECO, Kauai Island Utility Cooperative, a renewable energy organization and a solar vendor organization. The PUC has approved a procedural schedule with panel hearings scheduled for October 2007. Depending on their magnitude, changes made by the PUC by rule or order could have a negative effect on electric utility sales. Management cannot predict the outcome of the investigative proceeding.
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
(a) On July 19, 2006, August 3, 2006 and August 7, 2006, HEI issued an aggregate of 9,000 shares, 1,200 shares and 2,000 shares, respectively, of unregistered common stock pursuant to the HEI 1990 Nonemployee Director Stock Plan, as amended and restated effective May 2, 2006 (the HEI Nonemployee Director Plan). For the nine months ended September 30, 2006, HEI issued an aggregate of 27,600 shares of unregistered common stock. Under the HEI Nonemployee Director Plan, each HEI nonemployee director receives, in addition to an annual cash retainer, an annual stock grant of 1,400 shares of HEI common stock (2,000 shares for the first time grant to a new HEI director) and each nonemployee subsidiary director who is not also an HEI nonemployee director receives an annual stock grant of 1,000 shares of HEI common stock (600 shares for the first time grant to a new subsidiary director). The HEI Nonemployee Director Plan is currently the only plan for nonemployee directors and provides for annual stock grants (described above) and annual cash retainers for nonemployee directors of HEI and its subsidiaries.
HEI did not register the shares issued under the director stock plan since their issuance did not involve a “sale” as defined under Section 2(3) of the Securities Act of 1933, as amended. Participation by nonemployee directors of HEI and subsidiaries in the director stock plans is mandatory and thus does not involve an investment decision.
(b) Purchases of HEI common shares were made as follows:
ISSUER PURCHASES OF EQUITY SECURITIES
Period* | (a) Total Number of | (b) Average Price Paid per Share ** | (c) Total Number of | (d) Maximum Number (or | ||||
July 1 to 31, 2006 | 46,320 | 28.19 | — | NA | ||||
August 1 to 31, 2006 | 55,727 | 27.28 | — | NA | ||||
September 1 to 30, 2006 | 226,674 | 27.07 | — | NA | ||||
| 328,721 | 27.26 | — | NA | |||||
Period* | (a) Total Number of | (b) Average Price Paid per Share ** | (c) Total Number of | (d) Maximum Number | |||||
January 1 to 31, 2007 | 52,552 | $ | 27.05 | — | NA | ||||
February 1 to 28, 2007 | 42,511 | $ | 26.70 | — | NA | ||||
March 1 to 31, 2007 | 12,600 | $ | 25.90 | — | NA | ||||
| 107,663 | $ | 26.77 | — | NA | |||||
NA Not applicable.
| * | Trades (total number of shares purchased) are reflected in the month in which the order is placed. |
| ** | The purchases were made to satisfy the requirements of the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP) and Hawaiian Electric Industries Retirement Savings Plan (HEIRSP) for shares purchased for cash or by the reinvestment of dividends by participants under those plans and none of the purchases were made under publicly announced repurchase plans or programs. Average prices per share are calculated exclusive of any commissions payable to the brokers making the purchases for the DRIP and HEIRSP. Of the shares listed in column (a), |
Beginning on March 6, 2007, the Company began issuing new shares to satisfy the requirements of DRIP and HEIRSP.
| Item 5. | Other Information |
| A. | Ratio of earnings to fixed charges. |
Nine months ended September 30 | Years ended December 31 | Three months ended March 31, | Years ended December 31, | |||||||||||||||||||||||||
| 2006 | 2005 | 2005 | 2004 | 2003 | 2002 | 2001 | 2007 | 2006 | 2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||||||
HEI and Subsidiaries | ||||||||||||||||||||||||||||
Excluding interest on ASB deposits | 2.23 | 2.23 | 2.31 | 2.32 | 2.11 | 2.03 | 1.82 | 1.22 | 2.33 | 2.08 | 2.31 | 2.32 | 2.11 | 2.03 | ||||||||||||||
Including interest on ASB deposits | 1.85 | 1.93 | 1.98 | 2.00 | 1.84 | 1.72 | 1.52 | 1.14 | 1.95 | 1.73 | 1.98 | 2.00 | 1.84 | 1.72 | ||||||||||||||
HECO and Subsidiaries | 3.36 | 3.24 | 3.23 | 3.49 | 3.36 | 3.71 | 3.51 | .99 | 3.38 | 3.14 | 3.23 | 3.49 | 3.36 | 3.71 | ||||||||||||||
See HEI Exhibit 12.1 and HECO Exhibit 12.2.
| B. | News release. |
On November 1, 2006,May 3, 2007, HEI issued a news release, “Hawaiian Electric Industries, Inc. Reports ThirdFirst Quarter 20062007 Earnings.” See HEI Exhibit 99.
Carlito P. Caliboso (an attorney previously in private practice) continues to serve as Chairman of the PUC (term expiring June 30, 2010). Also serving as commissioner is John E. Cole (whose term expires June 30, 2012 and who previously served as the Executive Director of the Division of Consumer Advocacy, and prior to holding that position as a member of the Governor of the State of Hawaii’s Policy Team, which serves as advisor to the Governor on state-wide policy matters).
Commissioner Wayne H. Kimura resigned effective August 1, 2006. A replacement has not yet been announced.
Catherine P. Awakuni, an attorney formerly with the PUC staff, was named Executive Director of the Division of Consumer Advocacy effective September 18, 2006.
The Board of HEI approved, at its meeting on October 31, 2006, a change to the compensation of directors for HEI to provide that nonemployee directors of HEI will receive additional compensation of $8,000 per annum for service on each of the boards of utility subsidiaries MECO and HELCO effective October 31, 2006. Except for this change, the compensation of HEI directors remains the same. Only nonemployee directors of HEI are compensated for their service as directors
| Item 6. | Exhibits |
| HEI Exhibit 12.1 | Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, | |
| HEI Exhibit 31.1 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer) | |
| HEI Exhibit 31.2 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Eric K. Yeaman (HEI Chief Financial Officer) | |
| HEI Exhibit 32.1 | Written Statement of Constance H. Lau (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 | |
| HEI Exhibit 32.2 | Written Statement of Eric K. Yeaman (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 | |
| HEI Exhibit 99 | News release, dated | |
| HECO Exhibit 12.2 | Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, | |
| HECO Exhibit 31.3 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of T. Michael May (HECO Chief Executive Officer) | |
| HECO Exhibit 31.4 | Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer) | |
| HECO Exhibit 32.3 | Written Statement of T. Michael May (HECO Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 | |
| HECO Exhibit 32.4 | Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.
HAWAIIAN ELECTRIC INDUSTRIES, INC.
| HAWAIIAN ELECTRIC COMPANY, INC. | |||||||
| (Registrant) | (Registrant) | |||||||
By | /s/ Constance H. Lau | By | /s/ T. Michael May | |||||
Constance H. Lau | T. Michael May | |||||||
President and Chief Executive Officer | President and Chief Executive Officer | |||||||
(Principal Executive Officer of HEI) | (Principal Executive Officer of HECO) | |||||||
By | /s/ Eric K. Yeaman | By | /s/ Tayne S. Y. Sekimura | |||||
Eric K. Yeaman | Tayne S. Y. Sekimura | |||||||
Financial Vice President, Treasurer
| Financial Vice President | |||||||
| and Chief Financial Officer | (Principal Financial Officer of HECO) | |||||||
| (Principal Financial Officer of HEI) | ||||||||
By | /s/ Curtis Y. Harada | By | /s/ Patsy H. Nanbu | |||||
Curtis Y. Harada | Patsy H. Nanbu | |||||||
Controller | Controller | |||||||
(Chief Accounting Officer of HEI) | (Chief Accounting Officer of HECO) | |||||||
Date: | Date: | |||||||
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