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, 2010March 31, 2011
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Exact Name of Registrant as |
| Commission |
| I.R.S. Employer |
Specified in Its Charter |
| File Number |
| Identification No. |
HAWAIIAN ELECTRIC INDUSTRIES, INC. |
| 1-8503 |
| 99-0208097 |
and Principal Subsidiary |
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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 o
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
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 o No x
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
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) |
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Hawaiian Electric Company, Inc. ($6-2/3 Par Value) |
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Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x |
| Accelerated filer o |
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|
Non-accelerated filer o |
| Smaller reporting company o |
|
Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o |
| Accelerated filer o |
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|
Non-accelerated filer x |
| Smaller reporting company o |
|
Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended September 30, 2010March 31, 2011
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| Management’s Discussion and Analysis of Financial Condition and Results of Operations | ||
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Hawaiian Electric Industries, Inc. and Subsidiaries
Hawaiian Electric Company, Inc. and Subsidiaries
Form 10-Q—Quarter ended September 30, 2010March 31, 2011
Terms |
| Definitions |
|
| |
AFUDC |
| Allowance for funds used during construction |
AOCI |
| Accumulated other comprehensive income |
AOS |
| Adequacy of supply |
ARO | Asset retirement obligation | |
ASB |
| American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc. |
ASHI |
| American Savings Holdings, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B. |
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| |
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CIP CT-1 |
| Campbell Industrial Park 110 MW combustion turbine No. 1 |
Company |
| When used in Hawaiian Electric Industries, Inc. sections, the “Company” refers to Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); American Savings Holdings, Inc. and its subsidiary, American Savings Bank, F.S.B. and its former subsidiaries (listed under ASB); Pacific Energy Conservation Services, Inc. (dissolved on April 1, 2011); HEI Properties, Inc.
|
Consumer Advocate |
| Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii |
DBEDT |
| State of Hawaii Department of Business, Economic Development and Tourism |
DBF |
| State of Hawaii Department of Budget and Finance |
D&O |
| Decision and order |
DG |
| Distributed generation |
|
| |
Dodd-Frank Act |
| Dodd-Frank Wall Street Reform and Consumer Protection Act |
|
| |
DOH |
| Department of Health of the State of Hawaii |
DRIP |
| HEI Dividend Reinvestment and Stock Purchase Plan |
DSM |
| Demand-side management |
ECAC |
| Energy cost adjustment clauses |
EIP |
| 2010 Equity and Incentive Plan |
Energy Agreement |
| Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI |
EPA |
| Environmental Protection Agency — federal |
EPS |
| Earnings per share |
Exchange Act |
| Securities Exchange Act of 1934 |
|
| |
FDIC |
| Federal Deposit Insurance Corporation |
federal |
| U.S. Government |
FHLB |
| Federal Home Loan Bank |
FHLMC |
| Federal Home Loan Mortgage Corporation |
FNMA |
| Federal National Mortgage Association |
FSS |
| Forward Starting Swaps |
GLOSSARY OF TERMS, continued
Terms |
| Definitions |
GAAP |
| U.S. generally accepted accounting principles |
GHG |
| Greenhouse gas |
GNMA |
| Government National Mortgage Association |
HCEI |
| Hawaii Clean Energy Initiative |
HECO |
| Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp. |
HEI |
| Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., Pacific Energy Conservation Services, Inc. (dissolved on April 1, 2011), HEI Properties, Inc. |
|
| |
HEIRSP |
| Hawaiian Electric Industries Retirement Savings Plan |
HELCO |
| Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc. |
HPOWER |
| City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant |
IPP |
| Independent power producer |
IRP |
| Integrated resource plan |
Kalaeloa |
| Kalaeloa Partners, L.P. |
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| |
KWH |
| Kilowatthour |
MECO |
| Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc. |
MW |
| Megawatt/s (as applicable) |
|
| |
NII |
| Net interest income |
NPV |
| Net portfolio value |
NQSO |
| Nonqualified stock option |
O&M |
| Operation and maintenance |
OPEB |
| Postretirement benefits other than pensions |
OTS |
| Office of Thrift Supervision, Department of Treasury |
|
| |
PBF |
| Public benefits fund |
PPA |
| Power purchase agreement |
PRPs |
| Potentially responsible parties |
PUC |
| Public Utilities Commission of the State of Hawaii |
RAM |
| Revenue adjustment mechanism |
RBA |
| Revenue balancing account |
REG |
| Renewable Energy Group Marketing |
RFP |
| Request for proposal |
REIP | Renewable Energy Infrastructure Program | |
RHI |
| Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc. |
ROACE |
| Return on average common equity |
ROR |
| Return on average rate base |
RPS |
| Renewable portfolio standards |
SAR |
| Stock appreciation right |
SEC |
| Securities and Exchange Commission |
See |
| Means the referenced material is incorporated by reference |
SOIP |
| 1987 Stock Option and Incentive Plan, as amended |
SPRBs |
| Special Purpose Revenue Bonds |
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UBC |
| Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc. |
VIE |
| Variable interest entity |
This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.
Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following:
· international, national and local economic conditions, including the state of the Hawaii tourism and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB), which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii, and the implications and potential impacts of current capital and credit market conditions and federal and state responses to those conditions;
· weather and natural disasters such as(e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming, (suchsuch as more severe storms and rising sea levels), including their impact on Company operations and the economy (e.g., the effect of the March 2011 natural disasters in Japan on its economy and tourism in Hawaii);
· global developments, including unrest and conflict in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or in the Middle East and Iran’s nuclear activities;Korea;
· the timing and extent of changes in interest rates and the shape of the yield curve;
· the ability of the Company to access credit markets to obtain commercial paper and other short-term and long-term debt financing (including lines of credit) and to access capital markets to issue HEI common stock under volatile and challenging market conditions, and the cost of such financings, if available;
· the risks inherent in changes in the value of pension and other retirement plan assets and securities available for sale;
· changes in laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;
· the impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) and of the rules and regulations that the Dodd-Frank Act requires to be promulgated over the next several months;promulgated;
· increasing competition in the electric utility and banking industriesindustry (e.g., increased self-generation of electricity may have an adverse impact on HECO’s revenues and increased price competition for deposits, or an outflow of deposits to alternative investments, which may have an adverse impact on ASB’s cost of funds);
· the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement) setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), revenue decoupling and the fulfillment by the electric utilities of their commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering HCEI-related costs; reliance by the Company on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cable (to bring power to Oahu from Lanai and/or Molokai), biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);
· capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), combined heat and power (CHP) or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;
· the risk to generation reliability when generation peak reserve margins on Oahu are strained;
· fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);
· the impact of fuel price volatility on customer satisfaction and political and regulatory support for the utilities;
· the risks associated with increasing reliance on renewable energy, as contemplated under the Energy Agreement, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;
· the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);
· the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;
· new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB) or their competitors;
· federal, state, county and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (including changes in taxation, increases in capital requirements, regulatory changes resulting from the HCEI, environmental laws and regulations, the regulation of greenhouse gas (GHG) emissions, (GHG), healthcare reform, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);
· decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs);
· decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions and restrictions and penalties that may arise, for examplesuch as with respect to environmental conditions or renewable portfolio standards (RPS));
· potential enforcement actions by the OTSOffice of Thrift Supervision (OTS) (or its regulatory successors, the Office of the Comptroller of the Currency and the Federal Reserve Board) and other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under existing or new banking and consumer protection laws and regulations or with respect to capital adequacy);
· ability to recover and earn on increasing operationcosts and maintenance expenses and investment in infrastructure for the electric utilities, resulting in the need for more frequent rate cases;capital investments not covered by revenue adjustment mechanisms;
· the risks associated with the geographic concentration of HEI’s businesses and ASB’s loans, ASB’s concentration in a single product type (first(i.e., first mortgages) and ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers);
· changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the adoption of International Financial Reporting Standards (IFRS) or new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of variable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;
· changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;
· faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage servicingmortgage-servicing assets of ASB;
· �� changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses and charge-offs;
· changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;
· the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;
· the risks of suffering losses and incurring liabilities that are uninsured or underinsured; and
· other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).
Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
PART I - FINANCIAL INFORMATION
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Income (unaudited)
Three months ended March 31 |
| 2011 |
| 2010 |
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(in thousands, except per share amounts) |
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| Three months |
| Nine months |
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(in thousands, except per share amounts) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
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Revenues |
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Electric utility |
| $ | 623,126 |
| $ | 548,440 |
| $ | 1,755,332 |
| $ | 1,460,654 |
|
| $ | 645,335 |
| $ | 548,111 |
|
Bank |
| 71,429 |
| 71,947 |
| 213,975 |
| 229,478 |
|
| 65,313 |
| 70,914 |
| ||||||
Other |
| (14 | ) | (74 | ) | (62 | ) | (121 | ) |
| (15 | ) | 15 |
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|
| 694,541 |
| 620,313 |
| 1,969,245 |
| 1,690,011 |
|
| 710,633 |
| 619,040 |
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Expenses |
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Electric utility |
| 571,783 |
| 494,268 |
| 1,619,945 |
| 1,343,250 |
|
| 600,127 |
| 505,502 |
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Bank |
| 47,040 |
| 54,258 |
| 142,040 |
| 189,162 |
|
| 43,559 |
| 49,143 |
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Other |
| 3,087 |
| 3,148 |
| 10,291 |
| 9,247 |
|
| 3,572 |
| 3,688 |
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|
| 621,910 |
| 551,674 |
| 1,772,276 |
| 1,541,659 |
|
| 647,258 |
| 558,333 |
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Operating income (loss) |
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Electric utility |
| 51,343 |
| 54,172 |
| 135,387 |
| 117,404 |
|
| 45,208 |
| 42,609 |
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Bank |
| 24,389 |
| 17,689 |
| 71,935 |
| 40,316 |
|
| 21,754 |
| 21,771 |
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Other |
| (3,101 | ) | (3,222 | ) | (10,353 | ) | (9,368 | ) |
| (3,587 | ) | (3,673 | ) | ||||||
|
| 72,631 |
| 68,639 |
| 196,969 |
| 148,352 |
|
| 63,375 |
| 60,707 |
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Interest expense—other than on deposit liabilities and other bank borrowings |
| (21,015 | ) | (19,678 | ) | (61,916 | ) | (55,421 | ) |
| (20,140 | ) | (20,381 | ) | ||||||
Allowance for borrowed funds used during construction |
| 492 |
| 1,118 |
| 2,061 |
| 4,467 |
|
| 520 |
| 779 |
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Allowance for equity funds used during construction |
| 1,197 |
| 2,628 |
| 4,817 |
| 10,353 |
|
| 1,244 |
| 1,773 |
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Income before income taxes |
| 53,305 |
| 52,707 |
| 141,931 |
| 107,751 |
|
| 44,999 |
| 42,878 |
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Income taxes |
| 20,385 |
| 18,753 |
| 51,677 |
| 36,977 |
|
| 16,064 |
| 15,279 |
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Net income |
| 32,920 |
| 33,954 |
| 90,254 |
| 70,774 |
|
| 28,935 |
| 27,599 |
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Preferred stock dividends of subsidiaries |
| 471 |
| 471 |
| 1,417 |
| 1,417 |
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| 473 |
| 473 |
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Net income for common stock |
| $ | 32,449 |
| $ | 33,483 |
| $ | 88,837 |
| $ | 69,357 |
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| $ | 28,462 |
| $ | 27,126 |
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Basic earnings per common share |
| $ | 0.35 |
| $ | 0.37 |
| $ | 0.95 |
| $ | 0.76 |
|
| $ | 0.30 |
| $ | 0.29 |
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Diluted earnings per common share |
| $ | 0.35 |
| $ | 0.37 |
| $ | 0.95 |
| $ | 0.76 |
|
| $ | 0.30 |
| $ | 0.29 |
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Dividends per common share |
| $ | 0.31 |
| $ | 0.31 |
| $ | 0.93 |
| $ | 0.93 |
|
| $ | 0.31 |
| $ | 0.31 |
|
Weighted-average number of common shares outstanding |
| 93,699 |
| 91,522 |
| 93,148 |
| 91,173 |
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| 94,817 |
| 92,572 |
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Dilutive effect of share-based compensation |
| 192 |
| 131 |
| 257 |
| 105 |
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| 365 |
| 276 |
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Adjusted weighted-average shares |
| 93,891 |
| 91,653 |
| 93,405 |
| 91,278 |
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| 95,182 |
| 92,848 |
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SeeThe accompanying “Notes to Consolidated Financial Statements” for HEI.notes are an integral part of these consolidated financial statements.
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Balance Sheets (unaudited)
(dollars in thousands) |
| September 30, |
| December 31, |
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| March 31, |
| December 31, |
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Assets |
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Cash and cash equivalents |
| $ | 387,488 |
| $ | 503,922 |
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| $ | 316,254 |
| $ | 330,651 |
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Accounts receivable and unbilled revenues, net |
| 259,132 |
| 241,116 |
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| 286,876 |
| 266,996 |
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Available-for-sale investment and mortgage-related securities |
| 570,262 |
| 432,881 |
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| 670,949 |
| 678,152 |
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Investment in stock of Federal Home Loan Bank of Seattle |
| 97,764 |
| 97,764 |
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| 97,764 |
| 97,764 |
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Loans receivable, net |
| 3,466,550 |
| 3,670,493 |
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Property, plant and equipment, net of accumulated depreciation of $2,011,138 and $1,945,482 |
| 3,131,198 |
| 3,088,611 |
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Loans receivable held for investment, net |
| 3,549,750 |
| 3,489,880 |
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Loans held for sale, at lower of cost or fair value |
| 4,308 |
| 7,849 |
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Property, plant and equipment, net of accumulated depreciation of $2,032,500 in 2011 and $2,037,598 in 2010 |
| 3,175,375 |
| 3,165,918 |
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Regulatory assets |
| 422,177 |
| 426,862 |
|
| 481,812 |
| 478,330 |
| ||||
Other |
| 478,406 |
| 381,163 |
|
| 462,258 |
| 487,614 |
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Goodwill, net |
| 82,190 |
| 82,190 |
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Goodwill |
| 82,190 |
| 82,190 |
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Total assets |
| $ | 8,895,167 |
| $ | 8,925,002 |
|
| $ | 9,127,536 |
| $ | 9,085,344 |
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Liabilities and stockholders’ equity |
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Liabilities and shareholders’ equity |
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Liabilities |
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Accounts payable |
| $ | 142,971 |
| $ | 159,044 |
|
| $ | 162,748 |
| $ | 202,446 |
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Interest and dividends payable |
| 31,318 |
| 27,950 |
|
| 27,496 |
| 27,814 |
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Deposit liabilities |
| 3,958,636 |
| 4,058,760 |
|
| 4,035,255 |
| 3,975,372 |
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Short-term borrowings—other than bank |
| 27,296 |
| 41,989 |
|
| — |
| 24,923 |
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Other bank borrowings |
| 246,571 |
| 297,628 |
|
| 244,674 |
| 237,319 |
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Long-term debt, net—other than bank |
| 1,364,911 |
| 1,364,815 |
|
| 1,439,974 |
| 1,364,942 |
| ||||
Deferred income taxes |
| 253,284 |
| 188,875 |
|
| 291,470 |
| 278,958 |
| ||||
Regulatory liabilities |
| 289,568 |
| 288,214 |
|
| 304,375 |
| 296,797 |
| ||||
Contributions in aid of construction |
| 331,405 |
| 321,544 |
|
| 338,070 |
| 335,364 |
| ||||
Other |
| 735,261 |
| 700,242 |
|
| 752,630 |
| 823,479 |
| ||||
Total liabilities |
| 7,381,221 |
| 7,449,061 |
|
| 7,596,692 |
| $ | 7,567,414 |
| |||
|
|
|
|
|
|
|
|
|
|
| ||||
Preferred stock of subsidiaries - not subject to mandatory redemption |
| 34,293 |
| 34,293 |
|
| 34,293 |
| 34,293 |
| ||||
|
|
|
|
|
|
|
|
|
|
| ||||
Stockholders’ equity |
|
|
|
|
| |||||||||
Shareholders’ equity |
|
|
|
|
| |||||||||
Preferred stock, no par value, authorized 10,000,000 shares; issued: none |
| — |
| — |
|
| — |
| — |
| ||||
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 94,121,108 shares and 92,520,638 shares |
| 1,301,710 |
| 1,265,157 |
| |||||||||
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 95,288,966 shares in 2011 and 94,690,932 shares in 2010 |
| 1,329,901 |
| 1,314,199 |
| |||||||||
Retained earnings |
| 186,425 |
| 184,213 |
|
| 180,960 |
| 181,910 |
| ||||
Accumulated other comprehensive loss, net of tax benefits |
| (8,482 | ) | (7,722 | ) |
| (14,310 | ) | (12,472 | ) | ||||
Total stockholders’ equity |
| 1,479,653 |
| 1,441,648 |
| |||||||||
Total liabilities and stockholders’ equity |
| $ | 8,895,167 |
| $ | 8,925,002 |
| |||||||
Total shareholders’ equity |
| 1,496,551 |
| 1,483,637 |
| |||||||||
Total liabilities and shareholders’ equity |
| $ | 9,127,536 |
| $ | 9,085,344 |
|
SeeThe accompanying “Notes to Consolidated Financial Statements” for HEI.notes are an integral part of these consolidated financial statements.
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’Shareholders’ Equity (unaudited)
|
| Common stock |
| Retained |
| Accumulated |
|
|
| ||||||
(in thousands, except per share amounts) |
| Shares |
| Amount |
| earnings |
| loss |
| Total |
| ||||
Balance, December 31, 2009 |
| 92,521 |
| $ | 1,265,157 |
| $ | 184,213 |
| $ | (7,722 | ) | $ | 1,441,648 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
| ||||
Net income for common stock |
| — |
| — |
| 88,837 |
| — |
| 88,837 |
| ||||
Net unrealized gains on securities: |
|
|
|
|
|
|
|
|
|
|
| ||||
Net unrealized gains on securities arising during the period, net of taxes of $1,599 |
| — |
| — |
| — |
| 2,421 |
| 2,421 |
| ||||
Unrealized losses on derivatives qualified as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
| ||||
Net unrealized holding losses arising during the period, net of tax benefits of $2,278 |
| — |
| — |
| — |
| (3,575 | ) | (3,575 | ) | ||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
| ||||
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,932 |
| — |
| — |
| — |
| 3,034 |
| 3,034 |
| ||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $1,681 |
| — |
| — |
| — |
| (2,640 | ) | (2,640 | ) | ||||
Comprehensive income |
| — |
| — |
| 88,837 |
| (760 | ) | 88,077 |
| ||||
Issuance of common stock, net |
| 1,600 |
| 36,553 |
| — |
| — |
| 36,553 |
| ||||
Common stock dividends ($0.93 per share) |
| — |
| — |
| (86,625 | ) | — |
| (86,625 | ) | ||||
Balance, September 30, 2010 |
| 94,121 |
| $ | 1,301,710 |
| $ | 186,425 |
| $ | (8,482 | ) | $ | 1,479,653 |
|
Balance, December 31, 2008 |
| 90,516 |
| $ | 1,231,629 |
| $ | 210,840 |
| $ | (53,015 | ) | $ | 1,389,454 |
|
Cumulative effect of adoption of a standard on other-than- temporary impairment recognition, net of taxes of $2,497 |
| — |
| — |
| 3,781 |
| (3,781 | ) | — |
| ||||
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
| ||||
Net income for common stock |
| — |
| — |
| 69,357 |
| — |
| 69,357 |
| ||||
Net unrealized gains (losses) on securities: |
|
|
|
|
|
|
|
|
|
|
| ||||
Net unrealized gains on securities arising during the period, net of taxes of $16,248 |
| — |
| — |
| — |
| 24,607 |
| 24,607 |
| ||||
Net unrealized losses related to factors other than credit during the period, net of tax benefits of $6,650 |
| — |
| — |
| — |
| (10,072 | ) | (10,072 | ) | ||||
Less: reclassification adjustment for net realized losses included in net income, net of tax benefits of $6,125 |
| — |
| — |
| — |
| 9,276 |
| 9,276 |
| ||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
| ||||
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $5,562 |
| — |
| — |
| — |
| 8,717 |
| 8,717 |
| ||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $4,990 |
| — |
| — |
| — |
| (7,835 | ) | (7,835 | ) | ||||
Comprehensive income |
| — |
| — |
| 69,357 | �� | 24,693 |
| 94,050 |
| ||||
Issuance of common stock, net |
| 1,499 |
| 23,264 |
| — |
| — |
| 23,264 |
| ||||
Common stock dividends ($0.93 per share) |
| — |
| — |
| (84,860 | ) | — |
| (84,860 | ) | ||||
Balance, September 30, 2009 |
| 92,015 |
| $ | 1,254,893 |
| $ | 199,118 |
| $ | (32,103 | ) | $ | 1,421,908 |
|
|
| Common stock |
| Retained |
| Accumulated |
|
|
| ||||||
(in thousands, except per share amounts) |
| Shares |
| Amount |
| earnings |
| loss |
| Total |
| ||||
Balance, December 31, 2010 |
| 94,691 |
| $ | 1,314,199 |
| $ | 181,910 |
| $ | (12,472 | ) | $ | 1,483,637 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
| ||||
Net income for common stock |
| — |
| — |
| 28,462 |
| — |
| 28,462 |
| ||||
Net unrealized losses on securities: |
|
|
|
|
|
|
|
|
|
|
| ||||
Net unrealized losses on securities arising during the period, net of tax benefits of $414 |
| — |
| — |
| — |
| (626 | ) | (626 | ) | ||||
Losses on derivatives qualified as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
| ||||
Holding losses arising during the period, net of tax benefits of $6 |
| — |
| — |
| — |
| (9 | ) | (9 | ) | ||||
Less: reclassification adjustment to net income, net of tax benefits of $3 |
| — |
| — |
| — |
| 5 |
| 5 |
| ||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
| ||||
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $631 |
| — |
| — |
| — |
| 1,039 |
| 1,039 |
| ||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $1,431 |
| — |
| — |
| — |
| (2,247 | ) | (2,247 | ) | ||||
Other comprehensive income |
|
|
|
|
|
|
| (1,838 | ) |
|
| ||||
Comprehensive income |
|
|
|
|
|
|
|
|
| 26,624 |
| ||||
Issuance of common stock, net |
| 598 |
| 15,702 |
| — |
| — |
| 15,702 |
| ||||
Common stock dividends ($0.31 per share) |
| — |
| — |
| (29,412 | ) | — |
| (29,412 | ) | ||||
Balance, March 31, 2011 |
| 95,289 |
| $ | 1,329,901 |
| $ | 180,960 |
| $ | (14,310 | ) | $ | 1,496,551 |
|
Balance, December 31, 2009 |
| 92,521 |
| $ | 1,265,157 |
| $ | 184,213 |
| $ | (7,722 | ) | $ | 1,441,648 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
| ||||
Net income for common stock |
| — |
| — |
| 27,126 |
| — |
| 27,126 |
| ||||
Net unrealized gains on securities arising during the period, net of taxes of $696 |
| — |
| — |
| — |
| 1,053 |
| 1,053 |
| ||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
| ||||
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $609 |
| — |
| — |
| — |
| 958 |
| 958 |
| ||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $526 |
| — |
| — |
| — |
| (825 | ) | (825 | ) | ||||
Other comprehensive income |
|
|
|
|
|
|
| 1,186 |
|
|
| ||||
Comprehensive income |
|
|
|
|
|
|
|
|
| 28,312 |
| ||||
Issuance of common stock, net |
| 575 |
| 12,176 |
| — |
| — |
| 12,176 |
| ||||
Common stock dividends ($0.31 per share) |
| — |
| — |
| (28,693 | ) | — |
| (28,693 | ) | ||||
Balance, March 31, 2010 |
| 93,096 |
| $ | 1,277,333 |
| $ | 182,646 |
| $ | (6,536 | ) | $ | 1,453,443 |
|
SeeThe accompanying “Notes to Consolidated Financial Statements” for HEI.notes are an integral part of these consolidated financial statements.
Hawaiian Electric Industries, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (unaudited)
Nine months ended September 30 |
| 2010 |
| 2009 |
| |||||||||
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||
(in thousands) |
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
| |||||||||
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
| ||||
Net income |
| $ | 90,254 |
| $ | 70,774 |
|
| $ | 28,935 |
| $ | 27,599 |
|
Adjustments to reconcile net income to net cash provided by operating activities |
|
|
|
|
| |||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities |
|
|
|
|
| |||||||||
Depreciation of property, plant and equipment |
| 117,109 |
| 113,916 |
|
| 37,708 |
| 39,798 |
| ||||
Other amortization |
| 2,995 |
| 4,037 |
|
| 2,354 |
| 1,565 |
| ||||
Provision for loan losses |
| 12,310 |
| 27,000 |
|
| 4,550 |
| 5,359 |
| ||||
Loans receivable originated and purchased, held for sale |
| (286,950 | ) | (368,880 | ) |
| (35,015 | ) | (78,685 | ) | ||||
Proceeds from sale of loans receivable, held for sale |
| 306,587 |
| 400,213 |
|
| 43,048 |
| 82,814 |
| ||||
Net gain on sale of investment and mortgage-related securities |
| — |
| (44 | ) | |||||||||
Other-than-temporary impairment of available-for-sale mortgage-related securities |
| — |
| 15,444 |
| |||||||||
Changes in deferred income taxes |
| 75,821 |
| 2,958 |
|
| 16,687 |
| (129 | ) | ||||
Changes in excess tax benefits from share-based payment arrangements |
| 56 |
| 324 |
|
| (22 | ) | (43 | ) | ||||
Allowance for equity funds used during construction |
| (4,817 | ) | (10,353 | ) |
| (1,244 | ) | (1,773 | ) | ||||
Increase in cash overdraft |
| 884 |
| — |
| |||||||||
Increase (decrease) in cash overdraft |
| (2,688 | ) | 681 |
| |||||||||
Changes in assets and liabilities |
|
|
|
|
|
|
|
|
|
| ||||
Decrease (increase) in accounts receivable and unbilled revenues, net |
| (18,016 | ) | 48,480 |
|
| (19,880 | ) | 7,231 |
| ||||
Decrease (increase) in fuel oil stock |
| (42,569 | ) | 9,826 |
| |||||||||
Decrease in accounts, interest and dividends payable |
| (12,705 | ) | (641 | ) | |||||||||
Increase in fuel oil stock |
| (3,513 | ) | (26,506 | ) | |||||||||
Increase (decrease) in accounts, interest and dividends payable |
| (40,016 | ) | 2,155 |
| |||||||||
Changes in prepaid and accrued income taxes and utility revenue taxes |
| (45,787 | ) | (50,514 | ) |
| (1,594 | ) | (48,689 | ) | ||||
Changes in other assets and liabilities |
| (5,585 | ) | (35,561 | ) |
| (42,544 | ) | (1,508 | ) | ||||
Net cash provided by operating activities |
| 189,587 |
| 226,979 |
| |||||||||
Net cash provided by (used in) operating activities |
| (13,234 | ) | 9,869 |
| |||||||||
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
| ||||
Available-for-sale investment and mortgage-related securities purchased |
| (485,495 | ) | (247,425 | ) |
| (109,307 | ) | (170,385 | ) | ||||
Principal repayments on available-for-sale investment and mortgage-related securities |
| 350,673 |
| 304,728 |
|
| 114,529 |
| 48,338 |
| ||||
Proceeds from sale of available-for-sale investment and mortgage-related securities |
| — |
| 44 |
| |||||||||
Net decrease in loans held for investment |
| 171,242 |
| 396,706 |
| |||||||||
Net decrease (increase) in loans held for investment |
| (70,269 | ) | 38,072 |
| |||||||||
Proceeds from sale of real estate acquired in settlement of loans |
| 3,405 |
| — |
|
| 1,253 |
| 1,279 |
| ||||
Capital expenditures |
| (137,628 | ) | (239,441 | ) |
| (38,491 | ) | (34,816 | ) | ||||
Contributions in aid of construction |
| 16,775 |
| 7,472 |
|
| 5,749 |
| 3,729 |
| ||||
Other |
| 1,615 |
| 426 |
|
| 145 |
| — |
| ||||
Net cash provided by (used in) investing activities |
| (79,413 | ) | 222,510 |
| |||||||||
Net cash used in investing activities |
| (96,391 | ) | (113,783 | ) | |||||||||
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
| ||||
Net decrease in deposit liabilities |
| (100,124 | ) | (132,234 | ) | |||||||||
Net decrease in short-term borrowings with original maturities of three months or less |
| (14,693 | ) | — |
| |||||||||
Net decrease in retail repurchase agreements |
| (51,057 | ) | (18,573 | ) | |||||||||
Proceeds from other bank borrowings |
| — |
| 310,000 |
| |||||||||
Repayments of other bank borrowings |
| — |
| (604,517 | ) | |||||||||
Net increase (decrease) in deposit liabilities |
| 59,883 |
| (50,369 | ) | |||||||||
Net increase (decrease) in short-term borrowings with original maturities of three months or less |
| (24,923 | ) | 18,249 |
| |||||||||
Net increase (decrease) in retail repurchase agreements |
| 7,368 |
| (3,461 | ) | |||||||||
Proceeds from issuance of long-term debt |
| — |
| 153,186 |
|
| 125,000 |
| — |
| ||||
Repayment of long-term debt |
| (50,000 | ) | — |
| |||||||||
Changes in excess tax benefits from share-based payment arrangements |
| (56 | ) | (324 | ) |
| 22 |
| 43 |
| ||||
Net proceeds from issuance of common stock |
| 16,672 |
| 11,004 |
|
| 5,674 |
| 5,557 |
| ||||
Common stock dividends |
| (69,585 | ) | (73,931 | ) |
| (23,593 | ) | (23,048 | ) | ||||
Preferred stock dividends of subsidiaries |
| (1,417 | ) | (1,417 | ) |
| (473 | ) | (473 | ) | ||||
Decrease in cash overdraft |
| — |
| (9,847 | ) | |||||||||
Other |
| (6,348 | ) | (7,232 | ) |
| (3,730 | ) | (4,474 | ) | ||||
Net cash used in financing activities |
| (226,608 | ) | (373,885 | ) | |||||||||
Net increase (decrease) in cash and cash equivalents |
| (116,434 | ) | 75,604 |
| |||||||||
Net cash provided by (used in) financing activities |
| 95,228 |
| (57,976 | ) | |||||||||
Net decrease in cash and cash equivalents |
| (14,397 | ) | (161,890 | ) | |||||||||
Cash and cash equivalents, beginning of period |
| 503,922 |
| 183,435 |
|
| 330,651 |
| 503,922 |
| ||||
Cash and cash equivalents, end of period |
| $ | 387,488 |
| $ | 259,039 |
|
| $ | 316,254 |
| $ | 342,032 |
|
SeeThe accompanying “Notes to Consolidated Financial Statements” for HEI.notes are an integral part of these consolidated financial statements.
Hawaiian Electric Industries, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1 · Basis of presentation
The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by referenceincluded in HEI’s Form 10-K for the year ended December 31, 2009 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010.
In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of September 30, 2010March 31, 2011 and December 31, 2009,2010, the results of its operations for the three and nine months ended September 30, 2010 and 2009 and cash flows for the ninethree months ended September 30, 2010March 31, 2011 and 2009.2010. 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 |
|
| Electric Utility |
| Bank |
| Other |
| Total |
| ||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Three months ended September 30, 2010 |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Three months ended March 31, 2011 |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Revenues from external customers |
| $ | 623,090 |
| 71,429 |
| 22 |
| $ | 694,541 |
|
| $ | 645,299 |
| $ | 65,313 |
| $ | 21 |
| $ | 710,633 |
| ||
Intersegment revenues (eliminations) |
| 36 |
| — |
| (36 | ) |
|
|
| 36 |
| — |
| (36 | ) | — |
| ||||||||
Revenues |
| 623,126 |
| 71,429 |
| (14 | ) | 694,541 |
|
| 645,335 |
| 65,313 |
| (15 | ) | 710,633 |
| ||||||||
Income (loss) before income taxes |
| 37,197 |
| 24,359 |
| (8,251 | ) | 53,305 |
|
| 31,267 |
| 21,727 |
| (7,995 | ) | 44,999 |
| ||||||||
Income taxes (benefit) |
| 14,719 |
| 9,066 |
| (3,400 | ) | 20,385 |
|
| 11,579 |
| 7,876 |
| (3,391 | ) | 16,064 |
| ||||||||
Net income (loss) |
| 22,478 |
| 15,293 |
| (4,851 | ) | 32,920 |
|
| 19,688 |
| 13,851 |
| (4,604 | ) | 28,935 |
| ||||||||
Preferred stock dividends of subsidiaries |
| 498 |
| — |
| (27 | ) | 471 |
|
| 499 |
| — |
| (26 | ) | 473 |
| ||||||||
Net income (loss) for common stock |
| 21,980 |
| 15,293 |
| (4,824 | ) | 32,449 |
|
| 19,189 |
| 13,851 |
| (4,578 | ) | 28,462 |
| ||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Nine months ended September 30, 2010 |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Tangible assets (at March 31, 2011) |
| 4,211,560 |
| 4,769,234 |
| 57,710 |
| 9,038,504 |
| |||||||||||||||||
Three months ended March 31, 2010 |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Revenues from external customers |
| $ | 1,755,213 |
| 213,975 |
| 57 |
| $ | 1,969,245 |
|
| $ | 548,075 |
| $ | 70,914 |
| $ | 51 |
| $ | 619,040 |
| ||
Intersegment revenues (eliminations) |
| 119 |
| — |
| (119 | ) |
|
|
| 36 |
| — |
| (36 | ) | — |
| ||||||||
Revenues |
| 1,755,332 |
| 213,975 |
| (62 | ) | 1,969,245 |
|
| 548,111 |
| 70,914 |
| 15 |
| 619,040 |
| ||||||||
Income (loss) before income taxes |
| 95,063 |
| 71,842 |
| (24,974 | ) | 141,931 |
|
| 29,512 |
| 21,736 |
| (8,370 | ) | 42,878 |
| ||||||||
Income taxes (benefit) |
| 35,893 |
| 26,682 |
| (10,898 | ) | 51,677 |
|
| 10,961 |
| 8,000 |
| (3,682 | ) | 15,279 |
| ||||||||
Net income (loss) |
| 59,170 |
| 45,160 |
| (14,076 | ) | 90,254 |
|
| 18,551 |
| 13,736 |
| (4,688 | ) | 27,599 |
| ||||||||
Preferred stock dividends of subsidiaries |
| 1,496 |
| — |
| (79 | ) | 1,417 |
|
| 499 |
| — |
| (26 | ) | 473 |
| ||||||||
Net income (loss) for common stock |
| 57,674 |
| 45,160 |
| (13,997 | ) | 88,837 |
|
| 18,052 |
| 13,736 |
| (4,662 | ) | 27,126 |
| ||||||||
Assets (at September 30, 2010) |
| 4,089,328 |
| 4,804,155 |
| 1,684 |
| 8,895,167 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Three months ended September 30, 2009 |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Revenues from external customers |
| $ | 548,373 |
| $ | 71,947 |
| $ | (7 | ) | $ | 620,313 |
| |||||||||||||
Intersegment revenues (eliminations) |
| 67 |
| — |
| (67 | ) | — |
| |||||||||||||||||
Revenues |
| 548,440 |
| 71,947 |
| (74 | ) | 620,313 |
| |||||||||||||||||
Income (loss) before income taxes |
| 42,877 |
| 17,665 |
| (7,835 | ) | 52,707 |
| |||||||||||||||||
Income taxes (benefit) |
| 15,865 |
| 6,342 |
| (3,454 | ) | 18,753 |
| |||||||||||||||||
Net income (loss) |
| 27,012 |
| 11,323 |
| (4,381 | ) | 33,954 |
| |||||||||||||||||
Preferred stock dividends of subsidiaries |
| 498 |
| — |
| (27 | ) | 471 |
| |||||||||||||||||
Net income (loss) for common stock |
| 26,514 |
| 11,323 |
| (4,354 | ) | 33,483 |
| |||||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||||||||
Nine months ended September 30, 2009 |
|
|
|
|
|
|
|
|
| |||||||||||||||||
Revenues from external customers |
| 1,460,515 |
| 229,478 |
| 18 |
| 1,690,011 |
| |||||||||||||||||
Intersegment revenues (eliminations) |
| 139 |
| — |
| (139 | ) | — |
| |||||||||||||||||
Revenues |
| 1,460,654 |
| 229,478 |
| (121 | ) | 1,690,011 |
| |||||||||||||||||
Income (loss) before income taxes |
| 90,626 |
| 40,239 |
| (23,114 | ) | 107,751 |
| |||||||||||||||||
Income taxes (benefit) |
| 32,989 |
| 14,013 |
| (10,025 | ) | 36,977 |
| |||||||||||||||||
Net income (loss) |
| 57,637 |
| 26,226 |
| (13,089 | ) | 70,774 |
| |||||||||||||||||
Preferred stock dividends of subsidiaries |
| 1,496 |
| — |
| (79 | ) | 1,417 |
| |||||||||||||||||
Net income (loss) for common stock |
| 56,141 |
| 26,226 |
| (13,010 | ) | 69,357 |
| |||||||||||||||||
Assets (at December 31, 2009) |
| 3,978,392 |
| 4,940,985 |
| 5,625 |
| 8,925,002 |
| |||||||||||||||||
Tangible assets (at December 31, 2010) |
| 4,285,680 |
| 4,707,870 |
| 2,905 |
| 8,996,455 |
|
Intercompany electricelectricity sales of consolidated HECOthe electric utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income.income for common stock.
Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income.income for common stock.
3 · Electric utility subsidiary
For HECO’s consolidated HECO financial information, including its commitments and contingencies, see pages 2122 through 43.36 (HECO and Subsidiaries Consolidated Statements of Income (Unaudited) through Note 10).
4 · Bank subsidiary
Selected financial information
American Savings Bank, F.S.B. and Subsidiaries
Consolidated Statements of Income Data (unaudited)
|
| Three months ended |
| Nine months ended |
| |||||||||||||||
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
|
|
|
|
|
| ||||||
Interest and dividend income |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Interest and fees on loans |
| $ | 49,221 |
| $ | 53,080 |
| $ | 148,294 |
| $ | 166,535 |
|
| $ | 46,097 |
| $ | 49,745 |
|
Interest and dividends on investment and mortgage-related securities |
| 3,852 |
| 6,943 |
| 10,815 |
| 21,762 |
|
| 3,769 |
| 3,317 |
| ||||||
|
| 53,073 |
| 60,023 |
| 159,109 |
| 188,297 |
|
| 49,866 |
| 53,062 |
| ||||||
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Interest on deposit liabilities |
| 3,390 |
| 7,286 |
| 11,665 |
| 28,753 |
|
| 2,593 |
| 4,423 |
| ||||||
Interest on other borrowings |
| 1,414 |
| 2,205 |
| 4,258 |
| 7,710 |
|
| 1,367 |
| 1,426 |
| ||||||
|
| 4,804 |
| 9,491 |
| 15,923 |
| 36,463 |
|
| 3,960 |
| 5,849 |
| ||||||
Net interest income |
| 48,269 |
| 50,532 |
| 143,186 |
| 151,834 |
|
| 45,906 |
| 47,213 |
| ||||||
Provision for loan losses |
| 5,961 |
| 5,200 |
| 12,310 |
| 27,000 |
|
| 4,550 |
| 5,359 |
| ||||||
Net interest income after provision for loan losses |
| 42,308 |
| 45,332 |
| 130,876 |
| 124,834 |
|
| 41,356 |
| 41,854 |
| ||||||
Noninterest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fee income on deposit liabilities |
| 6,109 |
| 8,211 |
| 21,520 |
| 22,384 |
|
| 4,449 |
| 7,520 |
| ||||||
Fees from other financial services |
| 6,781 |
| 6,385 |
| 19,844 |
| 18,747 |
|
| 6,946 |
| 6,414 |
| ||||||
Fee income on other financial products |
| 1,697 |
| 1,613 |
| 4,957 |
| 4,285 |
|
| 1,673 |
| 1,525 |
| ||||||
Net losses on available-for-sale securities |
| — |
| (9,863 | ) | — |
| (15,400 | ) | |||||||||||
Other income |
| 3,769 |
| 5,578 |
| 8,545 |
| 11,165 |
|
| 2,379 |
| 2,393 |
| ||||||
|
| 18,356 |
| 11,924 |
| 54,866 |
| 41,181 |
|
| 15,447 |
| 17,852 |
| ||||||
Noninterest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Compensation and employee benefits |
| 18,168 |
| 17,721 |
| 54,477 |
| 55,072 |
|
| 17,505 |
| 17,402 |
| ||||||
Occupancy |
| 4,176 |
| 4,905 |
| 12,617 |
| 15,956 |
|
| 4,240 |
| 4,225 |
| ||||||
Data processing |
| 2,019 |
| 3,684 |
| 10,921 |
| 10,352 |
|
| 1,970 |
| 4,338 |
| ||||||
Services |
| 1,544 |
| 2,437 |
| 5,117 |
| 9,656 |
|
| 1,771 |
| 1,728 |
| ||||||
Equipment |
| 1,600 |
| 1,782 |
| 4,949 |
| 7,112 |
|
| 1,657 |
| 1,709 |
| ||||||
Loss on early extinguishment of debt |
| — |
| — |
| — |
| 101 |
| |||||||||||
Other expense |
| 8,798 |
| 9,062 |
| 25,819 |
| 27,527 |
|
| 7,933 |
| 8,568 |
| ||||||
|
| 36,305 |
| 39,591 |
| 113,900 |
| 125,776 |
|
| 35,076 |
| 37,970 |
| ||||||
Income before income taxes |
| 24,359 |
| 17,665 |
| 71,842 |
| 40,239 |
|
| 21,727 |
| 21,736 |
| ||||||
Income taxes |
| 9,066 |
| 6,342 |
| 26,682 |
| 14,013 |
|
| 7,876 |
| 8,000 |
| ||||||
Net income |
| $ | 15,293 |
| $ | 11,323 |
| 45,160 |
| $ | 26,226 |
|
| $ | 13,851 |
| $ | 13,736 |
|
American Savings Bank, F.S.B. and Subsidiaries
Consolidated Balance Sheets Data (unaudited)
(in thousands) |
| September 30, |
| December 31, |
| ||
Assets |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 350,404 |
| $ | 425,896 |
|
Federal funds sold |
| 1,000 |
| 1,479 |
| ||
Available-for-sale investment and mortgage-related securities |
| 570,262 |
| 432,881 |
| ||
Investment in stock of Federal Home Loan Bank of Seattle |
| 97,764 |
| 97,764 |
| ||
Loans receivable, net |
| 3,466,550 |
| 3,670,493 |
| ||
Other |
| 235,985 |
| 230,282 |
| ||
Goodwill, net |
| 82,190 |
| 82,190 |
| ||
|
| $ | 4,804,155 |
| $ | 4,940,985 |
|
Liabilities and stockholder’s equity |
|
|
|
|
| ||
Deposit liabilities—noninterest-bearing |
| $ | 830,593 |
| $ | 808,474 |
|
Deposit liabilities—interest-bearing |
| 3,128,043 |
| 3,250,286 |
| ||
Other borrowings |
| 246,571 |
| 297,628 |
| ||
Other |
| 96,306 |
| 92,129 |
| ||
|
| 4,301,513 |
| 4,448,517 |
| ||
Common stock |
| 330,493 |
| 329,439 |
| ||
Retained earnings |
| 174,815 |
| 172,655 |
| ||
Accumulated other comprehensive loss, net of tax benefits |
| (2,666 | ) | (9,626 | ) | ||
|
| 502,642 |
| 492,468 |
| ||
|
| $ | 4,804,155 |
| $ | 4,940,985 |
|
Other assets
(in thousands) |
| September 30, |
| December 31, |
| ||
Bank-owned life insurance |
| $ | 116,422 |
| $ | 113,433 |
|
Premises and equipment, net |
| 56,534 |
| 54,428 |
| ||
Prepaid expenses |
| 21,127 |
| 24,353 |
| ||
Accrued interest receivable |
| 14,825 |
| 15,247 |
| ||
Mortgage-servicing rights |
| 6,031 |
| 4,200 |
| ||
Real estate acquired in settlement of loans, net |
| 4,474 |
| 3,959 |
| ||
Other |
| 16,572 |
| 14,662 |
| ||
|
| $ | 235,985 |
| $ | 230,282 |
|
Other liabilities
(in thousands) |
| September 30, |
| December 31, |
|
| March 31, |
| December 31, |
| ||||
Assets |
|
|
|
|
| |||||||||
Cash and cash equivalents |
| $ | 220,066 |
| $ | 204,397 |
| |||||||
Federal funds sold |
| 374 |
| 1,721 |
| |||||||||
Available-for-sale investment and mortgage-related securities |
| 670,949 |
| 678,152 |
| |||||||||
Investment in stock of Federal Home Loan Bank of Seattle |
| 97,764 |
| 97,764 |
| |||||||||
Loans receivable held for investment, net |
| 3,549,750 |
| 3,489,880 |
| |||||||||
Loans held for sale, at lower of cost or fair value |
| 4,308 |
| 7,849 |
| |||||||||
Other |
| 232,865 |
| 234,806 |
| |||||||||
Goodwill |
| 82,190 |
| 82,190 |
| |||||||||
Total assets |
| $ | 4,858,266 |
| $ | 4,796,759 |
| |||||||
Liabilities and shareholder’s equity |
|
|
|
|
| |||||||||
Deposit liabilities—noninterest-bearing |
| $ | 907,444 |
| $ | 865,642 |
| |||||||
Deposit liabilities—interest-bearing |
| 3,127,811 |
| 3,109,730 |
| |||||||||
Other borrowings |
| 244,674 |
| 237,319 |
| |||||||||
Other |
| 87,030 |
| 90,683 |
| |||||||||
Total liabilities |
| 4,366,959 |
| 4,303,374 |
| |||||||||
Common stock |
| 330,898 |
| 330,562 |
| |||||||||
Retained earnings |
| 168,962 |
| 169,111 |
| |||||||||
Accumulated other comprehensive loss, net of tax benefits |
| (8,553 | ) | (6,288 | ) | |||||||||
Total shareholder’s equity |
| 491,307 |
| 493,385 |
| |||||||||
Total liabilities and shareholder’s equity |
| $ | 4,858,266 |
| $ | 4,796,759 |
| |||||||
Other assets |
|
|
|
|
| |||||||||
Bank-owned life insurance |
| $ | 118,679 |
| $ | 117,565 |
| |||||||
Premises and equipment, net |
| 55,772 |
| 56,495 |
| |||||||||
Prepaid expenses |
| 18,282 |
| 18,608 |
| |||||||||
Accrued interest receivable |
| 14,871 |
| 14,887 |
| |||||||||
Mortgage-servicing rights |
| 6,842 |
| 6,699 |
| |||||||||
Real estate acquired in settlement of loans, net |
| 5,797 |
| 4,292 |
| |||||||||
Other |
| 12,622 |
| 16,260 |
| |||||||||
|
| $ | 232,865 |
| $ | 234,806 |
| |||||||
Other liabilities |
|
|
|
|
| |||||||||
Accrued expenses |
| $ | 18,634 |
| $ | 17,270 |
|
| $ | 10,761 |
| $ | 16,426 |
|
Federal and state income taxes payable |
| 30,207 |
| 19,141 |
|
| 33,139 |
| 28,372 |
| ||||
Cashier’s checks |
| 24,656 |
| 26,877 |
|
| 22,830 |
| 22,396 |
| ||||
Advance payments by borrowers |
| 6,052 |
| 10,989 |
|
| 6,489 |
| 10,216 |
| ||||
Other |
| 16,757 |
| 17,852 |
|
| 13,811 |
| 13,273 |
| ||||
|
| $ | 96,306 |
| $ | 92,129 |
|
| $ | 87,030 |
| $ | 90,683 |
|
Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $182$180 million and $65 million, respectively, as of September 30, 2010March 31, 2011 and $233$172 million and $65 million, respectively, as of December 31, 2009.2010.
Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.
As of September 30, 2010,March 31, 2011, ASB had total commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 billion.
Investment and mortgage-related securities portfolio.
Available-for-sale securities. The book value and aggregate fair value by major security type were as follows:
|
| September 30, 2010 |
| December 31, 2009 |
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||||||||||||||||||||||||||||||
|
|
|
| Gross |
| Gross |
| Estimated |
|
|
| Gross |
| Gross |
| Estimated |
|
|
|
| Gross |
| Gross |
| Estimated |
|
|
| Gross |
| Gross |
| Estimated |
| ||||||||||||||||
|
| Book |
| unrealized |
| unrealized |
| fair |
| Book |
| unrealized |
| unrealized |
| fair |
|
| Amortized |
| unrealized |
| unrealized |
| fair |
| Amortized |
| unrealized |
| unrealized |
| fair |
| ||||||||||||||||
(in thousands) |
| value |
| gains |
| losses |
| value |
| value |
| gains |
| losses |
| value |
|
| cost |
| gains |
| losses |
| value |
| cost |
| gains |
| losses |
| value |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Investment securities — federal agency obligations |
| $ | 265,941 |
| $ | 583 |
| $ | (49 | ) | $ | 266,475 |
| $ | 104,091 |
| $ | 109 |
| $ | (156 | ) | $ | 104,044 |
| |||||||||||||||||||||||||
Federal agency obligations |
| $ | 288,393 |
| $ | 51 |
| $ | (3,122 | ) | $ | 285,322 |
| $ | 317,945 |
| $ | 171 |
| $ | (2,220 | ) | $ | 315,896 |
| |||||||||||||||||||||||||
Mortgage-related securities — FNMA, FHLMC and GNMA |
| 265,449 |
| 10,935 |
| (54 | ) | 276,330 |
| 319,642 |
| 7,967 |
| (88 | ) | 327,521 |
|
| 334,157 |
| 8,928 |
| (481 | ) | 342,604 |
| 310,711 |
| 9,570 |
| (311 | ) | 319,970 |
| ||||||||||||||||
Municipal bonds |
| 27,003 |
| 510 |
| (56 | ) | 27,457 |
| 1,300 |
| 16 |
| — |
| 1,316 |
|
| 43,575 |
| 77 |
| (629 | ) | 43,023 |
| 43,632 |
| 7 |
| (1,353 | ) | 42,286 |
| ||||||||||||||||
|
| $ | 558,393 |
| $ | 12,028 |
| $ | (159 | ) | $ | 570,262 |
| $ | 425,033 |
| $ | 8,092 |
| $ | (244 | ) | $ | 432,881 |
|
| $ | 666,125 |
| $ | 9,056 |
| $ | (4,232 | ) | $ | 670,949 |
| $ | 672,288 |
| $ | 9,748 |
| $ | (3,884 | ) | $ | 678,152 |
|
The following tables detailtable details the contractual maturities and yields of available-for-sale securities. All positions with variable maturities (e.g., callable debentures and mortgage backedmortgage-related securities) are disclosed based upon the bond’s contractual maturity. Actual average maturities may be substantially shorter than those detailed below.
|
|
|
| Weighted |
| Maturity<1 year |
| Maturity 1-5 years |
| Maturity 5-10 years |
| Maturity>10 years |
| |||||||||||||
|
| Book |
| average |
| Book |
| Yield |
| Book |
| Yield |
| Book |
| Yield |
| Book |
| Yield |
| |||||
(dollars in thousands) |
| value |
| yield (%) |
| value |
| (%) |
| value |
| (%) |
| value |
| (%) |
| value |
| (%) |
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment securities — federal agency obligations |
| $ | 265,941 |
| 1.32 |
| $ | 10,000 |
| 0.26 |
| $ | 215,408 |
| 1.18 |
| $ | 40,533 |
| 2.32 |
| $ | — |
| — |
|
Mortgage-related securities — FNMA, FHLMC and GNMA |
| 265,449 |
| 3.81 |
| — |
| — |
| 3,565 |
| 2.29 |
| 110,794 |
| 3.79 |
| 151,090 |
| 3.86 |
| |||||
Municipal bonds |
| 27,003 |
| 3.99 |
| 500 |
| 1.92 |
| 800 |
| 2.50 |
| 25,703 |
| 4.08 |
| — |
| — |
| |||||
|
| $ | 558,393 |
| 2.63 |
| $ | 10,500 |
| 0.34 |
| $ | 219,773 |
| 1.20 |
| $ | 177,030 |
| 3.49 |
| $ | 151,090 |
| 3.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Investment securities — federal agency obligations |
| $ | 104,091 |
| 1.08 |
| $ | — |
| — |
| $ | 94,091 |
| 1.01 |
| $ | 10,000 |
| 1.80 |
| $ | — |
| — |
|
Mortgage-related securities — FNMA, FHLMC and GNMA |
| 319,642 |
| 3.85 |
| — |
| — |
| 5,787 |
| 2.32 |
| 138,617 |
| 3.80 |
| 175,238 |
| 3.94 |
| |||||
Municipal bonds |
| 1,300 |
| 2.27 |
| 500 |
| 1.92 |
| 800 |
| 2.50 |
| — |
| — |
| — |
| — |
| |||||
|
| $ | 425,033 |
| 3.17 |
| $ | 500 |
| 1.92 |
| $ | 100,678 |
| 1.10 |
| $ | 148,617 |
| 3.67 |
| $ | 175,238 |
| 3.94 |
|
The net losses on available for sale securities for the third quarter of 2009 of $9.9 million consisted of $13.7 million of total other-than-temporary impairment losses, net of $3.8 million of non-credit losses recognized in other comprehensive income.
The net losses on available for sale securities for the nine months ended September 30, 2009 of $15.4 million included impairment losses of $15.4 million, which consisted of $32.1 million of total other-than- temporary impairment losses, net of $16.7 million of non-credit losses recognized in other comprehensive income.
March 31, 2011 |
| Amortized cost |
| Fair value |
| ||
(in thousands) |
|
|
|
|
| ||
Due in one year or less |
| $ | 20,800 |
| $ | 20,835 |
|
Due after one year through five years |
| 258,393 |
| 255,966 |
| ||
Due after five years through ten years |
| 42,308 |
| 41,323 |
| ||
Due after ten years |
| 10,467 |
| 10,221 |
| ||
|
| 331,968 |
| 328,345 |
| ||
Mortgage-related securities-FNMA,FHLMC and GNMA |
| 334,157 |
| 342,604 |
| ||
Total available-for-sale securities |
| $ | 666,125 |
| $ | 670,949 |
|
Gross unrealized losses and fair value. The gross unrealized losses and fair values (for securities held in available for sale by duration of time in which positions have been held in a continuous loss position) were as follows:
|
| Less than 12 months |
| 12 months or more |
| Total |
|
| Less than 12 months |
| 12 months or more |
| Total |
| ||||||||||||||||||||||||
|
| Gross |
| Fair |
| Gross |
| Fair |
| Gross |
| Fair |
|
| Gross unrealized |
| Fair |
| Gross unrealized |
| Fair |
| Gross unrealized |
| Fair |
| ||||||||||||
(in thousands) |
| losses |
| value |
| losses |
| value |
| losses |
| value |
|
| losses |
| value |
| losses |
| value |
| losses |
| value |
| ||||||||||||
September 30, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Investment securities — federal agency obligations |
| $ | (49 | ) | $ | 39,966 |
| $ | — |
| $ | — |
| $ | (49 | ) | $ | 39,966 |
| |||||||||||||||||||
March 31, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Federal agency obligations |
| $ | (3,122 | ) | $ | 239,090 |
| $ | — |
| $ | — |
| $ | (3,122 | ) | $ | 239,090 |
| |||||||||||||||||||
Mortgage-related securities — FNMA, FHLMC and GNMA |
| (54 | ) | 5,357 |
| — |
| — |
| (54 | ) | 5,357 |
|
| (481 | ) | 24,352 |
| — |
| — |
| (481 | ) | 24,352 |
| ||||||||||||
Municipal bonds |
| (56 | ) | 3,600 |
| — |
| — |
| (56 | ) | 3,600 |
|
| (629 | ) | 32,390 |
| — |
| — |
| (629 | ) | 32,390 |
| ||||||||||||
|
| $ | (159 | ) | $ | 48,923 |
| $ | — |
| $ | — |
| $ | (159 | ) | $ | 48,923 |
|
| $ | (4,232 | ) | $ | 295,832 |
| $ | — |
| $ | — |
| $ | (4,232 | ) | $ | 295,832 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Investment securities — federal agency obligations |
| $ | (156 | ) | $ | 54,834 |
| $ | — |
| $ | — |
| $ | (156 | ) | $ | 54,834 |
| |||||||||||||||||||
December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Federal agency obligations |
| $ | (2,220 | ) | $ | 205,316 |
| $ | — |
| $ | — |
| $ | (2,220 | ) | $ | 205,316 |
| |||||||||||||||||||
Mortgage-related securities — FNMA, FHLMC and GNMA |
| (88 | ) | 15,352 |
| — |
| — |
| (88 | ) | 15,352 |
|
| (311 | ) | 30,986 |
| — |
| — |
| (311 | ) | 30,986 |
| ||||||||||||
Municipal bonds |
| — |
| — |
| — |
| — |
| — |
| — |
|
| (1,353 | ) | 41,479 |
| — |
| — |
| (1,353 | ) | 41,479 |
| ||||||||||||
|
| $ | (244 | ) | $ | 70,186 |
| $ | — |
| $ | — |
| $ | (244 | ) | $ | 70,186 |
|
| $ | (3,884 | ) | $ | 277,781 |
| $ | — |
| $ | — |
| $ | (3,884 | ) | $ | 277,781 |
|
The unrealized losses on ASB’s investments in obligations issued by federal agencies were caused by interest rate movements. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost bases of the investments. Because ASB does not intend to sell the securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of their amortized costs bases, which may be at maturity, ASB does not consider these investments to be other-than-temporarily impaired at September 30, 2010.March 31, 2011.
The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.
Federal Deposit Insurance CorporationAllowance for loan losses. restoration plan.Under the Federal Deposit Insurance Reform ActASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio. The allowance for loan losses consists of 2005 (the Reform Act), the Federal Deposit Insurance Corporation (FDIC) may set the designated reserve ratio within a rangean allocated portion, which estimates credit losses for specifically identified loans and pools of 1.15% to 1.50%. The Reform Act requires that the FDIC’s Board of Directors adopt a restoration plan when the Deposit Insurance Fund (DIF) reserve ratio falls below 1.15% or is expected to within six months. Financial institution failures have significantly increased the DIF’s loss provisions, resulting in declines in the reserve ratio.loans, and an unallocated portion.
In May 2009, the board of directors of the FDIC voted to levy a special assessment on deposit institutions to build the DIF and restore public confidence in the banking system. ASB’s special assessment was $2.3 million and ASB recorded the charge in June 2009.
In November 2009, the Board of Directors of the FDIC approved a restoration plan that required banks to prepay, by December 30, 2009, their estimated quarterly, risk-based assessments for the fourth quarter of 2009, and for all of 2010, 2011 and 2012. For the fourth quarter of 2009 and all of 2010, the prepaid assessment rate was assessed according to a risk-based premium schedule adopted earlier in 2009. The prepaid assessment rate for 2011 and 2012 was the current assessment rate plus 3 basis points. The prepaid assessment was recorded as a prepaid asset as of December 30, 2009, and each quarter thereafter ASB will record a charge to earnings for its regular quarterly assessment and offset the prepaid expense until the asset is exhausted. Once the asset is exhausted, ASB will record an accrued expense payable each quarter for the assessment to be paid. If the prepaid assessment is not exhausted by December 30, 2014, any remaining amount will be returned to ASB. ASB’s prepaid assessment was approximately $24 million. For each of the quarters ended September 30, 2010 and 2009, ASB’s assessment rate was 14 basis points of deposits, or $1.4 million and $1.5 million, respectively.
The FDIC may impose additional special assessments in the future if it is deemed necessary to ensure the DIF ratio does not decline to a level that is close to zero or that could otherwise undermine public confidence in federal deposit insurance. Management cannot predict with certainty the timing or amounts of any additional assessments.
Deposit insurance coverage. In July 2010,The allowance for loan losses was comprised of the Dodd-Frank Wall Street Reformfollowing:
|
| Residential |
| Commercial |
| Home |
| Residen- |
| Commercial |
| Residential |
| Commer- |
| Consu- |
| Unallo- |
|
|
| ||||||||||
March 31, 2011 |
| 1-4 family |
| estate |
| of credit |
| land |
| construction |
| construction |
| loans |
| loans |
| cated |
| Total |
| ||||||||||
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Allowance for loan losses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Beginning balance |
| $ | 6,497 |
| $ | 1,474 |
| $ | 4,269 |
| $ | 6,411 |
| $ | 1,714 |
| $ | 7 |
| $ | 16,015 |
| $ | 3,325 |
| $ | 934 |
| $ | 40,646 |
|
Charge-offs |
| 1,791 |
| — |
| 115 |
| 971 |
| — |
| — |
| 1,023 |
| 833 |
| — |
| 4,733 |
| ||||||||||
Recoveries |
| 23 |
| — |
| 2 |
| 5 |
| — |
| — |
| 177 |
| 144 |
| — |
| 351 |
| ||||||||||
Provision |
| 3,336 |
| 66 |
| (876 | ) | 1,086 |
| 84 |
| (2 | ) | (59 | ) | 866 |
| 49 |
| 4,550 |
| ||||||||||
Ending balance |
| $ | 8,065 |
| $ | 1,540 |
| $ | 3,280 |
| $ | 6,531 |
| $ | 1,798 |
| $ | 5 |
| $ | 15,110 |
| $ | 3,502 |
| $ | 983 |
| $ | 40,814 |
|
Ending balance: individually evaluated for impairment |
| $ | 230 |
| $ | — |
| $ | — |
| $ | 2,940 |
| $ | — |
| $ | — |
| $ | 1,454 |
| $ | — |
| $ | — |
| $ | 4,624 |
|
Ending balance: collectively evaluated for impairment |
| $ | 7,835 |
| $ | 1,540 |
| $ | 3,280 |
| $ | 3,591 |
| $ | 1,798 |
| $ | 5 |
| $ | 13,656 |
| $ | 3,502 |
| $ | 983 |
| $ | 36,190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Financing Receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Ending balance |
| $ | 2,051,945 |
| $ | 300,248 |
| $ | 444,684 |
| $ | 60,671 |
| $ | 39,960 |
| $ | 3,568 |
| $ | 617,800 |
| $ | 86,895 |
| $ | — |
| $ | 3,605,771 |
|
Ending balance: individually evaluated for impairment |
| $ | 30,534 |
| $ | 10,135 |
| $ | 1,405 |
| $ | 41,843 |
| $ | — |
| $ | — |
| $ | 44,224 |
| $ | 25 |
| $ | — |
| $ | 128,166 |
|
Ending balance: collectively evaluated for impairment |
| $ | 2,021,411 |
| $ | 290,113 |
| $ | 443,279 |
| $ | 18,828 |
| $ | 39,960 |
| $ | 3,568 |
| $ | 573,576 |
| $ | 86,870 |
| $ | — |
| $ | 3,477,605 |
|
|
| Residential |
| Commercial |
| Home |
| Residen- |
| Commercial |
| Residential |
| Commer- |
| Consu- |
| Unallo- |
|
|
| ||||||||||
December 31, 2010 |
| 1-4 family |
| estate |
| of credit |
| land |
| construction |
| construction |
| loans |
| loans |
| cated |
| Total |
| ||||||||||
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Allowance for loan losses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Beginning balance |
| $ | 5,522 |
| $ | 861 |
| $ | 4,679 |
| $ | 4,252 |
| $ | 3,068 |
| $ | 19 |
| $ | 19,498 |
| $ | 2,590 |
| $ | 1,190 |
| $ | 41,679 |
|
Charge-offs |
| 6,142 |
| — |
| 2,517 |
| 6,487 |
| — |
| — |
| 6,261 |
| 3,408 |
| — |
| 24,815 |
| ||||||||||
Recoveries |
| 744 |
| — |
| 63 |
| 63 |
| — |
| — |
| 1,537 |
| 481 |
| — |
| 2,888 |
| ||||||||||
Provision |
| 6,373 |
| $ | 613 |
| 2,044 |
| 8,583 |
| (1,354 | ) | (12 | ) | 1,241 |
| $ | 3,662 |
| (256 | ) | 20,894 |
| ||||||||
Ending balance |
| $ | 6,497 |
| $ | 1,474 |
| $ | 4,269 |
| $ | 6,411 |
| $ | 1,714 |
| $ | 7 |
| $ | 16,015 |
| $ | 3,325 |
| $ | 934 |
| $ | 40,646 |
|
Ending balance: individually evaluated for impairment |
| $ | 230 |
| $ | — |
| $ | — |
| $ | 1,642 |
| $ | — |
| $ | — |
| $ | 1,588 |
| $ | — |
| $ | — |
| $ | 3,460 |
|
Ending balance: collectively evaluated for impairment |
| $ | 6,267 |
| $ | 1,474 |
| $ | 4,269 |
| $ | 4,769 |
| $ | 1,714 |
| $ | 7 |
| $ | 14,427 |
| $ | 3,325 |
| $ | 934 |
| $ | 37,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Financing Receivables: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Ending balance |
| $ | 2,087,813 |
| $ | 300,689 |
| $ | 416,453 |
| $ | 65,599 |
| $ | 38,079 |
| $ | 5,602 |
| $ | 551,683 |
| $ | 80,138 |
| $ | — |
| $ | 3,546,056 |
|
Ending balance: individually evaluated for impairment |
| $ | 34,615 |
| $ | 12,156 |
| $ | 827 |
| $ | 39,631 |
| $ | — |
| $ | — |
| $ | 28,886 |
| $ | 76 |
| $ | — |
| $ | 116,191 |
|
Ending balance: collectively evaluated for impairment |
| $ | 2,053,198 |
| $ | 288,533 |
| $ | 415,626 |
| $ | 25,968 |
| $ | 38,079 |
| $ | 5,602 |
| $ | 522,797 |
| $ | 80,062 |
| $ | — |
| $ | 3,429,865 |
|
Credit quality. ASB performs an internal loan review and Consumer Protection Act permanently raisedgrading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit quality problems so that appropriate steps can be initiated to avoid or minimize future losses. Loans subject to grading include commercial and CRE loans.
A ten-point risk rating system is used to determine loan grade and is based on borrower loan risk. The risk rating is a numerical representation of risk based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting issues and industry/economic factors.
The loan grade categories are:
1- Substantially risk free
2- Minimal risk
3- Modest risk
4- Better than average risk
5- Average risk
6- Acceptable risk
7- Special mention
8- Substandard
9- Doubtful
10- Loss
Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current standard maximum deposit insurance amount to $250,000. Previously,net worth and paying capacity of the standard maximum deposit insurance amountobligor or by the value of $100,000 had been temporarily raised to $250,000 through December 31, 2013. the asset or underlying collateral.
The Dodd Frank Act also redefines the assessment basecredit risk profile by internally assigned grade for loans was as average total consolidated assets less average tangible equity (previously the assessment base wasfollows:
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||||
(in thousands) |
| Commercial |
| Commercial |
| Commercial |
| Commercial |
| Commercial |
| Commercial |
| ||||||
Grade: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Pass |
| $ | 286,912 |
| $ | 39,960 |
| $ | 533,985 |
| $ | 285,624 |
| $ | 38,079 |
| $ | 462,078 |
|
Special mention |
| 1,079 |
| — |
| 24,485 |
| 526 |
| — |
| 44,759 |
| ||||||
Substandard |
| 12,257 |
| — |
| 59,222 |
| 14,539 |
| — |
| 44,259 |
| ||||||
Doubtful |
| — |
| — |
| 108 |
| — |
| — |
| 556 |
| ||||||
Loss |
| — |
| — |
| — |
| — |
| — |
| 31 |
| ||||||
Total |
| $ | 300,248 |
| $ | 39,960 |
| $ | 617,800 |
| $ | 300,689 |
| $ | 38,079 |
| $ | 551,683 |
|
The credit risk profile based on deposits).payment activity for loans was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
| Recorded |
| |||||||
|
| 30-59 |
| 60-89 |
| Greater |
|
|
|
|
| Total |
| Investment> |
| |||||||
|
| days |
| days |
| than |
| Total |
|
|
| financing |
| 90 days and |
| |||||||
March 31, 2011 |
| past due |
| past due |
| 90 days |
| past due |
| Current |
| receivables |
| accruing |
| |||||||
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Residential 1-4 family |
| $ | 5,740 |
| $ | 4,608 |
| $ | 35,402 |
| $ | 45,750 |
| $ | 2,006,195 |
| $ | 2,051,945 |
| $ | — |
|
Commercial real estate |
| — |
| — |
| — |
| — |
| 300,248 |
| 300,248 |
| — |
| |||||||
Home equity line of credit |
| 1,316 |
| 490 |
| 1,444 |
| 3,250 |
| 441,434 |
| 444,684 |
| — |
| |||||||
Residential land |
| 221 |
| 2,270 |
| 16,688 |
| 19,179 |
| 41,492 |
| 60,671 |
| 136 |
| |||||||
Commercial construction |
| — |
| — |
| — |
| — |
| 39,960 |
| 39,960 |
| — |
| |||||||
Residential construction |
| — |
| — |
| — |
| — |
| 3,568 |
| 3,568 |
| — |
| |||||||
Commercial loans |
| 1,333 |
| 511 |
| 2,481 |
| 4,325 |
| 613,475 |
| 617,800 |
| 114 |
| |||||||
Consumer loans |
| 536 |
| 309 |
| 570 |
| 1,415 |
| 85,480 |
| 86,895 |
| 420 |
| |||||||
Total loans |
| $ | 9,146 |
| $ | 8,188 |
| $ | 56,585 |
| $ | 73,919 |
| $ | 3,531,852 |
| $ | 3,605,771 |
| $ | 670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Recorded |
| |||||||
|
| 30-59 |
| 60-89 |
| Greater |
|
|
|
|
| Total |
| Investment> |
| |||||||
|
| days |
| days |
| than |
| Total |
|
|
| financing |
| 90 days and |
| |||||||
December 31, 2010 |
| past due |
| past due |
| 90 days |
| past due |
| Current |
| receivables |
| accruing |
| |||||||
(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Residential 1-4 family |
| $ | 8,245 |
| $ | 3,719 |
| $ | 36,419 |
| $ | 48,383 |
| $ | 2,039,430 |
| $ | 2,087,813 |
| $ | — |
|
Commercial real estate |
| — |
| 4 |
| — |
| 4 |
| 300,685 |
| 300,689 |
| — |
| |||||||
Home equity line of credit |
| 1,103 |
| 227 |
| 1,659 |
| 2,989 |
| 413,464 |
| 416,453 |
| — |
| |||||||
Residential land |
| 1,543 |
| 1,218 |
| 16,060 |
| 18,821 |
| 46,778 |
| 65,599 |
| 581 |
| |||||||
Commercial construction |
| — |
| — |
| — |
| — |
| 38,079 |
| 38,079 |
| — |
| |||||||
Residential construction |
| — |
| — |
| — |
| — |
| 5,602 |
| 5,602 |
| — |
| |||||||
Commercial loans |
| 892 |
| 1,317 |
| 3,191 |
| 5,400 |
| 546,283 |
| 551,683 |
| 64 |
| |||||||
Consumer loans |
| 629 |
| 410 |
| 617 |
| 1,656 |
| 78,482 |
| 80,138 |
| 320 |
| |||||||
Total loans |
| $ | 12,412 |
| $ | 6,895 |
| $ | 57,946 |
| $ | 77,253 |
| $ | 3,468,803 |
| $ | 3,546,056 |
| $ | 965 |
|
The credit risk profile based on nonaccrual loans, accruing loans 90 days or more past due and troubled debt restructured loans was as follows:
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||||
|
|
|
| Accruing loans |
| Trouble debt |
|
|
| Accruing loans |
| Trouble debt |
| ||||||
|
| Nonaccrual |
| 90 days or |
| restructured |
| Nonaccrual |
| 90 days or |
| restructured |
| ||||||
(in thousands) |
| loans |
| more past due |
| loans |
| loans |
| more past due |
| loans |
| ||||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Residential 1-4 family |
| $ | 36,339 |
| $ | — |
| $ | 4,584 |
| $ | 36,420 |
| $ | — |
| $ | 5,150 |
|
Commercial real estate |
| — |
| — |
| — |
| — |
| — |
| 1,963 |
| ||||||
Home equity line of credit |
| 1,628 |
| — |
| — |
| 1,659 |
| — |
| — |
| ||||||
Residential land |
| 17,712 |
| 136 |
| 27,896 |
| 15,479 |
| 581 |
| 27,689 |
| ||||||
Commercial construction |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Residential construction |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Commercial loans |
| 5,107 |
| 114 |
| 11,060 |
| 4,956 |
| 64 |
| 4,035 |
| ||||||
Consumer loans |
| 243 |
| 420 |
| — |
| 341 |
| 320 |
| — |
| ||||||
Total |
| $ | 61,029 |
| $ | 670 |
| $ | 43,540 |
| $ | 58,855 |
| $ | 965 |
| $ | 38,837 |
|
The total carrying amount and the total unpaid principal balance of impaired loans was as follows:
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||||||||||||||||
(in thousands) |
| Recorded |
| Unpaid |
| Related |
| Average |
| Interest |
| Recorded |
| Unpaid |
| Related |
| Average |
| Interest |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
With no related allowance recorded |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Residential 1-4 family |
| $ | 18,880 |
| $ | 26,129 |
| $ | — |
| $ | 19,697 |
| $ | 60 |
| $ | 18,205 |
| $ | 24,692 |
| $ | — |
| $ | 14,609 |
| $ | 278 |
|
Commercial real estate |
| 10,135 |
| 10,135 |
| — |
| 10,155 |
| 148 |
| 12,156 |
| 12,156 |
| — |
| 14,276 |
| 979 |
| ||||||||||
Home equity line of credit |
| 710 |
| 1,622 |
| — |
| 575 |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Residential land |
| 32,102 |
| 39,660 |
| — |
| 34,261 |
| 519 |
| 33,777 |
| 40,802 |
| — |
| 29,914 |
| 1,499 |
| ||||||||||
Commercial construction |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Residential construction |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Commercial loans |
| 38,331 |
| 38,331 |
| — |
| 35,150 |
| 659 |
| 22,041 |
| 22,041 |
| — |
| 29,636 |
| 1,846 |
| ||||||||||
Consumer loans |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
|
| 100,158 |
| 115,877 |
| — |
| 99,838 |
| 1,386 |
| 86,179 |
| 99,691 |
| — |
| 88,435 |
| 4,602 |
| ||||||||||
With an allowance recorded |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Residential 1-4 family |
| 3,900 |
| 3,900 |
| 230 |
| 3,906 |
| 60 |
| 3,917 |
| 3,917 |
| 230 |
| 2,807 |
| 175 |
| ||||||||||
Commercial real estate |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Home equity line of credit |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Residential land |
| 8,476 |
| 8,536 |
| 2,940 |
| 6,243 |
| 170 |
| 5,041 |
| 5,090 |
| 1,642 |
| 3,753 |
| 327 |
| ||||||||||
Commercial construction |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Residential construction |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Commercial loans |
| 5,893 |
| 5,893 |
| 1,454 |
| 5,941 |
| 100 |
| 6,845 |
| 6,845 |
| 1,588 |
| 2,796 |
| 182 |
| ||||||||||
Consumer loans |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
|
| 18,269 |
| 18,329 |
| 4,624 |
| 16,090 |
| 330 |
| 15,803 |
| 15,852 |
| 3,460 |
| 9,356 |
| 684 |
| ||||||||||
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Residential 1-4 family |
| 22,780 |
| 30,029 |
| 230 |
| 23,603 |
| 120 |
| 22,122 |
| 28,609 |
| 230 |
| 17,416 |
| 453 |
| ||||||||||
Commercial real estate |
| 10,135 |
| 10,135 |
| — |
| 10,155 |
| 148 |
| 12,156 |
| 12,156 |
| — |
| 14,276 |
| 979 |
| ||||||||||
Home equity line of credit |
| 710 |
| 1,622 |
| — |
| 575 |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Residential land |
| 40,578 |
| 48,196 |
| 2,940 |
| 40,504 |
| 689 |
| 38,818 |
| 45,892 |
| 1,642 |
| 33,667 |
| 1,826 |
| ||||||||||
Commercial construction |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Residential construction |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Commercial loans |
| 44,224 |
| 44,224 |
| 1,454 |
| 41,091 |
| 759 |
| 28,886 |
| 28,886 |
| 1,588 |
| 32,432 |
| 2,028 |
| ||||||||||
Consumer loans |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
|
| $ | 118,427 |
| $ | 134,206 |
| $ | 4,624 |
| $ | 115,928 |
| $ | 1,716 |
| $ | 101,982 |
| $ | 115,543 |
| $ | 3,460 |
| $ | 97,791 |
| $ | 5,286 |
|
5 · Retirement benefits
Defined benefit plans. For the first ninethree months of 2010,2011, the utilities contributed $23.8$30.7 million and HEI contributed $0.6$0.5 million to their respective retirement benefit plans, compared to $19.9$8.4 million and $1.00.2 million, respectively, in the first ninethree months of 2009.2010. The Company’s current estimate of contributions to its retirement benefit plans in 20102011 is $32$64 million ($3163 million to be made by the utilities and $1 million by HEI), compared to contributions of $25$32 million in 20092010 ($2431 million made by the utilities and $1 million by HEI). In addition, the Company expects to pay directly $2 million of benefits in 2010, compared2011, comparable to the $1$2 million paid in 2009.2010.
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 |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| |||||||||||||||||||||||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Service cost |
| $ | 7,376 |
| $ | 6,479 |
| $ | 1,248 |
| $ | 1,427 |
| $ | 21,424 |
| $ | 19,208 |
| $ | 3,539 |
| $ | 3,654 |
|
| $ | 8,917 |
| $ | 6,953 |
| $ | 1,267 |
| $ | 1,123 |
|
Interest cost |
| 16,197 |
| 15,468 |
| 2,565 |
| 2,678 |
| 48,330 |
| 46,520 |
| 7,901 |
| 8,363 |
|
| 16,309 |
| 16,040 |
| 2,461 |
| 2,684 |
| ||||||||||||
Expected return on plan assets |
| (17,272 | ) | (14,336 | ) | (2,792 | ) | (2,240 | ) | (51,687 | ) | (42,907 | ) | (8,310 | ) | (6,677 | ) |
| (17,101 | ) | (17,194 | ) | (2,648 | ) | (2,752 | ) | ||||||||||||
Amortization of unrecognized transition obligation |
| 1 |
| 1 |
| — |
| 262 |
| 2 |
| 2 |
| — |
| 1,831 |
|
| 1 |
| 1 |
| — |
| — |
| ||||||||||||
Amortization of prior service cost (credit) |
| (97 | ) | (100 | ) | (83 | ) | (34 | ) | (291 | ) | (288 | ) | (187 | ) | (27 | ) | |||||||||||||||||||||
Amortization of prior service cost (gain) |
| (97 | ) | (97 | ) | (224 | ) | (52 | ) | |||||||||||||||||||||||||||||
Recognized actuarial loss (gain) |
| 1,942 |
| 3,957 |
| (5 | ) | 86 |
| 5,449 |
| 11,890 |
| (8 | ) | 309 |
|
| 4,405 |
| 1,716 |
| 15 |
| (1 | ) | ||||||||||||
Net periodic benefit cost |
| 8,147 |
| 11,469 |
| 933 |
| 2,179 |
| 23,227 |
| 34,425 |
| 2,935 |
| 7,453 |
|
| 12,434 |
| 7,419 |
| 871 |
| 1,002 |
| ||||||||||||
Impact of PUC D&Os |
| 2,574 |
| (1,776 | ) | 1,512 |
| (270 | ) | 7,602 |
| (9,974 | ) | 4,133 |
| (1,002 | ) |
| (1,544 | ) | 3,008 |
| 1,018 |
| 1,288 |
| ||||||||||||
Net periodic benefit cost (adjusted for impact of PUC D&Os) |
| $ | 10,721 |
| $ | 9,693 |
| $ | 2,445 |
| $ | 1,909 |
| $ | 30,829 |
| $ | 24,451 |
| $ | 7,068 |
| $ | 6,451 |
|
| $ | 10,890 |
| $ | 10,427 |
| $ | 1,889 |
| $ | 2,290 |
|
The Company recorded retirement benefits expense of $29 million and $24$10 million in each of the first nine monthsquarters of 20102011 and 2009, respectively,2010, and charged the remaining amounts primarily to electric utility plant.
In the third quarter of 2010, MECO eliminated the electric discount benefit which will generate nominal credits through other benefit costs over the next few years as the total negative amendment credit is amortized.
Also, see Note 4, “Retirement benefits,” of HECO’s Notes to Consolidated Financial Statements.
Defined contribution plan.For the first nine monthsquarters of 2011 and 2010, and 2009, ASB’s total expense for its employees participating in the Hawaiian Electric Industries Retirement Savings Plan and the ASB 401(k) Plan combined was $2.9$0.9 million and $2.1$0.8 million, respectively. For the first nine monthsquarters of 20102011 and 2009,2010, ASB’s cash contributions to the plan were $3.2$2.4 million and $3.4$2.3 million, respectively.
6 · Share-based compensation
TheUnder the 2010 Equity and Incentive Plan (EIP) was approved by shareholders in May 2010 and allows, HEI tocan issue an aggregate of 4 million shares of common stock as additional incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, deferred shares,restricted stock units, performance shares and other share-based and cash-based awards.
Through September 30, 2010,March 31, 2011, grants under the EIP consisted of 77,500 deferred shares.18,009 restricted shares (counted as four shares for every share issued, or 72,036 shares), 161,517 restricted stock units and 375,319 shares that may be issued under the 2011-2013 long-term incentive plan (LTIP) at maximum levels.
Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 1.10.9 million shares of common stock (based on various assumptions, including LTIP awards at maximum levels and the use of the September 30, 2010March 31, 2011 market price of shares as the price on the exercise/payment dates) were outstanding as of September 30, 2010March 31, 2011 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs), restricted stock units, LTIP performance and other shares and dividend equivalents. As of May 11, 2010, no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered shares under the SOIP will be deregistered and delisted.
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 generally became exercisable in installments of 25% each year for four years, and expire if not exercised ten years from the date of the grant. NQSOs and SARs compensation expense has been recognized in accordance with the fair value-based measurement method of accounting. The estimated fair value of each NQSO and SAR grant was calculated on the date of grant using a Binomial Option Pricing Model.
Restricted stock awards under the SOIP generally become unrestricted four years after the date of grant and are forfeited for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations by reason of death, disability or termination without cause. Restricted stock awards compensation expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividends on restricted stock awards are paid quarterly in cash.
Deferred shares and restricted stock units generally vest and will be issued as unrestricted stock four years after the date of the grant and are forfeited for terminations of employment during the vesting period, except that pro-rata vesting is provided for terminations due to death, disability and retirement. Deferred shares and restricted stock units expense has been recognized in accordance with the fair-value-based measurement method of accounting. Dividend equivalent rights are accrued quarterly and are paid in cash at the end of the restriction period when the deferred shares and restricted stock units vest.
Stock performance awards granted under the 2009-2011 and 2010-2012 Long-Term Incentive Plans (LTIP) entitle the grantee to shares of common stock with dividend equivalent rights once service conditions and performance conditions are satisfied at the end of the three-year performance period. LTIP awards are forfeited for terminations of employment during the performance period, except that pro-rata participation is provided for terminations due to death, disability and retirement based upon completed months of service after a minimum of 12 months of service in the performance period. Compensation expense for the stock performance awards portion of the LTIP has been recognized in accordance with the fair-value-based measurement method of accounting for performance shares.
The Company’s share-based compensation expense and related income tax benefit are as follows:
|
| Three months ended |
| Nine months ended |
|
|
|
|
|
| ||||
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||
($ in millions) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Share-based compensation expense (1) |
| 0.6 |
| 0.3 |
| 2.0 |
| 0.7 |
|
| 1.2 |
| 0.6 |
|
Income tax benefit |
| 0.2 |
| 0.1 |
| 0.6 |
| 0.2 |
|
| 0.4 |
| 0.2 |
|
(1) The Company has not capitalized any share-based compensation cost.
Nonqualified stock options. Information about HEI’s NQSOs is summarized as follows:
September 30, 2010 |
| Outstanding & Exercisable (Vested) |
| ||||||||||||||||||||
Year of |
| Range of |
| Number |
| Weighted-average |
| Weighted-average |
| ||||||||||||||
|
|
|
| Outstanding & Exercisable (Vested) |
| ||||||||||||||||||
March 31, 2011 | March 31, 2011 |
|
|
| Weighted-average |
|
|
| |||||||||||||||
Year of |
| Range of |
| Number |
| remaining |
| Weighted-average |
| ||||||||||||||
grant |
| exercise prices |
| of options |
| contractual life |
| Exercise price |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2001 |
| $ | 17.96 |
| 64,000 |
| 0.6 |
| $ | 17.96 |
|
| $ | 17.96 |
|
| 7,500 |
| 0.1 |
| $ | 17.96 |
|
2002 |
| 21.68 |
| 82,000 |
| 1.4 |
| 21.68 |
|
| 21.68 |
|
| 70,000 |
| 1.1 |
| 21.68 |
| ||||
2003 |
| 20.49 |
| 117,500 |
| 2.2 |
| 20.49 |
|
| 20.49 |
|
| 105,500 |
| 1.9 |
| 20.49 |
| ||||
|
| $ | 17.96 – 21.68 |
| 263,500 |
| 1.6 |
| $ | 20.44 |
|
| $ | 17.96 – 21.68 |
| 183,000 |
| 1.5 |
| $ | 20.84 |
|
As of December 31, 2009,2010, NQSOs outstanding totaled 374,500215,500 (representing the same number of underlying shares), with a weighted-average exercise price of $19.73.$20.76. As of September 30, 2010,March 31, 2011, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $1.4$1.3 million.
NQSO activity and statistics are summarized as follows:
|
| Three months ended |
| Nine months ended |
| ||||||||||||||
($ in thousands, except prices) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| ||||||||||
Three months ended March 31 |
| 2011 |
| 2010 |
| ||||||||||||||
(dollars in thousands, except prices) |
|
|
|
|
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Shares expired |
| — |
| — |
| 2,000 |
| 1,000 |
|
| — |
| 2,000 |
| |||||
Weighted-average price of shares expired |
| — |
| — |
| $ | 20.49 |
| $ | 17.61 |
|
| — |
| $ | 20.49 |
| ||
Shares exercised |
| 46,000 |
| — |
| 109,000 |
| — |
|
| 32,500 |
| 46,000 |
| |||||
Weighted-average exercise price |
| $ | 21.52 |
| — |
| $ | 18.48 |
| — |
|
| $ | 20.27 |
| $ | 14.74 |
| |
Cash received from exercise |
| $ | 990 |
| — |
| $ | 2,014 |
| — |
|
| $ | 659 |
| $ | 678 |
| |
Intrinsic value of shares exercised (1) |
| $ | 287 |
| — |
| $ | 912 |
| — |
|
| $ | 258 |
| $ | 549 |
| |
Tax benefit realized for the deduction of exercises |
| $ | 81 |
| — |
| $ | 324 |
| — |
|
| $ | 101 |
| $ | 214 |
|
(1) Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.
Stock appreciation rights. Information about HEI’s SARs is summarized as follows:
September 30, 2010 |
| Outstanding & Exercisable (Vested) |
| ||||||||||||||||||||
Year of |
| Range of |
| Number of shares |
| Weighted-average |
| Weighted-average |
| ||||||||||||||
|
|
| Outstanding & Exercisable (Vested) |
| |||||||||||||||||||
March 31, 2011 | March 31, 2011 |
|
|
| Weighted-average |
|
|
| |||||||||||||||
Year of |
| Range of |
| Number of shares |
| remaining |
| Weighted-average |
| ||||||||||||||
grant |
| exercise prices |
| underlying SARs |
| contractual life |
| exercise price |
| ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
2004 |
| $ | 26.02 |
| 150,000 |
| 2.3 |
| $ | 26.02 |
|
| $ | 26.02 |
|
| 132,000 |
| 2.1 |
| $ | 26.02 |
|
2005 |
| 26.18 |
| 312,000 |
| 2.9 |
| 26.18 |
|
| 26.18 |
|
| 282,000 |
| 2.7 |
| 26.18 |
| ||||
|
| $ | 26.02 –26.18 |
| 462,000 |
| 2.7 |
| $ | 26.13 |
|
| $ | 26.02 –26.18 |
| 414,000 |
| 2.5 |
| $ | 26.13 |
|
As of December 31, 2009,2010, the shares underlying SARs outstanding totaled 480,000,450,000, with a weighted-average exercise price of $26.13. As of September 30, 2010,March 31, 2011, all SARs outstanding were exercisable and had no intrinsic value.
SARs activity and statistics are summarized as follows:
|
|
|
|
|
| ||
Three months ended March 31 |
| 2011 |
| 2010 |
| ||
(dollars in thousands, except prices) |
|
|
|
|
| ||
|
|
|
|
|
| ||
Shares forfeited |
| — |
| — |
| ||
Weighted-average price of shares forfeited |
| — |
| — |
| ||
Shares expired |
| 36,000 |
| 6,000 |
| ||
Weighted-average price of shares expired |
| $ | 26.10 |
| $ | 26.18 |
|
Shares exercised |
| — |
| — |
| ||
SARs activityRestricted shares and statistics are summarized as follows:
|
| Three months ended |
| Nine months ended |
| ||||||
($ in thousands, except prices) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Shares forfeited |
| — |
| — |
| — |
| 6,000 |
| ||
Weighted-average price of shares forfeited |
| — |
| — |
| — |
| $ | 26.18 |
| |
Shares expired |
| — |
| — |
| 18,000 |
| 305,000 |
| ||
Weighted-average price of shares expired |
| — |
| — |
| $ | 26.18 |
| $ | 26.10 |
|
Shares vested |
| — |
| — |
| — |
| 228,000 |
| ||
Aggregate fair value of vested shares |
| — |
| — |
| — |
| $ | 1,354 |
| |
Shares exercised |
| — |
| — |
| — |
| — |
| ||
Dividend equivalent shares distributed under Section 409A |
| — |
| — |
| — |
| 3,143 |
| ||
Weighted-average Section 409A distribution price |
| — |
| — |
| — |
| $ | 13.64 |
| |
Intrinsic value of shares distributed under Section 409A(1) |
| — |
| — |
| — |
| $ | 43 |
| |
Tax benefit realized for Section 409A distributions |
| — |
| — |
| — |
| $ | 17 |
| |
(1)Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the right.
Section 409A. As a result of the changes enacted in Section 409A of the Internal Revenue Code of 1986, as amended (Section 409A), for the nine months ended September 30, 2009 a total of 3,143 dividend equivalent shares for SAR grants were distributed to SOIP participants. Section 409A, which amended the federal income tax rules governing deferred compensation, required the Company to change the way certain affected dividend equivalents are paid in order to avoid significant adverse tax consequences to the SOIP participants. Generally, dividend equivalents subject to Section 409A will be paid within 2½ months after the end of the calendar year. Upon retirement, an SOIP participant may elect to take distributions of dividend equivalents subject to Section 409A at the time of retirement or at the end of the calendar year. The dividend equivalents associated with the 2005 SAR grants had no intrinsic value at December 31, 2009; thus, no distribution will be made in 2010. No further dividend equivalents are intended to be paid in accordance with this Section 409A modified distribution.
Restrictedrestricted stock awards. Information about HEI’s grants of restricted shares and restricted stock awards is summarized as follows:
|
| Three months ended September 30 |
| Nine months ended September 30 |
|
| 2011 |
| 2010 |
| ||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| |||||||||||||||||||||||
|
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||
Three months ended March 31 |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Outstanding, beginning of period |
| 78,700 |
| $ | 25.04 |
| 134,000 |
| $ | 25.50 |
| 129,000 |
| $ | 25.50 |
| 160,500 |
| $ | 25.51 |
|
| 89,709 |
| $ | 24.64 |
| 129,000 |
| $ | 25.50 |
|
Granted |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| — |
| — |
| — |
| — |
| ||||||
Vested and issued |
| — |
| — |
| — |
| — |
| (43,565 | ) | 26.29 |
| (3,851 | ) | 24.52 |
| |||||||||||||||
Vested |
| — |
| — |
| (1,565 | ) | 25.97 |
| |||||||||||||||||||||||
Forfeited |
| (7,000 | ) | 23.00 |
| (4,000 | ) | 25.36 |
| (13,735 | ) | 24.35 |
| (26,649 | ) | 25.68 |
|
| (1,000 | ) | 25.36 |
| (6,735 | ) | 25.75 |
| ||||||
Outstanding, end of period |
| 71,700 |
| $ | 25.24 |
| 130,000 |
| $ | 25.50 |
| 71,700 |
| $ | 25.24 |
| 130,000 |
| $ | 25.50 |
|
| 88,709 |
| $ | 24.63 |
| 120,700 |
| $ | 25.48 |
|
(1) Represents the weighted-averageWeighted-average grant-date fair value per share. The grant date fair value of a restricted stock award share was the closing or average price of HEI common stock on the date of grant.
ForAs of March 31, 2011, 18,009 restricted shares were outstanding under the nine months ended September 30, 2010EIP and 2009, total70,700 shares of restricted stock vested had a fair value of $1.1 million and $94,000, respectively. The tax benefits realized forwere outstanding under the tax deductions related to restricted stock awards were $0.1 million for each of the first nine months of 2010 and 2009.SOIP
As of September 30, 2010,March 31, 2011, there was $0.4$0.5 million of total unrecognized compensation cost related to nonvested restricted shares and restricted stock awards. The cost is expected to be recognized over a weighted-average period of 1.32.6 years.
Deferred shares and restrictedRestricted stock units. Information about HEI’s grants of deferred shares and restricted stock units areis summarized as follows:
|
| Three months ended September 30 |
| Nine months ended September 30 |
|
| 2011 |
| 2010 |
| ||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| |||||||||||||||||||||||
|
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||
Three months ended March 31 |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Outstanding, beginning of period |
| 146,500 |
| $ | 19.80 |
| 70,500 |
| $ | 16.99 |
| 70,500 |
| $ | 16.99 |
| — |
| $ | — |
|
| 146,500 |
| $ | 19.80 |
| 70,500 |
| $ | 16.99 |
|
Granted |
| — |
| — |
| — |
| — |
| 77,500 | (3) | 22.30 |
| 70,500 | (2) | 16.99 |
|
| 85,017 | (2) | 24.95 |
| — |
| — |
| ||||||
Vested and issued |
| — |
| — |
| — |
| — |
| (250 | ) | 16.99 |
| — |
| — |
| |||||||||||||||
Vested |
| — |
| — |
| (250 | ) | $ | 16.99 |
| ||||||||||||||||||||||
Forfeited |
| — |
| — |
| — |
| — |
| (1,250 | ) | 16.99 |
| — |
| — |
|
| (1,000 | ) | 22.60 |
| (1,250 | ) | $ | 16.99 |
| |||||
Outstanding, end of period |
| 146,500 |
| $ | 19.80 |
| 70,500 |
| $ | 16.99 |
| 146,500 |
| $ | 19.80 |
| 70,500 |
| $ | 16.99 |
|
| 230,517 |
| $ | 21.69 |
| 69,000 |
| $ | 16.99 |
|
(1) Represents the weighted-averageWeighted-average grant-date fair value per share. The grant date fair value of the deferred shares and restricted stock units was the average price of HEI common stock on the date of grant.
(2) Total weighted-average grant-date fair value of $1.2$2.1 million.
(3)Total weighted-average grant-date fair value of $1.7 million
As of September 30, 2010, 77,500 deferred sharesMarch 31, 2011, 161,517 restricted stock units were outstanding under the EIP and 69,000 restricted stock units were outstanding under the SOIP.
For the nine months ended September 30, 2010, total restricted stock units vested had a fair value of $4,000 and related tax benefits to be realized will be immaterial.
As of September 30, 2010,March 31, 2011, there was $2.0$3.4 million of total unrecognized compensation cost related to the nonvested deferred shares and restricted stock units. The cost is expected to be recognized over a weighted-average period of 3.23.3 years.
LTIP payable in stock. The 2010-20122011-2013 LTIP provides for performance awards under the EIP and the 2009-2011 LTIP and the 2010-2012 LTIP provide for payment inperformance awards under the SOIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions over a three-year performance period. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made based on targetsubject to the achievement of specified performance levels. The payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP containsperformance goals for both LTIP periods include awards with a market conditiongoal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. TheIn addition, the 2009-2011 LTIP has performance condition isgoals based on HEI return on average common equity (ROACE). The and the 2010-2012 LTIP has performance goals with performance conditions includerelated to levels of HEI consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on two-year averages (2011-2012). and the 2011-2013 LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE, HECO 3-year average consolidated net income, ASB return on assets and ASB 3-year average net income.
LTIP linked to TRS. Information about HEI’s LTIP grants linked to TRS is summarized as follows:
|
| Three months ended September 30 |
| Nine months ended September 30 |
|
| 2011 |
| 2010 |
| ||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| |||||||||||||||||||||||
|
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||
Three months ended March 31 |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Outstanding, beginning of period |
| 132,588 |
| $ | 20.42 |
| 36,198 |
| $ | 14.85 |
| 36,198 |
| $ | 14.85 |
| — |
| $ | — |
|
| 126,782 |
| $ | 20.33 |
| 36,198 |
| $ | 14.85 |
|
Granted |
| — |
| — |
| — |
| — |
| 97,191 |
| 22.45 |
| 36,198 | (2) | 14.85 |
|
| 74,540 |
| 35.46 |
| 97,191 | (2) | $ | 22.45 |
| |||||
Vested and issued |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| |||||||||||||||
Vested |
| — |
| — |
| — |
| — |
| |||||||||||||||||||||||
Forfeited |
| (5,806 | ) | $ | 22.45 |
| — |
| — |
| (6,607 | ) | 21.53 |
| — |
| — |
|
| (587 | ) | 22.45 |
| (801 | ) | $ | 14.85 |
| ||||
Outstanding, end of period |
| 126,782 |
| $ | 20.33 |
| 36,198 |
| $ | 14.85 |
| 126,782 |
| $ | 20.33 |
| 36,198 |
| $ | 14.85 |
|
| 200,735 |
| $ | 25.94 |
| 132,588 |
| $ | 20.42 |
|
(1) Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.
(2) Total weighted-average grant-date fair value of $0.5$2.2 million.
On February 8, 2010,4, 2011, LTIP grants (under the 2010-20122011-2013 LTIP) were made with the TRS condition payable with 97,191in 74,540 shares of HEI common stock (based on the grant date price of $18.95$24.95 and target TRS performance levels) with a weighted-average grant date fair value of $2.2$2.6 million based on the weighted-average grant date fair value per share of $22.45.$35.46.
The grant date fair values were determined using a Monte Carlo simulation model utilizing actual information for the common shares of HEI and its peers for the period from the beginning of the performance period to the grant date and estimated future stock volatility and dividends of HEI and its peers over the remaining three-year
performance period. The expected stock volatility assumptions for HEI and its peer group were based on the three-year historic stock volatility, and the annual dividend yield assumptions were based on dividend yields calculated on the basis of daily stock prices over the same three-year historical period. The following table summarizes the assumptions used to determine the fair value of the LTIP linked to TRS and the resulting fair value of LTIP granted:
|
| 2010 |
| 2009 |
|
| 2011 |
| 2010 |
| ||
Risk-free interest rate |
| 1.30% |
| 1.30% |
|
| 1.25% |
| 1.30% |
| ||
Expected life in years |
| 3 |
| 3 |
|
| 3 |
| 3 |
| ||
Expected volatility |
| 27.9% |
| 23.7% |
|
| 27.8 % |
| 27.9 % |
| ||
Dividend yield |
| 6.55% |
| 4.53% |
| |||||||
Range of expected volatility for Peer Group |
| 22.3% to 52.3% |
| 20.8% to 46.9% |
|
| 21.2% to 82.6% |
| 22.3% to 52.3% |
| ||
Grant date fair value (per share) |
| $ | 22.45 |
| $ | 14.85 |
|
| $35.46 |
| $22.45 |
|
As of September 30, 2010,March 31, 2011, there was $1.7$3.4 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 2.01.9 years.
LTIP linked to other performance conditions.Information about HEI’s LTIP grantsawards payable in shares linked to other performance conditions is summarized as follows:
|
| Three months ended September 30 |
| Nine months ended September 30 |
|
| 2011 |
| 2010 |
| ||||||||||||||||||||||
|
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| |||||||||||||||||||||||
|
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||
Three months ended March 31 |
| Shares |
| (1) |
| Shares |
| (1) |
| |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Outstanding, beginning of period |
| 184,535 |
| $ | 18.69 |
| 24,131 |
| $ | 16.99 |
| 24,131 |
| $ | 16.99 |
| — |
| $ | — |
|
| 161,310 |
| $ | 18.66 |
| 24,131 |
| $ | 16.99 |
|
Granted |
| — |
| — |
| — |
| — |
| 160,939 |
| 18.95 |
| 24,131 | (2) | 16.99 |
|
| 113,119 |
| 24.95 |
| 160,939 | (2) | $ | 18.95 |
| |||||
Vested |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| — |
| — |
| — |
| — |
| ||||||
Forfeited |
| (23,225 | ) | $ | 18.95 |
| — |
| — |
| (23,760 | ) | 18.90 |
| — |
| — |
|
| (879 | ) | 18.95 |
| (535 | ) | $ | 16.99 |
| ||||
Outstanding, end of period |
| 161,310 |
| $ | 18.66 |
| 24,131 |
| $ | 16.99 |
| 161,310 |
| $ | 18.66 |
| 24,131 |
| $ | 16.99 |
|
| 273,550 |
| $ | 21.26 |
| 184,535 |
| $ | 18.69 |
|
(1) Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.
(2) Total weighted-average grant-date fair value of $0.4$3.0 million.
On February 8, 2010,4, 2011, LTIP grants (under the 2010-20122011-2013 LTIP) with performance conditions were made payable in 160,939113,119 shares of HEI common stock (based on the grant date price of $18.95$24.95 and target performance levels)levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $3.0$2.8 million based on the weighted-average grant date fair value per share of $18.95.$24.95.
As of September 30, 2010,March 31, 2011, there was $2.6$4.2 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 2.1 years.
7 · Interest rate swap agreements
In June 2010, HEI entered into multiple Forward Starting Swaps (FSS) with notional amounts totaling $125 million to hedge against interest rate fluctuations on a portion of the $150 million of medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to better forecast its future interest expense. In January 2011, HEI settled FSS with notional amounts totaling $50 million and a negative fair value of $1.3 million as of December 31, 2010 for a payment of $1.0 million, which amount less the previously recognized ineffective portion of $0.3 million is being amortized to interest expense over five years beginning March 24, 2011. The remaining $75 million notional amount of FSS terminate in January and June 2011 and entitle HEI to receive/(pay) the present value of the positive/(negative) difference between three-month LIBOR and a fixed rate at termination applied to the notional amount over a five-year period. The outstanding FSS arewere designated and accounted for as cash flow hedges and havehad a negative fair value of $6.2$1.6 million as of September 30,March 24, 2011 and $2.8 million as of December 31, 2010 (recorded in “Other” liabilities on the consolidated balance sheet). Changes in fair value arewere recognized (1) in other comprehensive income to the extent that they are considered effective, and (2) in net income for any portion considered ineffective. The balance in accumulated other comprehensive income/(loss) (AOCI) at the dates
On March 24, 2011, HEI issued $125 million of the anticipated medium-term note issuances will be accreted/amortized into interest expense over the livesSenior Notes via a private placement ($75 million of the new4.41% notes based on the effective interest method. due March 24, 2016 and $50 million of 5.67% notes due March 24, 2021).
For the thirdfirst quarter of 2010,2011, the change in the ineffective portion of the change in fair value of the remaining FSS, or $0.4$0.1 million, ($0.2 million, net of tax benefits), was recorded as a derivative lossgain in “Interest expense—other than on deposit liabilities and other bank borrowings” and the change in the effective portion, or $3.6$0.1 million, net of tax benefits, was recorded as a net lossgain in AOCI. Of the $3.6accumulated other comprehensive income (AOCI). The $1.3 million net loss in AOCI as of March 24, 2011 for the remaining FSS is being amortized to interest expense over five years (similar to the $0.7 million net loss in AOCI for the settled FSS). Further changes in fair value of the remaining FSS will be recorded as a netderivative gain or loss in “interest expense—other than on deposit liabilities and other bank borrowings,” such as the $0.3 million is expectedderivative gain for March 24 to be reclassified to earnings during the next 12 months.
Table of Contents31, 2011.
8 · Earnings per share (EPS)
For the threequarters ended March 31, 2011 and nine months ended September 30, 2010, under the two-class method of computing basic and diluted EPS, distributed earnings were $0.31 and $0.93 per share respectively, and undistributed earningslosses were $0.04$0.01 and $0.02 per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For the three and nine months ended September 30, 2009, under the two-class method of computing basic and diluted EPS, distributed earnings were $0.31 and $0.93 per share, respectively, and undistributed earnings (loss) were $0.06 and $(0.17) per share, respectively, for both unvested restricted stock awards and unrestricted common stock.
As of September 30,March 31, 2011 and 2010, and 2009, the antidilutive effects of SARs (462,000of 414,000 shares and 474,000 shares of HEI common stock) and SARs and NQSOs (743,500 shares of HEI common stock),stock, respectively, for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of diluted EPS.
9 · Commitments and contingencies
See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.
10 · Fair value measurements
Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value
estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.
The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:
Cash and cash equivalents and short term borrowings—other than bank. The carrying amount approximated fair value because of the short maturity of these instruments.
Investment and mortgage-related securities. Fair value was based on observable inputs using market-based valuation techniques.
Loans receivable. For residential real estate loans, fair value is calculated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics.
For other types of loans, fair value is estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.
The fair value of all loans was adjusted to reflect current assessments of loan collectibility.collectability.
Deposit liabilities. The fair value of demand deposits, savings, accounts,negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was
estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.
Other bank borrowings. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.
Long-term debt. Fair value was obtained from a third-party financial services provider or BLOOMBERG PROFESSIONAL service based on the current rates offered for debt of the same or similar remaining maturities.
Forward Starting Swaps. Fair value was estimated by discounting the expected future cash flows of the swaps, using the contractual terms of the swaps, including the period to maturity, and observable market-based inputs, including forward interest rate curves. Fair value incorporates credit valuation adjustments to appropriately reflect nonperformance risk.
Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams are estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. The fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.
The estimated fair values of certain of the Company’s financial instruments were as follows:
|
| September 30, 2010 |
| December 31, 2009 |
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||||||
(in thousands) |
| Carrying or |
| Estimated |
| Carrying or |
| Estimated |
|
| Carrying or |
| Estimated |
| Carrying or |
| Estimated |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Financial assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Cash and cash equivalents |
| $ | 387,488 |
| $ | 387,488 |
| $ | 503,922 |
| $ | 503,922 |
| |||||||||||||
Cash and cash equivalents, excluding money market accounts |
| $ | 314,279 |
| $ | 314,279 |
| $ | 329,553 |
| $ | 329,553 |
| |||||||||||||
Money market accounts |
| 1,975 |
| 1,975 |
| 1,098 |
| 1,098 |
| |||||||||||||||||
Available-for-sale investment and mortgage-related securities |
| 570,262 |
| 570,262 |
| 432,881 |
| 432,881 |
|
| 670,949 |
| 670,949 |
| 678,152 |
| 678,152 |
| ||||||||
Investment in stock of Federal Home Loan Bank of Seattle |
| 97,764 |
| 97,764 |
| 97,764 |
| 97,764 |
|
| 97,764 |
| 97,764 |
| 97,764 |
| 97,764 |
| ||||||||
Loans receivable, net |
| 3,466,550 |
| 3,603,254 |
| 3,670,493 |
| 3,760,954 |
|
| 3,554,058 |
| 3,678,043 |
| 3,497,729 |
| 3,639,983 |
| ||||||||
Financial liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Deposit liabilities |
| 3,958,636 |
| 3,967,738 |
| 4,058,760 |
| 4,063,888 |
|
| 4,035,255 |
| 4,037,308 |
| 3,975,372 |
| 3,979,027 |
| ||||||||
Short-term borrowings—other than bank |
| 27,296 |
| 27,296 |
| 41,989 |
| 41,989 |
|
| — |
| — |
| 24,923 |
| 24,923 |
| ||||||||
Other bank borrowings |
| 246,571 |
| 265,565 |
| 297,628 |
| 307,154 |
|
| 244,674 |
| 257,362 |
| 237,319 |
| 251,822 |
| ||||||||
Long-term debt, net—other than bank |
| 1,364,911 |
| 1,403,063 |
| 1,364,815 |
| 1,336,250 |
|
| 1,439,974 |
| 1,373,642 |
| 1,364,942 |
| 1,345,770 |
| ||||||||
Forward Starting Swaps |
| 6,223 |
| 6,223 |
| — |
| — |
| |||||||||||||||||
Forward starting swaps |
| 1,317 |
| 1,317 |
| 2,762 |
| 2,762 |
| |||||||||||||||||
Off-balance sheet items |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
HECO-obligated preferred securities of trust subsidiary |
| 50,000 |
| 50,340 |
| 50,000 |
| 48,480 |
|
| 50,000 |
| 50,800 |
| 50,000 |
| 52,500 |
|
As of September 30, 2010March 31, 2011 and December 31, 2009,2010, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.2 billion and their estimated fair valuesvalue on such dates were $0.5$0.3 million and $0.2$0.4 million, respectively. As of September 30, 2010March 31, 2011 and December 31, 2009,2010, loans serviced by ASB for others had notional amounts of $762.6$838 million and $577.5$818 million and the estimated fair value of the servicing rights for such loans was $7.8$9.8 million and $5.6$8.8 million, respectively.
Bank and “other” segments
Fair value measurements on a recurring basis.basis. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods as has been the case during the currentrecent market disruption. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would
use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.
Assets measured at fair value on a recurring basis were as follows:
| ||||||||||
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| ||||||||
|
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| ||||||||
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|
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| |||||||
| ||||||||||
| ||||||||||
|
|
|
|
|
|
| ||||
|
|
|
| |||||||
|
|
|
| |||||||
|
|
|
|
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| |||||
|
|
|
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| |||
| ||||||||||
| ||||||||||
|
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| ||||
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| |||||||
|
|
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| |||||||
|
|
|
|
|
|
|
| Fair value measurements using |
| |||||||
|
| Quoted prices in |
| Significant other |
| Significant |
| |||
|
| active markets |
| observable |
| unobservable |
| |||
(in thousands) |
| assets (Level 1) |
| (Level 2) |
| (Level 3) |
| |||
March 31, 2011 |
|
|
|
|
|
|
| |||
Money market accounts (“other” segment) |
| $ | — |
| $ | 1,975 |
| $ | — |
|
Available-for-sale securities (bank segment) |
|
|
|
|
|
|
| |||
Mortgage-related securities-FNMA, FHLMC and GNMA |
| $ | — |
| $ | 342,604 |
| $ | — |
|
Federal agency obligations |
| — |
| 285,322 |
| — |
| |||
Municipal bonds |
| — |
| 43,023 |
| — |
| |||
|
| $ | — |
| $ | 670,949 |
| $ | — |
|
Forward starting swaps (“other” segment) |
| $ | — |
| $ | (1,317 | ) | $ | — |
|
December 31, 2010 |
|
|
|
|
|
|
| |||
Money market accounts (“other” segment) |
| $ | — |
| $ | 1,098 |
| $ | — |
|
Available-for-sale securities (bank segment) |
|
|
|
|
|
|
| |||
Mortgage-related securities-FNMA, FHLMC and GNMA |
| $ | — |
| $ | 319,970 |
| $ | — |
|
Federal agency obligations |
| — |
| 315,896 |
| — |
| |||
Municipal bonds |
| — |
| 42,286 |
| — |
| |||
|
| $ | — |
| $ | 678,152 |
| $ | — |
|
Forward starting swaps (“other” segment) |
| $ | — |
| $ | (2,762 | ) | $ | — |
|
Fair value measurements on a nonrecurring basis.From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with U.S. GAAP. These adjustments to fair value usually result from the application of lower-of-cost-or-market accounting or write-downs of individual assets. AsASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments to loans to reflect specific reserves on loans based on the current appraised value of the collateral or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. Specific reserves as of March 31, 2011 and December 31, 2009,2010 were $4.6 million and $3.5 million, respectively, and were included in loans receivable held for investment, net. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. During the first quarters of 2011 and 2010, goodwill was not measured at fair value. For the first quarters of 2011 and 2010, there were no adjustments to fair value for assets measured at fair value on a nonrecurring basis in accordance with U.S.GAAP other than the specific reserves on loans receivable held for investment.
From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. In the second and third quartersThe fair value of 2010, HECO’s asset retirement obligationobligations (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted (seeby HECO’s credit spread (also see Note 8, “Fair value measurements” of HECO “Notes to Consolidated Financial Statements” below)3).
11 · Cash flows
Supplemental disclosures of cash flow information. For the nine monthsquarters ended September 30,March 31, 2011 and 2010, and 2009, the Company paid interest (net of amounts capitalized and including bank interest) to non-affiliates amounting to $69$23 million and $75$24 million, respectively.
For the nine monthsquarters ended September 30,March 31, 2011 and 2010, and 2009, the Company paidpaid/(received) income taxes amounting to $44$(30) million and $14$8 million, respectively. The increaseIncome taxes were received in income taxes paid was2011 primarily due to higher operating income in 2010 andthe refunding of estimated tax payments made through September 2010 withoutprior to the retroactive effectextension of 2010 bonus depreciation (which was enacted after the payment of September 2010 estimated taxes).provisions.
Supplemental disclosures of noncash activities. Noncash increases in common stock for director and officer compensatory plans of the Company were $2.9 million and $1.5 million for the nine months ended September 30, 2010and 2009, respectively.
Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $17$6 million for each of the quarters ended March 31, 2011 and 2010.
Noncash increases in common stock for director and officer compensatory plans of the Company were $4.2 million and $11$0.9 million for the first nine months ofquarters ended March 31, 2011 and 2010, and 2009, respectively. HEI satisfied the requirements of the HEI DRIP and the HEIRSP (from April 16, 2009 through September 3, 2009) and the ASB 401(k) Plan (from May 7, 2009 through September 3, 2009) by acquiring for cash its common shares through open market purchases rather than by issuing additional shares. Effective September 4, 2009, HEI resumed satisfying the requirements of the HEI DRIP, HEIRSP and ASB 401(k) Plan through the issuance of additional shares of common stock.
Real estate acquired in settlement of loans in noncash transactions amounted to $4$3 million in each ofand $2 million for the first nine months ofquarters ended March 31, 2011 and 2010, and 2009.
Table of Contentsrespectively.
12 · Recent accounting pronouncements and interpretations
Variable interest entities. Troubled debt restructuring (TDR).In June 2009,April 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-2, “A Creditor’s Determination of Whether a standard that amends the guidanceRestructuring Is a Troubled Debt Restructuring,” which clarifies which loan modifications constitute TDRs and is intended to assist creditors in ASC Topic 810 related to the consolidation of variable interest entities (VIEs). The standard eliminates exceptions to consolidating qualifying special-purpose entities (QSPEs), contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company ismodification of the primary beneficiaryterms of a VIE. It also clarifies, but does not significantly change,receivable meets the characteristicscriteria to be considered a TDR, both for purposes of recording an impairment loss and for disclosure of TDRs. In evaluating whether a restructuring constitutes a TDR, a creditor must separately conclude that identifyboth (a) the restructuring constitutes a VIE. concession by the creditor; and (b) the debtor is experiencing financial difficulties. Clarifying guidance is provided on a creditor’s evaluation of whether it has granted a concession and whether a debtor is experiencing financial difficulties.
The Company adoptedwill adopt this standard in the firstthird quarter of 20102011 and does not expect the adoption did not impact the Company’s or HECO’s consolidated financial condition, results of operations or liquidity.
Allowance for Credit Losses. In July 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-20, “Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses,” which will require the Company to providehave a greater level of disaggregated information about the credit quality of the Company’s loans and leases and the Allowance for Loan and Lease Losses (the Allowance). This ASU will also require the Company to disclose additional information related to credit quality indicators, nonaccrual and past due information, and information related to impaired loans and loans modified in a troubled debt restructuring. The provisions of this ASU are effective for the Company’s reporting period ending December 31, 2010. As this ASU amends only the disclosure requirements for loans and leases and the Allowance, the adoption will have nomaterial impact on the Company’s consolidated statementsresults of income and balance sheet.operations, financial condition or liquidity.
13 · Credit agreement
Effective May 7, 2010, HEI entered into a revolving unsecurednoncollateralized credit agreement establishing a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on May 7, 2013, with a syndicate of eight financial institutions. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 225 basis points or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 100 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 40 basis points. The agreement contains provisions for revised pricing in the event of a ratings change. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have broad “material adverse change” clauses. However, the agreement does contain customary conditions which must be met in order to draw on it, including compliance with its covenants.
HEI’s $125 million credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes. HEI’s $100 million syndicated credit facility expiring March 31, 2011 was terminated concurrently with the effectiveness of this new$125 million syndicated credit facility.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Income (unaudited)
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||||||||
(in thousands) |
|
|
|
|
| |||||||||||||||
|
| Three months ended |
| Nine months ended |
|
|
|
|
|
| ||||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| |||||||||||
Operating revenues |
| $ | 622,223 |
| $ | 546,502 |
| $ | 1,751,029 |
| $ | 1,453,623 |
|
| $ | 644,301 |
| $ | 546,712 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Fuel oil |
| 235,534 |
| 186,719 |
| 662,608 |
| 463,893 |
|
| 260,860 |
| 211,752 |
| ||||||
Purchased power |
| 147,880 |
| 134,447 |
| 404,175 |
| 364,120 |
|
| 147,958 |
| 116,782 |
| ||||||
Other operation |
| 62,665 |
| 61,173 |
| 182,163 |
| 186,751 |
|
| 65,531 |
| 59,244 |
| ||||||
Maintenance |
| 30,618 |
| 25,968 |
| 89,894 |
| 81,562 |
|
| 29,196 |
| 27,053 |
| ||||||
Depreciation |
| 36,277 |
| 35,557 |
| 113,568 |
| 108,406 |
|
| 36,432 |
| 38,642 |
| ||||||
Taxes, other than income taxes |
| 58,317 |
| 50,031 |
| 164,278 |
| 137,741 |
|
| 59,995 |
| 51,791 |
| ||||||
Income taxes |
| 14,818 |
| 15,957 |
| 36,972 |
| 33,228 |
|
| 11,610 |
| 11,041 |
| ||||||
|
| 586,109 |
| 509,852 |
| 1,653,658 |
| 1,375,701 |
|
| 611,582 |
| 516,305 |
| ||||||
Operating income |
| 36,114 |
| 36,650 |
| 97,371 |
| 77,922 |
|
| 32,719 |
| 30,407 |
| ||||||
Other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Allowance for equity funds used during construction |
| 1,197 |
| 2,628 |
| 4,817 |
| 10,353 |
|
| 1,244 |
| 1,773 |
| ||||||
Other, net |
| 510 |
| 1,657 |
| 2,123 |
| 6,493 |
|
| 910 |
| 1,241 |
| ||||||
|
| 1,707 |
| 4,285 |
| 6,940 |
| 16,846 |
|
| 2,154 |
| 3,014 |
| ||||||
Interest and other charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Interest on long-term debt |
| 14,383 |
| 13,601 |
| 43,149 |
| 37,458 |
|
| 14,383 |
| 14,383 |
| ||||||
Amortization of net bond premium and expense |
| 799 |
| 735 |
| 2,192 |
| 2,092 |
|
| 783 |
| 667 |
| ||||||
Other interest charges |
| 653 |
| 705 |
| 1,861 |
| 2,048 |
|
| 539 |
| 599 |
| ||||||
Allowance for borrowed funds used during construction |
| (492 | ) | (1,118 | ) | (2,061 | ) | (4,467 | ) |
| (520 | ) | (779 | ) | ||||||
|
| 15,343 |
| 13,923 |
| 45,141 |
| 37,131 |
|
| 15,185 |
| 14,870 |
| ||||||
Net income |
| 22,478 |
| 27,012 |
| 59,170 |
| 57,637 |
|
| 19,688 |
| 18,551 |
| ||||||
Preferred stock dividends of subsidiaries |
| 228 |
| 228 |
| 686 |
| 686 |
|
| 229 |
| 229 |
| ||||||
Net income attributable to HECO |
| 22,250 |
| 26,784 |
| 58,484 |
| 56,951 |
|
| 19,459 |
| 18,322 |
| ||||||
Preferred stock dividends of HECO |
| 270 |
| 270 |
| 810 |
| 810 |
|
| 270 |
| 270 |
| ||||||
Net income for common stock |
| $ | 21,980 |
| $ | 26,514 |
| $ | 57,674 |
| $ | 56,141 |
|
| $ | 19,189 |
| $ | 18,052 |
|
HEI owns all of the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.
SeeThe accompanying “Notes to Consolidated Financial Statements”notes for HECO.HECO are an integral part of these consolidated financial statements.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Balance Sheets (unaudited)
(dollars in thousands, except par value) |
| September 30, |
| December 31, |
|
| March 31, |
| December 31, |
| ||||
Assets |
|
|
|
|
|
|
|
|
|
| ||||
Utility plant, at cost |
|
|
|
|
|
|
|
|
|
| ||||
Land |
| $ | 51,371 |
| $ | 52,530 |
|
| $ | 51,440 |
| $ | 51,364 |
|
Plant and equipment |
| 4,832,409 |
| 4,696,257 |
|
| 4,909,393 |
| 4,896,974 |
| ||||
Less accumulated depreciation |
| (1,915,263 | ) | (1,848,416 | ) |
| (1,946,072 | ) | (1,941,059 | ) | ||||
Construction in progress |
| 105,492 |
| 132,980 |
|
| 104,300 |
| 101,562 |
| ||||
Net utility plant |
| 3,074,009 |
| 3,033,351 |
|
| 3,119,061 |
| 3,108,841 |
| ||||
Current assets |
|
|
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents |
| 35,044 |
| 73,578 |
|
| 45,354 |
| 122,936 |
| ||||
Customer accounts receivable, net |
| 141,678 |
| 133,286 |
|
| 149,486 |
| 138,171 |
| ||||
Accrued unbilled revenues, net |
| 95,866 |
| 84,276 |
|
| 113,786 |
| 104,384 |
| ||||
Other accounts receivable, net |
| 6,841 |
| 8,449 |
|
| 9,332 |
| 9,376 |
| ||||
Fuel oil stock, at average cost |
| 121,230 |
| 78,661 |
|
| 156,218 |
| 152,705 |
| ||||
Materials and supplies, at average cost |
| 36,293 |
| 35,908 |
|
| 37,782 |
| 36,717 |
| ||||
Prepayments and other |
| 82,089 |
| 16,201 |
|
| 18,931 |
| 55,216 |
| ||||
Regulatory assets |
| 8,320 |
| 7,349 |
| |||||||||
Total current assets |
| 519,041 |
| 430,359 |
|
| 539,209 |
| 626,854 |
| ||||
Other long-term assets |
|
|
|
|
|
|
|
|
|
| ||||
Regulatory assets |
| 422,177 |
| 426,862 |
|
| 473,492 |
| 470,981 |
| ||||
Unamortized debt expense |
| 14,435 |
| 14,288 |
|
| 13,583 |
| 14,030 |
| ||||
Other |
| 59,666 |
| 73,532 |
|
| 66,215 |
| 64,974 |
| ||||
Total other long-term assets |
| 496,278 |
| 514,682 |
|
| 553,290 |
| 549,985 |
| ||||
|
| $ | 4,089,328 |
| $ | 3,978,392 |
| |||||||
Total assets |
| $ | 4,211,560 |
| $ | 4,285,680 |
| |||||||
Capitalization and liabilities |
|
|
|
|
|
|
|
|
|
| ||||
Capitalization |
|
|
|
|
|
|
|
|
|
| ||||
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 13,786,959 shares) |
| $ | 91,931 |
| $ | 91,931 |
| |||||||
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 13,830,823 shares) |
| $ | 92,224 |
| $ | 92,224 |
| |||||||
Premium on capital stock |
| 385,650 |
| 385,659 |
|
| 389,609 |
| 389,609 |
| ||||
Retained earnings |
| 846,350 |
| 827,036 |
|
| 856,405 |
| 854,856 |
| ||||
Accumulated other comprehensive income, net of income taxes |
| 1,961 |
| 1,782 |
|
| 736 |
| 709 |
| ||||
Common stock equity |
| 1,325,892 |
| 1,306,408 |
|
| 1,338,974 |
| 1,337,398 |
| ||||
Cumulative preferred stock — not subject to mandatory redemption |
| 34,293 |
| 34,293 |
|
| 34,293 |
| 34,293 |
| ||||
Long-term debt, net |
| 1,057,911 |
| 1,057,815 |
|
| 1,057,974 |
| 1,057,942 |
| ||||
Total capitalization |
| 2,418,096 |
| 2,398,516 |
|
| 2,431,241 |
| 2,429,633 |
| ||||
Current liabilities |
|
|
|
|
|
|
|
|
|
| ||||
Accounts payable |
| 116,710 |
| 132,711 |
|
| 137,956 |
| 178,959 |
| ||||
Interest and preferred dividends payable |
| 22,461 |
| 21,223 |
|
| 20,476 |
| 20,603 |
| ||||
Taxes accrued |
| 150,352 |
| 156,092 |
|
| 146,136 |
| 175,960 |
| ||||
Other |
| 52,099 |
| 48,192 |
|
| 50,078 |
| 56,354 |
| ||||
Total current liabilities |
| 341,622 |
| 358,218 |
|
| 354,646 |
| 431,876 |
| ||||
Deferred credits and other liabilities |
|
|
|
|
|
|
|
|
|
| ||||
Deferred income taxes |
| 244,455 |
| 180,603 |
|
| 281,422 |
| 269,286 |
| ||||
Regulatory liabilities |
| 289,568 |
| 288,214 |
|
| 304,375 |
| 296,797 |
| ||||
Unamortized tax credits |
| 58,083 |
| 56,870 |
|
| 59,454 |
| 58,810 |
| ||||
Retirement benefits liability |
| 293,069 |
| 296,623 |
|
| 333,518 |
| 355,844 |
| ||||
Other |
| 113,030 |
| 77,804 |
|
| 108,834 |
| 108,070 |
| ||||
Total deferred credits and other liabilities |
| 998,205 |
| 900,114 |
|
| 1,087,603 |
| 1,088,807 |
| ||||
Contributions in aid of construction |
| 331,405 |
| 321,544 |
|
| 338,070 |
| 335,364 |
| ||||
|
| $ | 4,089,328 |
| $ | 3,978,392 |
| |||||||
Total capitalization and liabilities |
| $ | 4,211,560 |
| $ | 4,285,680 |
|
SeeThe accompanying “Notes to Consolidated Financial Statements”notes for HECO.HECO are an integral part of these consolidated financial statements.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Changes in Common Stock Equity (unaudited)
|
| Common stock |
| Premium |
| Retained |
| Accumulated |
|
|
|
| Common stock |
| Premium |
| Retained |
| Accumulated |
|
|
| ||||||||||||||
(in thousands) |
| Shares |
| Amount |
| stock |
| earnings |
| income (loss) |
| Total |
|
| Shares |
| Amount |
| stock |
| earnings |
| income (loss) |
| Total |
| ||||||||||
Balance, December 31, 2009 |
| 13,787 |
| $ | 91,931 |
| $ | 385,659 |
| $ | 827,036 |
| $ | 1,782 |
| $ | 1,306,408 |
| ||||||||||||||||||
Balance, December 31, 2010 |
| 13,831 |
| $ | 92,224 |
| $ | 389,609 |
| $ | 854,856 |
| $ | 709 |
| $ | 1,337,398 |
| ||||||||||||||||||
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Net income for common stock |
| — |
| — |
| — |
| 57,674 |
| — |
| 57,674 |
|
| — |
| — |
| — |
| 19,189 |
| — |
| 19,189 |
| ||||||||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $1,796 |
| — |
| — |
| — |
| — |
| 2,819 |
| 2,819 |
| |||||||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $1,681 |
| — |
| — |
| — |
| — |
| (2,640 | ) | (2,640 | ) | |||||||||||||||||||||||
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $1,448 |
| — |
| — |
| — |
| — |
| 2,274 |
| 2,274 |
| |||||||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $1,431 |
| — |
| — |
| — |
| — |
| (2,247 | ) | (2,247 | ) | |||||||||||||||||||||||
Other comprehensive income |
|
|
|
|
|
|
|
|
| 27 |
|
|
| |||||||||||||||||||||||
Comprehensive income |
| — |
| — |
| — |
| 57,674 |
| 179 |
| 57,853 |
|
|
|
|
|
|
|
|
|
|
|
| 19,216 |
| ||||||||||
Common stock dividends |
| — |
| — |
| — |
| (38,360 | ) | — |
| (38,360 | ) |
| — |
| — |
| — |
| (17,640 | ) | — |
| (17,640 | ) | ||||||||||
Common stock issue expenses |
| — |
| — |
| (9 | ) | — |
| — |
| (9 | ) |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||||||
Balance, September 30, 2010 |
| 13,787 |
| $ | 91,931 |
| $ | 385,650 |
| $ | 846,350 |
| $ | 1,961 |
| $ | 1,325,892 |
| ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Balance, December 31, 2008 |
| 12,806 |
| $ | 85,387 |
| $ | 299,214 |
| $ | 802,590 |
| $ | 1,651 |
| $ | 1,188,842 |
| ||||||||||||||||||
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Balance, March 31, 2011 |
| 13,831 |
| $ | 92,224 |
| $ | 389,609 |
| $ | 856,405 |
| $ | 736 |
| $ | 1,338,974 |
| ||||||||||||||||||
Balance, December 31, 2009 |
| 13,787 |
| $ | 91,931 |
| $ | 385,659 |
| $ | 827,036 |
| $ | 1,782 |
| $ | 1,306,408 |
| ||||||||||||||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||
Net income for common stock |
| — |
| — |
| — |
| 56,141 |
| — |
| 56,141 |
|
| — |
| — |
| — |
| 18,052 |
| — |
| 18,052 |
| ||||||||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes of $5,101 |
| — |
| — |
| — |
| — |
| 8,008 |
| 8,008 |
| |||||||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $4,990 |
| — |
| — |
| — |
| — |
| (7,835 | ) | (7,835 | ) | |||||||||||||||||||||||
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $563 |
| — |
| — |
| — |
| — |
| 882 |
| 882 |
| |||||||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $526 |
| — |
| — |
| — |
| — |
| (825 | ) | (825 | ) | |||||||||||||||||||||||
Other comprehensive income |
|
|
|
|
|
|
|
|
| 57 |
|
|
| |||||||||||||||||||||||
Comprehensive income |
| — |
| — |
| — |
| 56,141 |
| 173 |
| 56,314 |
|
|
|
|
|
|
|
|
|
|
|
| 18,109 |
| ||||||||||
Common stock dividends |
| — |
| — |
| — |
| (15,150 | ) | — |
| (15,150 | ) | |||||||||||||||||||||||
Common stock issue expenses |
| — |
| — |
| (7 | ) | — |
| — |
| (7 | ) |
| — |
| — |
| (1 | ) | — |
| — |
| (1 | ) | ||||||||||
Common stock dividends |
| — |
| — |
| — |
| (32,756 | ) | — |
| (32,756 | ) | |||||||||||||||||||||||
Balance, September 30, 2009 |
| 12,806 |
| $ | 85,387 |
| $ | 299,207 |
| $ | 825,975 |
| $ | 1,824 |
| $ | 1,212,393 |
| ||||||||||||||||||
Balance, March 31, 2010 |
| 13,787 |
| $ | 91,931 |
| $ | 385,658 |
| $ | 829,938 |
| $ | 1,839 |
| $ | 1,309,366 |
|
SeeThe accompanying “Notes to Consolidated Financial Statements”notes for HECO.HECO are an integral part of these consolidated financial statements.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (unaudited)
Nine months ended September 30 |
| 2010 |
| 2009 |
| |||||||||
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||
(in thousands) |
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
| |||||||||
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
| ||||
Net income |
| $ | 59,170 |
| $ | 57,637 |
|
| $ | 19,688 |
| $ | 18,551 |
|
Adjustments to reconcile net income to net cash provided by operating activities |
|
|
|
|
| |||||||||
Adjustments to reconcile net income to net cash used in operating activities |
|
|
|
|
| |||||||||
Depreciation of property, plant and equipment |
| 113,568 |
| 108,406 |
|
| 36,432 |
| 38,642 |
| ||||
Other amortization |
| 5,360 |
| 7,702 |
|
| 2,288 |
| 2,097 |
| ||||
Changes in deferred income taxes |
| 74,720 |
| 12,532 |
|
| 13,521 |
| (1,834 | ) | ||||
Changes in tax credits, net |
| 1,939 |
| (501 | ) |
| 755 |
| 776 |
| ||||
Allowance for equity funds used during construction |
| (4,817 | ) | (10,353 | ) |
| (1,244 | ) | (1,773 | ) | ||||
Increase in cash overdraft |
| 884 |
| — |
| |||||||||
Increase (decrease) in cash overdraft |
| (2,688 | ) | 681 |
| |||||||||
Changes in assets and liabilities |
|
|
|
|
|
|
|
|
|
| ||||
Decrease (increase) in accounts receivable |
| (6,784 | ) | 32,423 |
|
| (11,271 | ) | 7,328 |
| ||||
Decrease (increase) in accrued unbilled revenues |
| (11,590 | ) | 14,183 |
| |||||||||
Decrease (increase) in fuel oil stock |
| (42,569 | ) | 9,826 |
| |||||||||
Increase in accrued unbilled revenues |
| (9,402 | ) | (486 | ) | |||||||||
Increase in fuel oil stock |
| (3,513 | ) | (26,506 | ) | |||||||||
Increase in materials and supplies |
| (385 | ) | (1,825 | ) |
| (1,065 | ) | (1,248 | ) | ||||
Increase in regulatory assets |
| (3,269 | ) | (13,829 | ) |
| (7,872 | ) | (1,143 | ) | ||||
Decrease in accounts payable |
| (16,001 | ) | (4,952 | ) | |||||||||
Changes in prepaid and accrued income and utility revenue taxes |
| (55,202 | ) | (62,388 | ) | |||||||||
Increase (decrease) in accounts payable |
| (42,123 | ) | 3,175 |
| |||||||||
Changes in prepaid and accrued income taxes and utility revenue taxes |
| 240 |
| (51,243 | ) | |||||||||
Changes in other assets and liabilities |
| 1,415 |
| 3,360 |
|
| (21,378 | ) | 3,276 |
| ||||
Net cash provided by operating activities |
| 116,439 |
| 152,221 |
| |||||||||
Net cash used in operating activities |
| (27,632 | ) | (9,707 | ) | |||||||||
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
| ||||
Capital expenditures |
| (131,140 | ) | (237,664 | ) |
| (37,556 | ) | (34,189 | ) | ||||
Contributions in aid of construction |
| 16,775 |
| 7,472 |
|
| 5,749 |
| 3,729 |
| ||||
Other |
| 657 |
| 340 |
| |||||||||
Net cash used in investing activities |
| (113,708 | ) | (229,852 | ) |
| (31,807 | ) | (30,460 | ) | ||||
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
| ||||
Common stock dividends |
| (38,360 | ) | (32,756 | ) |
| (17,640 | ) | (15,150 | ) | ||||
Preferred stock dividends of HECO and subsidiaries |
| (1,496 | ) | (1,496 | ) |
| (499 | ) | (499 | ) | ||||
Proceeds from issuance of long-term debt |
| — |
| 153,186 |
| |||||||||
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |
| — |
| (30,850 | ) | |||||||||
Decrease in cash overdraft |
| — |
| (9,847 | ) | |||||||||
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |
| — |
| 13,748 |
| |||||||||
Other |
| (1,409 | ) | (1,021 | ) |
| (4 | ) | — |
| ||||
Net cash provided by (used in) financing activities |
| (41,265 | ) | 77,216 |
| |||||||||
Net cash used in financing activities |
| (18,143 | ) | (1,901 | ) | |||||||||
Net decrease in cash and cash equivalents |
| (38,534 | ) | (415 | ) |
| (77,582 | ) | (42,068 | ) | ||||
Cash and cash equivalents, beginning of period |
| 73,578 |
| 6,901 |
|
| 122,936 |
| 73,578 |
| ||||
Cash and cash equivalents, end of period |
| $ | 35,044 |
| $ | 6,486 |
|
| $ | 45,354 |
| $ | 31,510 |
|
SeeThe accompanying “Notes to Consolidated Financial Statements”notes for HECO.HECO are an integral part of these consolidated financial statements.
Hawaiian Electric Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1 · Basis of presentation
The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2009 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Reports on SEC Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010.
In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of September 30, 2010March 31, 2011 and December 31, 20092010 and the results of their operations for the three and nine months ended September 30, 2010 and 2009 and their cash flows for the ninethree months ended September 30, 2010March 31, 2011 and 2009.2010. All such adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.
2 · Unconsolidated variable interest entities
HECO Capital Trust III. HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by each of Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) each in the respective principal amountsamount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of VIEs. Trust III’s balance sheets as of September 30, 2010March 31, 2011 and December 31, 20092010 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for the ninethree months ended September 30,March 31, 2011 and 2010 and 2009 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.
Power purchase agreements (PPAs). agreements.As of September 30, 2010,March 31, 2011, HECO and its subsidiaries had six PPAs totaling 540 megawatts (MW) of firm capacity and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 91% of the 540 MW of firm capacity is underpursuant to 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 nine monthsquarter ended September 30, 2010March 31, 2011 totaled $404$148 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $106$35 million, $162$62 million, $43$14 million and $33$13 million, respectively.
Some of the IPPs have provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (e.g., HPOWER), and thus excluded from the scope of accounting standards for VIEs. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.
An enterprise with an interest in a VIE or potential VIE created before December 31, 2003 and not thereafter materially modified is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information, but have been unsuccessful to date as it was not a contractual requirement prior to 2004. If the requested information is ultimately received from these IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and the potential recognition of losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.
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. However, HECO and its subsidiaries’ revenue tax payments to the taxing authorities are based on the prior year’s revenues. For the ninethree months ended September 30,March 31, 2011 and 2010, and 2009, HECO and its subsidiaries included approximately $156$57 million and $130$49 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.
4 · Retirement benefits
Defined benefit plans. For the first nine monthsquarter of 2010,2011, HECO and its subsidiaries contributed $23.8$31 million to their retirement benefit plans, compared to $19.9$8 million in the first nine monthsquarter of 2009.2010. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 20102011 is $31$63 million, compared to contributions of $24$31 million in 2009.2010. In addition, HECO and its subsidiaries expect to pay directly $1.4$2 million of benefits in 2010,2011, compared to $0.5$1 million paid in 2009.
Table of Contents2010.
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 |
| 2011 |
| 2010 |
| 2011 |
| 2010 |
| |||||||||||||||||||||||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
|
|
|
|
|
|
|
|
|
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||
Service cost |
| $ | 7,097 |
| $ | 6,205 |
| $ | 1,206 |
| $ | 1,385 |
| $ | 20,479 |
| $ | 18,372 |
| $ | 3,425 |
| $ | 3,549 |
|
| $ | 8,565 |
| $ | 6,610 |
| $ | 1,223 |
| $ | 1,088 |
|
Interest cost |
| 14,816 |
| 14,005 |
| 2,500 |
| 2,594 |
| 44,053 |
| 42,089 |
| 7,667 |
| 8,114 |
|
| 14,849 |
| 14,579 |
| 2,384 |
| 2,596 |
| ||||||||||||
Expected return on plan assets |
| (15,408 | ) | (12,735 | ) | (2,759 | ) | (2,204 | ) | (46,085 | ) | (38,101 | ) | (8,202 | ) | (6,565 | ) |
| (15,284 | ) | (15,324 | ) | (2,608 | ) | (2,715 | ) | ||||||||||||
Amortization of unrecognized transition obligation |
| — |
| — |
| (2 | ) | 259 |
| — |
| — |
| (6 | ) | 1,824 |
| |||||||||||||||||||||
Amortization of prior service cost (credit) |
| (186 | ) | (190 | ) | (86 | ) | (37 | ) | (560 | ) | (558 | ) | (197 | ) | (37 | ) | |||||||||||||||||||||
Recognized actuarial loss (gain) |
| 1,925 |
| 3,677 |
| (2 | ) | 79 |
| 5,377 |
| 11,021 |
| 2 |
| 296 |
| |||||||||||||||||||||
Amortization of net transition obligation |
| — |
| — |
| (2 | ) | (2 | ) | |||||||||||||||||||||||||||||
Amortization of net prior service cost (gain) |
| (187 | ) | (187 | ) | (227 | ) | (55 | ) | |||||||||||||||||||||||||||||
Amortization of net actuarial loss (gain) |
| 4,120 |
| 1,685 |
| 18 |
| 3 |
| |||||||||||||||||||||||||||||
Net periodic benefit cost |
| 8,244 |
| 10,962 |
| 857 |
| 2,076 |
| 23,264 |
| 32,823 |
| 2,689 |
| 7,181 |
|
| 12,063 |
| 7,363 |
| 788 |
| 915 |
| ||||||||||||
Impact of PUC D&Os |
| 2,574 |
| (1,776 | ) | 1,512 |
| (270 | ) | 7,602 |
| (9,974 | ) | 4,133 |
| (1,002 | ) |
| (1,544 | ) | 3,008 |
| 1,018 |
| 1,288 |
| ||||||||||||
Net periodic benefit cost (adjusted for impact of PUC D&Os) |
| $ | 10,818 |
| $ | 9,186 |
| $ | 2,369 |
| $ | 1,806 |
| $ | 30,866 |
| $ | 22,849 |
| $ | 6,822 |
| $ | 6,179 |
|
| $ | 10,519 |
| $ | 10,371 |
| $ | 1,806 |
| $ | 2,203 |
|
HECO and its subsidiaries recorded retirement benefits expense of $29$9 million and $22$10 million for the first nine monthsquarters of 20102011 and 2009,2010, respectively. The electric utilities charged a portion of the net periodic benefit cost to plant.
On March 11, 2011, the utilities’ union members ratified a new benefit agreement (see Note 5), which includes changes to retirement benefits for employees. Changes to retirement benefits for all employees commencing employment on or after May 1, 2011 include a reduction of benefits provided through the defined benefit plan and the addition of a 50% match by the applicable utility on the first 6% of employee deferrals to the defined contribution plan. In the third quarter 2010, MECO eliminated the electric discount benefit which will generate nominal credits through other benefit costs over the next few years as the total negative amendment credit is amortized.addition, new eligibility rules and contribution levels applicable to existing and new employees were adopted for postretirement welfare benefits.
5 · Commitments and contingencies
Hawaii Clean Energy Initiative. In January 2008, the State of Hawaii (State) and the U.S. Department of Energy (DOE) signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an Energy Agreementagreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement require approval of the PUC.
Among the major provisions of the Energy Agreement are the following: (a) pursuing an overall goala Renewable Portfolio standard of providing 70% of Hawaii’s electricity and ground transportation energy needs from clean energy sources40% by 2030; (b) establishing a surcharge to recover costs strandedpursuing an Energy Efficiency Portfolio standard of 30% by clean energy initiatives and to expedite cost recovery for infrastructure that supports greater use of renewable energy or grid efficiency;2030; (c) developing a feed-in tariff (FIT) system with standardized purchase prices for renewable energy; (d) replacing system-wide caps on net energy metering (NEM) with per circuit thresholds that require a further study before a proposed interconnection that would take the circuit over the threshold may proceed; (e) adopting a regulatory rate-making model under which the utilities’ revenues would be decoupled from KWHkilowatthour (KWH) sales; (f) continuing the existing energy cost adjustment clauses (ECACs),ECACs, subject to periodic review by the PUC; (g) establishing a surcharge to allow the utilities to pass through all reasonably incurred purchased power costs; (h) supporting the development and use of renewable biofuels; (i) promoting greater use of renewable energy, including wind power and solar energy; (j) providing for the retirement or placement on reserve standby status of older and less efficient fossil fuel fired generating units as
new, renewable generation is installed; (k) improving and expanding “load management” and “demand response” programs that allow the utilities to control customer loads to improve grid reliability and cost management; (l) the filing of PUC applications for approval of the installation of Advanced Metering Infrastructure, coupled with time-of-use or dynamic rate options for customers; (m) supporting prudent and cost effective investments in smart grid technologies; (n) delinking prices paid under all new renewable energy contracts from oil prices; and (o) exploring establishment of lifeline rates for low incomelow-income customers.
Many actions have been taken, and continue to be taken, to further the goals of the HCEI. In AugustFor example, in May 2010, HECO received PUC approval of its power purchase agreement with Kahuku Wind Power, LLC for the PUC issued a final decision and order (D&O)purchase of as-available energy, which became operational in the decoupling proceeding, which approved a proposed decoupling mechanism subject to certain modifications.March 2011. In October 2010, the PUC approved the implementation of FITsfeed-in tariffs for renewable energy generators, including applicable pricing, other terms and conditions and a standard form contract. In December 2010, the PUC allowed HECO to implement the decoupling mechanism approved in August 2010. The PUC also approved HECO’s proposed Purchase Power Adjustment Clause to recover non-energy purchased power agreement costs and ordered that the existing ECAC continue. In January 2011, the PUC approved the replacement of the present system-wide caps for NEM, with a 15% per circuit distribution threshold for DG penetration.
Renewable energy projectsprojects. . HECO and its subsidiaries continue to negotiate with developers of proposed projects (identified in the Energy Agreement) to integrate into its grid approximately 1,100 MW from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave and others. This includes HECO’s commitment to integrate, with the assistance of the State, up to 400 MW of wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from wind farmswindfarms proposed by developers to be built on the islands of Lanai and/or Molokai. The State and HECO have agreed to work together to ensure the supporting infrastructure needed is in place to reliably accommodate this large increment of wind power, including appropriate additional storage capacity investments and any required utility system connections or interfaces with the cable and the wind farmwindfarm facilities. In December 2009, the PUC issued a D&Odecision and order (D&O) that allows HECO to defer the costs of studies for this large wind project for later review of prudence and reasonableness.
Interim increases. As of September 30, 2010,March 31, 2011, HECO and its subsidiaries had recognized $167$8 million of revenues with respect to interim orders ($162 million related to interim orders regarding general rate increase requests and $5 million related to interim orders regarding certain integrated resource planning costs).requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.
Major projects.Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order include those described below.
In May 2011, based upon recommendations solicited from the Consumer Advocate, the PUC ordered that independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project, Campbell Industrial Park combustion turbine No. 1 (CIP CT-1)project, and transmission line, HECO’s East Oahu Transmission Project, HELCO’s CT-4, CT-5 and ST-7 and HECO’s Customer Information System (CIS).Project be undertaken. Any revenue requirements arising from specific project subject costs being audited shall either remain interim and subject to refund until audit completion, or remain within regulatory deferral accounts.
Campbell Industrial Park 110 MW combustion turbine No. 1 (CIP CT-1) and transmission line. HECO built a 110 MW simple cycle combustion turbine generating unit and added an additional 138 kilovolt (kV) transmission line to transmit power from generating units at CIP to the rest of the Oahu electric grid (collectively, the Project).
In a second interim D&O to HECO’s 2009 test year rate case issued in February 2010, the PUC granted HECO an increase of $12.7 million in annual revenues to recover $163 million of the costs of the Project.this project. As of September 30, 2010,March 31, 2011, HECO’s cost estimate for the Projectthis project was $196$195 million (of which $194$195 million had been incurred, including $9 million of allowance for funds used during construction (AFUDC)). In its 2011 test year rate case, HECO is seeking to recover actual project costs in excess of the $163 million estimate included in its 2009 test year rate case.being recovered. Management believes no adjustment to project costs is required as of September 30, 2010.March 31, 2011.
East Oahu Transmission Project (EOTP). HECO had planned a project to construct a partially underground transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied. In October 2007, the PUC approved HECO’s request to expend funds (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2) for a revised EOTP using different routes requiring the construction of subtransmission lines, but stated that the issue of recovery of the EOTP costs would be determined in a subsequent rate case, after the project is installed and in service.
Phase 1 was placed in service on June 29, 2010 and is currently estimated to cost $58 million (as a result of higher costs and the project delays). In its 2011 test year rate case, HECO is seeking to recover Phase 1 costs. In April 2010, HECO proposed a modification of Phase 2 that uses smart grid
technology and is estimated to cost $10 million (total cost of $15 million less $5 million of funding through the Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion in 2012.
As of September 30, 2010,March 31, 2011, the accumulated costs recorded for the EOTP amounted to $60$61 million ($58 million for Phase 1 and $2$3 million for Phase 2), including (i) $12 million of planning and permitting costs incurred prior to the 2002 denial of the permit, (ii) $24$25 million of planning, permitting and construction costs incurred after the denial of the permit and (iii) $24 million for AFUDC. Management believes no adjustment to project costs is required as of September 30, 2010.March 31, 2011.
HELCO generating unitsunit. In 1991, HELCO began planning to meet increased forecast demand for electricity. HELCO planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed byOn June 22, 2009, an 18 MW heat recovery steam generator (ST-7), at which time the units would be converted to a 56 MW (net) dual-train combined-cycle unit. In 1994, the PUC approved expenditures was placed into service by HELCO. As of March 31, 2011, HELCO’s cost estimate, and incurred costs, 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.”
CT-4 and CT-5 became operational in mid-2004 and thewere both $92 million. The costs of CT-4 and CT-5 (less a previously agreed to $12 million write-off)ST-7 were included in HELCO’s 20062010 test year rate case interim and final rate increases.
On June 22, 2009, ST-7 was placed into service. As of September 30, 2010, HELCO’s cost estimate for ST-7 was $92 million (of which $91 million had been incurred). HELCO is seeking to recover the costs of ST-7 in its 2010 test year rate case.
increase. Management believes that no further adjustment to project costs is required at September 30, 2010.as of March 31, 2011.
Customer Information System (CIS) Project. In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million for a new CIS,Customer Information System (CIS), provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.
HECO signed a contract with a software company in March 2006 with a transition to the new CIS originally scheduled to occur in February 2008, which transition did not occur. Disputes over the parties’ contractual obligations resulted in litigation, which subsequently was settled. HECO subsequently contracted with a new CIS software vendor and a new system integrator. The CIS Projectproject is proceeding with the implementation of the new software system. As of September 30, 2010, the accumulatedMarch 31, 2011, HECO’s total deferred and capital costs recordedcost estimate for the CIS amounted to $16 million.was $57 million (of which $25 million was recorded). Management believes no adjustment to project costs is required as of September March 31, 2011.
Environmental regulationregulation.. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In the last year,recent years, legislative and regulatory activity related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), has increased significantly and management anticipates that such activity will continue.
On April 20, 2011, the Federal Register published the EPA’s proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at the utilities’ Honolulu, Kahe and Waiau power plants on the island of Oahu. Although the proposed regulations provide some flexibility, management believes they do not adequately focus on site-specific conditions and cost-benefit factors and, if adopted as proposed, would require significant capital and annual operations and maintenance (O&M) expenditures. As proposed, the regulations would require facilities to come into compliance within 8 years of the effective date of the final rule, which the EPA expects to issue in 2012.
Subsequently, on May 3, 2011, the Federal Register published the EPA’s proposed National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs) that would establish Maximum Achievable Control Technology (MACT) standards for the control of hazardous air pollutant (HAP) in emissions from new and existing EGUs. The proposed rules, also known as EGU MACT, would apply to the 14 EGUs at the utilities’ Honolulu, Kahe and Waiau power plants. As proposed, the regulations would require significant capital and annual expenditures for the installation and operation of emission control equipment on the utilities’ EGUs. The CAA requires that facilities come into compliance with final MACT standards within 3 years of the final rule, although facilities may be granted a 1 year extension to install emission control technology. In view of the islolated nature of HECO’s electrical system and the proposed requirement to install control equipment on all HECO steam generating units while maintaining system reliability, the EGU MACT compliance schedule poses a significant challenge to HECO. Under the terms of a settlement agreement, the EPA is required to issue the final rule by November 16, 2011.
Depending upon the final outcome of the legislative and regulatory activity (including under the Clean Water Act with respect to cooling water intake controls andCWA 316(b) regulations, possible changes in CWA effluent standards, and the Clean Air Act with respect to hazardous air pollutant emissions,EGU MACT regulations, the tightening of the National Ambient Air Quality Standards, and the Regional Haze rule),rule under the CAA, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire certain generating units earlier than anticipated.
HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believesHECO and its subsidiaries believe the costs of responding to its subsidiaries’their releases identified to date will not have a material adverse effect, individually or in the aggregate, on the Company’s or HECO’s consolidated results of operations, financial condition or liquidity.cash flows.
Honolulu Harbor investigation. HECO has been involved since 1995 in a workworking group with several other potentially responsible parties (PRPs) identified by the State of Hawaii Department of Health (DOH), including oil companies, in investigating and responding to historical subsurface petroleum contamination in the Honolulu Harbor
area. A subset of the PRPs (the Participating Parties) entered into a joint defense agreement and ultimately entered into an Enforceable Agreement with the DOH to address petroleum contamination at the site. The Participating Parties are funding the investigative and remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work. Although the Honolulu Harbor investigation involves four units—Iwilei, Downtown, Kapalama and Sand Island—to date all the investigative and remedial work has focused on the Iwilei Unit.unit.
The Participating Parties have conducted subsurface investigations, assessments and preliminary oil removal, and anticipate finalizing remedial design work for the Iwilei unit in 2010.2011.
As of September 30, 2010,March 31, 2011, HECO’s remaining accrual for its estimated share of environmental costs for the Iwilei unit was $1.4 million ($3.3 million expensed less $1.9 million expended).$1.2 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the Participating Parties has not yet been established and (3) management cannot estimate the
costs to be incurred (if any) for the sites other than the Iwilei unit (such as its Honolulu power plant located in the Downtown unit), the cost estimate may be subject to significant change and additional material costs may be incurred.
Global climate change and greenhouse gas (GHG) emissions reduction. National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions. Carbon dioxide emissions, including those from the combustion of fossil fuels, comprise the largest percentage of GHG emissions.
In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities are participating in a Task Force established under Act 234, which is charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those to be undertakenbeing implemented under the Energy Agreement. A Task Force consultant prepared a work plan, which was submitted to the Hawaii Legislature in December 2009. Because the regulations implementing Act 234 have not yet been developed or promulgated, management cannot predict the impact of Act 234 on the electric utilities, and the Company, but compliance costs could be significant.
In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009 (ACES). Among other things, ACES establishes a declining cap on GHG emissions requiring a 3% emissions reduction by 2012 that increases periodically to 83% by 2050. ACES also establishes a trading and offset scheme for GHG allowances. The trading program combined with the declining cap is known as aSeveral approaches (e.g., “cap and trade” approach to emissions reduction. In September 2009, the U.S. Senate began consideration of the Clean Energy Jobs and American Power Act, which also includes cap and trade provisions. Since then, several other approaches) to GHG emission reduction have been either introduced or discussed in the U.S. Senate;Congress; however, no legislation has yet been enacted.
On September 22, 2009, the EPAfederal Environmental Protection Agency (EPA) issued theits Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions beginning in 2010.emissions. The utilities’ reports for 2010 are due on September 30, 2011. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Management believes the EPA will make the same or similar endangerment finding regarding GHG emissions from stationary sources like the utilities’ generating units.
In addition, the Prevention of Significant Deterioration (PSD) permit program of the CAA applies to designated air pollutants from new or modified stationary sources, such as utility electrical generation units. In June 2010, the EPA issued its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing facilities. States may need to increase fees to cover the increased level of activity caused by this rule. The GHG Tailoring Rule requires a number of existing HECO, HELCO and MECO facilities that are not currently subject to the Covered Source Permit program to submit an initial Covered Source Permit application to the DOH within one year. The EPA has stated that the PSD program will apply to GHG emissions onEffective January 2, 2011, because that isunder the date the federal GHG emission standards for motor vehicles (Tailpipe Rule) take effect.
The EPA is proposing and adopting these rules on a parallel track with federal climate change legislation. If comprehensive GHG emission control legislation is not adopted, then these (and other future) EPA rules would likely be finalized and be applicable to the utilities. In particular, the Company anticipates that, unless comprehensive GHG legislation is adopted,Significant Deterioration program, permitting after January 2, 2011 of new or modified stationary sources (such as utility electrical generating units) that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. In January 2011, the EPA announced that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation units that are or will be fired on biofuels.
HECO and its subsidiaries have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting demand-side management (DSM)DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, committing to burn renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generation units, and pursuing plans to testtesting biofuel blends in other HECO and MECO generating units. Management is unable to evaluate the ultimate impact on the Company’sutilities’ operations of eventual comprehensive GHG regulation. However, the Companymanagement believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.
While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the Company’sutilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquiditycash flows of the Company.electric utilities. For example, severe weather could cause significant harm to the Company’selectric utilities’ physical facilities.
Given Hawaii’s unique geographic location and its isolated electric grids, physical risks of the type associated with climate change have been considered by the Companyutilities in the planning, design, construction, operation and maintenance of itstheir facilities. To ensure the reliability of each island’s grid, the Company designsutilities design and constructs itsconstruct their electric generation systemsystems with greater levels of redundancy than is typical for U.S. mainland, interconnected systems. Although a major natural disaster could have severe financial implications, such risks have existed since the Company’s inception of the utilities and the Company makesthey make a concerted effort to prepare for a fast response in the event of an emergency.
The Company isutilities are undertaking an adaptation survey of itstheir facilities as a step in developing a longer-term strategy for responding to the consequences of global climate change.
BlueEarth BiofuelsApollo Energy Corporation/Tawhiri Power LLC. BlueEarth Maui BiodieselHELCO purchases energy generated at the Kamao’a windfarm pursuant to the Restated and Amended PPA for As-Available Energy (the RAC) dated October 13, 2004 between HELCO and Apollo Energy Corporation (Apollo), later assigned to Apollo’s affiliate, Tawhiri Power LLC (BlueEarth Maui), a joint venture(Tawhiri). The maximum allowed output of the windfarm is 20.5 MW.
In June 2010, HELCO and Tawhiri participated in an arbitration relating to pursue biodiesel development, was formed in early 2008 between BlueEarth Biofuels LLC (BlueEarth)disputes surrounding HELCO’s ownership and Uluwehiokama Biofuels Corp. (UBC), a non-regulated subsidiary of HECO. UBC invested $400,000 in BlueEarth Maui for a minority ownership interest. MECO began negotiating with BlueEarth Maui for a biodiesel fuel purchase contract, however, negotiations stalled. In October 2008, BlueEarth filed a civil action in federal district court against MECO, HECO and others alleging claims based on the parties’ failure to have reached agreement on the biodiesel supply and related land agreements. The lawsuit seeks damages and equitable relief. A trial date has been scheduled for June 2011. The project was terminated because the litigation was filed and UBC’s investmentpossessory interest in the ventureswitching station and reimbursement of certain interconnection costs. In December 2010, the arbitration panel issued its final award and order finding in favor of HELCO. In February 2011, the award was written offconfirmed and entered as a judgment in 2009.the Hawaii circuit court. Thus, Tawhiri transferred title to the switching station and rights to the land to HELCO and paid HELCO $0.6 million (which included reimbursement of certain interconnection costs, prejudgment interest and HELCO’s attorneys’ fees and costs). Tawhiri has appealed to the Hawaii Intermediate Court of Appeals both a decision by the PUC not to hear the issues that were presented to the arbitration panel and the circuit court’s confirmation of the arbitration panel’s award.
Asset retirement obligationsobligations.. In July 2009, HECO hired an industrial hygienist to conduct an inspectionAsset retirement obligations (AROs) represent legal obligations associated with the retirement of HECO’s Honolulu power plant, which inspection indicated that retired Generating Units Nos. 5 and 7 atcertain tangible long-lived assets, are measured as the plant were now deteriorating. The industrial hygienist recommended removing asbestos-containing materials and lead-based paint. Based on prior assessments, the timingpresent value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on its earnings. Regulatory assets are established to recognize future recoveries through depreciation rates for accretion and depreciation expenses related to AROs and associated assets. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and lead-based paint had not been estimable. Based on the inspection, however,other hazardous materials. In September 2009, HECO now intendsrecorded an estimated ARO of $23 million related to remove Units Nos. 5 and 7,removing retired generating units at its Honolulu power plant, including abating the asbestos and lead-based paint, overpaint. The obligation was subsequently increased in June 2010, due to an increase in the period 2010 to 2013. Accordingly, HECO recorded an asset retirement obligation in September 2009.estimated costs of the removal project. In August 2010, HECO recorded a similar asset retirement obligationestimated ARO of $12 million related to removing retired Generating Units Nos. 1 and 2generating units at HECO’s Waiau power plant, including abating the asbestos andplant.
Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:
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| $ | 48,714 |
| $ | 23,985 |
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lead-based paint, over the period 2011 to 2013. As of September 30, 2010, HECO’s asset retirement obligations related to Honolulu power plant Units Nos. 5 and 7, and Waiau power plant Units 1 and 2, were $35 million and $12 million, respectively.
Collective bargaining agreementsagreements.. As of September 30, 2010,March 31, 2011, approximately 55% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company.electric utilities. The collective bargaining agreement between the union and the electric utilities expired on October 31, 2010, but had been extended through January 31, 2011 while negotiations for a new agreement continued. A tentative new agreement was reached with the union on January 31, 2011, but the agreement was conditioned on ratification by the union’s members and the union’s members did not ratify the new agreement. On March 1, 2008, members of4, 2011 the union declared a strike on HECO and its subsidiaries. On March 11, 2011, the union’s members ratified a new collective bargaining agreement and a new benefit agreements with HECO, HELCOagreement and MECO.the union’s work stoppage ended. The agreements covernew collective bargaining agreement covers a three-year term from NovemberJanuary 1, 20072011 to October 31, 2010,2013 and provideprovides for non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective(1.75%, 2.5%, and 3.0% for 2011, 2012 and 2013, respectively). The new benefit agreement covers a term from January 1, 20092011 to October 31, 2014 and 4.5% effective January 1, 2010. The utilities are currently renegotiating the contractincludes changes to medical, dental and vision plans with the union.increased employee contributions and changes to retirement benefits for employees. See Note 4.
Limited insuranceinsurance.. HECO and its subsidiaries purchase insurance to protect themselves against loss or damage to their properties and against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s transmission and distribution systems (excluding substation buildings and contents)substations) have a replacement value roughly estimated at $5 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations, financial condition and liquidity could be materially adversely impacted. Also, if a series of losses occurred, each of which were subject to an insurance deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the utilities could incur losses in amounts that would have a material adverse effect on their results of operations, financial condition and liquidity.
6 · Cash flows
Supplemental disclosures of cash flow informationinformation.. For the nine monthsquarters ended September 30,March 31, 2011 and 2010, and 2009, HECO and its subsidiaries paid interest amounting to $42$15 million and $29$14 million, respectively.
For the nine monthsquarters ended September 30,March 31, 2011 and 2010, and 2009, HECO and its subsidiaries paidpaid/(received) income taxes amounting to $37$(33) million and $12$8 million, respectively. The increaseIncome taxes were received in income taxes paid was2011 primarily due to higher operating income in 2010 andthe refunding of estimated tax payments made through September 2010 withoutprior to the retroactive effectextension of 2010 bonus depreciation (which was enacted after the payment of September 2010 estimated taxes).provisions.
Supplemental disclosure of noncash activitiesactivities.. The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $4.8$1.2 million and $10.4$1.8 million for the nine monthsquarters ended September 30,March 31, 2011 and 2010, and 2009, respectively.
7 · Recent accounting pronouncements and interpretations
For a discussion of recent accounting pronouncements and interpretations, see Note 12 of HEI’s “Notes to Consolidated Financial Statements.
8 · Fair value measurements
Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the electric utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the electric utilities were to sell their entire holdings of a particular financial instrument at one time. Because no market exists for a portion of the electric utilities’ financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in determining such fair values.
The electric utilities used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:
Cash and cash equivalents and short-term borrowings. The carrying amount approximated fair value because of the short maturity of these instruments.
Long-term debt. Fair value was obtained from a third-party financial services provider or the BLOOMBERG PROFESSIONAL service based on the current rates offered for debt of the same or similar remaining maturities.
Off-balance sheet financial instruments. Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.
The estimated fair values of the financial instruments held or issued by the electric utilities were as follows:
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Cash and cash equivalents |
| $ | 35,044 |
| $ | 35,044 |
| $ | 73,578 |
| $ | 73,578 |
|
| $ | 45,354 |
| $ | 45,354 |
| $ | 122,936 |
| $ | 122,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Financial liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Long-term debt, net, including amounts due within one year |
| 1,057,911 |
| 1,071,586 |
| 1,057,815 |
| 1,018,900 |
|
| 1,057,974 |
| 975,916 |
| 1,057,942 |
| 1,020,550 |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Off-balance sheet item |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
HECO-obligated preferred securities of trust subsidiary |
| 50,000 |
| 50,340 |
| 50,000 |
| 48,480 |
|
| 50,000 |
| 50,800 |
| 50,000 |
| 52,500 |
|
Fair value measurements on a nonrecurring basis. From time to time, the utilities may be required to measure certain assets at fair value on a nonrecurring basis in accordance with U.S. GAAP. These adjustments to fair value usually result from the application of lower-of-cost-or-market accounting or write-downs of individual assets. As of DecemberMarch 31, 2009,2011, there were no adjustments to fair value for assets measured at fair value on a nonrecurring basis in accordance with U.S. GAAP. In
From time to time, the second quarter of 2010, HECO increased its asset retirement obligation (ARO) relatedutilities may be required to the Honolulu power plant by $11 million to $35 million (Level 3) due to an increasemeasure certain liabilities at fair value on a nonrecurring basis in estimated removal and abatement costs. In the third quarter of 2010, HECO increased its ARO by $13 million to $48 million (Level 3) due to the addition of estimated removal and abatement costs for two units at the Waiau power plant.accordance with GAAP. The fair value of the utilities ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread. See Note 5.
9 · Credit agreement
Effective May 7, 2010, HECO entered into a revolving unsecurednoncollateralized credit agreement establishing a line of credit facility of $175 million, with a letter of credit sub-facility expiring on May 6, 2011, with a syndicate of eight financial institutions. The agreement has an initial term which expires on May 6, 2011, but its term will extendagreement’s termination date was extended to May 7, 2013 if approved by the PUC.after having received PUC approval. Any draws on the facility bear interest at the “Adjusted LIBO Rate” plus 200225 basis points or the greatest of (a) the “Prime Rate,” (b) the sum of the “Federal Funds Rate” plus 50 basis points and (c) the “Adjusted LIBO Rate” for a one month “Interest Period” plus 100 basis points per annum, as defined in the agreement. Annual fees on the undrawn commitments are 3040 basis points. The agreement contains provisions for revised pricing in the event of a long-term ratings change.change (such as when S&P lowered its long-term ratings for HECO, HELCO and MECO in November 2010). 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, including compliance with several covenants.
HECO’s $175 million credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes. HECO’s $175 million syndicated credit facility expiring March 31, 2011 was terminated concurrently with the effectiveness of this newreplacement syndicated credit facility. In July 2010, HECO filed with the PUC an application seeking approval to extend the termination date of its credit agreement from May 6, 2011 to May 7, 2013.
10 · Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income
|
| Three months ended |
| Nine months ended |
| |||||||||||||||
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
|
|
|
|
|
| ||||||
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income) |
| $ | 51,343 |
| $ | 54,172 |
| $ | 135,387 |
| $ | 117,404 |
|
| $ | 45,208 |
| $ | 42,609 |
|
Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income taxes on regulated activities |
| (14,818 | ) | (15,957 | ) | (36,972 | ) | (33,228 | ) |
| (11,610 | ) | (11,041 | ) | ||||||
Revenues from nonregulated activities |
| (903 | ) | (1,938 | ) | (4,303 | ) | (7,031 | ) |
| (1,034 | ) | (1,399 | ) | ||||||
Add: Expenses from nonregulated activities |
| 492 |
| 373 |
| 3,259 |
| 777 |
| |||||||||||
Add: |
|
|
|
|
| |||||||||||||||
Expenses from nonregulated activities |
| 155 |
| 238 |
| |||||||||||||||
Operating income from regulated activities after income taxes (per HECO consolidated statements of income) |
| $ | 36,114 |
| $ | 36,650 |
| $ | 97,371 |
| $ | 77,922 |
|
| $ | 32,719 |
| $ | 30,407 |
|
11 · Consolidating financial information
HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated.
HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) relating to the trust preferred securities of Trust III (see Note 2 above). HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (Loss) (unaudited)
Three months ended March 31, 2011
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassi-fications |
| HECO |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating revenues |
| $ | 449,824 |
| 99,635 |
| 94,842 |
| — |
| — |
| — |
| $ | 644,301 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Fuel oil |
| 183,266 |
| 26,491 |
| 51,103 |
| — |
| — |
| — |
| 260,860 |
| ||
Purchased power |
| 112,751 |
| 30,022 |
| 5,185 |
| — |
| — |
| — |
| 147,958 |
| ||
Other operation |
| 47,255 |
| 8,268 |
| 10,008 |
| — |
| — |
| — |
| 65,531 |
| ||
Maintenance |
| 21,192 |
| 3,851 |
| 4,153 |
| — |
| — |
| — |
| 29,196 |
| ||
Depreciation |
| 22,883 |
| 8,323 |
| 5,226 |
| — |
| — |
| — |
| 36,432 |
| ||
Taxes, other than income taxes |
| 41,889 |
| 9,173 |
| 8,933 |
| — |
| — |
| — |
| 59,995 |
| ||
Income taxes |
| 4,698 |
| 3,769 |
| 3,143 |
| — |
| — |
| — |
| 11,610 |
| ||
|
| 433,934 |
| 89,897 |
| 87,751 |
| — |
| — |
| — |
| 611,582 |
| ||
Operating income |
| 15,890 |
| 9,738 |
| 7,091 |
| — |
| — |
| — |
| 32,719 |
| ||
Other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Allowance for equity funds used during construction |
| 960 |
| 83 |
| 201 |
| — |
| — |
| — |
| 1,244 |
| ||
Equity in earnings of subsidiaries |
| 11,490 |
| — |
| — |
| — |
| — |
| (11,490 | ) | — |
| ||
Other, net |
| 732 |
| 106 |
| 92 |
| (2 | ) | (3 | ) | (15 | ) | 910 |
| ||
|
| 13,182 |
| 189 |
| 293 |
| (2 | ) | (3 | ) | (11,505 | ) | 2,154 |
| ||
Interest and other charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Interest on long-term debt |
| 9,130 |
| 2,985 |
| 2,268 |
| — |
| — |
| — |
| 14,383 |
| ||
Amortization of net bond premium and expense |
| 513 |
| 143 |
| 127 |
| — |
| — |
| — |
| 783 |
| ||
Other interest charges |
| 378 |
| 81 |
| 95 |
| — |
| — |
| (15 | ) | 539 |
| ||
Allowance for borrowed funds used during construction |
| (408 | ) | (33 | ) | (79 | ) | — |
| — |
| — |
| (520 | ) | ||
|
| 9,613 |
| 3,176 |
| 2,411 |
| — |
| — |
| (15 | ) | 15,185 |
| ||
Net income (loss) |
| 19,459 |
| 6,751 |
| 4,973 |
| (2 | ) | (3 | ) | (11,490 | ) | 19,688 |
| ||
Preferred stock dividend of subsidiaries |
| — |
| 134 |
| 95 |
| — |
| — |
| — |
| 229 |
| ||
Net income (loss) attributable to HECO |
| 19,459 |
| 6,617 |
| 4,878 |
| (2 | ) | (3 | ) | (11,490 | ) | 19,459 |
| ||
Preferred stock dividends of HECO |
| 270 |
| — |
| — |
| — |
| — |
| — |
| 270 |
| ||
Net income (loss) for common stock |
| $ | 19,189 |
| 6,617 |
| 4,878 |
| (2 | ) | (3 | ) | (11,490 | ) | $ | 19,189 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (Loss) (unaudited)
Three months ended September 30,March 31, 2010
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating revenues |
| $ | 436,919 |
| 95,645 |
| 89,659 |
| — |
| — |
| — |
| $ | 622,223 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Fuel oil |
| 168,019 |
| 22,968 |
| 44,547 |
| — |
| — |
| — |
| 235,534 |
| ||
Purchased power |
| 111,552 |
| 30,206 |
| 6,122 |
| — |
| — |
| — |
| 147,880 |
| ||
Other operation |
| 44,949 |
| 7,848 |
| 9,868 |
| — |
| — |
| — |
| 62,665 |
| ||
Maintenance |
| 20,258 |
| 4,995 |
| 5,365 |
| — |
| — |
| — |
| 30,618 |
| ||
Depreciation |
| 21,197 |
| 9,127 |
| 5,953 |
| — |
| — |
| — |
| 36,277 |
| ||
Taxes, other than income taxes |
| 40,924 |
| 8,904 |
| 8,489 |
| — |
| — |
| — |
| 58,317 |
| ||
Income taxes |
| 8,665 |
| 3,327 |
| 2,826 |
| — |
| — |
| — |
| 14,818 |
| ||
|
| 415,564 |
| 87,375 |
| 83,170 |
| — |
| — |
| — |
| 586,109 |
| ||
Operating income |
| 21,355 |
| 8,270 |
| 6,489 |
| — |
| — |
| — |
| 36,114 |
| ||
Other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Allowance for equity funds used during construction |
| 923 |
| 129 |
| 145 |
| — |
| — |
| — |
| 1,197 |
| ||
Equity in earnings of subsidiaries |
| 9,454 |
| — |
| — |
| — |
| — |
| (9,454 | ) | — |
| ||
Other, net |
| 267 |
| 147 |
| 120 |
| (2 | ) | (2 | ) | (20 | ) | 510 |
| ||
|
| 10,644 |
| 276 |
| 265 |
| (2 | ) | (2 | ) | (9,474 | ) | 1,707 |
| ||
Interest and other charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Interest on long-term debt |
| 9,130 |
| 2,985 |
| 2,268 |
| — |
| — |
| — |
| 14,383 |
| ||
Amortization of net bond premium and expense |
| 512 |
| 160 |
| 127 |
| — |
| — |
| — |
| 799 |
| ||
Other interest charges |
| 476 |
| 92 |
| 105 |
| — |
| — |
| (20 | ) | 653 |
| ||
Allowance for borrowed funds used during construction |
| (369 | ) | (66 | ) | (57 | ) | — |
| — |
| — |
| (492 | ) | ||
|
| 9,749 |
| 3,171 |
| 2,443 |
| — |
| — |
| (20 | ) | 15,343 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net income (loss) |
| 22,250 |
| 5,375 |
| 4,311 |
| (2 | ) | (2 | ) | (9,454 | ) | 22,478 |
| ||
Preferred stock dividend of subsidiaries |
| — |
| 133 |
| 95 |
| — |
| — |
| — |
| 228 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net income (loss) attributable to HECO |
| 22,250 |
| 5,242 |
| 4,216 |
| (2 | ) | (2 | ) | (9,454 | ) | 22,250 |
| ||
Preferred stock dividends of HECO |
| 270 |
| — |
| — |
| — |
| — |
| — |
| 270 |
| ||
Net income (loss) for common stock |
| $ | 21,980 |
| 5,242 |
| 4,216 |
| (2 | ) | (2 | ) | (9,454 | ) | $ | 21,980 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (Loss) (unaudited)
Three months ended September 30, 2009
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating revenues |
| $ | 380,722 |
| 87,631 |
| 78,149 |
| — |
| — |
| — |
| $ | 546,502 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Fuel oil |
| 131,717 |
| 19,370 |
| 35,632 |
| — |
| — |
| — |
| 186,719 |
| ||
Purchased power |
| 101,625 |
| 26,442 |
| 6,380 |
| — |
| — |
| — |
| 134,447 |
| ||
Other operation |
| 43,854 |
| 8,055 |
| 9,264 |
| — |
| — |
| — |
| 61,173 |
| ||
Maintenance |
| 15,844 |
| 5,794 |
| 4,330 |
| — |
| — |
| — |
| 25,968 |
| ||
Depreciation |
| 19,928 |
| 8,253 |
| 7,376 |
| — |
| — |
| — |
| 35,557 |
| ||
Taxes, other than income taxes |
| 34,703 |
| 8,052 |
| 7,276 |
| — |
| — |
| — |
| 50,031 |
| ||
Income taxes |
| 10,596 |
| 3,262 |
| 2,099 |
| — |
| — |
| — |
| 15,957 |
| ||
|
| 358,267 |
| 79,228 |
| 72,357 |
| — |
| — |
| — |
| 509,852 |
| ||
Operating income |
| 22,455 |
| 8,403 |
| 5,792 |
| — |
| — |
| — |
| 36,650 |
| ||
Other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Allowance for equity funds used during construction |
| 2,376 |
| 21 |
| 231 |
| — |
| — |
| — |
| 2,628 |
| ||
Equity in earnings of subsidiaries |
| 8,874 |
| — |
| — |
| — |
| — |
| (8,874 | ) | — |
| ||
Other, net |
| 1,666 |
| 68 |
| 134 |
| (3 | ) | (134 | ) | (74 | ) | 1,657 |
| ||
|
| 12,916 |
| 89 |
| 365 |
| (3 | ) | (134 | ) | (8,948 | ) | 4,285 |
| ||
Interest and other charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Interest on long-term debt |
| 8,659 |
| 2,674 |
| 2,268 |
| — |
| — |
| — |
| 13,601 |
| ||
Amortization of net bond premium and expense |
| 451 |
| 165 |
| 119 |
| — |
| — |
| — |
| 735 |
| ||
Other interest charges |
| 503 |
| 142 |
| 134 |
| — |
| — |
| (74 | ) | 705 |
| ||
Allowance for borrowed funds used during construction |
| (1,026 | ) | 4 |
| (96 | ) | — |
| — |
| — |
| (1,118 | ) | ||
|
| 8,587 |
| 2,985 |
| 2,425 |
| — |
| — |
| (74 | ) | 13,923 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net income (loss) |
| 26,784 |
| 5,507 |
| 3,732 |
| (3 | ) | (134 | ) | (8,874 | ) | 27,012 |
| ||
Preferred stock dividend of subsidiaries |
| — |
| 133 |
| 95 |
| — |
| — |
| — |
| 228 |
| ||
Net income (loss) attributable to HECO |
| 26,784 |
| 5,374 |
| 3,637 |
| (3 | ) | (134 | ) | (8,874 | ) | 26,784 |
| ||
Preferred stock dividends of HECO |
| 270 |
| — |
| — |
| — |
| — |
| — |
| 270 |
| ||
Net income (loss) for common stock |
| $ | 26,514 |
| 5,374 |
| 3,637 |
| (3 | ) | (134 | ) | (8,874 | ) | $ | 26,514 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (Loss) (unaudited)
Nine months ended September 30, 2010
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating revenues |
| $ | 1,220,589 |
| 276,120 |
| 254,320 |
| — |
| — |
| — |
| $ | 1,751,029 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Fuel oil |
| 464,482 |
| 69,600 |
| 128,526 |
| — |
| — |
| — |
| 662,608 |
| ||
Purchased power |
| 302,106 |
| 83,671 |
| 18,398 |
| — |
| — |
| — |
| 404,175 |
| ||
Other operation |
| 130,795 |
| 25,097 |
| 26,271 |
| — |
| — |
| — |
| 182,163 |
| ||
Maintenance |
| 55,898 |
| 16,305 |
| 17,691 |
| — |
| — |
| — |
| 89,894 |
| ||
Depreciation |
| 65,022 |
| 27,380 |
| 21,166 |
| — |
| — |
| — |
| 113,568 |
| ||
Taxes, other than income taxes |
| 114,481 |
| 25,741 |
| 24,056 |
| — |
| — |
| — |
| 164,278 |
| ||
Income taxes |
| 25,417 |
| 7,369 |
| 4,186 |
| — |
| — |
| — |
| 36,972 |
| ||
|
| 1,158,201 |
| 255,163 |
| 240,294 |
| — |
| — |
| — |
| 1,653,658 |
| ||
Operating income |
| 62,388 |
| 20,957 |
| 14,026 |
| — |
| — |
| — |
| 97,371 |
| ||
Other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Allowance for equity funds used during construction |
| 4,081 |
| 330 |
| 406 |
| — |
| — |
| — |
| 4,817 |
| ||
Equity in earnings of subsidiaries |
| 18,173 |
| — |
| — |
| — |
| — |
| (18,173 | ) | — |
| ||
Other, net |
| 2,271 |
| 402 |
| (464 | ) | (6 | ) | (12 | ) | (68 | ) | 2,123 |
| ||
|
| 24,525 |
| 732 |
| (58 | ) | (6 | ) | (12 | ) | (18,241 | ) | 6,940 |
| ||
Interest and other charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Interest on long-term debt |
| 27,391 |
| 8,954 |
| 6,804 |
| — |
| — |
| — |
| 43,149 |
| ||
Amortization of net bond premium and expense |
| 1,429 |
| 395 |
| 368 |
| — |
| — |
| — |
| 2,192 |
| ||
Other interest charges |
| 1,342 |
| 288 |
| 299 |
| — |
| — |
| (68 | ) | 1,861 |
| ||
Allowance for borrowed funds used during construction |
| (1,733 | ) | (168 | ) | (160 | ) | — |
| — |
| — |
| (2,061 | ) | ||
|
| 28,429 |
| 9,469 |
| 7,311 |
| — |
| — |
| (68 | ) | 45,141 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net income (loss) |
| 58,484 |
| 12,220 |
| 6,657 |
| (6 | ) | (12 | ) | (18,173 | ) | 59,170 |
| ||
Preferred stock dividend of subsidiaries |
| — |
| 400 |
| 286 |
| — |
| — |
| — |
| 686 |
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Net income (loss) attributable to HECO |
| 58,484 |
| 11,820 |
| 6,371 |
| (6 | ) | (12 | ) | (18,173 | ) | 58,484 |
| ||
Preferred stock dividends of HECO |
| 810 |
| — |
| — |
| — |
| — |
| — |
| 810 |
| ||
Net income (loss) for common stock |
| $ | 57,674 |
| 11,820 |
| 6,371 |
| (6 | ) | (12 | ) | (18,173 | ) | $ | 57,674 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Income (Loss) (unaudited)
Nine months ended September 30, 2009
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassi-fications |
| HECO |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating revenues |
| $ | 986,578 |
| 251,936 |
| 215,109 |
| — |
| — |
| — |
| $ | 1,453,623 |
|
| $ | 376,104 |
| 89,032 |
| 81,576 |
| — |
| — |
| — |
| $ | 546,712 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Fuel oil |
| 317,456 |
| 50,896 |
| 95,541 |
| — |
| — |
| — |
| 463,893 |
|
| 146,342 |
| 23,479 |
| 41,931 |
| — |
| — |
| — |
| 211,752 |
| ||||
Purchased power |
| 261,799 |
| 86,580 |
| 15,741 |
| — |
| — |
| — |
| 364,120 |
|
| 85,861 |
| 25,702 |
| 5,219 |
| — |
| — |
| — |
| 116,782 |
| ||||
Other operation |
| 131,574 |
| 26,767 |
| 28,410 |
| — |
| — |
| — |
| 186,751 |
|
| 41,626 |
| 9,017 |
| 8,601 |
| — |
| — |
| — |
| 59,244 |
| ||||
Maintenance |
| 49,950 |
| 17,428 |
| 14,184 |
| — |
| — |
| — |
| 81,562 |
|
| 17,074 |
| 3,395 |
| 6,584 |
| — |
| — |
| — |
| 27,053 |
| ||||
Depreciation |
| 61,523 |
| 24,754 |
| 22,129 |
| — |
| — |
| — |
| 108,406 |
|
| 21,913 |
| 9,126 |
| 7,603 |
| — |
| — |
| — |
| 38,642 |
| ||||
Taxes, other than income taxes |
| 93,659 |
| 23,708 |
| 20,374 |
| — |
| — |
| — |
| 137,741 |
|
| 35,723 |
| 8,328 |
| 7,740 |
| — |
| — |
| — |
| 51,791 |
| ||||
Income taxes |
| 22,515 |
| 6,402 |
| 4,311 |
| — |
| — |
| — |
| 33,228 |
|
| 7,905 |
| 2,647 |
| 489 |
| — |
| — |
| — |
| 11,041 |
| ||||
|
| 938,476 |
| 236,535 |
| 200,690 |
| — |
| — |
| — |
| 1,375,701 |
|
| 356,444 |
| 81,694 |
| 78,167 |
| — |
| — |
| — |
| 516,305 |
| ||||
Operating income |
| 48,102 |
| 15,401 |
| 14,419 |
| — |
| — |
| — |
| 77,922 |
|
| 19,660 |
| 7,338 |
| 3,409 |
| — |
| — |
| — |
| 30,407 |
| ||||
Other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Allowance for equity funds used during construction |
| 8,254 |
| 1,530 |
| 569 |
| — |
| — |
| — |
| 10,353 |
|
| 1,559 |
| 95 |
| 119 |
| — |
| — |
| — |
| 1,773 |
| ||||
Equity in earnings of subsidiaries |
| 18,083 |
| — |
| — |
| — |
| — |
| (18,083 | ) | — |
|
| 5,293 |
| — |
| — |
| — |
| — |
| (5,293 | ) | — |
| ||||
Other, net |
| 5,713 |
| 1,007 |
| 331 |
| (11 | ) | (147 | ) | (400 | ) | 6,493 |
|
| 1,114 |
| 115 |
| 45 |
| (2 | ) | (5 | ) | (26 | ) | 1,241 |
| ||||
|
| 32,050 |
| 2,537 |
| 900 |
| (11 | ) | (147 | ) | (18,483 | ) | 16,846 |
|
| 7,966 |
| 210 |
| 164 |
| (2 | ) | (5 | ) | (5,319 | ) | 3,014 |
| ||||
Interest and other charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest on long-term debt |
| 23,995 |
| 6,659 |
| 6,804 |
| — |
| — |
| — |
| 37,458 |
|
| 9,130 |
| 2,985 |
| 2,268 |
| — |
| — |
| — |
| 14,383 |
| ||||
Amortization of net bond premium and expense |
| 1,256 |
| 475 |
| 361 |
| — |
| — |
| — |
| 2,092 |
|
| 433 |
| 117 |
| 117 |
| — |
| — |
| — |
| 667 |
| ||||
Other interest charges |
| 1,516 |
| 591 |
| 341 |
| — |
| — |
| (400 | ) | 2,048 |
|
| 425 |
| 101 |
| 99 |
| — |
| — |
| (26 | ) | 599 |
| ||||
Allowance for borrowed funds used during construction |
| (3,566 | ) | (666 | ) | (235 | ) | — |
| — |
| — |
| (4,467 | ) |
| (684 | ) | (49 | ) | (46 | ) | — |
| — |
| — |
| (779 | ) | ||||
|
| 23,201 |
| 7,059 |
| 7,271 |
| — |
| — |
| (400 | ) | 37,131 |
|
| 9,304 |
| 3,154 |
| 2,438 |
| — |
| — |
| (26 | ) | 14,870 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Net income (loss) |
| 56,951 |
| 10,879 |
| 8,048 |
| (11 | ) | (147 | ) | (18,083 | ) | 57,637 |
|
| 18,322 |
| 4,394 |
| 1,135 |
| (2 | ) | (5 | ) | (5,293 | ) | 18,551 |
| ||||
Preferred stock dividend of subsidiaries |
| — |
| 400 |
| 286 |
| — |
| — |
| — |
| 686 |
|
| — |
| 134 |
| 95 |
| — |
| — |
| — |
| 229 |
| ||||
Net income (loss) attributable to HECO |
| 56,951 |
| 10,479 |
| 7,762 |
| (11 | ) | (147 | ) | (18,083 | ) | 56,951 |
|
| 18,322 |
| 4,260 |
| 1,040 |
| (2 | ) | (5 | ) | (5,293 | ) | 18,322 |
| ||||
Preferred stock dividends of HECO |
| 810 |
| — |
| — |
| — |
| — |
| — |
| 810 |
|
| 270 |
| — |
| — |
| — |
| — |
| — |
| 270 |
| ||||
Net income (loss) for common stock |
| $ | 56,141 |
| 10,479 |
| 7,762 |
| (11 | ) | (147 | ) | (18,083 | ) | $ | 56,141 |
|
| $ | 18,052 |
| 4,260 |
| 1,040 |
| (2 | ) | (5 | ) | (5,293 | ) | $ | 18,052 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance Sheet (unaudited)
September 30, 2010March 31, 2011
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassi-fications |
| HECO |
| ||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Utility plant, at cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Land |
| $ | 43,248 |
| 5,108 |
| 3,015 |
| — |
| — |
| — |
| $ | 51,371 |
|
| $ | 43,242 |
| 5,182 |
| 3,016 |
| — |
| — |
| — |
| $ | 51,440 |
|
Plant and equipment |
| 2,954,843 |
| 1,005,755 |
| 871,811 |
| — |
| — |
| — |
| 4,832,409 |
|
| 3,005,933 |
| 1,019,463 |
| 883,997 |
| — |
| — |
| — |
| 4,909,393 |
| ||||
Less accumulated depreciation |
| (1,120,269 | ) | (400,922 | ) | (394,072 | ) | — |
| — |
| — |
| (1,915,263 | ) |
| (1,146,151 | ) | (400,502 | ) | (399,419 | ) | — |
| — |
| — |
| (1,946,072 | ) | ||||
Construction in progress |
| 73,799 |
| 19,389 |
| 12,304 |
| — |
| — |
| — |
| 105,492 |
|
| 80,330 |
| 10,022 |
| 13,948 |
| — |
| — |
| — |
| 104,300 |
| ||||
Net utility plant |
| 1,951,621 |
| 629,330 |
| 493,058 |
| — |
| — |
| — |
| 3,074,009 |
|
| 1,983,354 |
| 634,165 |
| 501,542 |
| — |
| — |
| — |
| 3,119,061 |
| ||||
Investment in wholly owned subsidiaries, at equity |
| 469,495 |
| — |
| — |
| — |
| — |
| (469,495 | ) | — |
|
| 505,256 |
| — |
| — |
| — |
| — |
| (505,256 | ) | — |
| ||||
Current assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents |
| 32,260 |
| 2,053 |
| 635 |
| 90 |
| 6 |
| — |
| 35,044 |
|
| 42,824 |
| 1,617 |
| 821 |
| 87 |
| 5 |
| — |
| 45,354 |
| ||||
Advances to affiliates |
| 7,050 |
| — |
| 19,500 |
| — |
| — |
| (26,550 | ) | — |
|
| — |
| 30,800 |
| 17,000 |
| — |
| — |
| (47,800 | ) | — |
| ||||
Customer accounts receivable, net |
| 100,067 |
| 22,266 |
| 19,345 |
| — |
| — |
| — |
| 141,678 |
|
| 100,010 |
| 25,773 |
| 23,703 |
| — |
| — |
| — |
| 149,486 |
| ||||
Accrued unbilled revenues, net |
| 66,475 |
| 14,764 |
| 14,627 |
| — |
| — |
| — |
| 95,866 |
|
| 81,839 |
| 16,532 |
| 15,415 |
| — |
| — |
| — |
| 113,786 |
| ||||
Other accounts receivable, net |
| 7,159 |
| 3,061 |
| 530 |
| — |
| — |
| (3,909 | ) | 6,841 |
|
| 8,982 |
| 2,222 |
| 2,105 |
| — |
| — |
| (3,977 | ) | 9,332 |
| ||||
Fuel oil stock, at average cost |
| 91,106 |
| 13,313 |
| 16,811 |
| — |
| — |
| — |
| 121,230 |
|
| 114,899 |
| 16,436 |
| 24,883 |
| — |
| — |
| — |
| 156,218 |
| ||||
Materials & supplies, at average cost |
| 19,449 |
| 4,288 |
| 12,556 |
| — |
| — |
| — |
| 36,293 |
| |||||||||||||||||||
Materials and supplies, at average cost |
| 18,928 |
| 4,913 |
| 13,941 |
| — |
| — |
| — |
| 37,782 |
| |||||||||||||||||||
Prepayments and other |
| 51,392 |
| 21,503 |
| 9,194 |
| — |
| — |
| — |
| 82,089 |
|
| 14,114 |
| 2,640 |
| 2,877 |
| — |
| — |
| (700 | ) | 18,931 |
| ||||
Regulatory assets |
| 6,069 |
| 1,142 |
| 1,109 |
| — |
| — |
| — |
| 8,320 |
| |||||||||||||||||||
Total current assets |
| 374,958 |
| 81,248 |
| 93,198 |
| 90 |
| 6 |
| (30,459 | ) | 519,041 |
|
| 387,665 |
| 102,075 |
| 101,854 |
| 87 |
| 5 |
| (52,477 | ) | 539,209 |
| ||||
Other long-term assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Regulatory assets |
| 311,329 |
| 57,195 |
| 53,653 |
| — |
| — |
| — |
| 422,177 |
|
| 355,064 |
| 60,611 |
| 57,817 |
| — |
| — |
| — |
| 473,492 |
| ||||
Unamortized debt expense |
| 9,543 |
| 2,736 |
| 2,156 |
| — |
| — |
| — |
| 14,435 |
|
| 8,940 |
| 2,598 |
| 2,045 |
| — |
| — |
| — |
| 13,583 |
| ||||
Other |
| 36,242 |
| 8,027 |
| 15,397 |
| — |
| — |
| — |
| 59,666 |
|
| 42,456 |
| 8,768 |
| 14,991 |
| — |
| — |
| — |
| 66,215 |
| ||||
Total other long-term assets |
| 357,114 |
| 67,958 |
| 71,206 |
| — |
| — |
| — |
| 496,278 |
|
| 406,460 |
| 71,977 |
| 74,853 |
| — |
| — |
| — |
| 553,290 |
| ||||
|
| $ | 3,153,188 |
| 778,536 |
| 657,462 |
| 90 |
| 6 |
| (499,954 | ) | $ | 4,089,328 |
| |||||||||||||||||
Total assets |
| $ | 3,282,735 |
| 808,217 |
| 678,249 |
| 87 |
| 5 |
| (557,733 | ) | $ | 4,211,560 |
| |||||||||||||||||
Capitalization and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Capitalization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Common stock equity |
| $ | 1,325,892 |
| 244,695 |
| 224,707 |
| 88 |
| 5 |
| (469,495 | ) | $ | 1,325,892 |
|
| $ | 1,338,974 |
| 273,159 |
| 232,011 |
| 84 |
| 2 |
| (505,256 | ) | $ | 1,338,974 |
|
Cumulative preferred stock—not subject to mandatory redemption |
| 22,293 |
| 7,000 |
| 5,000 |
| — |
| — |
| — |
| 34,293 |
|
| 22,293 |
| 7,000 |
| 5,000 |
| — |
| — |
| — |
| 34,293 |
| ||||
Long-term debt, net |
| 672,252 |
| 211,271 |
| 174,388 |
| — |
| — |
| — |
| 1,057,911 |
|
| 672,285 |
| 211,287 |
| 174,402 |
| — |
| — |
| — |
| 1,057,974 |
| ||||
Total capitalization |
| 2,020,437 |
| 462,966 |
| 404,095 |
| 88 |
| 5 |
| (469,495 | ) | 2,418,096 |
|
| 2,033,552 |
| 491,446 |
| 411,413 |
| 84 |
| 2 |
| (505,256 | ) | 2,431,241 |
| ||||
Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Short-term borrowings-affiliate |
| 19,500 |
| 7,050 |
| — |
| — |
| — |
| (26,550 | ) | — |
|
| 47,800 |
| — |
| — |
| — |
| — |
| (47,800 | ) | — |
| ||||
Accounts payable |
| 83,814 |
| 19,033 |
| 13,863 |
| — |
| — |
| — |
| 116,710 |
|
| 103,469 |
| 19,008 |
| 15,479 |
| — |
| — |
| — |
| 137,956 |
| ||||
Interest and preferred dividends payable |
| 14,194 |
| 4,318 |
| 3,953 |
| — |
| — |
| (4 | ) | 22,461 |
|
| 12,656 |
| 4,113 |
| 3,711 |
| — |
| — |
| (4 | ) | 20,476 |
| ||||
Taxes accrued |
| 98,312 |
| 28,690 |
| 23,350 |
| — |
| — |
| — |
| 150,352 |
|
| 95,655 |
| 26,104 |
| 25,077 |
| — |
| — |
| (700 | ) | 146,136 |
| ||||
Other |
| 33,685 |
| 7,729 |
| 14,587 |
| 2 |
| 1 |
| (3,905 | ) | 52,099 |
|
| 31,372 |
| 9,586 |
| 13,087 |
| 3 |
| 3 |
| (3,973 | ) | 50,078 |
| ||||
Total current liabilities |
| 249,505 |
| 66,820 |
| 55,753 |
| 2 |
| 1 |
| (30,459 | ) | 341,622 |
|
| 290,952 |
| 58,811 |
| 57,354 |
| 3 |
| 3 |
| (52,477 | ) | 354,646 |
| ||||
Deferred credits and other liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Deferred income taxes |
| 180,060 |
| 43,960 |
| 20,435 |
| — |
| — |
| — |
| 244,455 |
|
| 205,482 |
| 47,625 |
| 28,315 |
| — |
| — |
| — |
| 281,422 |
| ||||
Regulatory liabilities |
| 194,910 |
| 55,389 |
| 39,269 |
| — |
| — |
| — |
| 289,568 |
|
| 206,979 |
| 57,835 |
| 39,561 |
| — |
| — |
| — |
| 304,375 |
| ||||
Unamortized tax credits |
| 32,988 |
| 12,922 |
| 12,173 |
| — |
| — |
| — |
| 58,083 |
|
| 34,157 |
| 13,005 |
| 12,292 |
| — |
| — |
| — |
| 59,454 |
| ||||
Retirement benefits liability |
| 219,691 |
| 34,470 |
| 38,908 |
| — |
| — |
| — |
| 293,069 |
|
| 253,541 |
| 37,565 |
| 42,412 |
| — |
| — |
| — |
| 333,518 |
| ||||
Other |
| 69,779 |
| 30,253 |
| 12,998 |
| — |
| — |
| — |
| 113,030 |
|
| 67,988 |
| 28,372 |
| 12,474 |
| — |
| — |
| — |
| 108,834 |
| ||||
Total deferred credits and other liabilities |
| 697,428 |
| 176,994 |
| 123,783 |
| — |
| — |
| — |
| 998,205 |
|
| 768,147 |
| 184,402 |
| 135,054 |
| — |
| — |
| — |
| 1,087,603 |
| ||||
Contributions in aid of construction |
| 185,818 |
| 71,756 |
| 73,831 |
| — |
| — |
| — |
| 331,405 |
|
| 190,084 |
| 73,558 |
| 74,428 |
| — |
| — |
| — |
| 338,070 |
| ||||
|
| $ | 3,153,188 |
| 778,536 |
| 657,462 |
| 90 |
| 6 |
| (499,954 | ) | $ | 4,089,328 |
| |||||||||||||||||
Total capitalization and liabilities |
| $ | 3,282,735 |
| 808,217 |
| 678,249 |
| 87 |
| 5 |
| (557,733 | ) | $ | 4,211,560 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Balance Sheet (unaudited)
December 31, 20092010
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassi-fications |
| HECO |
| ||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Utility plant, at cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Land |
| $ | 43,075 |
| 5,109 |
| 4,346 |
| — |
| — |
| — |
| $ | 52,530 |
|
| $ | 43,240 |
| 5,108 |
| 3,016 |
| — |
| — |
| — |
| $ | 51,364 |
|
Plant and equipment |
| 2,833,296 |
| 995,585 |
| 867,376 |
| — |
| — |
| — |
| 4,696,257 |
|
| 2,984,887 |
| 1,030,520 |
| 881,567 |
| — |
| — |
| — |
| 4,896,974 |
| ||||
Less accumulated depreciation |
| (1,081,441 | ) | (379,526 | ) | (387,449 | ) | — |
| — |
| — |
| (1,848,416 | ) |
| (1,134,423 | ) | (408,704 | ) | (397,932 | ) | — |
| — |
| — |
| (1,941,059 | ) | ||||
Construction in progress |
| 115,644 |
| 10,920 |
| 6,416 |
| — |
| — |
| — |
| 132,980 |
|
| 78,934 |
| 9,828 |
| 12,800 |
| — |
| — |
| — |
| 101,562 |
| ||||
Net utility plant |
| 1,910,574 |
| 632,088 |
| 490,689 |
| — |
| — |
| — |
| 3,033,351 |
|
| 1,972,638 |
| 636,752 |
| 499,451 |
| — |
| — |
| — |
| 3,108,841 |
| ||||
Investment in wholly owned subsidiaries, at equity |
| 462,006 |
| — |
| — |
| — |
| — |
| (462,006 | ) | — |
|
| 500,801 |
| — |
| — |
| — |
| — |
| (500,801 | ) | — |
| ||||
Current assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash and cash equivalents |
| 70,981 |
| 2,006 |
| 474 |
| 98 |
| 19 |
| — |
| 73,578 |
|
| 121,019 |
| 1,229 |
| 594 |
| 89 |
| 5 |
| — |
| 122,936 |
| ||||
Advances to affiliates |
| 20,100 |
| — |
| 11,000 |
| — |
| — |
| (31,100 | ) | — |
|
| — |
| 30,950 |
| 29,500 |
| — |
| — |
| (60,450 | ) | — |
| ||||
Customer accounts receivable, net |
| 89,365 |
| 24,502 |
| 19,419 |
| — |
| — |
| — |
| 133,286 |
|
| 93,474 |
| 23,484 |
| 21,213 |
| — |
| — |
| — |
| 138,171 |
| ||||
Accrued unbilled revenues, net |
| 58,022 |
| 13,648 |
| 12,606 |
| — |
| — |
| — |
| 84,276 |
|
| 71,712 |
| 16,018 |
| 16,654 |
| — |
| — |
| — |
| 104,384 |
| ||||
Other accounts receivable, net |
| 5,967 |
| 2,294 |
| 1,317 |
| — |
| — |
| (1,129 | ) | 8,449 |
|
| 11,536 |
| 3,319 |
| 668 |
| — |
| — |
| (6,147 | ) | 9,376 |
| ||||
Fuel oil stock, at average cost |
| 49,847 |
| 12,640 |
| 16,174 |
| — |
| — |
| — |
| 78,661 |
|
| 121,280 |
| 15,751 |
| 15,674 |
| — |
| — |
| — |
| 152,705 |
| ||||
Materials & supplies, at average cost |
| 18,378 |
| 4,006 |
| 13,524 |
| — |
| — |
| — |
| 35,908 |
| |||||||||||||||||||
Materials and supplies, at average cost |
| 18,890 |
| 4,498 |
| 13,329 |
| — |
| — |
| — |
| 36,717 |
| |||||||||||||||||||
Prepayments and other |
| 10,163 |
| 4,268 |
| 2,614 |
| — |
| — |
| (844 | ) | 16,201 |
|
| 36,974 |
| 9,825 |
| 8,417 |
| — |
| — |
| — |
| 55,216 |
| ||||
Regulatory assets |
| 5,294 |
| 1,064 |
| 991 |
| — |
| — |
| — |
| 7,349 |
| |||||||||||||||||||
Total current assets |
| 322,823 |
| 63,364 |
| 77,128 |
| 98 |
| 19 |
| (33,073 | ) | 430,359 |
|
| 480,179 |
| 106,138 |
| 107,040 |
| 89 |
| 5 |
| (66,597 | ) | 626,854 |
| ||||
Other long-term assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Regulatory assets |
| 312,953 |
| 59,372 |
| 54,537 |
| — |
| — |
| — |
| 426,862 |
|
| 352,038 |
| 61,051 |
| 57,892 |
| — |
| — |
| — |
| 470,981 |
| ||||
Unamortized debt expense |
| 9,392 |
| 2,679 |
| 2,217 |
| — |
| — |
| — |
| 14,288 |
|
| 9,240 |
| 2,681 |
| 2,109 |
| — |
| — |
| — |
| 14,030 |
| ||||
Other |
| 47,502 |
| 9,718 |
| 16,312 |
| — |
| — |
| — |
| 73,532 |
|
| 41,236 |
| 8,257 |
| 15,481 |
| — |
| — |
| — |
| 64,974 |
| ||||
Total other long-term assets |
| 369,847 |
| 71,769 |
| 73,066 |
| — |
| — |
| — |
| 514,682 |
|
| 402,514 |
| 71,989 |
| 75,482 |
| — |
| — |
| — |
| 549,985 |
| ||||
|
| $ | 3,065,250 |
| 767,221 |
| 640,883 |
| 98 |
| 19 |
| (495,079 | ) | $ | 3,978,392 |
| |||||||||||||||||
Total assets |
| $ | 3,356,132 |
| 814,879 |
| 681,973 |
| 89 |
| 5 |
| (567,398 | ) | $ | 4,285,680 |
| |||||||||||||||||
Capitalization and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Capitalization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Common stock equity |
| $ | 1,306,408 |
| 240,576 |
| 221,319 |
| 94 |
| 17 |
| (462,006 | ) | $ | 1,306,408 |
|
| $ | 1,337,398 |
| 270,573 |
| 230,137 |
| 86 |
| 5 |
| (500,801 | ) | $ | 1,337,398 |
|
Cumulative preferred stock—not subject to mandatory redemption |
| 22,293 |
| 7,000 |
| 5,000 |
| — |
| — |
| — |
| 34,293 |
|
| 22,293 |
| 7,000 |
| 5,000 |
| — |
| — |
| — |
| 34,293 |
| ||||
Long-term debt, net |
| 672,200 |
| 211,248 |
| 174,367 |
| — |
| — |
| — |
| 1,057,815 |
|
| 672,268 |
| 211,279 |
| 174,395 |
| — |
| — |
| — |
| 1,057,942 |
| ||||
Total capitalization |
| 2,000,901 |
| 458,824 |
| 400,686 |
| 94 |
| 17 |
| (462,006 | ) | 2,398,516 |
|
| 2,031,959 |
| 488,852 |
| 409,532 |
| 86 |
| 5 |
| (500,801 | ) | 2,429,633 |
| ||||
Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Short-term borrowings-affiliate |
| 11,000 |
| 20,100 |
| — |
| — |
| — |
| (31,100 | ) | — |
|
| 60,450 |
| — |
| — |
| — |
| — |
| (60,450 | ) | — |
| ||||
Accounts payable |
| 103,073 |
| 17,369 |
| 12,269 |
| — |
| — |
| — |
| 132,711 |
|
| 135,739 |
| 22,888 |
| 20,332 |
| — |
| — |
| — |
| 178,959 |
| ||||
Interest and preferred dividends payable |
| 14,186 |
| 4,088 |
| 2,954 |
| — |
| — |
| (5 | ) | 21,223 |
|
| 13,648 |
| 4,196 |
| 2,762 |
| — |
| — |
| (3 | ) | 20,603 |
| ||||
Taxes accrued |
| 101,288 |
| 31,274 |
| 24,374 |
| — |
| — |
| (844 | ) | 156,092 |
|
| 116,840 |
| 31,229 |
| 27,891 |
| — |
| — |
| — |
| 175,960 |
| ||||
Other |
| 28,956 |
| 8,670 |
| 11,684 |
| 4 |
| 2 |
| (1,124 | ) | 48,192 |
|
| 35,784 |
| 13,065 |
| 13,646 |
| 3 |
| — |
| (6,144 | ) | 56,354 |
| ||||
Total current liabilities |
| 258,503 |
| 81,501 |
| 51,281 |
| 4 |
| 2 |
| (33,073 | ) | 358,218 |
|
| 362,461 |
| 71,378 |
| 64,631 |
| 3 |
| — |
| (66,597 | ) | 431,876 |
| ||||
Deferred credits and other liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Deferred income taxes |
| 141,160 |
| 25,984 |
| 13,459 |
| — |
| — |
| — |
| 180,603 |
|
| 198,753 |
| 44,971 |
| 25,562 |
| — |
| — |
| — |
| 269,286 |
| ||||
Regulatory liabilities |
| 196,284 |
| 52,669 |
| 39,261 |
| — |
| — |
| — |
| 288,214 |
|
| 201,587 |
| 56,190 |
| 39,020 |
| — |
| — |
| — |
| 296,797 |
| ||||
Unamortized tax credits |
| 31,393 |
| 12,886 |
| 12,591 |
| — |
| — |
| — |
| 56,870 |
|
| 33,661 |
| 12,857 |
| 12,292 |
| — |
| — |
| — |
| 58,810 |
| ||||
Retirement benefits liability |
| 221,311 |
| 35,584 |
| 39,728 |
| — |
| — |
| — |
| 296,623 |
|
| 271,499 |
| 39,811 |
| 44,534 |
| — |
| — |
| — |
| 355,844 |
| ||||
Other |
| 36,113 |
| 30,207 |
| 11,484 |
| — |
| — |
| — |
| 77,804 |
|
| 66,898 |
| 28,739 |
| 12,433 |
| — |
| — |
| — |
| 108,070 |
| ||||
Total deferred credits and other liabilities |
| 626,261 |
| 157,330 |
| 116,523 |
| — |
| — |
| — |
| 900,114 |
|
| 772,398 |
| 182,568 |
| 133,841 |
| — |
| — |
| — |
| 1,088,807 |
| ||||
Contributions in aid of construction |
| 179,585 |
| 69,566 |
| 72,393 |
| — |
| — |
| — |
| 321,544 |
|
| 189,314 |
| 72,081 |
| 73,969 |
| — |
| — |
| — |
| 335,364 |
| ||||
|
| $ | 3,065,250 |
| 767,221 |
| 640,883 |
| 98 |
| 19 |
| (495,079 | ) | $ | 3,978,392 |
| |||||||||||||||||
Total capitalization and liabilities |
| $ | 3,356,132 |
| 814,879 |
| 681,973 |
| 89 |
| 5 |
| (567,398 | ) | $ | 4,285,680 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Changes in Common Stock Equity (unaudited)
NineThree months ended September 30, 2010March 31, 2011
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassi-fications |
| HECO |
| ||||
Balance, December 31, 2009 |
| $ | 1,306,408 |
| 240,576 |
| 221,319 |
| 94 |
| 17 |
| (462,006 | ) | $ | 1,306,408 |
| |||||||||||||||||
Balance, December 31, 2010 |
| $ | 1,337,398 |
| 270,573 |
| 230,137 |
| 86 |
| 5 |
| (500,801 | ) | $ | 1,337,398 |
| |||||||||||||||||
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) for common stock |
| 57,674 |
| 11,820 |
| 6,371 |
| (6 | ) | (12 | ) | (18,173 | ) | 57,674 |
|
| 19,189 |
| 6,617 |
| 4,878 |
| (2 | ) | (3 | ) | (11,490 | ) | 19,189 |
| ||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes |
| 2,819 |
| 593 |
| 461 |
| — |
| — |
| (1,054 | ) | 2,819 |
| |||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits |
| (2,640 | ) | (579 | ) | (443 | ) | — |
| — |
| 1,022 |
| (2,640 | ) | |||||||||||||||||||
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits |
| 2,274 |
| 357 |
| 283 |
| — |
| — |
| (640 | ) | 2,274 |
| |||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes |
| (2,247 | ) | (357 | ) | (286 | ) | — |
| — |
| 643 |
| (2,247 | ) | |||||||||||||||||||
Comprehensive income (loss) |
| 57,853 |
| 11,834 |
| 6,389 |
| (6 | ) | (12 | ) | (18,205 | ) | 57,853 |
|
| 19,216 |
| 6,617 |
| 4,875 |
| (2 | ) | (3 | ) | (11,487 | ) | 19,216 |
| ||||
Common stock dividends |
| (38,360 | ) | (7,710 | ) | (3,001 | ) | — |
| — |
| 10,711 |
| (38,360 | ) |
| (17,640 | ) | (4,031 | ) | (3,001 | ) | — |
| — |
| 7,032 |
| (17,640 | ) | ||||
Common stock issue expenses |
| (9 | ) | (5 | ) | — |
| — |
| — |
| 5 |
| (9 | ) | |||||||||||||||||||
Balance, September 30, 2010 |
| $ | 1,325,892 |
| 244,695 |
| 224,707 |
| 88 |
| 5 |
| (469,495 | ) | $ | 1,325,892 |
| |||||||||||||||||
Balance, March 31, 2011 |
| $ | 1,338,974 |
| 273,159 |
| 232,011 |
| 84 |
| 2 |
| (505,256 | ) | $ | 1,338,974 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Changes in Common Stock Equity (unaudited)
NineThree months ended September 30, 2009March 31, 2010
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassi-fications |
| HECO |
| ||||
Balance, December 31, 2008 |
| $ | 1,188,842 |
| 221,405 |
| 215,382 |
| 105 |
| 141 |
| (437,033 | ) | $ | 1,188,842 |
| |||||||||||||||||
Balance, December 31, 2009 |
| $ | 1,306,408 |
| 240,576 |
| 221,319 |
| 94 |
| 17 |
| (462,006 | ) | $ | 1,306,408 |
| |||||||||||||||||
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) for common stock |
| 56,141 |
| 10,479 |
| 7,762 |
| (11 | ) | (147 | ) | (18,083 | ) | 56,141 |
|
| 18,052 |
| 4,260 |
| 1,040 |
| (2 | ) | (5 | ) | (5,293 | ) | 18,052 |
| ||||
Retirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of taxes |
| 8,008 |
| 1,206 |
| 989 |
| — |
| — |
| (2,195 | ) | 8,008 |
| |||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits |
| (7,835 | ) | (1,193 | ) | (971 | ) | — |
| — |
| 2,164 |
| (7,835 | ) | |||||||||||||||||||
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits |
| 882 |
| 189 |
| 161 |
| — |
| — |
| (350 | ) | 882 |
| |||||||||||||||||||
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes |
| (825 | ) | (185 | ) | (154 | ) | — |
| — |
| 339 |
| (825 | ) | |||||||||||||||||||
Comprehensive income (loss) |
| 56,314 |
| 10,492 |
| 7,780 |
| (11 | ) | (147 | ) | (18,114 | ) | 56,314 |
|
| 18,109 |
| 4,264 |
| 1,047 |
| (2 | ) | (5 | ) | (5,304 | ) | 18,109 |
| ||||
Capital stock expense |
| (7 | ) | (2 | ) | (1 | ) | — |
| — |
| 3 |
| (7 | ) | |||||||||||||||||||
Common stock dividends |
| (32,756 | ) | — |
| (4,264 | ) | — |
| — |
| 4,264 |
| (32,756 | ) |
| (15,150 | ) | (3,434 | ) | (1,600 | ) | — |
| — |
| 5,034 |
| (15,150 | ) | ||||
Issuance of common stock |
| — |
| — |
| — |
| — |
| 25 |
| (25 | ) | — |
| |||||||||||||||||||
Balance, September 30, 2009 |
| $ | 1,212,393 |
| 231,895 |
| 218,897 |
| 94 |
| 19 |
| (450,905 | ) | $ | 1,212,393 |
| |||||||||||||||||
Common stock issue expenses |
| (1 | ) | — |
| — |
| — |
| — |
| — |
| (1 | ) | |||||||||||||||||||
Balance, March 31, 2010 |
| $ | 1,309,366 |
| 241,406 |
| 220,766 |
| 92 |
| 12 |
| (462,276 | ) | $ | 1,309,366 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Cash Flows (unaudited)
NineThree months ended September 30, 2010March 31, 2011
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Elimination |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Elimination |
| HECO |
| ||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net income (loss) |
| $ | 58,484 |
| 12,220 |
| 6,657 |
| (6 | ) | (12 | ) | (18,173 | ) | $ | 59,170 |
|
| $ | 19,459 |
| 6,751 |
| 4,973 |
| (2 | ) | (3 | ) | (11,490 | ) | $ | 19,688 |
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Equity in earnings |
| (18,248 | ) | — |
| — |
| — |
| — |
| 18,173 |
| (75 | ) |
| (11,515 | ) | — |
| — |
| — |
| — |
| 11,490 |
| (25 | ) | ||||
Common stock dividends received from subsidiaries |
| 10,786 |
| — |
| — |
| — |
| — |
| (10,711 | ) | 75 |
|
| 7,057 |
| — |
| — |
| — |
| — |
| (7,032 | ) | 25 |
| ||||
Depreciation of property, plant and equipment |
| 65,022 |
| 27,380 |
| 21,166 |
| — |
| — |
| — |
| 113,568 |
|
| 22,883 |
| 8,323 |
| 5,226 |
| — |
| — |
| — |
| 36,432 |
| ||||
Other amortization |
| 3,686 |
| 2,595 |
| (921 | ) | — |
| — |
| — |
| 5,360 |
|
| 1,167 |
| 660 |
| 461 |
| — |
| — |
| — |
| 2,288 |
| ||||
Changes in deferred income taxes |
| 45,875 |
| 20,643 |
| 8,202 |
| — |
| — |
| — |
| 74,720 |
|
| 7,674 |
| 2,849 |
| 2,998 |
| — |
| — |
| — |
| 13,521 |
| ||||
Changes in tax credits, net |
| 1,992 |
| 132 |
| (185 | ) | — |
| — |
| — |
| 1,939 |
|
| 592 |
| 154 |
| 9 |
| — |
| — |
| — |
| 755 |
| ||||
Allowance for equity funds used during construction |
| (4,081 | ) | (330 | ) | (406 | ) | — |
| — |
| — |
| (4,817 | ) |
| (960 | ) | (83 | ) | (201 | ) | — |
| — |
| — |
| (1,244 | ) | ||||
Increase in cash overdraft |
| — |
| — |
| 884 |
| — |
| — |
| — |
| 884 |
| |||||||||||||||||||
Decrease in overdraft |
| — |
| (2,527 | ) | (161 | ) | — |
| — |
| — |
| (2,688 | ) | |||||||||||||||||||
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Decrease (increase) in accounts receivable |
| (11,894 | ) | 1,469 |
| 861 |
| — |
| — |
| 2,780 |
| (6,784 | ) | |||||||||||||||||||
Increase in accrued unbilled revenues |
| (8,453 | ) | (1,116 | ) | (2,021 | ) | — |
| — |
| — |
| (11,590 | ) | |||||||||||||||||||
Increase in fuel oil stock |
| (41,259 | ) | (673 | ) | (637 | ) | — |
| — |
| — |
| (42,569 | ) | |||||||||||||||||||
Decrease (increase) in materials and supplies |
| (1,071 | ) | (282 | ) | 968 |
| — |
| — |
| — |
| (385 | ) | |||||||||||||||||||
Increase in accounts receivable |
| (3,982 | ) | (1,192 | ) | (3,927 | ) | — |
| — |
| (2,170 | ) | (11,271 | ) | |||||||||||||||||||
Decrease (increase) in accrued unbilled revenues |
| (10,127 | ) | (514 | ) | 1,239 |
| — |
| — |
| — |
| (9,402 | ) | |||||||||||||||||||
Decrease (increase) in fuel oil stock |
| 6,381 |
| (685 | ) | (9,209 | ) | — |
| — |
| — |
| (3,513 | ) | |||||||||||||||||||
Increase in materials and supplies |
| (38 | ) | (415 | ) | (612 | ) | — |
| — |
| — |
| (1,065 | ) | |||||||||||||||||||
Increase in regulatory assets |
| (1,801 | ) | (1,144 | ) | (324 | ) | — |
| — |
| — |
| (3,269 | ) |
| (6,518 | ) | (708 | ) | (646 | ) | — |
| — |
| — |
| (7,872 | ) | ||||
Increase (decrease) in accounts payable |
| (19,259 | ) | 1,664 |
| 1,594 |
| — |
| — |
| — |
| (16,001 | ) | |||||||||||||||||||
Changes in prepaid and accrued income and utility revenue taxes |
| (45,651 | ) | (2,567 | ) | (6,984 | ) | — |
| — |
| — |
| (55,202 | ) | |||||||||||||||||||
Decrease in accounts payable |
| (35,481 | ) | (1,603 | ) | (5,039 | ) | — |
| — |
| — |
| (42,123 | ) | |||||||||||||||||||
Changes in prepaid and accrued income taxes and utility revenue taxes |
| (2,688 | ) | 270 |
| 2,658 |
| — |
| — |
| — |
| 240 |
| |||||||||||||||||||
Changes in other assets and liabilities |
| 21,933 |
| (20,580 | ) | 2,845 |
| (2 | ) | (1 | ) | (2,780 | ) | 1,415 |
|
| (19,159 | ) | (2,247 | ) | (2,145 | ) | — |
| 3 |
| 2,170 |
| (21,378 | ) | ||||
Net cash provided by (used in) operating activities |
| 56,061 |
| 39,411 |
| 31,699 |
| (8 | ) | (13 | ) | (10,711 | ) | 116,439 |
|
| (25,255 | ) | 9,033 |
| (4,376 | ) | (2 | ) | — |
| (7,032 | ) | (27,632 | ) | ||||
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Capital expenditures |
| (86,893 | ) | (22,998 | ) | (21,249 | ) | — |
| — |
| — |
| (131,140 | ) |
| (25,594 | ) | (6,752 | ) | (5,210 | ) | — |
| — |
| — |
| (37,556 | ) | ||||
Contributions in aid of construction |
| 10,079 |
| 5,073 |
| 1,623 |
| — |
| — |
| — |
| 16,775 |
|
| 3,218 |
| 2,122 |
| 409 |
| — |
| — |
| — |
| 5,749 |
| ||||
Other |
| 657 |
| — |
| — |
| — |
| — |
| — |
| 657 |
| |||||||||||||||||||
Advances from (to) affiliates |
| 13,050 |
| — |
| (8,500 | ) | — |
| — |
| (4,550 | ) | — |
|
| — |
| 150 |
| 12,500 |
| — |
| — |
| (12,650 | ) | — |
| ||||
Net cash used in investing activities |
| (63,107 | ) | (17,925 | ) | (28,126 | ) | — |
| — |
| (4,550 | ) | (113,708 | ) | |||||||||||||||||||
Net cash provided by (used in) investing activities |
| (22,376 | ) | (4,480 | ) | 7,699 |
| — |
| — |
| (12,650 | ) | (31,807 | ) | |||||||||||||||||||
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Common stock dividends |
| (38,360 | ) | (7,710 | ) | (3,001 | ) | — |
| — |
| 10,711 |
| (38,360 | ) |
| (17,640 | ) | (4,031 | ) | (3,001 | ) | — |
| — |
| 7,032 |
| (17,640 | ) | ||||
Preferred stock dividends of HECO and subsidiaries |
| (810 | ) | (400 | ) | (286 | ) | — |
| — |
| — |
| (1,496 | ) |
| (270 | ) | (134 | ) | (95 | ) | — |
| — |
| — |
| (499 | ) | ||||
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |
| 8,500 |
| (13,050 | ) | — |
| — |
| — |
| 4,550 |
| — |
| |||||||||||||||||||
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |
| (12,650 | ) | — |
| — |
| — |
| — |
| 12,650 |
| — |
| |||||||||||||||||||
Other |
| (1,005 | ) | (279 | ) | (125 | ) | — |
| — |
| — |
| (1,409 | ) |
| (4 | ) | — |
| — |
| — |
| — |
| — |
| (4 | ) | ||||
Net cash used in financing activities |
| (31,675 | ) | (21,439 | ) | (3,412 | ) | — |
| — |
| 15,261 |
| (41,265 | ) |
| (30,564 | ) | (4,165 | ) | (3,096 | ) | — |
| — |
| 19,682 |
| (18,143 | ) | ||||
Net increase (decrease) in cash and cash equivalents |
| (38,721 | ) | 47 |
| 161 |
| (8 | ) | (13 | ) | — |
| (38,534 | ) |
| (78,195 | ) | 388 |
| 227 |
| (2 | ) | — |
| — |
| (77,582 | ) | ||||
Cash and cash equivalents, beginning of period |
| 70,981 |
| 2,006 |
| 474 |
| 98 |
| 19 |
| — |
| 73,578 |
|
| 121,019 |
| 1,229 |
| 594 |
| 89 |
| 5 |
| — |
| 122,936 |
| ||||
Cash and cash equivalents, end of period |
| $ | 32,260 |
| 2,053 |
| 635 |
| 90 |
| 6 |
| — |
| $ | 35,044 |
|
| $ | 42,824 |
| 1,617 |
| 821 |
| 87 |
| 5 |
| — |
| $ | 45,354 |
|
Hawaiian Electric Company, Inc. and Subsidiaries
Consolidating Statement of Cash Flows (unaudited)
NineThree months ended September 30, 2009March 31, 2010
(in thousands) |
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Reclassifications |
| HECO |
|
| HECO |
| HELCO |
| MECO |
| RHI |
| UBC |
| Elimination |
| HECO |
| ||||
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Net income (loss) |
| $ | 56,951 |
| 10,879 |
| 8,048 |
| (11 | ) | (147 | ) | (18,083 | ) | $ | 57,637 |
|
| $ | 18,322 |
| 4,394 |
| 1,135 |
| (2 | ) | (5 | ) | (5,293 | ) | $ | 18,551 |
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Equity in earnings |
| (18,158 | ) | — |
| — |
| — |
| — |
| 18,083 |
| (75 | ) |
| (5,318 | ) | — |
| — |
| — |
| — |
| 5,293 |
| (25 | ) | ||||
Common stock dividends received from subsidiaries |
| 4,339 |
| — |
| — |
| — |
| — |
| (4,264 | ) | 75 |
|
| 5,059 |
| — |
| — |
| — |
| — |
| (5,034 | ) | 25 |
| ||||
Depreciation of property, plant and equipment |
| 61,523 |
| 24,754 |
| 22,129 |
| — |
| — |
| — |
| 108,406 |
|
| 21,913 |
| 9,126 |
| 7,603 |
| — |
| — |
| — |
| 38,642 |
| ||||
Other amortization |
| 2,804 |
| 2,554 |
| 2,344 |
| — |
| — |
| — |
| 7,702 |
|
| 1,124 |
| 862 |
| 111 |
| — |
| — |
| — |
| 2,097 |
| ||||
Changes in deferred income taxes |
| 6,081 |
| 5,414 |
| 1,037 |
| — |
| — |
| — |
| 12,532 |
|
| (939 | ) | (294 | ) | (601 | ) | — |
| — |
| — |
| (1,834 | ) | ||||
Changes in tax credits, net |
| 115 |
| (332 | ) | (284 | ) | — |
| — |
| — |
| (501 | ) |
| 804 |
| 60 |
| (88 | ) | — |
| — |
| — |
| 776 |
| ||||
Allowance for equity funds used during construction |
| (8,254 | ) | (1,530 | ) | (569 | ) | — |
| — |
| — |
| (10,353 | ) |
| (1,559 | ) | (95 | ) | (119 | ) | — |
| — |
| — |
| (1,773 | ) | ||||
Increase in cash overdraft |
| — |
| — |
| 681 |
| — |
| — |
| — |
| 681 |
| |||||||||||||||||||
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Decrease in accounts receivable |
| 16,450 |
| 5,969 |
| 6,017 |
| — |
| 11 |
| 3,976 |
| 32,423 |
|
| 2,454 |
| 1,026 |
| 463 |
| — |
| — |
| 3,385 |
| 7,328 |
| ||||
Decrease in accrued unbilled revenues |
| 8,199 |
| 4,319 |
| 1,665 |
| — |
| — |
| — |
| 14,183 |
| |||||||||||||||||||
Decrease (increase) in accrued unbilled revenues |
| (641 | ) | (156 | ) | 311 |
| — |
| — |
| — |
| (486 | ) | |||||||||||||||||||
Decrease (increase) in fuel oil stock |
| 14,029 |
| (377 | ) | (3,826 | ) | — |
| — |
| — |
| 9,826 |
|
| (26,075 | ) | 918 |
| (1,349 | ) | — |
| — |
| — |
| (26,506 | ) | ||||
Decrease (increase) in materials and supplies |
| (2,284 | ) | 286 |
| 173 |
| — |
| — |
| — |
| (1,825 | ) |
| (1,215 | ) | (299 | ) | 266 |
| — |
| — |
| — |
| (1,248 | ) | ||||
Increase in regulatory assets |
| (7,460 | ) | (2,973 | ) | (3,396 | ) | — |
| — |
| — |
| (13,829 | ) |
| (771 | ) | (293 | ) | (79 | ) | — |
| — |
| — |
| (1,143 | ) | ||||
Increase (decrease) in accounts payable |
| 2,600 |
| (8,992 | ) | 1,440 |
| — |
| — |
| — |
| (4,952 | ) |
| 2,123 |
| (67 | ) | 1,119 |
| — |
| — |
| — |
| 3,175 |
| ||||
Changes in prepaid and accrued income and utility revenue taxes |
| (42,546 | ) | (9,342 | ) | (10,500 | ) | — |
| — |
| — |
| (62,388 | ) | |||||||||||||||||||
Changes in prepaid and accrued income taxes and utility revenue taxes |
| (38,496 | ) | (6,680 | ) | (6,067 | ) | — |
| — |
| — |
| (51,243 | ) | |||||||||||||||||||
Changes in other assets and liabilities |
| 12,299 |
| (4,439 | ) | (509 | ) | (13 | ) | (2 | ) | (3,976 | ) | 3,360 |
|
| 3,883 |
| 3,533 |
| (755 | ) | (1 | ) | 1 |
| (3,385 | ) | 3,276 |
| ||||
Net cash provided by (used in) operating activities |
| 106,688 |
| 26,190 |
| 23,769 |
| (24 | ) | (138 | ) | (4,264 | ) | 152,221 |
|
| (19,332 | ) | 12,035 |
| 2,631 |
| (3 | ) | (4 | ) | (5,034 | ) | (9,707 | ) | ||||
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Capital expenditures |
| (159,900 | ) | (55,283 | ) | (22,481 | ) | — |
| — |
| — |
| (237,664 | ) |
| (25,488 | ) | (4,212 | ) | (4,489 | ) | — |
| — |
| — |
| (34,189 | ) | ||||
Contributions in aid of construction |
| 4,253 |
| 1,993 |
| 1,226 |
| — |
| — |
| — |
| 7,472 |
|
| 1,339 |
| 1,546 |
| 844 |
| — |
| — |
| — |
| 3,729 |
| ||||
Advances from (to) affiliates |
| 36,650 |
| — |
| 2,000 |
| — |
| — |
| (38,650 | ) | — |
|
| 4,400 |
| — |
| 3,000 |
| — |
| — |
| (7,400 | ) | — |
| ||||
Other |
| 221 |
| — |
| — |
| — |
| 119 |
| — |
| 340 |
| |||||||||||||||||||
Investment in consolidated subsidiary |
| (25 | ) | — |
| — |
| — |
| — |
| 25 |
| — |
| |||||||||||||||||||
Net cash provided by (used in) investing activities |
| (118,801 | ) | (53,290 | ) | (19,255 | ) | — |
| 119 |
| (38,625 | ) | (229,852 | ) | |||||||||||||||||||
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Net cash used in investing activities |
| (19,749 | ) | (2,666 | ) | (645 | ) | — |
| — |
| (7,400 | ) | (30,460 | ) | |||||||||||||||||||
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||
Common stock dividends |
| (32,756 | ) | — |
| (4,264 | ) | — |
| — |
| 4,264 |
| (32,756 | ) |
| (15,150 | ) | (3,434 | ) | (1,600 | ) | — |
| — |
| 5,034 |
| (15,150 | ) | ||||
Preferred stock dividends of HECO and subsidiaries |
| (810 | ) | (400 | ) | (286 | ) | — |
| — |
| — |
| (1,496 | ) |
| (270 | ) | (134 | ) | (95 | ) | — |
| — |
| — |
| (499 | ) | ||||
Proceeds from issuance of long-term debt |
| 90,000 |
| 63,186 |
| — |
| — |
| — |
| — |
| 153,186 |
| |||||||||||||||||||
Proceeds from issuance of common stock |
| — |
| — |
| — |
| — |
| 25 |
| (25 | ) | — |
| |||||||||||||||||||
Net increase in short-term borrowings from affiliate with original maturities of three months or less |
| (32,850 | ) | (36,650 | ) | — |
| — |
| — |
| 38,650 |
| (30,850 | ) | |||||||||||||||||||
Decrease in cash overdraft |
| (9,847 | ) | — |
| — |
| — |
| — |
| — |
| (9,847 | ) | |||||||||||||||||||
Other |
| (1,018 | ) | (2 | ) | (1 | ) | — |
| — |
| — |
| (1,021 | ) | |||||||||||||||||||
Net cash provided by (used in) financing activities |
| 12,719 |
| 26,134 |
| (4,551 | ) | — |
| 25 |
| 42,889 |
| 77,216 |
| |||||||||||||||||||
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |
| 10,748 |
| (4,400 | ) | — |
| — |
| — |
| 7,400 |
| 13,748 |
| |||||||||||||||||||
Net cash used in financing activities |
| (4,672 | ) | (7,968 | ) | (1,695 | ) | — |
| — |
| 12,434 |
| (1,901 | ) | |||||||||||||||||||
Net increase (decrease) in cash and cash equivalents |
| 606 |
| (966 | ) | (37 | ) | (24 | ) | 6 |
| — |
| (415 | ) |
| (43,753 | ) | 1,401 |
| 291 |
| (3 | ) | (4 | ) | — |
| (42,068 | ) | ||||
Cash and cash equivalents, beginning of period |
| 2,264 |
| 3,148 |
| 1,349 |
| 123 |
| 17 |
| — |
| 6,901 |
|
| 70,981 |
| 2,006 |
| 474 |
| 98 |
| 19 |
| — |
| 73,578 |
| ||||
Cash and cash equivalents, end of period |
| $ | 2,870 |
| 2,182 |
| 1,312 |
| 99 |
| 23 |
| — |
| $ | 6,486 |
|
| $ | 27,228 |
| 3,407 |
| 765 |
| 95 |
| 15 |
| — |
| $ | 31,510 |
|
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” incorporated by referenceincluded in HEI’s and HECO’s Form 10-K for the year ended December 31, 20092010 and should be read in conjunction with the 20092010 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI’s and HECO’s Form 10-K for 2010, as well as the quarterly (as of and for the three months ended March 31, 2011) financial statements and notes thereto included in the Forms 10-Q for the first, second and third quarters of 2010.this Form 10-Q.
RESULTS OF OPERATIONS
(in thousands, except per |
| Three months ended |
| % |
| Primary reason(s) for |
| ||||
share amounts) |
| 2010 |
| 2009 |
| change |
| significant change* |
| ||
Revenues |
| $ | 694,541 |
| $ | 620,313 |
| 12 |
| Increase for the electric utility segment, partly offset by a decrease for the bank segment |
|
|
|
|
|
|
|
|
|
|
| ||
Operating income |
| 72,631 |
| 68,639 |
| 6 |
| Increase for the bank segment, partly offset by a decrease for the electric utility segment |
| ||
|
|
|
|
|
|
|
|
|
| ||
Net income for common stock |
| 32,449 |
| 33,483 |
| (3 | ) | Higher operating income, more than offset by lower AFUDC, higher “interest expense—other than on deposit liabilities and other bank borrowings” and higher income taxes** |
| ||
|
|
|
|
|
|
|
|
|
| ||
Basic earnings per common share |
| 0.35 |
| $ | 0.37 |
| (5 | ) | Lower net income and higher weighted average shares outstanding |
| |
|
|
|
|
|
|
|
|
|
| ||
Weighted-average number of common shares outstanding |
| 93,699 |
| 91,522 |
| 2 |
| Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans |
| ||
(in thousands, except per |
| Nine months ended |
| % |
| Primary reason(s) for |
|
| Three months ended |
| % |
| Primary reason(s) for |
| ||||||||
share amounts) |
| 2010 |
| 2009 |
| change |
| significant change* |
|
| 2011 |
| 2010 |
| change |
| significant change* |
| ||||
Revenues |
| $ | 1,969,245 |
| $ | 1,690,011 |
| 17 |
| Increase for the electric utility segment, partly offset by a decrease for the bank segment |
|
| $ | 710,633 |
| $ | 619,040 |
| 15 |
| Increase for the electric utility segment, partly offset by a decrease for the bank segment |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Operating income |
| 196,969 |
| 148,352 |
| 33 |
| Increase for the electric utility and the bank segments |
|
| 63,375 |
| 60,707 |
| 4 |
| Increase for the electric utility segment, partly offset by a decrease for the bank segment |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Net income for common stock |
| 88,837 |
| 69,357 |
| 28 |
| Higher operating income, partly offset by lower AFUDC, higher “interest expense—other than on deposit liabilities and other bank borrowings” and higher income taxes** |
|
| 28,462 |
| 27,126 |
| 5 |
| Higher operating income, lower “interest expense—other than on deposit liabilities and other bank borrowings”, partly offset by higher income taxes** and lower AFUDC |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Basic earnings per common share |
| $ | 0.95 |
| $ | 0.76 |
| 25 |
| Higher net income, partly offset by higher weighted average shares outstanding |
|
| $ | 0.30 |
| $ | 0.29 |
| 3 |
| Higher net income, partly offset by higher weighted average shares outstanding |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Weighted-average number of common shares outstanding |
| 93,148 |
| 91,173 |
| 2 |
| Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans |
|
| 94,817 |
| 92,572 |
| 2 |
| Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans |
|
* Also, see segment discussions which follow.
** The Company’s effective tax rates (federal and state) for the third quarters of 2010 and 2009 were 38% and 36%, respectively. The Company’s effective tax rates (federal(combined federal and state) for the first nine monthsquarters of 20102011 and 20092010 were 36% and 34%, respectively..
Tablethe Company initiated aggressive strategies to set both the utilities and ASB on a new course — the utilities entered into an agreement with the State to create a clean energy future for Hawaii and ASB set new performance standards. In 2010 and the first quarter 2011, the Company made major progress on these strategies and the bank demonstrated improved profitability and reduced risk (see segment discussions below). Together, HEI’s unique combination of Contentsa utility and bank continues to provide the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries while providing an attractive dividend for investors. Challenges for 2011 include the impact on the Hawaii economy and tourism of the devastating March 2011 earthquakes and tsunami in Japan and the volatile interest rate environment which followed.
DividendsDividends.. The payout ratios for 20092010 and the first nine monthsquarter of 20102011 were 137%102% and 98%103%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.
Economic conditions.
Note: The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; Blue Chip Financial Forecasts;U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS®; Bureau of Economic Analysis and national and local newspapers).
Although theThe U.S. economy, has grownas measured by gross domestic product (GDP), is estimated to increase by 2.6% and 3.2% for four consecutivethe first and second quarters the pace of economic expansion remains relatively weak. According2011, respectively, compared to the October 2010immediately preceding quarter, respectively, according to the April 2011 Blue Chip Economic Indicators, gross domestic product (GDP) grewmarking the second consecutive month the consensus forecast of growth has been lowered. According to the “advance” estimate released by the Bureau of Economic Analysis on April 28, 2011, real GDP increased at a seasonally adjustedan annual rate of 1.7%1.8% in the second quarter of 2010 and is estimated to be 1.9% in the third quarter. The latest projection for the fourth quarter is 2.3% and for the first quarter of 2011 from the fourth quarter of 2010. The decline in the forecast of real GDP growth is 2.5%.likely from a combination of several factors such as the increase in the projections for inflation, looming cuts in government spending and a variety of monthly economic activity indicators that failed to meet consensus expectations such as consumer spending, construction activity and business investments.
Crude oil prices are currently at their highest level since 2008. The GDP consensus forecast continues to predict gradually improving economic growth through the first halfprice of a barrel of West Texas Intermediate crude oil averaged $89 in February 2011 and $103 in March 2011 and settled at $113.93 on April 29, 2011. The U.S. Energy Information Administration April 2011 Short-Term Energy Outlook is projecting an average of $106 in 2011.
Japan’sMeanwhile, the Hawaii economy grew modestlyreceived an unexpectedly strong boost from the visitor industry in 2010. Through the secondfirst quarter of 2010 with2011, tourism continued its strong recovery posting a seasonally annual adjusted rate of 1.5%. Growth in the third quarter was likely better due to improved consumer spending as a result of government subsidies. However, difficulties to sustain this growth lie ahead for the remainder of the year as real exports decline due to the strong yen, industrial production slows and the effects of the governmental fiscal stimulus dissipate. The Bank of Japan’s cutting of interest rates to zero and announcing a $60 billion fund to purchase financial assets signify concern that more government assistance is needed to bolster the economy.
Economic growth in both the U.S. and Japan, albeit slow, are positive indicators for the Hawaii economy. State economists are projecting that Hawaii’s economy will continue to expand but at a modest pace through 2011.
The outlook for two of Hawaii’s major industries, visitors and construction, remains mixed. August 2010 marks the ninth consecutive month of positive growth since December 2009 in visitors by air with August 2010 capping off a relatively strong summer as compared to last year. Boosted by additional air seat capacity, total visitor arrivals were up 7.0% through the first eight months of 2010 as compared to the same period in 2009. Total visitor expenditures rose by 12.7% over the first eight months due to the9.1% increase in visitor arrivals and higher average dailya 16.9% increase in visitor spending. Givenexpenditures compared to the modestfirst quarter of 2010. The strong gain in the first two months of the year was followed by significant decreases in visitor bookings from Japan following the devastating events of the March 11, 2011 earthquake, tsunami and nuclear crisis. All other markets continued to see an increase in arrivals over 2010. The long-term global and local effects of these tragic events in Japan remain uncertain. In light of these events, the visitor industry has taken initiatives to target growth prospectsfrom other major markets to offset the decline from Japan, including in Hawaii’s primaryconnection with the Asia Pacific Economic Cooperation summit in November 2011 that is anticipated to bring about 15,000 world government and business leaders from 21 economies to Hawaii.
The strong boost in visitor markets, UHERO is projecting annual visitor arrivalsspending before the tsunami-related slowdown were positives for 2010the economy, but economic growth has been slow to be up by 6.7% over 2009spread to other areas. In particular, construction activity and annual expenditures to be up by 8.7%. DBEDT poststhe job market have not realized similar recovery predictions with arrivals at 4.6% and expenditures up 8.2% for 2010.improvements.
Hawaii’s seasonally adjusted unemployment rate through March 2011 was 6.3%, which remains well below the national unemployment rate of 8.8%. Furloughs for state and county employees, which were implemented for the fiscal year beginning July 1, 2010, continue for some state agencies and three out of the four counties. However, six of seven bargaining units of the state’s largest public union recently ratified a new contract that will end furloughs as of July 1, 2011 in exchange for a reduction in pay and an increased share of health care premiums as a step towards balancing the state and county budgets.
According to local economists, private construction industry continueshas stabilized and is headed for limited growth. The big driver in construction on Oahu is expected to struggle, but some positive signs have emergedbe rail transit and other government infrastructure spending. The rail project is projected to lead to a sharp increase in recent months. The declineconstruction later in permitting has slowed and, following the delay in implementing federal stimulus spending, public contracts are now making a contribution2011, assuming no additional delays to the industry. For the first eight months of 2010, the value of total private building permits in Hawaii declined by 5.8% from the same period in 2009 (values for permits for new residential construction and additions and alterations declined, but increased for commercial and industrial permits). Construction jobs were down 7.5% during this period, a slight improvement over the previous quarter.schedule.
Hawaii’s housing market continues on its path to recovery following a challenging 2009. As of September 30, 2010, Oahube mixed with first quarter 2011 home and condominiums sales are up 20.4% for single-family homes and 21.4% for condominiums. Median saleshigher across the state while prices are also showing improvement with increases of 4.2% over last year in single-family homes, but are flat for condominiums. Average days on the market have reduced significantly on Oahucontinue to 32 days forfall.
Interest rates during the first nine monthsquarter of 2010 compared to 52 days for the same period last year for single-family homes. Similarly on Maui, Kauai2011, while volatile, fluctuated within a narrow range. Despite inflationary pressures from higher commodity prices and the island of Hawaii, sales volume is upincreasing momentum in the 30% range through August 2010, but median salesglobal economic recovery, U.S. prices lag behind last year’s prices for(excluding-food and energy) increased modestly. Excess capacity within the three islands. Housing recovery should move forward slowly asU.S. economy allowed Federal Open Market Committee members to retain a very accommodative monetary policy, which also kept short-term rates low. Bloomberg US forecast of economists project slightly higher rates by the end of 2011 with short-term rates rising faster than long-term rates. This compression in the yield curve could pressure bank net interest rates remain low and affordability associated with lower prices present favorable purchase conditions. Inventory associated withmargins if the foreclosure situation and depressed prices of distressed sales, however, may hamperchanges are more than transitory shifts in the recovery.
The job market continues to struggle and is expected to be the last aspectshape of the economy to show signs of recovery. Hawaii’s seasonally adjusted unemployment rate in September 2010 was 6.3% and remains well belowyield curve.
the national unemployment rate of 9.6% and is sixth lowest in the nation, but is high relative to historical periods. DBEDT projects total wage and salary jobs will decline by (0.6)% through 2010, followed by a modest 1% increase in 2011. Total jobs were down 0.8% in the first eight months of 2010 as compared to the same period last year. This reflects a slight improvement from the 1.4% decline in the first five months of 2010. Furloughs for county employees in all four counties were implemented for the fiscal year beginning July 1, 2010 and state employee furloughs, with the exception of teachers, continue.
Real personal income (which includes unemployment compensation) growth in Hawaii in 2010Hawaii’s economic recovery is expected to be 0.4% accordinggrow in strength during 2011, albeit modest by historical standards, as it spreads beyond the visitor industry. Risks to UHERO’s estimateHawaii’s economic improvement could come from delays in the Oahu rail project, rising energy and 0.3% accordingconsumer prices, government spending curtailments as the federal and local governments are challenged with balancing their budgets and political unrest and other shocks to DBEDT’s estimate. This follows two consecutive yearsthe U.S. or world economies.
Major tax legislation in 2010. Congress enacted several bills in 2010 dealing with health care reform, job creation and economic stimulus. Two bills enacted contained major tax provisions directly affecting the Company. The first was the Small Business Jobs Act of decline2010, which included the extension of 50% bonus depreciation for all businesses retroactive to January 1, 2010. The second was the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, which included an extension of 50% bonus depreciation for property placed into service before January 1, 2013 and 100% bonus depreciation for property acquired between September 8, 2010 and January 1, 2012. For the Company, the bonus depreciation provisions result in real personal income.an estimated increase in federal tax depreciation of $75 million for 2010 and $165 million for 2011, primarily attributable to HECO and its subsidiaries. The Company continues to evaluate the impacts of bonus depreciation in light of the Internal Revenue Services’ guidance issued on March 29, 2011, regarding bonus depreciation, qualifying property and its transition rules. A number of energy-related tax breaks were also extended, including the biodiesel credit through 2012 and the grants in lieu of the electricity production credit through 2011.
The priceCompany will continue to analyze these 2010 Acts for their impacts on results of a barrel of crude oil has fluctuated steadily over the year in the $70-$83 trading rangeoperations, financial condition and is expected to average $79 per barrel in the fourth quarter of 2010 according to the U.S. Energy Information Administration October 2010 Short-Term Energy Outlook.
Interest rates remained low during the first nine months of 2010cash flows and are expected to remain low for the remainder of the year. The low level of interest rates continues to put downward pressure on yields of both loans and investments. Mortgage rates are currently seeing historical low levels, helping fuel some of the recovery in the housing market.opportunities they present.
Retirement benefits. For the first nine monthsquarter of 2010,2011, the Company’s and HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a gain, after investment management fees, of 7.3%4.2%. The market value of the defined benefit retirement plans’ assets of the Company as of September 30, 2010March 31, 2011 was $915 million$1.0 billion compared to $874$983 million at December 31, 2009,2010, an increase of approximately $41$57 million. The market value of the defined benefit retirement plans’ assets of HECO and its subsidiaries as of September 30, 2010March 31, 2011 was $829$944 million compared to $792$891 million at December 31, 2009,2010, an increase of approximately $37$53 million.
The CompanyHEI and HECO and its subsidiaries estimate that the cash funding for their qualified defined benefit pension plans in 20102011 will be about $28$1 million and $27$59 million, respectively, which should fully satisfy the minimum required contribution, including requirements of the utilities’ pension tracking mechanisms and the plans’ funding policy. Further,The increase in June 2010,expected contributions is driven by the President signedminimum funding requirements under the PreservationPension Protection Act of Access to Care for Medicare Beneficiaries and Pension Relief Act, which provides, among other things, limited funding relief for defined benefit pension plans.2006. The Companyincrease is currently analyzing options with regard to this law that would havea combination of the effect of lowering HECO’s anticipatedfunding the plan based on high-quality bond rates as of the valuation date, including a 7-year amortization of the excess of target liability over valuation assets, the decrease in discount rates from 2010 contributions to 2011 that increased the pension plan by about $3 million.measure of target liability and the depletion of credit balances that were used to moderate the increases in minimum funding related to prior years.
Other factors could cause changes to the required contribution levels. The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels more conservative assumptions must be used to value obligations and restrictions on participant benefit accruals may be placed on the plans. If the plans fall below these thresholds, then, to avoid adverse consequences, funds in excess of the minimum required contribution may be contributed to the plan trust.
The following table reflects the sensitivity to the qualified defined benefit pension projected benefit obligation (PBO) as of December 31, 2010, associated with a change in the pension benefits discount rate actuarial assumption by the indicated basis points and constitutes “forward-looking statements.”
|
|
| ||||
|
|
|
| |||
|
|
|
|
Commitments and contingenciescontingencies.. See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretationsinterpretations.. See Note 12 of HEI’s “Notes to Consolidated Financial Statements.”
“Other” segment.
|
| Three months ended |
| % |
|
|
| ||||
(in thousands) |
| 2010 |
| 2009 |
| change |
| Primary reason(s) for significant change |
| ||
Revenues |
| $ | (14 | ) | $ | (74 | ) | NM |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Operating loss |
| (3,101 | ) | (3,222 | ) | NM |
| Lower retirement benefit expense, partly offset by higher compensation expense and bank fees |
| ||
|
|
|
|
|
|
|
|
|
| ||
Net loss |
| (4,824 | ) | (4,354 | ) | NM |
| See explanation for operating loss and higher interest expense due in part to higher borrowings |
| ||
|
| Nine months ended |
| % |
|
|
|
| Three months ended |
| % |
|
|
| ||||||||
(in thousands) |
| 2010 |
| 2009 |
| change |
| Primary reason(s) for significant change |
|
| 2011 |
| 2010 |
| change |
| Primary reason(s) for significant change |
| ||||
Revenues |
| $ | (62 | ) | $ | (121 | ) | NM |
|
|
|
| $ | (15 | ) | $ | 15 |
| NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Operating loss |
| (10,353 | ) | (9,368 | ) | NM |
| Higher compensation expense and bank fees, partly offset by lower retirement benefit expense |
|
| (3,587 | ) | (3,673 | ) | NM |
| Lower administrative and general expenses |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Net loss |
| (13,997 | ) | (13,010 | ) | NM |
| See explanation for operating loss and higher interest expense due in part to higher borrowings, partly offset by tax adjustments |
|
| (4,578 | ) | (4,662 | ) | NM |
| See explanation for operating loss |
|
NM Not meaningful.
The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; Pacific Energy Conservation Services, Inc., a contract services company which provided windfarm operational and maintenance services to an affiliated electric utility until the windfarm was dismantled in the fourth quarter of 2010;2010 (dissolved in April 2011); HEI Properties, Inc., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.
FINANCIAL CONDITION
Liquidity and capital resourcesresources.. The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements infor the foreseeable future.
The consolidated capital structure of HEI (excluding ASB’s deposit liabilities and other bank borrowings) was as follows as of the dates indicated:follows:
(dollars in millions) |
| September 30, 2010 |
| December 31, 2009 |
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Short-term borrowings—other than bank |
| $ | 27 |
| 1 | % | $ | 42 |
| 2 | % |
| $ | — |
| — | % | $ | 25 |
| 1 | % |
Long-term debt, net—other than bank |
| 1,365 |
| 47 |
| 1,365 |
| 47 |
|
| 1,440 |
| 49 |
| 1,365 |
| 47 |
| ||||
Preferred stock of subsidiaries |
| 34 |
| 1 |
| 34 |
| 1 |
|
| 34 |
| 1 |
| 34 |
| 1 |
| ||||
Common stock equity |
| 1,480 |
| 51 |
| 1,442 |
| 50 |
|
| 1,497 |
| 50 |
| 1,484 |
| 51 |
| ||||
|
| $ | 2,906 |
| 100 | % | $ | 2,883 |
| 100 | % |
| $ | 2,971 |
| 100 | % | $ | 2,908 |
| 100 | % |
HEI’s short-term borrowings and HEI’s line of credit facility were as follows:
|
| Three months ended |
| Balance |
| |||||
(in millions) |
| Average balance |
| March 31, 2011 |
| December 31, 2010 |
| |||
Short-term borrowings(1) |
|
|
|
|
|
|
| |||
HEI commercial paper |
| $ | 22 |
| $ | — |
| $ | 25 |
|
HEI line of credit draws |
| — |
| — |
| — |
| |||
|
| $ | 22 |
| $ | — |
| $ | 25 |
|
Line of credit facility (expiring May 7, 2013) |
|
|
| $ | 125 |
| $ | 125 |
| |
Undrawn capacity under HEI’s line of credit facility |
|
|
| 125 |
| 125 |
|
(1)This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are discussed below under “Electric utility—Financial Condition—Liquidity and capital resources. At April 29, 2011, HEI had no outstanding commercial paper and its line of credit facility was undrawn.
HEI utilizes short-term debt, typically commercial paper, to support normal operations, to refinance commercial paper, to retire long-term debt, to pay dividends and for other temporary requirements. HEI also periodically makes short-term loans to HECO to meet HECO’s cash requirements, including the funding of loans by HECO to HELCO and MECO, but no such short-term loans to HECO were outstanding as of September 30, 2010.March 31, 2011. HEI periodically utilizes long-term debt, historically consisting of medium-term notes and other unsecured indebtedness, to fund
investments in and loans to its subsidiaries to support their capital improvement or other requirements, to repay long-term and short-term indebtedness and for other corporate purposes.
Effective May 7, 2010, HEI entered into a revolving unsecurednoncollateralized credit agreement establishing a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on May 7, 2013, with a syndicate of eight financial institutions. See Note 13 of HEI’s “Notes to Consolidated Financial Statements.”
The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HEI’s Issuer Rating (e.g., from BBB/Baa2 to BBB-/Baa3 by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively) would result in a commitment fee increase of 5 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 10 basis points and an interest rate decrease of 25 basis points on any drawn amounts. The agreement contains customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults, HEI’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements may result in an event of default. For example, under its agreement, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 19%20% as of September 30, 2010,March 31, 2011, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (Net(actual Net Worth of $1.5 billion as of September 30, 2010,March 31, 2011, as calculated under the agreement).
In addition to their impact on pricing under HEI’s short-term borrowings and HEI’s linecredit agreement, the rating of credit facility were as follows for the period and as of the dates indicated:
|
| Nine months ended |
| Balance |
| |||||
(in millions) |
| Average balance |
| September 30, 2010 |
| December 31, 2009 |
| |||
Short-term borrowings(1) |
|
|
|
|
|
|
| |||
HEI commercial paper |
| $ | 38 |
| $ | 27 |
| $ | 42 |
|
HEI line of credit draws |
| — |
| — |
| — |
| |||
|
| $ | 38 |
| $ | 27 |
| $ | 42 |
|
Line of credit facility (expiring May 7, 2013) |
|
|
| $ | 125 |
| $ | 100 |
| |
Undrawn capacity under HEI’s line of credit facility |
|
|
| 125 |
| 100 |
|
(1)This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are discussed below under “Electric utility—Financial Condition—Liquidity and capital resources. At October 29, 2010, HEI’s outstanding commercial paper balance was $37 million and its line of credit facility was undrawn.
Management believes that, if HEI’s commercial paper and debt securities could significantly impact the ability of HEI to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (i.e., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings wereof HEI securities. On July 30, 2010, Moody’s changed HEI’s rating outlook to stable from negative and affirmed HEI’s long-term and short-term (commercial paper) ratings, indicating that the ratings affirmation and outlook change reflects the progress being made by the company and various stakeholders to transform the regulatory framework for HEI’s electric utilities to a decoupling structure that will reduce sales volume risk and produce more timely recovery of invested capital and operations and maintenance (O&M) costs. Moody’s indicated that the rating could be downgraded if the PUC does not follow through with the regulatory transformation contemplated under the HCEI, including all elements of the decoupling mechanism, or if credit markets for commercial paper with HEI’s ratings orcash flow to debt declined to below 15% and its cash flow coverage of interest fell below 3.3 times on a sustainable basis. On November 15, 2010, S&P issued an update in general were to tighten,which it would be difficult and expensivelowered its long-term ratings for HEI to sell commercial paper or HEI might not be able to sell commercial paper in“BBB-” from “BBB,” and indicated the future. Such limitations could cause HEI to drawoutlook as “stable.” In addition, S&P affirmed its “A-3” short-term rating on its syndicated credit facility instead, and the costs of such borrowings could increase under the terms of the credit agreement as a result of any such ratings downgrades. Similarly, if HEI’s long-term debt ratings were to be downgraded, it would be difficult and more expensive for HEI to issue long-term debt. Such limitations and/or increased costs could materially adversely affect the results of operations and financial condition of HEI and its subsidiaries.revised HEI’s financial profile to “aggressive” from “significant.” S&P indicated the rating downgrade reflects an “aggressive” financial profile combined with weak cash flow generation at HEI’s electric utilities, delays in implementing new utility rate recovery mechanisms, the growing risks of regulatory disallowances in future rate cases, and a protracted recession.
As of OctoberApril 29, 2010,2011, the Standard & Poor’s (S&P) and Moody’s Investors Service’s (Moody’s) ratings of HEI securities were as follows:
|
| S&P |
| Moody’s |
|
Commercial paper |
| A-3 |
| P-2 |
|
Senior unsecured debt |
|
|
| Baa2 |
|
The above ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
The rating agencies use a combinationManagement believes that, if HEI’s commercial paper ratings were to be downgraded, or if credit markets for commercial paper with HEI’s ratings or in general were to tighten, it would be difficult and expensive for HEI to sell commercial paper or secure other short-term borrowings or HEI might not be able to sell commercial paper in the future. Such limitations could cause HEI to draw on its syndicated credit facility instead, and the costs of 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 determiningborrowings could increase under the terms of the credit agreement as a result of any such ratings downgrades. Similarly, if HEI’s long-term debt ratings were to be downgraded, it would be difficult and more expensive for HEI to issue long-term debt. Such limitations and/or increased costs could materially adversely affect the results of operations, financial condition and cash flows of HEI securities. In May 2009, S&P revised HEI’s outlook to negative from stable, and lowered its commercial paper rating to “A-3” from “‘A-2”. S&P indicated the rating actions reflected its view that the next two years are likely to be challenging for HEI’s electric utilities, which HEI relies on for cash flows to service its own obligations, chiefly debt repayment and common stock distributions. S&P stated that the deterioration in the Hawaii economy is likely to weaken HEI’s 2009 and 2010 consolidated metrics, which it observed have been only marginally supportive of the “BBB” corporate credit ratings currently assigned to HEI. In May 2010, S&P noted that “[t]he negative outlook on Hawaiian Electric Industries Inc. (HEI) ratings reflects a weak consolidated financial profile that has been weighed down by the island recession and the need for more timely rate relief for HEI’s electric utilities. We are concerned that 2010 could bring more underperformance for Hawaiian Electric Co. Inc. (HECO).” S&P further stated, “Given the importance of HECO to consolidated HEI cash flows, we would likely lower the corporate credit ratings on the parent and HECO one notch to ‘BBB-’ unless we are able to see a clear path in 2010 to an improvement in HECO’s credit metrics, which would at minimum require us to conclude that the electric utility is able to maintain funds from operations (FFO) to total debt of 15%, FFO interest coverage in the area of 3.5x, and leverage of less than 60%.” S&P also indicated that “[a]n upgrade is not likely due to HECO’s need to restore its financial profile to levels consistent with the current rating.”
On July 30, 2010, Moody’s changed HEI’s rating outlook to stable from negative and affirmed HEI’s long-term and short-term (commercial paper) ratings. Moody’s stated in its August 2, 2010 Credit Opinion on HEI:
The ratings affirmation and outlook change reflects the progress being made by the company and various stakeholders to transform the regulatory framework for HEI’s electric utilities to a decoupling structure that will reduce sales volume risk and produce more timely recovery of invested capital and operations and maintenance (O&M) costs….
The stable rating outlook at HEI incorporates our belief that the regulatory transition underway in Hawaii will proceed in an orderly fashion with the Hawaii PUC issuing the final decoupling order during 2010. The stable rating outlook factors in our expectation that profitability initiatives at ASB will produce fairly predictable earnings enabling the bank to provide regular dividends to HEI without jeopardizing the bank’s strong capital position.
…[A] ny rating change for HEI will largely be driven by the utility’s performance. HEI’s ratings could be upgraded if the regulatory transition underway is executed in an orderly fashion leading to an improvement in credit metrics such that the HEI’s cash flow to debt exceeds 18% and its cash flow coverage of interest is in excess of 4.0x on a sustainable basis.
The rating could be downgraded if the Hawaii PUC does not follow through with the regulatory transformation contemplated under the HCEI, including all elements of the decoupling mechanism. Quantitatively, the ratings could be downgraded if HEI’s cash flow to debt declined to below 15% and its cash flow coverage of interest fell below 3.3x on a sustainable basis.subsidiaries.
Issuances of common stock through the Hawaiian Electric Industries, Inc. Dividend Reinvestment and Stock Purchase Plan (DRIP),DRIP, the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP)HEIRSP and the ASB 401k401(k) Plan are important sources of capital for HEI. HEI raised $32$11 million through the issuance of approximately 1.40.4 million shares under these plans during the first nine monthsquarter of 2010.2011. HEI also makes registered public offerings of its common stock from time to time.
On March 24, 2011, HEI issued $125 million of Senior Notes via a private placement ($75 million of 4.41% notes due March 24, 2016 and $50 million of 5.67% notes due March 24, 2021). HEI used part of the net proceeds from the issuance of the notes to pay down commercial paper (originally issued to refinance $50 million of 4.23% medium-term notes that matured on March 15, 2011) and will ultimately use the remaining proceeds to refinance part of the $100 million of 6.141% medium-term notes that will mature on August 15, 2011. The notes contain customary representation and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement, expiring on May 7, 2013 (see Note 13 of HEI’s “Notes to Consolidated Financial Statements”). For example, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less or “Consolidated Net Worth” of at least $975 million.
For the first nine monthsquarter of 2010,2011, net cash providedused by operating activities of consolidated HEI was $190$13 million. Net cash used by investing activities for the same period was $79$96 million, primarily due to net increases in ASBASB’s loans held for investment securities and mortgage-related securities and HECO’s consolidated capital expenditures, partly offset by a net decrease in ASB’s loans held for investment.ASB investment securities and mortgage-related securities. Net cash used inprovided by financing activities during this period was $227$95 million as a result of several factors, including net decreasesincreases in long-term debt, deposit liabilities and retail repurchase agreements and the payment of common stock dividends, partly offset by proceeds from the issuance of common stock under HEI plans, partly offset by decreases in short-term borrowings and funds from short-term borrowings.the payment of common stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), HECO’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition—Liquidity and capital resources” sections below.) During the thirdfirst quarter of 2010,2011, HECO and ASB paid dividends to HEI of $11$18 million ($38and $14 million, year to date) and $20 million ($43 million year to date), respectively.
Forecasted HEI consolidated “net cash used in investing activities” (excluding “investing” cash flows from ASB) for 20102011 through 20122013 consists primarily of the net capital expenditures of HECO and its subsidiaries. In addition to the funds required for the electric utilities’ construction programs, approximately $157$207 million will be required during 2011 through 20122013 to repay maturing HEI medium-term notes (or an additional $82 million after consideration of the $125 million of notes issued via a private placement on March 24, 2011), which maturing medium-term notes are expected to be repaid with the proceeds from the issuance of commercial paper, bank borrowings, other medium-term notes,medium- or long-term debt, common stock issued under Companythe Company’s plans and/or dividends from subsidiaries. In addition, approximately $57.5 million of HECO special purpose revenue bonds will be maturing in 2012, which bonds are expected to be repaid with proceeds from issuances of long-term debt. Additional debt and/or equity financing may be utilized to pay down commercial paper or other short-term borrowings or may be required to fund unanticipated expenditures not included in the 20102011 through 20122013 forecast, such as increases in the costs of or an acceleration of the construction of capital projects of the utilities, unanticipated utility capital expenditures that may be required by the Hawaii Clean Energy Initiative (HCEI)HCEI or new environmental laws and regulations, unbudgeted acquisitions or investments in new businesses, significant increases in retirement benefit funding requirements and higher tax payments that would result if certain tax positions taken by the Company do not prevail.prevail or if taxes are increased by federal or state legislation. In addition, existing debt may be refinanced prior to maturity (potentially at more favorable rates) with additional debt or equity financing (or both).
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 1652 to 17 (except for “Limited insurance,” which is updated in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2010), 4353, 72 to 48,76, and 5986 to 6189 of HEI’s MD&A which is incorporated into included in Part II, Item 7 of HEI’s 20092010 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 19, 2010.10-K.
Additional factors that may affect future results and financial condition are described above on pages iv and v under “Forward-Looking Statements.”
MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES
In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.
In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s financial condition and results of operations, and currently require management’s most difficult, subjective or complex judgments.
For information about these material estimates and critical accounting policies, see pages 1753 to 18, 4854, 76 to 50,77, and 61 to 6289 of HEI’s MD&A which is incorporated intoincluded in Part II, Item 7 of HEI’s 20092010 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 19, 2010.10-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, |
| Three months ended |
| % |
|
|
|
| Three months ended |
| % |
|
|
| ||||||||
except per barrel amounts) |
| 2010 |
| 2009 |
| change |
| Primary reason(s) for significant change |
|
| 2011 |
| 2010 |
| change |
| Primary reason(s) for significant change |
| ||||
Revenues |
| $ | 623,126 |
| $ | 548,440 |
| 14 |
| Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers $(80 million), HECO test year 2009 interim rate increase $(8 million) and MECO test year 2010 interim rate increase $(2 million), partially offset by lower KWH sales $(18 million) and lower DSM costs recovered through a surcharge $(1 million) |
|
| $ | 645,335 |
| $ | 548,111 |
| 18 |
| Higher fuel oil and purchased power costs, the effects of which are generally passed on to customers ($83 million), higher KWH sales ($10 million), HECO test year 2009 ($2 million), HELCO test year 2010 ($1 million) and MECO test year 2010 ($2 million) interim rate increases, partly offset by the decoupling revenue adjustment at HECO ($1 million). |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Fuel oil |
| 235,534 |
| 186,719 |
| 26 |
| Higher fuel oil costs, partly offset by increased fuel efficiency and less KWHs generated |
|
| 260,860 |
| 211,752 |
| 23 |
| Higher fuel oil costs and more KWHs generated |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Purchased power |
| 147,880 |
| 134,447 |
| 10 |
| Higher fuel costs |
|
| 147,958 |
| 116,782 |
| 27 |
| Higher fuel costs and more KWHs purchased |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Other operation |
| 62,665 |
| 61,173 |
| 2 |
| See “Results — three months ended September 30, 2010” below |
|
| 65,531 |
| 59,244 |
| 11 |
| See “Results — three months ended March 31, 2011” below |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Maintenance |
| 30,618 |
| 25,968 |
| 18 |
| See “Results — three months ended September 30, 2010” below |
|
| 29,196 |
| 27,053 |
| 8 |
| See “Results — three months ended March 31, 2011” below |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Depreciation |
| 36,277 |
| 35,557 |
| 2 |
| Additions to plant in service in 2009 |
|
| 36,432 |
| 38,642 |
| (6 | ) | Lower depreciation rates implemented in conjunction with the HELCO and MECO test year 2010 interim D&Os |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Taxes, other than income taxes |
| 58,317 |
| 50,031 |
| 17 |
| Increase in revenues |
|
| 59,995 |
| 51,791 |
| 16 |
| Increase in revenues |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Other |
| 492 |
| 373 |
| 32 |
|
|
|
| 155 |
| 238 |
| (35 | ) |
|
| ||||
Operating income |
| 51,343 |
| 54,172 |
| (5 | ) | Higher expenses and lower sales, partly offset by HECO test year 2009 interim rate increase and MECO test year 2010 interim rate increase |
|
| 45,208 |
| 42,609 |
| 6 |
| See “Results — three months ended March 31, 2011” below |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Net income for common stock |
| 21,980 |
| 26,514 |
| (17 | ) | Lower operating income, lower AFUDC due to HECO’s CT-1 being placed in service in August 2009, and higher interest expense due to revenue bond drawdowns |
|
| 19,189 |
| 18,052 |
| 6 |
| Higher operating income, partly offset by lower AFUDC |
| ||||
Kilowatthour sales (millions) |
| 2,497 |
| 2,572 |
| (3 | ) |
|
|
| 2,350 |
| 2,273 |
| 3 |
| Warmer, more humid weather |
| ||||
Wet-bulb temperature (Oahu average; degrees Fahrenheit) |
| 69.8 |
| 71.5 |
| (2 | ) |
|
|
| 67.1 |
| 65.7 |
| 2 |
|
|
| ||||
Cooling degree days (Oahu) |
| 1,428 |
| 1,588 |
| (10 | ) |
|
|
| 920 |
| 857 |
| 7 |
|
|
| ||||
Average fuel oil cost per barrel |
| $ | 89.97 |
| $ | 66.40 |
| 35 |
|
|
|
| $ | 101.03 |
| $ | 81.95 |
| 23 |
|
|
|
Customer accounts (end of period) |
| 444,190 |
| 441,886 |
| 1 |
|
|
|
| 445,151 |
| 443,294 |
| — |
|
|
|
Note: The electric utilities had an effective tax rate for the first quarters of 2011 and 2010 of 37%.
See “Economic conditions�� in the “HEI Consolidated” section above.
Recent developments. In 2010 and the first quarter of 2011, the utilities made significant progress in implementing their clean energy strategies and the PUC issued several important regulatory decisions, all of which are key steps to support Hawaii’s efforts to reduce its dependence on oil. Included in the PUC decisions were a number of interim and final rate case decisions.
With PUC approval, HECO implemented on March 1, 2011 a new regulatory model that is intended to facilitate meeting the State’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio
(dollars in thousands, |
| Nine months ended |
| % |
|
|
| ||||
except per barrel amounts) |
| 2010 |
| 2009 |
| change |
| Primary reason(s) for significant change |
| ||
Revenues |
| $ | 1,755,332 |
| $ | 1,460,654 |
| 20 |
| Higher fuel oil and purchased energy fuel costs, the effects of which are generally passed on to customers $(276 million), HECO test year 2009 interim rate increase $(42 million) and MECO test year 2010 interim rate increase $(2 million), partially offset by lower DSM costs recovered through a surcharge $(19 million) and lower KWH sales $(11 million) |
|
|
|
|
|
|
|
|
|
|
| ||
Expenses |
|
|
|
|
|
|
|
|
| ||
Fuel oil |
| 662,608 |
| 463,893 |
| 43 |
| Higher fuel oil costs and more KWHs generated, partly offset by increased fuel efficiency |
| ||
|
|
|
|
|
|
|
|
|
| ||
Purchased power |
| 404,175 |
| 364,120 |
| 11 |
| Higher fuel costs, partly offset by less KWHs purchased |
| ||
|
|
|
|
|
|
|
|
|
| ||
Other operation |
| 182,163 |
| 186,751 |
| (2 | ) | See “Results — nine months ended September 30, 2010” below |
| ||
|
|
|
|
|
|
|
|
|
| ||
Maintenance |
| 89,894 |
| 81,562 |
| 10 |
| See “Results — nine months ended September 30, 2010” below |
| ||
|
|
|
|
|
|
|
|
|
| ||
Depreciation |
| 113,568 |
| 108,406 |
| 5 |
| Additions to plant in service in 2009 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Taxes, other than income taxes |
| 164,278 |
| 137,741 |
| 19 |
| Increase in revenues |
| ||
|
|
|
|
|
|
|
|
|
| ||
Other |
| 3,259 |
| 777 |
| 319 |
| Write-down of investment in combined heat and power system in July 2010 (see “Most recent rate requests” below) |
| ||
|
|
|
|
|
|
|
|
|
| ||
Operating income |
| 135,387 |
| 117,404 |
| 15 |
| HECO test year 2009 interim rate increase and MECO test year 2010 interim rate increase, partly offset by higher expenses and lower sales |
| ||
|
|
|
|
|
|
|
|
|
| ||
Net income for common stock |
| 57,674 |
| 56,141 |
| 3 |
| Higher operating income, partly offset by lower AFUDC due to HECO’s CT-1 and HELCO’s ST-7 being placed in service in August and June 2009, respectively, and higher interest expense due to revenue bond drawdowns |
| ||
|
|
|
|
|
|
|
|
|
| ||
Kilowatthour sales (millions) |
| 7,144 |
| 7,203 |
| (1 | ) |
|
| ||
Wet-bulb temperature (Oahu average; degrees Fahrenheit) |
| 67.8 |
| 68.5 |
| (1 | ) |
|
| ||
Cooling degree days (Oahu) |
| 3,495 |
| 3,591 |
| (3 | ) |
|
| ||
Average fuel oil cost per barrel |
| $ | 86.12 |
| $ | 59.21 |
| 45 |
|
|
|
Note:standard. The electric utilities hadmodel, referred to as “decoupling,” delinks revenues from sales and includes annual revenue adjustments for O&M expenses and rate base additions. Decoupling provides for more timely cost recovery and earning on investments and should result in a significant improvement from the utilities’ under-earning situation over the last several years. HECO’s goal is to achieve an effective tax rate forROACE within 100 basis points of its 10% allowed ROACE by the third quartersend of 2010 and 2009 of 40% and 37%, respectively. The electric utilities had an effective tax rate for the first nine months of 2010 and 2009 of 38% and 37%, respectively.2012.
See “Economic conditions”Under decoupling, the most significant drivers for improving the ROACE are:
1.spending within PUC approved amounts for major projects and completing projects on schedule;
2.managing O&M expenses relative to authorized O&M adjustments, especially during periods of increasing demand; and
3.rate case outcomes that cover O&M requirements and rate base items not included in the “HEI Consolidated” section above.revenue adjustment mechanisms (RAMs).
Also critical to closing the ROACE gap are HECO’s 2011 rate case, decoupling implementation for HELCO and MECO, and getting timely recovery of completed software project costs. The HECO 2011 rate case will reset base sales revenues, O&M and rate base for the decoupling mechanisms going forward. The utilities expect 2011 O&M expenses to increase by about 7%, excluding DSM, primarily reflecting higher costs to execute the clean energy plan. The 2011 O&M increase is largely included in the O&M RAM and HECO’s 2011 rate request.
Many other actions have been taken and continue to be taken to increase renewable energy in Hawaii. The utilities have the opportunity to stabilize and lower customer bills over time as they become less dependent on costly oil for generation. See “Renewable energy strategy” below for examples of such actions, which will help the utilities to continue to meet or exceed their clean energy goals and provides rate base growth to support these renewables.
The utilities have increased their five-year 2011-2015 capital expenditures forecast to $2.2 billion from $1.6 billion for the 2010-2014 forecast, with an expected compounded annual rate base growth rate of approximately 5%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Four major initiatives comprise approximately 40% of the 5-year plan: (1) replacing aging infrastructure; (2) environmental compliance; (3) fuel infrastructure investments; and (4) infrastructure investments to integrate renewables into the system. Estimates for these projects could change with time, based on external factors such as the timing and technical requirements for environmental compliance.
Results — three months ended September 30, 2010March 31, 2011.. Operating income for the thirdfirst quarter of 2010 decreased 5% from2011 was higher by 6% when compared to the same periodquarter in 20092010 due primarily to lowerhigher sales and interim rate increases for HECO, HELCO and MECO, partly offset by higher “Other operation” and “Maintenance” (O&M) expenses, partly offset by interim rate increases for HECO and MECO.
Net income for common stock declined 17% compared with the same quarter last year for the same reasons given for “Operating income” above and due to lower AFUDC and higher interest expense.expenses. Kilowatthour sales were
down 2.9%increased 3.4% due primarily to cooler and lesswarmer, more humid weather and resulted in an estimated net income declineincrease of $4 million.
Higher O&M expenses ($7$3.5 million, excluding demand-side management (DSM) program costs) and higher financing costs and depreciation expensenet of ($4 million), primarily due to generating units put into service in the latter part of 2009, were largely offset by $10 million in rate relief granted in HECO’s 2009 and MECO’s 2010 test year rate cases. Highersales decoupling adjustment. “Other operation” expenses (excluding DSM program costs) included $1 million higher employee benefits and $1 million higher injuries and damages expense, partially offset by $2 million lower bad debt expense (resulting primarily from the recovery of amounts previously written off related to three large accounts). Maintenance expense increased $5 million primarily due to higher generating station maintenance and the replacement of critical equipment for system reliability.
Results — nine months ended September 30, 2010. Operating income for the first nine months of 2010 increased 15% from the same period in 2009 due primarily to interim rate increases, improved fuel efficiency (primarily due to ST-7), partly offset by higher O&M expense (excluding DSM program costs) and lower KWH sales.
Net income for common stock increased 3% compared with the same period last year for the same reasons given for “Operating income” above, partly offset by lower AFUDC and higher interest expense. For the first nine months of 2010, KWH sales decreased 0.8% compared with the same period in 2009, primarily due to cooler and less humid weather. Management expects full year 2010 sales to be approximately 1% lower than 2009.
Interim rate relief granted in HECO’s 2009 and MECO’s 2010 test year rate cases amounted to approximately $44 million. “Other operation” expenses (excluding DSM program costs) increased by $22$6.3 million in the first nine monthsquarter of 20102011 compared to the same period in 20092010 primarily due to $14higher emissions fees as prior year fees were waived in 2010 ($2 million) and $1.3 million higher administrative and generalDSM expense (see “Demand-side management programs” below) that are generally passed on to customers through surcharges. Maintenance expenses (including $9increased $2.1 million higher employee benefit costs and $2 million higher injuries and damages expense) and $3 million higher production and transmission and distribution operations expenses, partly offset by $4 million of lower bad debt expense. Maintenance expense increased $8 million primarily due to $5 million higher production maintenance expense due to increases in the number and scope of generating unit overhauls and full year CT-1 cost and $4 million higher transmission and distribution maintenance including the replacement of critical equipment for system reliability.higher vegetation, substation and overhead and underground line maintenance.
O&M expenses (excluding DSM program costs) for the year 20102011 are expected to be approximately 13%7% higher than 20092010 as the electric utilities expect higher production expenses higher contract services costs, and higher transmissionto improve the operational flexibility of their generating units. Transmission and distribution expenses are expected to maintain system reliability. Also,increase consistent with new asset management initiatives to modernize infrastructure. In addition, additional expenses are expected for the costs to operate and maintain CIP CT-1, and are expected to be incurred for environmental compliance in response to existing compliance programs as well as numerous new, more stringent regulatory requirements, andcontinue to execute the provisions of the Energy Agreement. Partly offsetting the anticipated increased costs are lower DSM expenses (that are generally passed on to customers through a surcharge) due to the transition of energy efficiency programs to a third-party administrator in July 2009, and termination of lease payments for distributed generators in the latter half of 2010. HCEI-related initiatives appear to be progressing at a pace to achieve the state’s clean energy goals under the HCEI.
The costs of supplying energy to meet demand and the maintenance costs required to sustain high availability of the aging generating units have been increasing.
Renewable energy strategy. The electric utilities have been taking actions intended to protect Hawaii’s island ecology and counter global warming,reduce GHG emissions, while continuing to provide reliable power to customers, and committed to a number of related actions in the Energy Agreement. A three-pronged strategy supports attainment of the requirements and goals of the State of Hawaii Renewable Portfolio Standards (RPS), the Hawaii Global Warming Solutions Act of 2007 and the HCEI by: (1) the “greening” of existing assets, (2) the expansion of renewable energy
generation and (3) the acceleration of energy efficiency and load management programs. Major initiatives are being pursued in each category.
In May2009, Hawaii’s RPS law was amended to require electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO reported achievingmet the 10% RPS for 2010 with a consolidated RPS of 19% in 2009.20.7%, including DSM energy savings. This was accomplished through a combination of municipal solid waste, geothermal, wind, biomass, hydro, photovoltaic and biodiesel renewable generation resources; renewable energy displacement technologies; and energy savings from efficiency technologies. HECO noted that DSM programs contributed significantly to achieving the 19% RPS level and,
indicated that, without including the DSM energy savings, the RPS would have been 9.2% instead of 19%9.5%. Under current RPS law, energyEnergy savings resulting from energy efficiency programs will not count toward the RPS fromafter 2014.
In January 1, 2015.2007, the PUC opened a docket (RPS Docket) to examine Hawaii’s RPS law. In December 2007, the PUC issued a D&O approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. In the D&O, the PUC deferred an RPS incentive framework to a new generic docket (Renewable Energy Infrastructure Program (REIP) Docket). In December 2008, the PUC approved a potential penalty of $20 for every megawatthour that an electric utility is deficient under the RPS law. The PUC must evaluate the standards every five years, beginning in 2013, to determine whether the standards remain effective and achievable or should be revised.
The electric utilities are actively exploringpursuing the use of biofuels for existing and planned company-owned generating units. HECO has committed to using nearly 100% biofuels for itsHECO’s new 110 MW generating unit. HECO is also researching the possibility of switching its steam generating units from fossil fuels to biofuels, andunit began on-going operations in the Energy Agreement has committed to do so if economically and technically feasible and if adequate biofuels are available. HECO is also studying potential investments in fuel-related infrastructure to support the handling of biofuels. In June 2010 the PUC approved HECO and MECO’swith 100% biodiesel fuel supply contracts for their respective biodiesel demonstration projects, the inclusion of the costssupplied under such contracts in their ECACs and, in the case of HECO, the commitment of funds (estimated at $5.2 million) for the purchase of capital equipment. Also in June 2010, the PUC approved a two-year biodiesel supply contract with Renewable Energy Group Marketing and& Logistics, LLC (REG) primarily for CIP CT-1.as approved by the PUC in June 2010. HECO is also moving toward operating some of its steam-generating units with a blend of fossil and biofuels (co-firing). In JulyJune 2010, the PUC approved the purchase of 400,000 gallons ofHECO’s and MECO’s biofuel supply contracts for their respective biofuel demonstration projects. In February 2011, HECO successfully demonstrated that Unit 3 at its Kahe Power Plant could be powered using up to 100% biofuel. MECO is currently testing biodiesel to be used for operational testing and to collect emissions data for CIP CT-1.at its Maalaea Power Plant.
In March 2010, HECO and its subsidiaries issued a request for proposal (RFP) for biofuels produced from feedstocksfeedstock grown in, made in, or otherwise originating in Hawaii (local biofuel) to potentially supply multiple locations, including the sitelocations. In January 2011, HELCO signed a 20-year contract, subject to PUC approval, with Aina Koa Pono-Ka’u LLC to supply 16 million gallons of CIP CT-1 (after the expiration of the REG contract). Bids were received and are under evaluation.biodiesel per year with initial consumption to begin by 2015. HECO expects to issue additional fuel RFPs inis continuing negotiations with other bidders. In January 2011, including anHECO issued a RFP for fuel forbiodiesel to supply CIP CT-1 upon the expiration of the REG contract.contract in July 2012 and is currently evaluating proposals received. HECO expects to issue a RFP in 2011 for commercial supplies of biofuel to co-fire with fossil fuel at HECO’s Kahe Power Plant by 2015. Under current RPS law, biofuel use in existing and new generating units counts toward the RPS.
The electric utilities also support renewable energy through the negotiation and execution of PPAs with non-utility generators using renewable sources (e.g., refuse-fired, geothermal, hydroelectric, photovoltaic and wind turbine generating systems).
On April 30, 2009, HECO filed an application with the PUC for approval of a Photovoltaic (PV) Host Pilot Program, which would be a two-year pilot program whereby HECO, HELCO and MECO would lease rooftops or other space from property owners, with a focus on governmental facilities, for the installation of third-party owned photovoltaicPV systems. The PV developer would own, operate and maintain the system and sell the energy to the utilities at a fixed rate under a long-term contract. On August 31, 2010, HECO proposed several modifications to the pilot program, including deferment of HELCO’s and MECO’s participation in the program and utilization of select PV Host projects on Oahu as test platforms to evaluate grid integration technologies (as well as to help address grid integration issues associated with existing and growing penetration levels of distributed intermittent generation). Pilot program implementation is pending PUC approval.
In June 2008, the PUC approved HECO’sHECO issued an Oahu Renewable Energy Request for Proposals (RFP)(2008 RFP) for combined renewable energy projects up to 100 MW. In February 2011, HECO executed a PPA with Kalaeloa Solar Two for a 5 MW and HECO issued the RFP shortly thereafter. HECO is currently negotiating PPAsPV project. Negotiations continue with the bidders in the Award Group.a proposed wind project (70 MW).
Included in the bids received in response to the 2008 RFP were proposals for two large scale neighbor island wind projects that would produce energy to be imported from Lanai and Molokai to Oahu via a yet-to-be-built
undersea transmission cable system.system (Interisland Wind Projects). In accordance with the Energy Agreement, the proposals for two large scale neighbor island wind projects (Bigthe Interisland Wind projects)Projects were bifurcated from the Oahu Renewable Energy RFP for separate negotiation. Subsequently, HECO requestedreceived a PUC waiver from the competitive bidding framework for the two non-conformingnonconforming proposals and HECO reached agreement on a term sheet by the PUC decisiondeadline in March 2011 with only one of the two project developers (for a 200 MW to 400 MW windfarm to be built on Lanai). Since agreement on a term sheet with the other developer could not be reached by the PUC deadline, no further consideration is pending.being given to the other proposal. The term sheet that was executed with the Lanai developer allows for the possibility that the developer may elect to arrange with another developer to build a portion of the total 400 MW on the island of Molokai, subject to certain conditions including PUC acceptance of the arrangement. In April 2011, the Lanai developer informed HECO of its intent to exercise this option. The developer who initially proposed the Molokai windfarm, but failed to execute a term sheet, has since filed a letter to the PUC indicating its objection to the arrangement.
In September 2010 and January 2011, MECO executed PPAs with Kaheawa Wind Power II, LLC (PPA approved by the PUC) and Auwahi Wind Energy, LLC (PPA pending PUC approval), respectively, for the purchase of 21 MW (each) of as available wind energy. In February 2011, the PUC opened dockets related to MECO’s and HECO’s plans to proceed with competitive bidding processes to acquire up to approximately 50 MW and 300 MW, respectively, of new, renewable firm dispatchable capacity generation resources, with the initial increments expected to come on line in the 2015 and 2016 timeframes, respectively.
On September 30, 2010, the PUC approved the electric utilities’ proposed Electric Vehicle (EV) Charging Time of Use Pilot Rates for three years, which are now available to 1,000 HECO, 300 HELCO and 300 MECOa total of 1,600 customers for charging highway-capable, four-wheeled EVs. The EV Pilot Rates will remain in effect for three yearsall 3 service territories and are designed to encourage early adoption of EVs and incentivize customers to charge EVs during off-peak times of the day. EV charge stations have been installed at various HECO and customer sites. HECO received its first EV in March 2011 and more EVs are expected to be added to HECO’s fleet.
The electric utilities promote research and development in the areas supporting renewable energy such as biofuels, ocean energy, batteryenergy storage, smart grids and integration of non-firm power into the separate island electric grids. The utilities are evaluating several potential energy storage and smart grid demonstration projects, and conducting various integration studies.
CompetitionCompetition.. 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 independent power producers (IPPs)IPPs and customer self-generation, with or without cogeneration.
Competitive bidding proceeding. In December 2006, the PUC issued a decision that included a final competitive bidding framework, which became effective immediately. The final framework states, among other things, that under the framework: (1) a utility is required to use competitive bidding to acquire a future generation resource or a block of generation resources unless the PUC finds bidding to be unsuitable; (2) the framework does not apply in certain situations identified in the framework; (3) waivers from competitive bidding for certain circumstances will be considered; (4) the utility is required to select an independent observer from a list approved by the PUC whenever the utility or its affiliate seeks to advance a project proposal (i.e., in competition with those offered by bidders); (5) the utility may consider its own self-bid proposals in response to generation needs identified in its RFP; and (6) for any resource to which competitive bidding does not apply (due to waiver or exemption), the utility retains its traditional obligation to offer to purchase capacity and energy from a Qualifying Facility (QF) at avoided cost upon reasonable terms and conditions approved by the PUC.
Management cannot currently predict the ultimate effect of the framework on the ability of the utilities to acquire or build additional generating capacity in the future.
The utilities received approval for waivers from the competitive framework to negotiate modifications to existing PPAs that generate electricity from renewable resources. Also, certain renewable energy projects were “grandfathered” from the competitive bidding process. OfThe PUC can also grant waivers on its own volition to renewable energy projects that are not exempt from the “grandfathered” projects,Competitive Bidding Framework (as was done in December 2010 for four 5 MW solar facilities proposed for Oahu).
In February 2011, the PUC has approvedopened dockets to administer the PPA with Kahuku Wind Power, the PUC is considering the PPA with Honua Power,competitive bidding processes for HECO and HECO continues to negotiate with OTEC International.MECO.
Distributed generation (DG) proceeding. In January 2006, the PUC issued a D&O indicating that its policy is to promote the development of a market structure that assures DG is available at the lowest feasible cost, DG that is economical and reliable has an opportunity to come to fruition and DG that is not cost-effective does not enter the system. The D&Owhich affirmed the ability of the utilities to procure and operate DGdistributed generation (DG) for utility purposes at utility sites. The PUC also indicated its desire to promote the development of a competitive market for customer-sited DG. The PUC found that the “disadvantages outweigh the advantages” of allowing a utility to provide DG services on a customer’s site. However, the PUC also found that the utility “is the most informed potential provider of DG” and it would not be in the public interest to exclude the utilities from providing DG services at this early stage of DG market development. Therefore, the D&O allows the utility to provide DG services on a customer-owned site as a regulated service when (1) the DG resolves a legitimate system need, (2) the DG is the lowest cost (lowest reasonable cost) alternative to meet that need and (3) it can be shown that, in an open and competitive process acceptable to the PUC, the customer operator was unable to find another entity ready and able to supply the proposed DG service at a price and quality comparable to the utility’s offering.
In April 2006,March 2010, the PUC provided clarification toapproved the conditions under which the utilities are allowed to provide regulated DG services (e.g., the utilities can use a portfolio perspective—a DG project aggregated with other DG systemsamended agreement between HECO 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 integrated resource plan (IRP) framework).
In September 2008, HECO executed an agreement with the State of Hawaii Department of Transportation to develop a dispatchable standby generation (DSG) facility at the Honolulu International Airport that will be owned by the State and operated by HECO. The agreement has been approved by the PUC which also waived the project from the Competitive Bidding Framework. The DSGdispatchable standby generation facility is projected to be in operation in AprilOctober 2012.
HECO is also evaluating the potential to develop utility-owned DG at Oahu military bases in order to meet utility system needs and the energy objectives of the federal Department of Defense (DOD).Defense.
In February 2008, the PUC approved a MECO agreement for the installation of a CHP system at a hotel site on the island of Lanai. The CHPLanai of a combined heat and power system, which was placed in service in September 2009.
DG tariff proceeding. In 2008, the PUC approved modifications to the utilities’ interconnection tariffs and a standby service tariff. In January 2010, the utilities requested modifications of the DG interconnection tariff. In May 2010, the PUC approved certain modifications that had been stipulated to by the parties, including (1) modifying requirements for conducting detailed interconnection studies; (2) establishing a standard three-party interconnection agreement; (3) including cross-limitation of liability and non-indemnification language with respect to projects where a State of Hawaii agency is the customer; and (4) requiring additional information regarding the customer’s generating facility. The remaining issues continue to be evaluated in the proceeding. Final statements of position are due in December 2010.
DG and distributed energy storage under the Energy Agreement. Under the Energy Agreement, the utilities committed to facilitate planning for distributed energy resources through a new Clean Energy Scenario Planning process. Under this process, Locational Value Maps were developed in 2009 to identify areas where DG and distributed energy storage would provide utility system benefits and can be reasonably accommodated.
The utilities also agreed to power utility-owned DG using sustainable biofuels or other renewable technologies and fuels, and to support either customer-owned or utility-owned distributed energy storage. The utilities are currently planning distributed energy storage research, development and demonstration projects for installation in 2011-2012.
The parties to the Energy Agreement support reconsideration of the PUC’s restrictions on utility-owned DG where it is proven that utility ownership and dispatch clearly benefits grid reliability and ratepayer interests, and the equipment is competitively procured. The parties also support HECO’s dispatchable standby generation units upon showing reasonable ratepayer benefits.
The utilities may contract with third parties to aggregate fleets of DG or standby generators for utility dispatch or under PPAs, or may undertake such aggregation themselves if no third parties respond to a solicitation for such services.
The Energy Agreement also provides that to the degree that transmission and distribution automation and other smart grid technology investments are needed to facilitate distributed energy resource utilization, those investments should be recoverable through a Clean Energy Infrastructure Surcharge (which was replaced by the Renewable Energy Infrastructure Program (REIP) Surcharge) and later placed in rate base in the next rate case proceeding.
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 an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the return on average common equity (ROACE) and return on rate base (ROR)) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.
ROACEs of 10.7% were found to be reasonable by the PUC in the most recent final rate decisions issued in September 2010, October 2010 and July 2010 in HECO, HELCO and MECO rate cases based on 2007, 2006 and 2007 test years, respectively. The ROACEs used by the PUC for purposes of the most recent interim rate increases issued in August 2009 and July 2010 in HECO and MECO rate cases based on 2009 and 2010 test years, respectively, were both 10.5%, and these ROACEs have not been reduced to reflect the implementation of decoupling. The settlement agreement between HELCO and the Consumer Advocate for HELCO’s 2010 test year rate case, which is subject to PUC approval, includes a 10.125% ROACE that reflects the implementation of decoupling (see “HELCO—2010 test year rate case” below).
For the 12 months ended September 30, 2010,March 31, 2011, the actual ROACEs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates) for HECO, HELCO and MECO were 7.32%5.63%, 7.25%7.26% and 4.10%5.59%, respectively. The utilities’ actual ROACEs were lower than their final and interim D&O ROACEs primarily due to lower KWH sales than the sales used to determine the interim rates and increased O&M expenses.
The RORs found to be reasonable by the PUC in the most recent final rate decisions were 8.62% for HECO, 8.33% for HELCO and 8.67% for MECO (final D&Os noted above). The RORs used by the PUC for purposes of the
most recent interim increases were 8.45% for HECO and 8.43% for MECO (interim D&Os noted above). For the 12 months ended September 30, 2010,March 31, 2011, the actual RORs (calculated under the rate-making method, which excludes the effects of items not included in determining electric utility rates) for HECO, HELCO and MECO were 6.58%5.63%, 6.59%6.55% and 4.99%5.81%, respectively.
In the most recent interim and final rate decisions, the PUC allowed the use by each utility of pension and postretirement benefits other than pensions (OPEB) tracking mechanisms (with varied treatment of the pension assets of each utility) and allowed the continuation of each utility’s ECAC.
The pensionfollowing table summarizes certain details of each utility’s most recent rate cases, including the details of the increases requested, whether the utility and OPEB tracking mechanisms are reflectedthe Consumer Advocate reached a settlement that they proposed to the PUC, the details of increases granted in test year estimates for HELCOinterim and MECO’s 2010 test year and HECO’s 2011 test year rate case applications. In HECO’s and MECO’s 2007 and HELCO’s 2006 test year rate case final PUC D&Os or whether an interim or final PUC D&O remains pending.
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Test year |
| Date (applied/ |
| Amount |
| % over |
| ROACE |
| RORB |
| Ratebase |
| % |
| Stipulated |
| Reflects |
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(dollars in millions) |
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HECO |
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2007 |
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Request |
| 12/22/06 |
| $ | 99.6 |
| 7.1 | % | 11.25 | % | 8.92 | % | $ | 1,214 |
| 55.10 | % | Yes |
| No |
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Interim increase |
| 10/22/07 |
| 70.0 |
| 5.0 |
| 10.70 |
| 8.62 |
| 1,158 |
| 55.10 |
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| No |
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Interim increase (adjusted) |
| 6/20/08 |
| 77.9 |
| 5.6 |
| 10.70 |
| 8.62 |
| 1,158 |
| 55.10 |
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| No |
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Final increase |
| 3/1/11 |
| 77.5 |
| 5.5 |
| 10.70 |
| 8.62 |
| 1,158 |
| 55.10 |
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| No |
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2009 |
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Request (1) |
| 7/3/08 |
| $ | 97.0 |
| 5.2 | % | 11.25 | % | 8.81 | % | $ | 1,408 |
| 54.30 | % | Yes |
| No |
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Interim increase (1st) |
| 8/3/09 |
| 61.1 |
| 4.7 |
| 10.50 |
| 8.45 |
| 1,169 |
| 55.81 |
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| No |
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Interim increase (2nd, plus 1st) |
| 2/20/10 |
| 73.8 |
| 5.7 |
| 10.50 |
| 8.45 |
| 1,251 |
| 55.81 |
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| No |
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Final increase (2) |
| 3/1/11 |
| 66.4 |
| 5.1 |
| 10.00 |
| 8.16 |
| 1,250 |
| 55.81 |
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| Yes |
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2011 |
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Request (3) |
| 7/30/10 |
| $ | 94.0 |
| 5.4 | % | 10.75 | % | 8.54 | % | $ | 1,569 |
| 56.29 | % |
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| Yes |
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Interim increase |
| Pending |
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HELCO |
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2006 |
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Request |
| 5/5/06 |
| $ | 29.9 |
| 9.2 | % | 11.25 | % | 8.65 | % | $ | 369 |
| 50.83 | % | Yes |
| No |
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Interim increase |
| 4/5/07 |
| 24.6 |
| 7.6 |
| 10.70 |
| 8.33 |
| 357 |
| 51.19 |
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| No |
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Final increase (4) |
| 1/14/11 |
| 24.6 |
| 7.6 |
| 10.70 |
| 8.33 |
| 357 |
| 51.19 |
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| No |
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2010 |
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Request (5) |
| 12/9/09 |
| $ | 20.9 |
| 6.0 | % | 10.75 | % | 8.73 | % | $ | 487 |
| 55.91 | % | Yes |
| Yes |
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Interim increase |
| 1/14/11 |
| 6.0 |
| 1.7 |
| 10.50 |
| 8.59 |
| 465 |
| 55.91 |
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| No |
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Final increase |
| Pending |
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MECO |
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2007 |
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Request |
| 2/23/07 |
| $ | 19.0 |
| 5.3 | % | 11.25 | % | 8.98 | % | $ | 386 |
| 54.89 | % | Yes |
| No |
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Interim increase |
| 12/21/07 |
| 13.2 |
| 3.7 |
| 10.70 |
| 8.67 |
| 383 |
| 54.89 |
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| No |
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Final increase |
| 1/12/11 |
| 13.2 |
| 3.7 |
| 10.70 |
| 8.67 |
| 383 |
| 54.89 |
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| No |
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2010 |
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Request (6) |
| 9/30/09 |
| $ | 28.2 |
| 9.7 | % | 10.75 | % | 8.57 | % | $ | 390 |
| 56.86 | % | Yes |
| Yes |
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Interim increase |
| 8/1/10 |
| 10.3 |
| 3.3 |
| 10.50 |
| 8.43 |
| 387 |
| 56.86 |
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| No |
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Interim increase (adjusted) |
| 1/12/11 |
| 8.5 |
| 2.7 |
| 10.50 |
| 8.43 |
| 387 |
| 56.86 |
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| No |
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Final increase |
| Pending |
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Note: The “Request Date” reflects the PUC approved their pension and OPEB tracking mechanisms. For a descriptionfiling date for the rate proceeding. All other line items reflect the effective dates of the utilities’ pensionrevised schedules and OPEB tracking mechanisms, see “Balance sheet recognitiontariffs as a result of the funded status of retirement plans”PUC-approved increases.
(1)In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 105 of HECO’s “Notes to Consolidated Financial Statements” incorporated by reference in HEI’s Form 10-K for the year ended December 31, 2009. For a description of the utilities’ ECACs, see below.
For a discussion of HECO’s 2009 test year rate case and the interim increase granted, see “Most recent rate requests” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in HECO’s Form 10-Q for the quarter ended March 31, 2010.
HECO).
2007 test year rate case. On December 22, 2006, HECO filed a request for a general rate increase of $99.6 million, or 7.1% over the electric rates then in effect, based on a 2007 test year, an 11.25% ROACE and an 8.92% ROR on a $1.214 billion average rate base. HECO’s application included a proposed new tiered rate structure for residential customers to reward customers who practice energy conservation with lower electric rates for lower monthly usage.
On September 6, 2007, HECO,(2)Because the Consumer Advocate and the DOD (collectively, the parties) executed and filed an agreement on most of the issues in this rate case, and on October 22, 2007, the PUC issued, and HECO implemented, an interim D&O granting HECO anfinal increase of $70was $7.4 million less in annual revenues, over rates effective at the time of the interim D&O, subject to refund with interest. The interim increase was based on the settlement agreement which included, as a negotiated compromise of the parties’ respective positions, an ROACE of 10.7%, an 8.62% ROR, a $1.158 billion average rate base and a capital structure which includes a 55.1% common equity capitalization. In May 2008, the interim increase was adjusted from $70HECO refunded $2.1 million to $77.9 millioncustomers (including interest) in annual revenues to take into account the changes in current effective rates as a result of the final D&O in the 2005 test year rate case. In September 2008, the interim increase was corrected to $77.5 million based on a filing submitted by HECO.February 2011.
On September 14, 2010, the PUC issued a final D&O that confirmed the interim increase of $77.5 million, approved the pension and postretirement benefits other than pension tracking mechanisms (which had been approved on an interim basis), confirmed that (3)HECO’s ECAC complies with Act 162 and approved the stipulated rate design, which includes the new tiered rate structure for residential customers. Decouplingrequest was not addressed in this proceeding and the final D&O did not address the implementation of decoupling.
2011 test year rate case. On July 30, 2010, HECO filed a request with the PUC for a general rate increase of $94 million, or 5.4% over the electric rates currently in effect, based on a 2011 test year, the estimated impacts of the implementation of decoupling as proposed in the PUC’s separate decoupling docket and depreciation rates and methods as proposed by HECO in a separate depreciation proceeding. Excluding the effects of the implementation of decoupling, the effective revenue request is $113.5 million, or 6.6%. The request includes an increase of $54 million, or 3.1% (or $74 million, or 4.3% without the implementation of decoupling), primarily to pay for major capital projects and operating and maintenancehigher O&M costs to maintain and improve service reliability. The remainder of the request isreliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and increase fuel security.
The request is based on(4)Final D&O appealed by a 10.75% return on average common equity (ROACE), an 8.54% return on rate base (ROR), a $1.57 billion average rate base and a capital structure which includes a 56% common equity capitalization. HECO’s electric rates currentlyparticipant in effect include an annual final rate increase of $77.5 million granted by the PUC in HECO’s 2007 test year rate case proceeding. The appeal is pending, but has not affected implementation of the rate increase.
(5)HELCO’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and an annual interim rate increase of $73.8 million granted by theincreasing O&M expenses.
(6)MECO’s request was primarily to cover investment to improve service reliability and higher O&M expenses.
PUC in HECO’s 2009 test year rate case. The interim rate increase is subject to a final decision from the PUC, and subject to refund with interest if and to the extent that the final decision provides for a lesser increase.
The proposed rate increase would recover investments in capital projects completed or to be completed since the 2009 test year rate case (e.g., higher depreciation expense), including investments in the 110 MW biofuel generating facility that were not part of the 2009 test year rate case and Phase 1 of the East Oahu Transmission Project (which was placed in service on June 29, 2010); increased costs to support the integration of more renewable energy generation; other capital improvements; and higher operation and maintenance costs required to maintain and improve system reliability.
HELCO.
2006 test year rate case. In May 2006, HELCO filed a request for a general rate increase of $29.9 million, or 9.24% over the electric rates then in effect, based on a 2006 test year, an 8.65% ROR, an 11.25% ROACE and a $369 million average rate base. HELCO’s application included a proposed new tiered rate structure, which was 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. The proposed rate increase would pay for improvements made to increase reliability, including transmission and distribution lineimprovements and the two generating units at the Keahole power plant (CT-4 and CT-5), and increased O&M expenses.
In March 2007, HELCO and the Consumer Advocate reached settlement agreements on all revenue requirement issues in the rate case proceeding. HELCO agreed to write off a portion of CT-4 and CT-5 costs, which resulted in an after-tax charge of approximately $7 million in the first quarter of 2007.
On April 4, 2007, the PUC issued an interim D&O granting HELCO an increase of 7.58%, or $24.6 million in annual revenues, over revenues at present rates. The interim increase reflected the settlement of the revenue requirement issues reached between HELCO and the Consumer Advocate and was based on an average rate base of $357 million (which reflects the write-off of a portion of CT-4 and CT-5 costs) and an ROR of 8.33% (incorporating an ROACE of 10.7%). On May 15, 2007, HELCO and the Consumer Advocate filed a settlement letter that reflected their agreement on the remaining rate design issues in the proceeding.
On October 28, 2010, the PUC issued a final D&O that confirmed the interim increase of $24.6 million, approved the pension and postretirement benefits other than pension tracking mechanisms (which had been approved on an interim basis), confirmed that HELCO’s ECAC complies with Act 162, and approved the stipulated rate design, which includes the new tiered rate structure. Decoupling was not addressed in this proceeding and the final D&O did not address the implementation of decoupling.
2010 test year rate case. On December 9, 2009, HELCO filed a request for a general rate increase of $20.9 million, or 6.0% over the electric rates then in effect, based on a 2010 test year, a 10.75% ROACE and an 8.73% ROR on a $487 million rate base. The proposed rate increase would cover investments for system upgrade projects, including an 18 MW heat recovery steam generator (ST-7) and two major transmission line upgrades, as well as increasing O&M expenses. HELCO’s proposed ROR and ROACE assume (1) the establishment of an RBA and a revenue adjustment mechanism, based on the Joint Decoupling Proposal (see “Decoupling Proceeding” below), (2) the implementation of the REIP/CEIS, which the PUC has approved in a separate proceeding, and (3) a purchased power adjustment clause to recover non-energy PPA costs proposed in the proceeding. If the proposals are not approved, the test year revenue requirements would be $22.1 million, based on an 8.87% ROR and an 11.0% ROACE.
HELCO’s filing also proposes adoption of inverted tiered rates and an optional residential time-of-use service rate to enable customers to manage their energy usage.
HELCO and the Consumer Advocate executed and filed a settlement agreement on all material issues in this rate case proceeding on September 16, 2010, and filed a Joint Statement of Probable Entitlement on October 5, 2010, which are subject to approval by the PUC. If the PUC does not accept the material terms of the settlement agreement, either or both of the parties may withdraw from the agreement and pursue their respective positions in the proceeding without prejudice. If the settlement is approved by the PUC, the net interim increase in annual
revenues would amount to $4.4 million, or a 1.2% increase. As part of the settlement agreement, HELCO would reset the heat rate used in its ECAC calculation when the interim rates become effective, which would shift $13.9 million of revenues that would have been included in the ECAC revenues to the interim increase and result in a total interim increase of $18.3 million. The agreement included a 10.125% ROACE, an 8.38% ROR, a $465 million average rate base and a capital structure which includes 56% of common equity. In the settlement agreement, the parties agree that the negotiated ROACE and ROR reflect the implementation of decoupling and other recovery mechanisms when interim rates go into effect. The interim increase also reflects the new depreciation rates and methods proposed by HELCO and approved by the PUC on a temporary basis in a separate depreciation proceeding.
The difference between the amount requested in the initial application and the $4.4 million net increase under the settlement relates primarily to changes in expenses since the rate case was filed and changes in the ROACE and ROR.
Management cannot predict the timing, or the ultimate outcome, of an interim or final D&O in this rate case.
MECO.
2010 test year rate case. On September 30, 2009, MECO filed a request for a general rate increase of $28.2 million, or 9.7% over the electric rates then in effect, based on a 2010 test year, a 10.75% ROACE and an 8.57% ROR on a $390 million rate base. The proposed rate increase would cover investments to improve service reliability, including the replacement and upgrade of power plant control systems, installation of a new 150-kW photovoltaic system, replacement and upgrade of underground lines, new or expanded substations to support growth and improve service, and higher O&M expenses due to MECO’s aging infrastructure. MECO’s proposed ROR and ROACE assume the establishment of an RBA and a revenue adjustment mechanism, based on the Joint Decoupling Proposal. If the Joint Decoupling Proposal is not approved, the test year revenue requirements would be recalculated using an 11% ROACE and an 8.72% ROR.
On June 21, 2010, MECO and the Consumer Advocate executed and filed a settlement agreement on all material issues in this rate case proceeding, which agreement is subject to approval by the PUC. On July 27, 2010, the PUC issued an interim D&O granting MECO an increase of $10.3 million in annual revenues, or 3.3% over revenues currently in effect. The tariff changes implementing the interim increase became effective on August 1, 2010. The interim increase is based on the settlement agreement, which included a 10.5% ROACE, an 8.43% ROR, a $387 million average rate base and a capital structure which includes 56.9% of common equity. The interim increase also reflects the new depreciation rates and methods proposed by MECO and approved by the PUC on a temporary basis in a separate depreciation proceeding, but does not reflect the implementation of decoupling.
Under the settlement agreement, MECO agreed to limit to $3.5 million the investment in plant for a CHP system installed at a hotel site in September 2009. The actual cost was $4.8 million, and the amount approved by the PUC in February 2008 was $2.1 million. As a result, in the second quarter of 2010, MECO charged to expense approximately $1.3 million of its investment in the CHP system.
Management cannot predict the timing, or the ultimate outcome, of a final D&O in this rate case.
Decoupling proceeding.proceeding. In the Energy Agreement, the parties agreed to seek approval from the PUC to implement beginning with the HECO 2009 test-year rate case interim decision, a decoupling mechanism, similar to that in place for several California utilities, which decouples revenues from KWH sales and provides for revenue adjustments (increases/decreases) for the differences (shortages/overages) between the amount determined in the last rate case and (a) the current cost of operating the utility as deemed reasonable and approved by the PUC, (b) the return on and return of ongoing capital investment (excluding projects included in a proposed new CEIS), and (c) changes in tax expense due to changes in State or Federal tax rates. The decoupling mechanism would be subject to review at any time by the PUC or upon request of any utility or the Consumer Advocate.cases.
In October 2008, the PUC opened an investigative proceeding to examine implementing a decoupling mechanism for the utilities. In May 2009, the utilities and the Consumer Advocate filed their joint proposal (Joint Decoupling Proposal) for a decoupling mechanism with three components: (1) a sales decoupling component via a
revenue balancing account (RBA), (2) a revenue escalation component via a revenue adjustment mechanism (RAM) and (3) an earnings sharing mechanism.
In February 2010, The RBA mechanism provides for revenue adjustments (increases or decreases) between rate cases to account for the PUC approveddifference between the Joint Decoupling Proposal (with subsequent modifications torevenues allowed in the proposal agreed tomost recent rate case (target revenues) and the revenues actually received by the utilitiesutility. The RAM provides for changes in revenue requirements between rate cases for inflation-indexed changes in O&M expenses (other than expenses recovered through surcharges) and the Consumer Advocate), subject to the issuance of a final D&O, and ordered the utilities and the Consumer Advocate to jointly submitallow for the PUC’s considerationreturn on and return of changes in certain elements of rate base (e.g., plant additions excluding plant additions recovered through the REIP Surcharge) between rate cases. The RAM provides more timely recovery of invested capital and O&M costs since some portion of the increased costs between rate cases will be recovered without the need for a proposed Final D&O, which they did on March 23, 2010.rate proceeding. The earnings sharing mechanism provides for a reduction of rates between rate cases in the event the utility exceeds the ROACE allowed in its most recent rate case.
On August 31, 2010, the PUC issued a Final D&O, which approved the decoupling mechanism proposed in the Joint Decoupling Proposal, subject to certain modifications. Those modifications excluded from the RAM merit wage increases from the revenue adjustment mechanism, required additional information relatedand cost overruns for major capital projects (capital projects greater than or equal to Baseline Capital Projects,$2.5 million), with recovery of such increases and required the utilities and the Consumer Advocateoverruns to jointly file an outreach plan. Implementation of sales decoupling is to occur when rates that reflect a reduced rate of return due to decoupling are approved by the PUC in either an interim or final D&Obe considered in the utilities’ pendingutility’s next rate cases.case.
In the Settlement Letter filed in the HELCO 2010 test year rate case, HELCO resubmitted three of its tariffs to reflect the provisions of the Decoupling Final D&O. To enable the implementation of decoupling upon issuance of the interim D&O for this rate case, the Consumer Advocate and HELCO agreed to a ROACE for interim relief purposes that assumes the implementation of the decoupling mechanism, the Renewable Energy Infrastructure Program surcharge, and the Purchased Power Adjustment Clause, and agreed to accept the PUC’s decision on the final ROACE authorized in HECO’s 2009 test year rate case asissued on December 29, 2010, the PUC approved a reduced ROACE due to decoupling and other new cost recovery mechanisms, and allowed HECO to implement the approved decoupling mechanism. Effective March 1, 2011, HECO established the RBA and started recording the difference between target revenues from its HECO 2009 rate case and actual revenues. On March 31, 2011, HECO submitted its revised tariff to enable the RAM revenue adjustment of $12.7 million ($4.7 million for O&M costs and $8.0 million for invested capital) for the period from March 1, 2011 (the effective date for decoupling) through December 31, 2011. The collection period for the RAM revenue adjustment is 12 months and, unless the tariff is suspended by the PUC, HECO will begin billing customers on June 1, 2011. HECO’s understanding is that, when an interim D&O is issued in its 2011 rate case, the accrual of revenues would end, and the tariff would be adjusted to reflect the RAM revenue accrual from March 1, 2011 to the effective date of the interim rate increase authorized by the interim D&O. However, the Consumer Advocate submitted comments in April 2011 on HECO’s revised tariff, taking the position that HECO is not entitled to RAM revenues prior to the effective date of the revised tariff of June 1, 2011 (if not suspended), and the RAM revenue adjustment would end when an interim D&O is issued in the 2011 rate case. Because there is uncertainty on how the PUC will decide the issue, HECO has not recorded RAM revenues for March 2011 of approximately $1.3 million.
Authorizations for the implementation of decoupling for HELCO and MECO are pending final ROACE for HELCO’sD&Os or other action by the PUC in their pending 2010 test year rate case. Management cannot predictcases. Per the timing, ordecoupling D&O, the ultimate outcome,utilities will file staggered rate cases every three years, the first being HECO’s 2011 test year filed in July 2010. In May 2011, MECO filed a Notice of Intent to file an interim or final D&O in this proceeding.application for a general rate increase, using a 2012 test year.
Energy Cost Adjustment Clauses (ECACs). The rate schedules of the electric utilities include ECACs under which electric rates are adjusted for changes in the weighted-average price paid for fuel oil and certain components of purchased power, and the relative amounts of company-generated power and purchased power.
The HECO (2009 and 2011(2011 test years)year), HELCO (2006 and 2010(2010 test years)year) and MECO (2010 test year) rate increase applications requested the continuation of their ECACs in their present forms.ECACs. In the final D&Os for the HELCO 2006, MECO and HECO 2007 and HECO 2009 test year rate cases, the PUC found that HELCO’s, MECO’s and HECO’s ECACs comply with Act 162 and should be implemented as agreed by the parties to the respective rate case proceedings.
Other regulatory matters.In addition to the items below, also see “Hawaii Clean Energy Initiative” and “Major projects” in Note 5 of HECO’s “Notes to Consolidated Financial Statements” for a number of actions committed to in the Energy Agreement that will require PUC approval.Statements.”
Demand-side management programs.
Energy Efficiency (EE) DSM Programs. In February 2007, the PUC required that the administration of all EEEnergy Efficiency (EE) DSM programs be turned over to a non-utility, third-party administrator. The PUC executed a public benefits fund (PBF) administrator contract with Science Applications International Corporation (SAIC) and on July 1, 2009, SAIC began administering the EE DSM programs. A PBF surcharge on electric utility revenues (1% in 2010, 1.5% in 2011 and 2012 and 2% thereafter) is being used to fund EE DSM programs, incentives, program administration, and other related program costs, as expended by SAIC for the programs or by program contractors.costs.
The EE DSM Docket D&O also provided for HECO’s recovery of DSM program costs and utility incentives. With respectincentives prior to cost recovery, the PBF were subject to PUC continuesreview and approval. Because the utilities were not able to permit recoveryrecover the entire amount of reasonably-incurred DSM implementation costs, under the IRP framework. On June 29, 2009 HECO filed with the PUC a request to increase its residential DSM programs budget by a net $1.4 million (an estimated $2.5 million overrun in certain programs offset by an estimated $1.1 million underrun in other programs) primarily to pay customer incentives related to DSM program applications completed and approved through June 30, 2009. In June 2009, HECO accrued and expensed the net $1.4 million of incentives. HECO is awaiting a determination from the PUC on its request to increase its program budget. In its DSM surcharge filing with the PUC on March 31, 2010, HECO calculated revised DSM surcharge levels effective April 1, 2010, but since HECO’s June 29, 2009 budget increase request was pending at the PUC, HECO did not include in the revised DSM surcharge levels $2.3 million in DSM program expenditures, that were in excessthe utilities recorded an expense of PUC approved program budgets.
DSM utility incentives are derived from a graduated performance-based schedule of net system benefits. In order to qualify for an incentive, the utility must meet cumulative MW and MWh reduction goals for its EE DSM programs in the commercial, industrial and residential sectors. The amount of the annual incentive has been subject to caps determined separately for each utility.
HECO and MECO earned their maximum DSM utility incentives of $4 million and $0.3 million, respectively, in 2008. HECO earned $0.7$1.3 million in December 2010. HECO began recovering $0.6 million in 2009 DSM utility incentives in 2009, however, in its DSM surcharge filing with the PUC on March 31, 2010, HECO’s revised DSM surcharge levels did not include recovery of the $0.7 million in incentives pending the PUC’s review of the calculation.April 2011.
Load Managementmanagement DSM Programs.programs. Unlike the EE DSM programs, load management DSM programs continue to be administered by the utilities. HECO’s residential load management program includes a monthly electric bill credit for eligible customers who participate in the program, which allows HECO to disconnect the customer’s residential electric water heaters or central air conditioning systems from HECO’s system to reduce system load when deemed necessary by HECO. The commercial and industrial load management program provides an incentive on the portion of the demand load that eligible customers allow to be controlled or interrupted by HECO. This program includes small business direct load control and voluntary program elements.
In December 2009, the PUC approved HECO’s requests to extend the Commercial and Industrial Direct Load Control (CIDLC) Program and the Residential Direct Load Control (RDLC) Program through 2012. The CIDLC Program application includedprovides an action planincentive on the portion of the demand load that eligible commercial/industrial customers allow HECO to be control or interrupt. The RDLC Program includes a monthly electric bill credit for aeligible residential customers who allow HECO to disconnect their electric water heaters or central air conditioning systems from HECO’s system to reduce system load aggregator pilot program. In October 2010, HECO filed an RDLC program increase request to accommodate anticipated base expenses for the cost of a program impact evaluation needed to update the cost-effectiveness calculations identifiedwhen deemed necessary by the PUC.
In April 2008, HECO filed an application for approval of a Dynamic Pricing Pilot (DPP) Program that allows prices to change from normal tariff rates as system conditions change and encourages customer curtailment of load through price incentives when there is insufficient generation to meet a projected peak demand period. In September 2010, HECO withdrew the DPP Program application due in part to the uncertain deployment schedule for smart meters in the utilities’ service territories.HECO.
In August 2010, HECO filed an application for a Fast Demand Response Pilot (Fast DR) Program—a two-year pilot program designed to test commercial and industrial market acceptance of load reductions within 10-minutes of event notification, and demonstrate the technical aspects of semi-automatic and automatic mechanisms to initiate customer reductions in load. A PUC decision is pending.
Renewable Energy Infrastructure Program. The Renewable Energy Infrastructure Program (REIP) proposed by HECO in December 2007 consisted of two components: (1) renewable energy infrastructure projects that facilitate third-party development of renewable energy resources, maintain existing renewable energy resources and/or enhance energy choices for customers and (2) the creation and implementation of a temporary renewable energy infrastructure surcharge to recover the capital costs, deferred costs for software development and licenses, and/or other relevant costs approved by the PUC. These costs would be removed from the surcharge and included in base rates in the utility’s next rate case. In December 2009, the PUC issued a D&O approving HECO’s proposed REIP, including the REIP surcharge, subject to certain conditions specified in the D&O. The PUC may review the benefits and continued need for the REIP every three years or earlier if necessary.
The PUC approved the use of the REIP surcharge to recover certain interconnection costs for a wind project. In July 2010, the utilities submitted (as directed by the PUC) proposed Standards and Guidelines for Utility Funding of Renewable Infrastructure Projects Associated with Independent Power Producers.
Delinking energy payment rates from oil costs. On April 18, 2008, the PUC initiated a docket to examine the methodology for calculating Schedule Q electricity payment rates in the State of Hawaii. In general, Schedule Q rates are available to customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the electric utility. The proceeding was intended to examine new methodologies for calculating Schedule Q payment rates, with the intent of removing or reducing any linkages between the price of fossil fuels and the rate for non-fossil fuel generated electricity. The parties to the Energy Agreement agreed that all new renewable energy contracts are to be delinked from fossil fuel and that the utilities would seek to renegotiate existing PPAs with IPPs that are based on fossil fuel prices to delink their energy payment rates from oil costs. In December 2010, HECO, HELCO and MECO filed updated avoided energy costs rates and Schedule Q rates to be effective for 2011, subject to monthly adjustment of the fuel component of the rates for changes in fuel prices. A Stipulated Procedural Schedule for the Schedule Q proceeding, which calls for the filing of final statements of position in April 2012, was approved by the PUC in January 2011.
Clean energy scenario planning, and integrated resource planning and requirements for additional generating capacity. The PUC issued an order in 1992 requiring the energy utilities in Hawaii to develop IRPs,integrated resource plans (IRPs), which would then be approved, rejected or modified by the PUC. The goal of integrated resource planning is the identification of demand- and supply-side resources and the integration of these resources for meeting near- and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost. The utilities’ latest IRPs are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in HEI’s Form 10-K for the year ended December 31, 2009.
TheUnder the PUC’s IRP framework, the utilities were to be entitled to recover all appropriate and reasonable integrated resource planning and implementationIRP costs including the costs of DSM programs, either through a surcharge or through their base rates. Under procedural schedules for the IRP cost proceedings, the utilities were able to recover their incremental IRP costs in the month following the filing of their actual costs incurred for the year, subject to refund with interest pending the PUC’s final D&O approving recovery in the docket for each year’s costs. HELCO, HECO and MECO nowcurrently recover IRP costs (which are included in O&M) through base rates. Also, see “Demand-side management programs” above.Previously they recovered their costs through a surcharge. In January 2011, the PUC issued a D&O that allowed the utilities to recover their 2002-2007 IRP planning costs, but disallowed certain costs, primarily costs incurred during a rate case test year. The utilities had been reserving for a potential refund for portions of the cost previously recovered and related interest, based on final D&Os issued for 1995-2001 IRP planning costs. In December 2010, the utilities recorded additional charges of $0.8 million to fully accrue for this refund, and in the first quarter of 2011 refunded approximately $1.2 million to its customers.
The parties to the Energy Agreement agreed to seek to replace the IRP process with a new Clean Energy Scenario Planning (CESP) process intended to be used to determine future investments in generation and transmission that will be necessary to facilitate high levels of renewable energy production and reductions in electricity use through energy efficiency programs. In the fourth quarter of 2008, the PUC closed the IRP-4 processes and directed the utilities to suspend all activities pursuant to the IRP framework to allow for resources to be diverted to the development of the CESP framework.
HECO and the Consumer Advocate filed a proposed CESP framework with the PUC in April 2009. In May 2009, the PUC opened an investigative proceeding to examine the proposed framework. As consensus between all partiesIn March 2011, the PUC filed a D&O modifying, updating and participants inexpanding the proceeding could not be reached, four revised proposed frameworks were separately filed in August 20101992 IRP framework by incorporating the concept of scenario planning, requiring the use of an independent entity to facilitate the IRP process and maintaining IRP rather than CESP as the title for the PUC’s consideration.process. The CESP framework filed jointlyIRP planning process will begin upon the issuance by HECOthe PUC of an order opening the docket. Thereafter, the independent entity shall be selected and its subsidiaries,retained by the Consumer Advocate, Kauai Island Utility CooperativePUC, the utilities shall file a schedule that they intend to follow in their IRP processes and the County of Kauai proposes a planning process resulting in aadvisory group shall be selected by the PUC. The utilities must file their IRP report and associated 5-year Action Plan developed from multiple scenarios and associated 20-year resource plans for each scenario. The proposed focus on scenario planning and shorter-term action plans (rather than 20-year plans) recognizes that planning assumptions are uncertain and thatwithin one year after the planning framework should facilitate making adjustments to resource plans as circumstances change. PUC adoptionselection of a CESP framework is pending.the advisory group.
Adequacy of supply (AOS).
HECOHECO.. HECO’s 2010 AOS In February 2011, HECO filed its 2011 Adequacy of Supply (AOS) letter, filed in February 2010,which indicated that based on the December 2009 update to its May 2010 sales and peak forecast, and on the full availability of CIP CT-1, HECO estimates it would have a reserve capacity surplus of approximately 30 MW in 2010 and that itsHECO’s generation capacity for years 20102011 to 2014 will be sufficient2015 is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. HECO anticipates that it will acquire 8 MW from a distributed standby generation facility at the Honolulu International Airport and 27 MW from an expansion of the existing H-Power waste-to-energy facility within the next two years. Beginning in 2016, HECO anticipates that based on increasing demand it will begin experiencing reserve capacity shortfalls if no more firm generating capacity is added to the system. Also, four existing generating units may be retired within the next 10 years because of their age or more stringent environmental regulations. In February 2011, at HECO’s request, the PUC opened a new docket to commence the competitive bidding process to acquire approximately 300 MW of new, firm generating capacity to replace the capacity that would be lost with the retirement of these four units and to accommodate load growth.
HELCOHELCO.. HELCO’s 2010 In January 2011, HELCO filed its 2011 AOS letter, filed in January 2010which indicated that HELCO’s generation capacity for the period 2010 to 2012through 2013 is sufficiently large to meet all reasonably expected demands for service and provide reasonable reserves for emergencies. HELCO is currently negotiating with two IPPsan IPP to supply additional firm renewable generating capacity to the HELCO grid.capacity. Should thesethis additional firm renewable facilitiesfacility come on line within the next three
years as anticipated, HELCO will not have a need for additional firm capacity in the foreseeable future. HELCO, however, may choose to add additional renewable generating capacity to replace existing nonrenewable generation.
MECOMECO.. MECO’s 2010 In January 2011, MECO filed its 2011 AOS letter, filed in January 2010which indicated that MECO’s generation capacity for the period 2010 to 2012 wasthrough 2014 is sufficient to meet the forecasted demands on the islands of Maui, Lanai and Molokai, andbut also stated that the estimated need date for additional increments of firm capacity will be needed on Maui was 2021. Subsequently, MECO’s June 2010 salesin 2015 and peak forecast reflected higher future peaks than its previous forecast. In June 2010, MECO filed2018 to accommodate the anticipated loss of capacity from an updateIPP at the end of 2014 and to its 2010 AOS letter for Maui based on its analysis of the new forecast. MECO’s update indicated that Maui’s generation capacity for the period 2011 to 2014 is sufficient to meet the forecasted demands and that the estimated need date for additional firm capacity on Maui is moved up to 2015.accommodate load growth.
December 2008 outage. On December 26, 2008, an island-wide outage occurred on the island of Oahu during a severe lightning storm that resulted in a loss of electric service to HECO customers ranging from approximately 7 to 20 hours. On January 12, 2009, the PUC initiated an investigation of the outage.
In March 2009, HECO submitted an outage report prepared by its expert consultant, POWER. The outage report concludedFebruary 2011, the PUC issued a final D&O finding that the island-wideactivities and performance of HECO prior to and during the power outage was triggered by lightning strikeswere reasonable and in the public interest and that no penalties would be imposed on or near HECO’s transmission system. POWER found that: (1)HECO due to the HECO system was in proper operating condition and was appropriately staffed at the time of the lightning storm, and (2) HECO’s restoration efforts were prudent and allowed for restoration of power as quickly as possible under the circumstances.outage.
Intra-governmental wheeling of electricity. In June 2007, the PUC initiated a docket to examine the feasibility of implementing intra-governmental wheeling of electricity in the State of Hawaii. The PUC subsequently suspended this docket, but reinstated it in November 2010. In January 2010,2011, the Consumer Advocate submitted its StatementPUC adopted the procedural schedule proposed by the Parties and Participants, which includes a panel hearing around the fourth quarter of Position that HECO could not have anticipated or prevented the outage through reasonable measures and could not have reasonably shortened the outage and restored power more quickly to customers. The Consumer Advocate further stated that penalties should not be assessed for the outage, but recommended that numerous studies be performed with the objective of preventing or minimizing the scope and duration of future power outages.
Management cannot at this time predict the outcome of the PUC’s investigation of the 2008 outage or its impact on HECO.2012
Collective bargaining agreementsagreements.. 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. See, for example,Also see, “Hawaii Clean Energy Initiative” and “Environmental regulation” in Note 5 of HECO’s “Notes to Consolidated Financial Statements.”Statements” and “Major tax legislation in 2011” above.
Increase in oil tax. On July 1, 2010, the state tax on petroleum products shipped to Hawaii increased from $0.05 to $1.05 per barrel. The higher tax, which is passed on to consumers, increased the price of gasoline and electricity and is expected to generate funds to reduce the state’s budget deficit and financesupport local food production and renewable energy programs.
Renewable energy. In 2008, a Hawaii law was enacted that is intended to facilitate the permitting of larger (200 MW or greater) renewable energy projects.
In 2009, a Hawaii law was enacted that authorizes preferential rates to agricultural energy producers selling electricity to utilities. This will help support the long-term development of locally grown biofuel crops, cultivating potential local renewable fuel sources for the utilities. In addition, pursuant to Act 50 (also adopted in 2009), avoided cost is no longer the primary consideration in determining a just and reasonable rate for non-fossil fuel generated electricity. This will allow the utilities to negotiate purchased power prices for renewable energy that have the potential to be more stable and less costly than current pricing tied to avoided cost.
Biofuels. In 2007, a Hawaii law was enacted with the stated purpose of encouraging further production and use of biofuels in Hawaii. It established that biofuel processing facilities in Hawaii are a permitted use in designated agricultural districts and established a program with the Hawaii Department of Agriculture to encourage the production in Hawaii of energy feedstock (i.e., raw materials for biofuels).
In 2008, a Hawaii law was enacted that encourages the development of biofuels by authorizing the Hawaii Board of Land and Natural Resources to lease public lands to growers or producers of plant and animal material used for the production of biofuels.
Other developments.
Advanced Metering Infrastructure (AMI). In December 2008, theThe utilities, filed anPUC and Consumer Advocate support a broad range of smart grid initiatives, including AMI, project application with the PUC for approval to implement an AMI project, covering approximately 451,000 meters (65%as important components of a clean energy strategy. The utilities are assessing, testing and deploying various smart grid technologies on Oahu, 20% on the island of Hawaiitheir systems. On March 31, 2011, HECO and 15% on Maui). The AMI project application included a request to approve a contract between Sensus Metering Systems, Inc. (Sensus) and HECO under which the utilities would purchase smart meters and pay Sensussigned an agreement to provide and maintain a radio frequency communication system to operate the smart meters and related equipment.
HECO submitted a proposal to the PUC in May 2010, describing an extended pilot testcontinue further testing of the AMI system and smart meters involving 5,000 new Sensus AMI meters. HECO’s proposal also contained an update on developments in the Smart Grid, CIS and cyber-security areas.
On July 26, 2010, the PUC issued an Order denying HECO, HELCO and MECO’s requests for an extended pilot test of their AMI system and smart meters on Oahu, and dismissing the utilities’ AMI application, without prejudice. In its Order, the PUC reiterated its support for an AMI and smart grid concept to reducetechnologies in Hawaii. The cost of the state’s dependence on fossil fuels, but noted that future AMI and smart grid applications should include ortesting conducted under this agreement will be preceded by an overall smart grid plan or proposal filed with the PUC.
As of September 30, 2010, the utilities did not have any deferred costs related to the AMI project proceeding. Management is currently evaluating the PUC’s Order and the future plans for AMI. HECO and Sensus have agreed that their respective rights to terminate their contract (based on the lack of PUC application approval) shall extend until March 31, 2011.expensed.
Commitments and contingenciescontingencies.. See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretationsinterpretations.. See Note 7 of HECO’s “Notes to Consolidated Financial Statements.”
FINANCIAL CONDITION
Liquidity and capital resources. Management believes that HECO’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retirement benefits and other cash requirements infor the foreseeable future.
HECO’s consolidated capital structure was as followsfollows:
(dollars in millions) |
| March 31, 2011 |
| December 31, 2010 |
| ||||||
Short-term borrowings |
| $ | — |
| — | % | $ | — |
| — | % |
Long-term debt, net |
| 1,058 |
| 44 |
| 1,058 |
| 44 |
| ||
Preferred stock |
| 34 |
| 1 |
| 34 |
| 1 |
| ||
Common stock equity |
| 1,339 |
| 55 |
| 1,338 |
| 55 |
| ||
|
| $ | 2,431 |
| 100 | % | $ | 2,430 |
| 100 | % |
HECO’s short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows:
|
| Average balance |
| Balance |
| |||||
(in millions) |
| Three months ended |
| March 31, |
| December 31, |
| |||
Short-term borrowings(1) |
|
|
|
|
|
|
| |||
Commercial paper |
| $ | — |
| $ | — |
| $ | — |
|
Line of credit draws |
| — |
| — |
| — |
| |||
Borrowings from HEI |
| — |
| — |
| — |
| |||
Line of credit facilities |
|
|
|
|
|
|
| |||
Undrawn capacity under line of credit facility expiring May 7, 2013 |
| N/A |
| 175 |
| 175 |
| |||
(1)There were no external short-term borrowings during the first quarter of 2011. At March 31, 2011, HECO had $31 million and $17 million of short-term borrowings from HELCO and MECO, respectively, which borrowings are eliminated in consolidation. At April 29, 2011, HECO had no outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $33 million and $18 million from HELCO and MECO, respectively.
The principal amount of special purpose revenue bonds (SPRBs) that have been authorized by the Hawaii legislature for future issuance by the State of Hawaii Department of Budget and Finance (DBF) for the benefit of the dates indicated:utilities was as follows:
(dollars in millions) |
| September 30, 2010 |
| December 31, 2009 |
| ||||||
Short-term borrowings |
| $ | — |
| — | % | $ | — |
| — | % |
Long-term debt, net |
| 1,058 |
| 44 |
| 1,058 |
| 44 |
| ||
Preferred stock |
| 34 |
| 1 |
| 34 |
| 1 |
| ||
Common stock equity |
| 1,326 |
| 55 |
| 1,306 |
| 55 |
| ||
|
| $ | 2,418 |
| 100 | % | $ | 2,398 |
| 100 | % |
(in millions) |
| March 31, 2011 |
| December 31, 2010 |
| ||
2007 legislative SPRBs authorization (expiring June 30, 2012) |
|
|
|
|
| ||
HECO |
| $ | 170 |
| $ | 170 |
|
HELCO |
| 55 |
| 55 |
| ||
MECO |
| 25 |
| 25 |
| ||
Total special purpose revenue bonds available for issue |
| $ | 250 |
| $ | 250 |
|
HECO utilizes short-term debt, typically commercial paper, to support normal operations, to refinance short-term debt and for other temporary requirements. HECO also borrows short-term from HEI for itself and on behalf of
HELCO and MECO, and HECO may borrow from or loan to HELCO and MECO short-term. The intercompany borrowings among the utilities, but not the borrowings from HEI, are eliminated in the consolidation of HECO’s financial statements. HECO and its subsidiaries periodically utilize long-term debt, historically borrowings of the
proceeds of special purpose bondsSPRBs issued by the State of Hawaii Department of Budget and Finance (DBF),DBF, to finance the utilities’ capital improvement projects, or to repay short-term borrowings used to finance such projects. The PUC must approve issuances, if any, of equity and long-term debt securities by HECO, HELCO and MECO.
Due to market conditions since September 2008 which(which resulted in a tightening of the commercial paper market, higher commercial paper rates and limitations on maturity options as welloptions) and as a result of an S&P downgrade of HECO’s short-term borrowing rating to A-3 from A-2, HECO drew on its previous $175 million syndicated line of credit facility in June and July 2009, rather than issue commercial paper. All such draws/borrowings were repaid in August 2009. HECO re-entered the commercial paper market in March 2010, experiencing higher rates and shorter terms.
Effective May 7, 2010, HECO entered into a revolving unsecurednoncollateralized credit agreement establishing a line of credit facility of $175 million, with a letter of credit sub-facility, with a syndicate of eight financial institutions. See Note 9 of HECO’s “Notes to Consolidated Financial Statements.”
The credit agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Issuer Rating (e.g., from BBB+/Baa1BBB/Baa2 to BBB/Baa2BBB-/Baa3 by S&P and Moody’s, respectively) would result in a commitment fee increase of 105 basis points and an interest rate increase of 25 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB/Baa2 to BBB+/Baa1 to A-/A3 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 510 basis points and an interest rate decrease of 25 basis points on any drawn amounts. The agreement contains customary conditions that must be met in order to draw on it, including compliance with several covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting its ability as well as the ability of any of its subsidiaries to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratio(actual ratios of 46%43% for HELCO and 43%42% for MECO as of September 30, 2010,March 31, 2011, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements may result in an event of default. For example, under its agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio(actual ratio of 55% as of September 30, 2010,March 31, 2011, as calculated under the agreement).
In addition to their impact on pricing under HECO’s credit agreement, the ratings of HECO’s commercial paper and debt securities could significantly impact the ability of HECO to sell its commercial paper and issue debt securities and/or the cost of such debt. The rating agencies use a combination of qualitative measures (e.g., assessment of business risk that incorporates an analysis of the qualitative factors such as management, competitive positioning, operations, markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratings of HECO securities. On July 30, 2010, Moody’s changed HECO’s rating outlook to stable from negative and affirmed HECO’s long-term and short-term borrowings (other than from MECO), HECO’s line(commercial paper) ratings, indicating that the ratings affirmation and outlook change reflects the progress being made to transform the regulatory framework for the utilities to a decoupling structure that will reduce sales volume risk and produce more timely recovery of credit facilitiesinvested capital and O&M costs. Moody’s indicated the principal amount of special purpose revenue bonds that have been authorized byrating could be downgraded if the Hawaii legislature for future issuance byPUC does not follow through with the DBF forregulatory transformation contemplated under the benefitHCEI, including all elements of the decoupling mechanism, or if the utilities’ cash flow to debt declined to below 17% on a sustainable basis and its cash flow coverage of interest fell below 3.5 times. On November 15, 2010, S&P issued an update in which it lowered its long-term ratings for HECO, HELCO and MECO to “BBB-” from “BBB,” and indicated the outlook as “stable.” In addition, S&P affirmed its “A-3” short-term rating of HECO and revised HECO’s financial profile to “aggressive” from “significant.” S&P indicated the rating downgrade reflects an “aggressive” financial profile combined with weak cash flow generation at HEI’s electric utilities, were as follows fordelays in implementing new utility rate recovery mechanisms, the periodgrowing risks of regulatory disallowances in future rate cases and as of the dates indicated:
|
| Nine months ended |
| Balance |
| |||||
(in millions) |
| Average |
| September 30, |
| December 31, |
| |||
Short-term borrowings(1) |
|
|
|
|
|
|
| |||
Commercial paper |
| $ | 5 |
| $ | — |
| $ | — |
|
Line of credit draws |
| — |
| — |
| — |
| |||
Borrowings from HEI |
| — |
| — |
| — |
| |||
Line of credit facilities |
|
|
|
|
|
|
| |||
Undrawn capacity under line of credit facility expiring May 6, 2011 |
| N/A |
| 175 |
| 175 |
| |||
Special purpose revenue bonds authorized for issue |
|
|
|
|
|
|
| |||
2007 legislative authorization (expiring June 30, 2012) |
|
|
|
|
|
|
| |||
HECO |
|
|
| 170 |
| 170 |
| |||
HELCO |
|
|
| 55 |
| 55 |
| |||
MECO |
|
|
| 25 |
| 25 |
| |||
Total special purpose revenue bonds available for issue |
|
|
| $ | 250 |
| $ | 250 |
| |
(1)At October 29, 2010, HECO had no outstanding commercial paper, its line of credit facility was undrawn, and it had no borrowings from HEI.
At September 30, 2010, HECO had $20 million of short-term borrowings from MECO and HELCO had $7 million of short-term borrowings from HECO.a protracted recession.
Management believes that, if HECO’s commercial paper ratings were to be further downgraded or if credit markets were to further tighten, it would be even more difficult and expensive to sell commercial paper or secure other short-term borrowings. Similarly, management believes that if HECO’s long-term credit ratings were to be downgraded, or if credit markets further tighten, it could be even more difficult and/or expensive for DBF and/or the Company to sell special purpose revenue bonds and other debt securities, respectively, for the benefit of the utilities in the future. Such limitations and/or increased costs could materially adversely affect the results of operations and financial condition of HECO and its subsidiaries.
As of OctoberApril 29, 2010,2011, the S&P and Moody’s ratings of HECO securities were as follows:
|
| S&P |
| Moody’s |
| |
|
|
|
|
|
| |
Commercial paper |
| A-3 |
| P-2 |
| |
Special purpose revenue bonds-insured |
|
|
|
|
| |
Ambac Assurance Corporation ($0.2 billion) |
|
| BBB-* |
|
| |
Financial Guaranty Insurance Company ($0.3 billion) |
|
| BBB-* |
|
| |
MBIA Insurance Corporation ($0.3 billion) |
|
|
|
| Baa1** | |
Syncora Guarantee Inc. (formerly XL Capital Assurance Inc.) ($0.1 billion) |
|
| BBB-* |
|
| |
Special purpose revenue bonds — uninsured ($150 million) |
|
|
| Baa1 |
| |
HECO-obligated preferred securities of trust subsidiary |
|
|
| Baa2 |
| |
Cumulative preferred stock (selected series) |
| Not rated |
| Baa3 |
|
The above ratings reflect only the view, at the time the ratings are issued, of the applicable rating agency, from whom an explanation of the significance of such ratings may be obtained. Such ratings are not recommendations to buy, sell or hold any securities; such ratings may be subject to revision or withdrawal at any time by the rating agencies; and each rating should be evaluated independently of any other rating.
* Rating corresponds to HECO’s rating (senior unsecured debt rating by S&P or issuer rating by Moody’s) because, as a result of rating agency actions to lower or withdraw the ratings of these bond insurers after the bonds were issued, HECO’s current ratings are either higher than the current rating of the applicable bond insurer or the bond insurer is not rated.
** Following MBIA Insurance Corporation’s (MBIA’s) announced restructuring in February 2009, the revenue bonds issued for the benefit of HECO and its subsidiaries and insured by MBIA have been reinsured by MBIA Insurance Corp. of Illinois (MBIA Illinois), whose name was subsequently changed to National Public Finance Guarantee Corp. (National). The financial strength rating of National by S&P is A.BBB. Moody’s ratings on securities that are guaranteed or “wrapped” by a financial guarantor are generally maintained at a level equal to the higher of the rating of the guarantor (if rated at the investment grade level) or the published underlying rating. The insurance financial strength rating of National by Moody’s is Baa1, which is the same as Moody’s issuer rating for HECO.
The rating agencies use a combination of qualitative measures (e.g., assessment of business riskManagement believes that, incorporates an analysisif HECO’s commercial paper ratings were to be further downgraded or if credit markets were to further tighten, it would be even more difficult and expensive for HECO to sell commercial paper or secure other short-term borrowings or HECO might not be able to sell commercial paper in the future. Similarly, management believes that if HECO’s long-term credit ratings were to be further downgraded, or if credit markets further tighten, it could be even more difficult and/or expensive for DBF and/or the Company to sell SPRBs and other debt securities, respectively, for the benefit of the qualitative factors such as management, competitive positioning,utilities in the future. Such limitations and/or increased costs could materially adversely affect the results of operations markets and regulation) as well as quantitative measures (e.g., cash flow, debt, interest coverage and liquidity ratios) in determining the ratingsfinancial condition of HECO securities. In May 2009, S&P revised HECO’s outlook to negative from stable, and lowered HECO’s short-term rating to “A-3” from “A-2.” S&P indicated the rating actions reflected its view that the next two years are likely to be challenging for HEI’s electric utilities. S&P stated that the deterioration in the Hawaii economy is likely to weaken 2009 and 2010 consolidated metrics, which it observed have been only marginally supportive of the “BBB” corporate credit ratings currently assigned to HECO. In May 2010, S&P noted that “[t]he negative outlook on Hawaiian Electric Company, Inc. (HECO) ratings reflects a weak consolidated financial profile that has been weighted down by the island recession and the need for more timely rate relief. We are concerned that 2010 could be another year of underperformance for HECO. HECO’s stand-alone financial performance has been weak for the rating and has shown scant signs of improvement since 2007, a fact that underpins our negative outlook and the need to see improvement in 2010.” S&P further stated that “[w]e expect to lower the corporate credit rating on HECO one notch to ‘BBB-’ unless we are able to see a clear path in 2010 to an improvement in HECO’s credit metrics, which would at minimum require us to conclude that the electric utility is able to maintain funds from operations (FFO) to total debt of 15%, FFO interest coverage in the area of 3.5x, and leverage of less than 60%.” S&P also indicated that “[a]n upgrade is not likely due to HECO’s need to restore its financial profile to levels consistent with the current rating.”
On July 30, 2010, Moody’s changed HECO’s rating outlook to stable from negative and affirmed HECO’s long-term and short-term (commercial paper) ratings. Moody’s stated in its August 2, 2010 Credit Opinion on HECO:
Table of Contentssubsidiaries.
The ratings affirmationPUC must approve issuances, if any, of equity and outlook change reflects the progress being madelong-term debt securities by HECO, HELCO and MECO. Revenue bonds are issued by the company and various stakeholdersDBF to transform the regulatory framework for HEI’s electric utilities to a decoupling structure that will reduce sales volume risk and produce more timely recoveryfinance capital improvement projects of invested capital and operations and maintenance (O&M) costs….
The stable rating outlook…incorporates our belief that the regulatory transition underway in Hawaii will proceed in an orderly fashion with the Hawaii PUC issuing the final decoupling order during 2010 for the three utilities.
In light of the sizeable capital investment programs and the remaining uncertainty that surrounds associated rate case decisions contemplated by HECO and its subsidiaries, limited near-term prospects exist forbut the rating to be upgraded. However, HECO’s ratings could be upgraded ifsource of their repayment is the regulatory transition underway is executed in an orderly fashion leading to an improvement in credit metrics such that the utility’s cash flow to debt exceeds 22%unsecured obligations of HECO and its cash flow coveragesubsidiaries under loan agreements and notes issued to the DBF, including HECO’s guarantees of interest is greater than 4.5x on a sustainable basis.
The rating could be downgraded if the Hawaii PUC does not follow through with the regulatory transformation contemplated under the HCEI, including all elements of the decoupling mechanism. Quantitatively, the ratings could be downgraded if the utilities’ cash flow to debt declined to below 17% on a sustainable basis and its cash flow coverage of interest fell below 3.5x.
subsidiaries’ obligations. The payment of principal and interest due on Special Purpose Revenue Bonds (SPRBs)SPRBs currently outstanding and issued prior to 2009 are insured either by Ambac Assurance Corporation, Financial Guaranty Insurance Company, MBIA Insurance Corporation (MBIA) (which bonds have been reinsured by National Public Finance Guarantee Corp.) or Syncora Guarantee Inc. (which bonds have been reinsured by Syncora Capital Assurance Inc.). The insured outstanding revenue bondsSPRBs were initially issued with S&P and Moody’s ratings of AAA and Aaa, respectively, based on the ratings at the time of issuance of the applicable bond insurer. Beginning in 2008, however, ratings of the insurers (or their predecessors) were downgraded and/or withdrawn by S&P and Moody’s, resulting in a downgrade of the bond ratings of all of the bonds as shown in the ratings table above. The $150 million of SPRBs sold by the DBF for the benefit of HECO and HELCO on July 30, 2009, were sold without bond insurance.
HECO and HELCO sold $93 million and $3 million, respectively,On November 15, 2010, the PUC approved the request of their common stock to HEI and HECO, respectively, in December 2009. For HECO’s $93 million of common stock, HECO received $62 million of cash from HEI and reduced its intercompany note payable to HEI by $31 million in a noncash transaction. On April 5, 2010, HECO, HELCO and MECO filed with the PUC an application for the approval of the sale of each utility’s common stock over a five-year period from 2010 through 2014 (HECO’s sale to HEI of up to $210 million and HELCO’sHELCO and MECO’s sales to HECO of up to $43 million and $15 million, respectively), and the purchase of the HELCO and MECO common stock by HECO. In December 2010, HELCO and MECO sold $23 million and $3 million, respectively, of their common stock to HECO, overand HECO sold $4 million of its common stock to HEI. On March 31, 2011, HECO, HELCO and MECO filed with the five-year period.PUC an application for the authorization to issue up to $250 million in obligations for HECO, up to $25 million for HELCO and up to $25 million for MECO, in one or more registered public offerings or private placements on or before December 31, 2015.
Operating activities provided $116used $28 million in net cash during the first nine monthsquarter of 2010.2011. Investing activities during the same period used net cash of $114$32 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period used net cash of $41$18 million, primarily due the payment of $40$18 million of common and preferred dividends.
Management periodically reviews capital expenditure estimates and the timing of construction projects. These estimates may change significantly as a result of many considerations, including changes in economic conditions, changes in forecasts of KWH sales and peak load, the availability of purchased power and changes in expectations concerning the construction and ownership of future generation units, the availability of generating sites and transmission and distribution corridors, the need for fuel infrastructure investments, the ability to obtain adequate and timely rate increases, escalation in construction costs, commitments under the Energy Agreement, the impacts of DSM programs and CHP installations, the effects of opposition to proposed construction projects and requirements of environmental and other regulatory and permitting authorities.
RESULTS OF OPERATIONS
|
| Three months ended September 30 |
| % |
|
|
| ||||
(in thousands) |
| 2010 |
| 2009 |
| change |
| Primary reason(s) for significant change |
| ||
Revenues |
| $ | 71,429 |
| $ | 71,947 |
| (1 | ) | Lower interest income primarily due to lower earning asset balances (as a result of the sale of most of the 1-4 family residential loan production in 2009 and the first nine months of 2010 and the sale of the private-issue mortgage-related securities portfolio in the fourth quarter of 2009) and lower yields on earning assets (due to the lower interest rate environment), partly offset by higher noninterest income (due to an other-than-temporary impairment on the mortgage-related securities portfolio in the third quarter of 2009) |
|
|
|
|
|
|
|
|
|
|
| ||
Operating income |
| 24,389 |
| 17,689 |
| 38 |
| Higher noninterest income (due to losses on available-for-sale securities in the third quarter in 2009) and lower noninterest expenses (due to the performance improvement project), partially offset by lower net interest income and higher provision for loan losses |
| ||
|
|
|
|
|
|
|
|
|
| ||
Net income |
| 15,293 |
| 11,323 |
| 35 |
| Higher operating income, partly offset by higher income taxes |
| ||
|
| Nine months ended September 30 |
| % |
|
|
|
| Three months ended March 31 |
| % |
|
|
| ||||||||
(in thousands) |
| 2010 |
| 2009 |
| change |
| Primary reason(s) for significant change |
|
| 2011 |
| 2010 |
| change |
| Primary reason(s) for significant change |
| ||||
Revenues |
| $ | 213,975 |
| $ | 229,478 |
| (7 | ) | Lower interest income primarily due to lower earning asset balances (as a result of the sale of most of the 1-4 family residential loan production in 2009 and the first nine months of 2010 and the sale of the private-issue mortgage-related securities portfolio in the fourth quarter of 2009) and lower yields on earning assets (due to the lower interest rate environment), partly offset by higher noninterest income (due to an other-than-temporary impairment on the mortgage-related securities portfolio in 2009) |
|
| $ | 65,313 |
| $ | 70,914 |
| (8 | ) | Lower interest income primarily due to lower earning asset balances as a result of the sale of substantially all of the 1-4 family residential loan production in the first nine months of 2010 and lower yields on earning assets due to the lower interest rate environment |
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Operating income |
| 71,935 |
| 40,316 |
| 78 |
| Lower provision for loan losses, higher noninterest income (due to losses on available-for-sale securities in the second and third quarters in 2009) and lower noninterest expenses (due to the performance improvement project), partially offset by lower net interest income |
|
| 21,754 |
| 21,771 |
| — |
| Lower net interest and noninterest income, largely offset by lower noninterest expenses and lower provision for loan losses |
| ||||
|
|
|
|
|
|
|
|
|
| |||||||||||||
Net income |
| 45,160 |
| 26,226 |
| 72 |
| Higher operating income, partly offset by higher income taxes |
|
| 13,851 |
| 13,736 |
| 1 |
| Lower income tax expense |
|
SeeNote 4 of HEI’s “Notes to Consolidated Financial Statements” and “Economic conditions” in the “HEI Consolidated” section above.
In 2010, ASB successfully completed its multi-year Performance Improvement Project that began in 2008. The many initiatives of this project resulted in substantially improved profitability and reduced risk in 2010, which continued into the first quarter of 2011.
For the three months ended March 31, 2011, ASB reported a strong 1.15% return on assets and 57% efficiency ratio, and ASB’s profitability metrics were in line or better than the average of its high performing peers. Key drivers of this improved performance include:
671.ASB’s significant reduction of non-interest expense;
2.ASB’s reduction of its exposure to riskier non-core assets;
3.ASB’s lowering of its funding costs through its free checking product and lower CD balances; and
4.ASB’s optimization of its balance sheet and capital efficiency and improvement of its capital ratios by exercising discipline through the downturn on what was selected to put on its balance sheet and holding additional capital to hedge against the downside of the credit cycle.
In addition, as Hawaii’s economy started to improve, ASB saw declines in the provision expense year over year. Importantly, ASB’s credit quality metrics through the down cycle has been better than the average of its peers due to its historic disciplined and conservative underwriting standards.
Management is now working to grow its bank franchise in Hawaii and remains focused on maintaining ASB as a high performing community bank with a targeted return on assets of 1.2%, net interest margin above 4% and an efficiency ratio in the mid-50s. Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base, reduced cost structure and lower-risk profile to continue to deliver strong performance compared to industry averages.
Average balance sheet and net interest marginmargin.. The following tables set forth average balances, together with interest and dividend income earned and accrued, and resulting yields and costs for the three and nine months ended September 30, 2010March 31, 2011 and 2009.2010.
|
| Three months ended September 30 |
| ||||||||||||||
|
| 2010 |
| 2009 |
| ||||||||||||
($ in thousands) |
| Average |
| Interest |
| Average |
| Average |
| Interest |
| Average |
| ||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Other investments (1) |
| $ | 335,002 |
| $ | 151 |
| 0.18 |
| $ | 270,177 |
| $ | 122 |
| 0.18 |
|
Investment and mortgage-related securities |
| 586,706 |
| 3,701 |
| 2.52 |
| 662,419 |
| 6,821 |
| 4.12 |
| ||||
Loans receivable (2) |
| 3,555,997 |
| 49,221 |
| 5.52 |
| 3,845,469 |
| 53,080 |
| 5.51 |
| ||||
Total interest-earning assets |
| 4,477,705 |
| 53,073 |
| 4.73 |
| 4,778,065 |
| 60,023 |
| 5.01 |
| ||||
Allowance for loan losses |
| (36,218 | ) |
|
|
|
| (43,792 | ) |
|
|
|
| ||||
Non-interest-earning assets |
| 418,266 |
|
|
|
|
| 346,107 |
|
|
|
|
| ||||
Total assets |
| $ | 4,859,753 |
|
|
|
|
| $ | 5,080,380 |
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Liabilities and Stockholder’s Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest-bearing demand and savings deposits |
| $ | 2,419,983 |
| 776 |
| 0.13 |
| $ | 2,279,477 |
| 1,289 |
| 0.22 |
| ||
Time certificates |
| 744,040 |
| 2,614 |
| 1.39 |
| 1,083,713 |
| 5,997 |
| 2.20 |
| ||||
Total interest-bearing deposits |
| 3,164,023 |
| 3,390 |
| 0.43 |
| 3,363,190 |
| 7,286 |
| 0.86 |
| ||||
Other borrowings |
| 257,156 |
| 1,414 |
| 2.16 |
| 397,327 |
| 2,205 |
| 2.17 |
| ||||
Total interest-bearing liabilities |
| 3,421,179 |
| 4,804 |
| 0.56 |
| 3,760,517 |
| 9,491 |
| 1.00 |
| ||||
Non-interest bearing liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Deposits |
| 832,732 |
|
|
|
|
| 749,328 |
|
|
|
|
| ||||
Other |
| 97,914 |
|
|
|
|
| 88,775 |
|
|
|
|
| ||||
Stockholder’s equity |
| 507,928 |
|
|
|
|
| 481,760 |
|
|
|
|
| ||||
Total Liabilities and Stockholder’s Equity |
| $ | 4,859,753 |
|
|
|
|
| $ | 5,080,380 |
|
|
|
|
| ||
Net interest income |
|
|
| $ | 48,269 |
|
|
|
|
| $ | 50,532 |
|
|
| ||
Net interest margin (%) (3) |
|
|
|
|
| 4.31 |
|
|
|
|
| 4.23 |
|
|
| Nine months ended September 30 |
| |||||||||||||||||||||||||||||||
|
| 2010 |
| 2009 |
| |||||||||||||||||||||||||||||
($ in thousands) |
| Average |
| Interest |
| Average |
| Average |
| Interest |
| Average |
| |||||||||||||||||||||
Three months ended March 31 |
| 2011 |
| 2010 |
| |||||||||||||||||||||||||||||
(dollars in thousands) |
| Average |
| Interest |
| Average |
| Average |
| Interest |
| Average |
| |||||||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Other investments (1) |
| $ | 347,418 |
| $ | 471 |
| 0.18 |
| $ | 202,570 |
| $ | 177 |
| 0.12 |
|
| $ | 236,045 |
| $ | 86 |
| 0.15 |
| $ | 394,588 |
| $ | 183 |
| 0.19 |
|
Investment and mortgage-related securities |
| 539,348 |
| 10,344 |
| 2.56 |
| 660,450 |
| 21,585 |
| 4.36 |
|
| 659,326 |
| 3,809 |
| 2.31 |
| 454,960 |
| 3,134 |
| 2.75 |
| ||||||||
Loans receivable (2) |
| 3,625,186 |
| 148,294 |
| 5.46 |
| 3,999,395 |
| 166,535 |
| 5.56 |
|
| 3,546,322 |
| 46,097 |
| 5.22 |
| 3,679,380 |
| 49,745 |
| 5.43 |
| ||||||||
Total interest-earning assets |
| 4,511,952 |
| 159,109 |
| 4.70 |
| 4,862,415 |
| 188,297 |
| 5.17 |
| |||||||||||||||||||||
Total interest-earning assets(3) |
| 4,441,693 |
| 49,992 |
| 4.52 |
| 4,528,928 |
| 53,062 |
| 4.70 |
| |||||||||||||||||||||
Allowance for loan losses |
| (39,506 | ) |
|
|
|
| (41,252 | ) |
|
|
|
|
| (39,827 | ) |
|
|
|
| (40,868 | ) |
|
|
|
| ||||||||
Non-interest-earning assets |
| 413,051 |
|
|
|
|
| 345,201 |
|
|
|
|
|
| 416,309 |
|
|
|
|
| 412,987 |
|
|
|
|
| ||||||||
Total assets |
| $ | 4,885,497 |
|
|
|
|
| $ | 5,166,364 |
|
|
|
|
|
| $ | 4,818,175 |
|
|
|
|
| $ | 4,901,047 |
|
|
|
|
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Liabilities and Stockholder’s Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Liabilities and shareholder’s equity: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||
Interest-bearing demand and savings deposits |
| $ | 2,400,738 |
| 2,732 |
| 0.15 |
| $ | 2,200,539 |
| 5,434 |
| 0.33 |
|
| $ | 2,460,794 |
| $ | 704 |
| 0.12 |
| $ | 2,369,574 |
| 1,040 |
| 0.18 |
| |||
Time certificates |
| 794,222 |
| 8,933 |
| 1.50 |
| 1,214,775 |
| 23,319 |
| 2.57 |
|
| 645,356 |
| 1,889 |
| 1.19 |
| 848,526 |
| 3,383 |
| 1.62 |
| ||||||||
Total interest-bearing deposits |
| 3,194,960 |
| 11,665 |
| 0.49 |
| 3,415,314 |
| 28,753 |
| 1.13 |
|
| 3,106,150 |
| 2,593 |
| 0.34 |
| 3,218,100 |
| 4,423 |
| 0.56 |
| ||||||||
Other borrowings |
| 275,045 |
| 4,258 |
| 2.05 |
| 453,738 |
| 7,710 |
| 2.24 |
|
| 242,385 |
| 1,367 |
| 2.26 |
| 294,869 |
| 1,426 |
| 1.94 |
| ||||||||
Total interest-bearing liabilities |
| 3,470,005 |
| 15,923 |
| 0.61 |
| 3,869,052 |
| 36,463 |
| 1.26 |
|
| 3,348,535 |
| 3,960 |
| 0.48 |
| 3,512,969 |
| 5,849 |
| 0.67 |
| ||||||||
Non-interest bearing liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Deposits |
| 816,134 |
|
|
|
|
| 733,810 |
|
|
|
|
|
| 883,635 |
|
|
|
|
| 796,705 |
|
|
|
|
| ||||||||
Other |
| 95,779 |
|
|
|
|
| 87,455 |
|
|
|
|
|
| 91,517 |
|
|
|
|
| 92,844 |
|
|
|
|
| ||||||||
Stockholder’s equity |
| 503,579 |
|
|
|
|
| 476,047 |
|
|
|
|
| |||||||||||||||||||||
Total Liabilities and Stockholder’s Equity |
| $ | 4,885,497 |
|
|
|
|
| $ | 5,166,364 |
|
|
|
|
| |||||||||||||||||||
Shareholder’s equity |
| 494,488 |
|
|
|
|
| 498,529 |
|
|
|
|
| |||||||||||||||||||||
Total liabilities and shareholder’s equity |
| $ | 4,818,175 |
|
|
|
|
| $ | 4,901,047 |
|
|
|
|
| |||||||||||||||||||
Net interest income |
|
|
| $ | 143,186 |
|
|
|
|
| $ | 151,834 |
|
|
|
|
|
| $ | 46,032 |
|
|
|
|
| $ | 47,213 |
|
|
| ||||
Net interest margin (%) (3) |
|
|
|
|
| 4.23 |
|
|
|
|
| 4.17 |
| |||||||||||||||||||||
Net interest margin (%) (4) |
|
|
|
|
| 4.16 |
|
|
|
|
| 4.18 |
|
(1) Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle ($98 million as of September 30, 2010)March 31, 2011).
(2) Includes loan fees of $2.1$1.2 million and $1.5$1.4 million for the three months ended September 30,March 31, 2011 and 2010, and 2009, respectively, $4.7 million and $5.3 million for the nine months ended September 30, 2010 and 2009, respectively, together with interest accrued prior to suspension of interest accrual on nonaccrual loans. Includesloans, includes nonaccrual loans.
(3)Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $126,000 and nil for the three months ended March 31, 2011 and 2010, respectively.
(4) Defined as net interest income as a percentage of average earning assets.
Earning assets, costing liabilities and other factorsfactors.. Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The current interest rate environment is impacted by disruptions in the financial markets and these conditions may have a negative impact on ASB’s net interest margin.
Loan originations and mortgage-related securities are ASB’s primary sources of earning assets.
Loan portfolio. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. The following table sets forth the composition of ASB’s loan portfolio as of the dates indicated:portfolio:
|
| September 30, 2010 |
| December 31, 2009 |
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||
(dollars in thousands) |
| Balance |
| % of |
| Balance |
| % of |
|
| Balance |
| % of total |
| Balance |
| % of total |
| ||||
Real estate loans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Residential 1-4 family |
| $ | 2,104,936 |
| 60.1 |
| $ | 2,319,738 |
| 62.5 |
|
| $ | 2,051,945 |
| 56.9 |
| $ | 2,087,813 |
| 58.9 |
|
Commercial real estate |
| 280,318 |
| 8.0 |
| 255,458 |
| 6.9 |
|
| 300,248 |
| 8.3 |
| 300,689 |
| 8.5 |
| ||||
Home equity line of credit |
| 402,805 |
| 11.5 |
| 328,164 |
| 8.8 |
|
| 444,684 |
| 12.3 |
| 416,453 |
| 11.7 |
| ||||
Residential land |
| 75,880 |
| 2.1 |
| 96,515 |
| 2.6 |
|
| 60,671 |
| 1.7 |
| 65,599 |
| 1.8 |
| ||||
Commercial construction |
| 35,290 |
| 1.0 |
| 68,107 |
| 1.8 |
|
| 39,960 |
| 1.1 |
| 38,079 |
| 1.1 |
| ||||
Residential construction |
| 7,652 |
| 0.2 |
| 16,598 |
| 0.5 |
|
| 3,568 |
| 0.1 |
| 5,602 |
| 0.2 |
| ||||
Total real estate loans, net |
| 2,906,881 |
| 82.9 |
| 3,084,580 |
| 83.1 |
|
| 2,901,076 |
| 80.4 |
| 2,914,235 |
| 82.2 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commercial |
| 514,095 |
| 14.7 |
| 542,686 |
| 14.6 |
| |||||||||||||
Consumer |
| 83,889 |
| 2.4 |
| 84,906 |
| 2.3 |
| |||||||||||||
Commercial loans |
| 617,800 |
| 17.2 |
| 551,683 |
| 15.5 |
| |||||||||||||
Consumer loans |
| 86,895 |
| 2.4 |
| 80,138 |
| 2.3 |
| |||||||||||||
|
| 3,504,865 |
| 100.0 |
| 3,712,172 |
| 100.0 |
|
| 3,605,771 |
| 100.0 |
| 3,546,056 |
| 100.0 |
| ||||
Less: Allowance for loan losses |
| 38,315 |
|
|
| 41,679 |
|
|
| |||||||||||||
Less: Deferred fees and discounts |
| (15,207 | ) |
|
| (15,530 | ) |
|
| |||||||||||||
Allowance for loan losses |
| (40,814 | ) |
|
| (40,646 | ) |
|
| |||||||||||||
Total loans, net |
| $ | 3,466,550 |
|
|
| $ | 3,670,493 |
|
|
|
| $ | 3,549,750 |
|
|
| $ | 3,489,880 |
|
|
|
The decreaseincrease in the total loan portfolio during the first nine monthsquarter of 20102011 was primarily due to an increase in ASB’s strategic decision to sell mostcommercial loan and home equity lines of the salable residential loans it originated during the nine month period ($254 million of loans sold).credit portfolios.
Loan portfolio risk elements.When a borrower failsSee Note 4 of HEI’s “Notes to make a required payment on a loan and does not cure the delinquency promptly, the loan is classified as delinquent. If delinquencies are not cured promptly, ASB normally commences a collection action, including foreclosure proceedings in the case of secured loans. In a foreclosure action, the property securing the delinquent debt is sold at a public auction in which ASB may participate as a bidder to protect its interest. If ASB is the successful bidder, the property is classified as real estate owned until it is sold.Consolidated Financial Statements.
The following table sets forth certain information with respect to nonperforming assets as of the dates indicated:
(dollars in thousands) |
| September 30, |
| December 31, |
| ||
Real estate loans: |
|
|
|
|
| ||
Residential 1-4 family |
| $ | 35,309 |
| $ | 31,686 |
|
Commercial real estate |
| 717 |
| 344 |
| ||
Home equity line of credit |
| 1,829 |
| 2,755 |
| ||
Residential land |
| 17,863 |
| 25,162 |
| ||
Commercial construction |
| — |
| — |
| ||
Residential construction |
| — |
| 325 |
| ||
Total real estate loans, net |
| 55,718 |
| 60,272 |
| ||
Commercial |
| 4,731 |
| 4,171 |
| ||
Consumer |
| 780 |
| 715 |
| ||
Total nonperforming loans |
| 61,229 |
| 65,158 |
| ||
Real estate owned: |
|
|
|
|
| ||
Residential 1-4 family |
| 1,493 |
| 1,806 |
| ||
Residential land |
| 2,981 |
| 2,153 |
| ||
Total real estate owned loans |
| 4,474 |
| 3,959 |
| ||
Total nonperforming assets |
| $ | 65,703 |
| $ | 69,117 |
|
Nonperforming assets to total loans and REO |
| 1.87 | % | 1.85 | % |
The level of nonperforming loans reflects the impact of current unemployment levels in Hawaii and the weak economic environment globally, nationally and in Hawaii.
Allowance for loan losses. The following table sets forth the allocation of ASB’s allowance for loan losses and the percentage of loans in each category to total loans as of the dates indicated:
|
| September 30, 2010 |
| December 31, 2009 |
| ||||||
(dollars in thousands) |
| Balance |
| % of total |
| Balance |
| % of total |
| ||
Real estate loans: |
|
|
|
|
|
|
|
|
| ||
Residential 1-4 family |
| $ | 5,697 |
| 60.1 |
| $ | 5,522 |
| 62.5 |
|
Commercial real estate |
| 1,385 |
| 8.0 |
| 861 |
| 6.9 |
| ||
Home equity line of credit |
| 4,183 |
| 11.5 |
| 4,679 |
| 8.8 |
| ||
Residential land |
| 2,981 |
| 2.1 |
| 4,252 |
| 2.6 |
| ||
Commercial construction |
| 1,591 |
| 1.0 |
| 3,068 |
| 1.8 |
| ||
Residential construction |
| 7 |
| 0.2 |
| 19 |
| 0.5 |
| ||
Total real estate loans, net |
| 15,844 |
| 82.9 |
| 18,401 |
| 83.1 |
| ||
|
|
|
|
|
|
|
|
|
| ||
Commercial |
| 18,293 |
| 14.7 |
| 19,498 |
| 14.6 |
| ||
Consumer |
| 3,461 |
| 2.4 |
| 2,590 |
| 2.3 |
| ||
|
| 37,598 |
| 100.0 |
| 40,489 |
| 100.0 |
| ||
Unallocated |
| 717 |
|
|
| 1,190 |
|
|
| ||
Total allowance for loan losses |
| $ | 38,315 |
|
|
| $ | 41,679 |
|
|
|
Total allowance for loan losses to end of period loans |
| 1.09 | % |
|
| 1.12 | % |
|
|
Investment and mortgage-related securities. As of September 30, 2010,March 31, 2011, the bank’s investment portfolio consisted of 48%51% mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) or Government National Mortgage Association (GNMA), 47%43% federal agency obligations and 5%6% municipal bonds. As of December 31, 2009,2010, the bank’s investment portfolio consisted of 75%47% mortgage-related securities issued by FNMA, FHLMC or GNMA, 24%47% federal agency obligations and 1%6% municipal bonds.
Principal and interest on mortgage-related securities issued by FNMA, FHLMC and GNMA are guaranteed by the issuer, and the securities carry implied AAA ratings.
Deposits and other borrowings. Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Deposit retention and growth willCore deposits continue to be strong, as depositors remain challenges in the current environment due to competition for deposits and the level of short-term interest rates.risk adverse. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be additional sources of funds. As of September 30,March 31, 2011 and December 31, 2010, ASB’s costing liabilities consisted of 94% deposits and 6% borrowings. At December 31, 2009, ASB’s costing liabilities consisted of 93% deposits and 7% other borrowings. The weighted average cost of deposits for the three and nine months ended September 30, 2010 were 0.34% and 0.39%March 31, 2011 was 0.26%, respectively, compared to the weighted average cost of deposits0.45% for the three and nine months ended September 30, 2009 of 0.70% and 0.93%, respectively.March 31, 2010.
Other factors. Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in fair value of those instruments. In addition, changes in credit spreads also impact the fair values of those instruments.
Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) could reduce the market value of available-for-sale investment and mortgage-related securities and reduce stockholder’sshareholder’s equity through a balance sheet charge to AOCI, this reduction in the market value of investments and mortgage-related securities would not result in a charge to net income in the absence of a sale of such securities (such as those that occurred in the fourth quarter of 2009 and in thea 2008 balance sheet restructure) or an “other-than-temporary” impairment in the value of the securities. As of September 30, 2010March 31, 2011 and December 31, 2009,2010, the unrealized gains, net of taxes, on available-for-sale investments and mortgage-relatedmortgage-
related securities (including securities pledged for repurchase agreements) in AOCI was $7$3 million and $5$4 million, respectively. See “Quantitative“Item 3. Quantitative and qualitative disclosures about market risk.”
Results — three and nine months ended September 30, 2010March 31, 2011.. Net interest income before provision for loan losses for the thirdfirst quarter and first nine months of 20102011 decreased by 4% and 6%$1.3 million, or 3%, respectively, when compared to the same periodquarter in 20092010 as lower funding costs were more than offset by the impact of lower average balances and yields on interest-earning assets.
loans and lower yields on investment and mortgage-related securities. Net interest margin decreased from 4.18% in the first quarter of 2010 to 4.16% in the first quarter of 2011 due to lower yields on the investment and mortgage-related securities portfolio and loans receivable. The decrease in the average loan portfolio balance compared to the first quarter of 2010 was due to a decrease in the average 1-4 family residential loan portfolio of $240 million as a result of the sale of substantial residential loan production in 2010 and lower loan production in 2011. Average residential land balances decreased by $30 million compared to the first quarter of 2010 due to paydowns in the portfolio. The average home equity lines of credit portfolio increased by $101 million compared to the first quarter of 2010 due to promotional campaigns during 2010. The increase in the average investment and mortgage-related securities portfolios was primarily due to the purchase of federal agency securities and obligations with excess liquidity. Average deposit balances in 2010 decreased by $25 million compared to the thirdfirst quarter and first nine months of 20092010. The average term certificate balance decreased by $203 million due to decreases in the average time certificate balanceoutflow of term certificates throughout 2010 and the first quarter of 2011 as ASB diddetermined not to aggressively price its timeterm certificate products, partly offset by increasesproducts. Offsetting the decrease in the term certificate portfolio was growth in the average core deposit balance of $178 million as ASB introduced new deposit products and attracted core deposit products.deposits to partially offset the outflow of term certificates. The shift in deposit mix from higher cost time certificates to lower cost savings and checking accounts, along with the repricing of deposits as a result of a downward movement in the general level of interest rates, has contributed to the decreased funding costs in 2010. Also, higher costingcosts. Average other borrowings decreased by $52 million compared to the first quarter of 2010 primarily due to the payoffan outflow of maturing amounts.
The decrease in funding costs was partly offset by lower yields on the investment and mortgage-related securities portfolio as ASB sold its higher yielding private-issue mortgage-related securities portfolio in the fourth quarter of 2009 to reduce ASB’s overall credit risk and had challenges finding investments with adequate risk-adjusted returns for its excess liquidity, leading it to invest its excess liquidity in other investments (primarily deposit accounts) bearing low interest rates. ASB’s average loan portfolio balances decreased due to decreases in the average 1-4 family residential loan portfolio as ASB sold most of its salable residential loan production during 2009 and the first nine months of 2010. The net interest margin of 4.31% for the third quarter of 2010 would have been approximately 9 basis points lower, or 4.22%, if not for the accelerated recognition of deferred fees primarily due to loan repayments which are typically high in this type of low interest rate environment. Average commercial, residential land and construction loan balances decreased due to paydowns in those portfolios. The average home equity line of credit portfolio balance increased due to a promotional campaign in the first half of 2010. In the second and third quarters of 2010, to utilize its excess liquidity, ASB purchased securities, primarily federal agency obligations that had generally shorter durations.retail repurchase agreements.
During the third-first quarter of 2010,2011, ASB recorded a provision for loan losses of $6.0 million due in part to the reclassification of certain commercial loans that are current as to principal and interest payments, but have identified weaknesses, and net charge-offs in 1-4 family residential loans, residential land loans and home equity
lines of credit. During the third quarter of 2009, ASB recorded a provision for loan losses of $5.2 million due in part to higher nonperforming residential land loans and higher delinquencies in residential and consumer loans. During the first nine months of 2010, ASB recorded a provision for loan losses of $12.3$4.6 million primarily due to the net charge-offs during the quarter for 1-4 family, and residential land, loans. During the first nine months of 2009, ASB recorded a provision for loan losses of $27 million due to the classification and partial charge-off of a commercial credit, higher nonperforming residential land loans and higher residential and consumer loan delinquencies.loans. Continued financial stress on ASB’s customers may result in higher levels of delinquencies and losses.
|
| Nine months ended |
| Year ended |
| |||||
(in thousands) |
| 2010 |
| 2009 |
| 2009 |
| |||
Allowance for loan losses, January 1 |
| $ | 41,679 |
| $ | 35,798 |
| $ | 35,798 |
|
Provision for loan losses |
| 12,310 |
| 27,000 |
| 32,000 |
| |||
Less: net charge-offs |
| 15,674 |
| 16,900 |
| 26,119 |
| |||
Allowance for loan losses, end of period |
| $ | 38,315 |
| $ | 45,898 |
| $ | 41,679 |
|
Ratio of allowance for loan losses, end of period, to end of period loans outstanding |
| 1.09 | % | 1.21 | % | 1.12 | % | |||
Ratio of net charge-offs during the period to average loans outstanding (annualized) |
| 0.58 | % | 0.56 | % | 0.66 | % | |||
Nonaccrual loans |
| $ | 55,561 |
| $ | 62,095 |
| $ | 65,323 |
|
Third During the first quarter of 2010, noninterest income increased by $6.4ASB recorded a provision for loan losses of $5.4 million or 54%, when compared to the third quarter of 2009, primarily due to a $9.9 million other-than-temporary impairment charge on its mortgage-related securities portfolio innet charge-offs during the third quarter of 2009. Fee income on deposit liabilities for the third quarter of 2010 was $2.1 million lower than the same period in 2009 as new overdraft fee rules, which became effective in the third quarter of 2010, decreased overdraft fees by approximately $1.8 million.1-4 family and residential land and consumer loans.
First nine months of 2010 noninterest income increased by $13.7 million, or 33%, when compared to the first nine months of 2009, primarily due to other-than-temporary impairment charges on its mortgage-related securities portfolio in 2009, partially offset by a lower gain on sale of loans in 2010. The gain on sale of loans for 2009 included the sale of a commercial loan.
|
| Three months ended |
| Nine months ended |
| ||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Fee income on deposit liabilities |
| $ | 6,109 |
| $ | 8,211 |
| $ | 21,520 |
| $ | 22,384 |
|
Fees from other financial services |
| 6,781 |
| 6,385 |
| 19,844 |
| 18,747 |
| ||||
Fee income on other financial products |
| 1,697 |
| 1,613 |
| 4,957 |
| 4,285 |
| ||||
Net gains (losses) on available-for-sale securities |
| — |
| (9,863 | ) | — |
| (15,400 | ) | ||||
Other income |
|
|
|
|
|
|
|
|
| ||||
Gain on sale of loans |
| 2,490 |
| 4,302 |
| 4,610 |
| 7,834 |
| ||||
Bank-owned life insurance |
| 1,019 |
| 1,022 |
| 3,013 |
| 3,000 |
| ||||
Other |
| 260 |
| 254 |
| 922 |
| 331 |
| ||||
Total noninterest income |
| $ | 18,356 |
| $ | 11,924 |
| $ | 54,866 |
| $ | 41,181 |
|
Noninterest expense for the third quarter of 2010 decreased by $3.3 million, or 8%, when compared to the third quarter of 2009. Lower data processing, occupancy and services expenses were the result of ASB’s process improvement project, which reduced the ASB’s cost structure through improved processes and procedures, and improved the efficiency of ASB.
Noninterest expense for the first nine months of 2010 decreased by $11.9 million, or 9%, when compared to the first nine months of 2009. Lower compensation, occupancy, equipment and services expenses were the result of ASB’s process improvement project. The increase in data processing expense was primarily due to costs incurred to convert ASB’s systems to Fiserv Inc.’s bank platform system. The FDIC insurance premium in the first nine months of 2009 included a special assessment of $2.3 million.
|
| Three months ended |
| Year ended |
| |||||
(in thousands) |
| 2011 |
| 2010 |
| 2010 |
| |||
Allowance for loan losses, January 1 |
| $ | 40,646 |
| $ | 41,679 |
| $ | 41,679 |
|
Provision for loan losses |
| 4,550 |
| 5,359 |
| 20,894 |
| |||
Less: net charge-offs |
| 4,382 |
| 5,738 |
| 21,927 |
| |||
Allowance for loan losses, end of period |
| $ | 40,814 |
| $ | 41,300 |
| $ | 40,646 |
|
Ratio of allowance for loan losses, end of period, to end of period loans outstanding |
| 1.14 | % | 1.13 | % | 1.15 | % | |||
Ratio of net charge-offs during the period to average loans outstanding (annualized) |
| 0.49 | % | 0.62 | % | 0.61 | % | |||
Nonaccrual loans |
| $ | 61,029 |
| $ | 68,469 |
| 58,855 |
|
|
| Three months ended |
| Nine months ended |
| ||||||||
(in thousands) |
| 2010 |
| 2009 |
| 2010 |
| 2009 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Compensation and benefits |
| $ | 18,168 |
| $ | 17,721 |
| $ | 54,477 |
| $ | 55,072 |
|
Occupancy |
| 4,176 |
| 4,905 |
| 12,617 |
| 15,956 |
| ||||
Data processing |
| 2,019 |
| 3,684 |
| 10,921 |
| 10,352 |
| ||||
Services |
| 1,544 |
| 2,437 |
| 5,117 |
| 9,656 |
| ||||
Equipment |
| 1,600 |
| 1,782 |
| 4,949 |
| 7,112 |
| ||||
Other |
|
|
|
|
|
|
|
|
| ||||
FDIC insurance premium |
| 1,500 |
| 1,639 |
| 4,758 |
| 7,140 |
| ||||
Marketing |
| 385 |
| 548 |
| 1,709 |
| 1,763 |
| ||||
Office supplies, printing and postage |
| 990 |
| 937 |
| 2,984 |
| 2,828 |
| ||||
Communication |
| 599 |
| 597 |
| 1,608 |
| 1,881 |
| ||||
Other |
| 5,324 |
| 5,341 |
| 14,760 |
| 14,016 |
| ||||
Total noninterest expense |
| $ | 36,305 |
| $ | 39,591 |
| $ | 113,900 |
| $ | 125,776 |
|
First quarter of 2011 noninterest income decreased by $2.4 million, or 13%, when compared to the first quarter of 2010, primarily due to lower deposit liability fees as a result of new overdraft fee regulations, which took effect in mid-2010.
Three months ended March 31 |
| 2011 |
| 2010 |
| ||
(in thousands) |
|
|
|
|
| ||
Fees from other financial services |
| $ | 6,946 |
| $ | 6,414 |
|
Fee income on deposit liabilities |
| 4,449 |
| 7,520 |
| ||
Fee income on other financial products |
| 1,673 |
| 1,525 |
| ||
Other income |
|
|
|
|
| ||
Gain on sale of loans |
| 658 |
| 1,042 |
| ||
Bank-owned life insurance |
| 970 |
| 1,006 |
| ||
Other |
| 751 |
| 345 |
| ||
Total noninterest income |
| $ | 15,447 |
| $ | 17,852 |
|
Noninterest expense for the first quarter of 2011 decreased by $2.9 million, or 8%, when compared to the first quarter of 2010, primarily due to lower data processing expense as a result of ASB’s conversion to Fiserv Inc.’s bank platform system in May 2010.
Three months ended March 31 |
| 2011 |
| 2010 |
| ||
(in thousands) |
|
|
|
|
| ||
Compensation and benefits |
| $ | 17,505 |
| $ | 17,402 |
|
Occupancy |
| 4,240 |
| 4,225 |
| ||
Data processing |
| 1,970 |
| 4,338 |
| ||
Services |
| 1,771 |
| 1,728 |
| ||
Equipment |
| 1,657 |
| 1,709 |
| ||
Other |
|
|
|
|
| ||
FDIC insurance premium |
| 1,427 |
| 1,659 |
| ||
Marketing |
| 641 |
| 954 |
| ||
Office supplies, printing and postage |
| 918 |
| 867 |
| ||
Communication |
| 387 |
| 497 |
| ||
Other |
| 4,560 |
| 4,591 |
| ||
Total noninterest expense |
| $ | 35,076 |
| $ | 37,970 |
|
Legislation and regulation.ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (OTS), whose regulatory functions are to be transferred to the Office of the Comptroller of the Currency (OCC) as described below, and the FDIC.Federal Deposit Insurance Corporation (FDIC). Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholders.shareholder. See the discussion below under “Liquidity and capital resources.” Also see “Federal Deposit Insurance Corporation restoration plan” and “Deposit insurance coverage” in Note 4 of HEI’s “Notes to Consolidated Financial Statements.”
In January 2010, the FDIC released for comment a proposal to modify its risk-based deposit insurance system to account for risks posed by the compensation systems of insured banks and their holding companies. Management cannot predict at this time whether the proposed rule will be adopted as proposed or in some modified form or, if adopted, what impact it may have on ASB’s FDIC insurance rate.
Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Regulation of the financial services industry, including regulation of HEI and ASB, will undergo substantial changes as a result of the enactment of the Dodd-Frank Act.Act, which became law in July 2010. The Dodd-Frank Act increases regulation and oversight of the financial services industry and imposes restrictions on the ability of firms within the industry to conduct business consistent with historical practices. Most importantlyImportantly for HEI and ASB, the Dodd-Frank Act will abolish their historical federal financial institution regulator, the OTS, effective one year from the enactment date (subject to extension by not more than an additional six months). Supervision and regulation overof HEI, as a thrift holding company, will move to the Federal Reserve, and supervision and regulation overof ASB, as a federally chartered savings bank, will move to the OCC. While the laws and regulations applicable to HEI and ASB will not generally change—the Home Owners Loan Act and regulations issued thereunder will still apply—the applicable laws and regulations will be interpreted, and new and amended regulations will be adopted, by the Federal Reserve and the OCC, respectively.OCC. HEI will for the first time be subject to minimum consolidated capital requirements, and ASB may be required to be supervised through ASHI, its intermediate holding company. The Dodd-Frank Act requires regulators, at a minimum, to apply to bank and thrift holding companies leverage and risk-based capital standards that are at least as strict as those in effect at the insured depository institution level on the date the Act became effective, although there will be a phase-in period for meeting these standards. In addition, HEI will continue to be required to serve as
a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.
More stringent affiliate transaction rules will apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards are raised with respect to the ability of ASB to merge with or acquire another institution. While the Dodd-Frank Act requires the minimum reserve ratio for the Deposit Insurance Fund to be increased from 1.15% to 1.35% by 2020, this change may not impact ASB because in establishing assessments the FDIC is required to offset the effect of this increase for depository institutions with total consolidated assets of less than $10 billion. Based on the proposed changes to the assessment base and rates, ASB anticipates a reduction in its annual FDIC assessment by approximately $2 million. ASB may be affected by the provision of the Dodd-Frank Act that repeals, effective in July
2011 (unless extended), the prohibition on payments of interest by banks or savings associations on demand deposit accounts for businesses.
The Dodd-Frank Act establishes a Consumer Financial Protection Bureau (Bureau) to be housed in the Federal Reserve to take sole responsibility (subject to limited oversight by the new Financial Stability Oversight Council) for rulemaking under the principal federal consumer financial protection laws, such as the Truth in Lending Act, Real Estate Settlement Procedures Act, Equal Credit Opportunity Act, Truth in Savings Act, Fair Debt Collection Practices Act and several other consumer protection laws, but enforcement of these laws and rules will be by the OCC in the case of ASB because it has less than $10 billion in assets. The Bureau will have broad power in that it will have authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures, including the use of new model forms it may adopt. ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act that acknowledges that a federal savings bank may be subject to state regulation and only allows federal law to preempt state law on a “case by case” basis in the consumer financial protection area when (1) the state law would have a discriminatory effect on the bank compared to that on a bank chartered in that state; (2) the state law prevents or significantly interferes with a bank’s exercise of its power; or (3) the state law is preempted by another federal law.
The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms. Regulations are required to be adopted under these provisions of the Dodd-Frank Act within 18 months after the date that is to be specified by the Secretary of the Treasury for the transfer of consumer protection power to the Bureau. ASB cannot predict at this time what effect these new rules may ultimately have on its mortgage origination practices, its ability to originate mortgage loans or the costs it will incur in complying with these requirements.
The Dodd-Frank Act will affect financial regulation more generally as well, although many of these regulatory changes may not impact ASB or the Company directly, either because they are limited in application to larger entities or because they relate to activities in which ASB is not substantially engaged. For example, the Dodd-Frank Act establishes a Financial Stability Oversight Council that would, among other things, designate certain nonbank financial companies that it considers to be of systemic risk to be supervised by the Federal Reserve, as well as monitor the financial markets for trends affecting systemic risk and coordinate the regulatory activities of the federal bank regulators. It also would establish a mechanism for the FDIC to resolve systemically important companies that may fail. The ability of companies to engage in derivatives transactions and hedge for their own account likely will be impacted by provisions in the Dodd-Frank Act that require such transactions to be moved to exchanges and for capital and margin to be held against them, as well as by the so-called “Volcker rule,” which will limit the ability of financial institutions to invest for their own account once the rule becomes effective (but with exceptions important to ASB, such as for purchases of U.S. government or agency obligations).
HEI will also be affected by provisions ofThe “Durbin Amendment” to the Dodd-Frank Act relatingrequires the Federal Reserve to corporate governanceissue rules to ensure that debit card interchange fees are “reasonable and executive compensation, including provisions requiring shareholder “sayproportional” to the processing costs incurred. The Federal Reserve has proposed a cap on pay” votes, mandating additional disclosures concerning executive compensation and compensation consultants and advisors, further restricting proxy voting by brokersdebit card interchange fees that card issuers can receive to 12 cents per transaction. ASB currently earns an average of 52 cents per transaction. As specified in the absence of instructions and permittingDodd-Frank Act, these regulations will exempt banks with less than $10 billion in assets. However, market pressures could very well push the SECimpact down to adopt rules in its discretion requiring public companies under specified conditions to include shareholder nominees in management’s proxy solicitation materials.all banks.
Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until a year or more after its enactment, when implementing regulations are issued and effective. Thus, management cannot predict the ultimate
impact of the Dodd-Frank Act, as amended, on the Company or ASB at this time. Nor can management predict the impact or substance of other future federal or state legislation or regulation, or the application thereof.
Credit CARD Act. On May 22, 2009, President Obama signed the Credit Card Accountability Responsibility and Disclosure Act of 2009 into law. Among other things, it requires that consumers receive a reasonable amount of time to make their credit card payments, prohibits payment allocation methods that unfairly maximize interest charges, prohibits issuers from raising the interest rate on an existing credit card balance in certain circumstances, and prohibits issuers from charging over-limit fees unless the cardholder agreed to allow the issuer to complete over-limit transactions and restricts the manner in which the issuer may assess over-limit fees. The major provisions of the Act were effective February 22, 2010.
New overdraft rules.On November 12, 2009, the Board of Governors of the Federal Reserve System announced that it amended Regulation E (which implements the Electronic Fund Transfer Act) to limit the ability of a financial institution to assess an overdraft fee for paying automated teller machine or one-time debit card transactions that overdraw a consumer’s account, unless the consumer affirmatively consents, or opts in, to the
institution’s payment of overdrafts for those transactions. These new rules applyapplied on July 1, 2010 for new accounts and August 15, 2010 for existing accounts. In 2009, these types of overdraft fees totaled approximately $15 million pretax.pretax for ASB. The amendment had a negative impact on ASB’s noninterest income of approximately $1.8$2.8 million pretax for the thirdfirst quarter of 2011 compared to the first quarter of 2010.
FHLB of Seattle stock. As of September 30, 2010,March 31, 2011, ASB’s investment in stock of the FHLB of Seattle of $97.8$98 million was carried at cost because it can only be redeemed at par. There is a minimum required investment based on measurements of ASB’s capital, assets and/or borrowing levels. The FHLB of Seattle reported net income of $8.2$20.5 million for the second quarter of 2010 compared to a net loss of $34.3$161.6 million for the same period in 2009. The FHLB of Seattle reported retained earnings of $67.2$73.4 million as of December 31, 2010 and was in compliance with all of its regulatory capital requirements. However,In October 2010, the FHLB of Seattle remains classified as “undercapitalized” by its regulator,entered into a Stipulation and Consent to the Issuance of a Consent Order with the Federal Housing Finance Agency, which requires the FHLB of Seattle to take certain actions related to its business and operations. The Consents provide that, following a stabilization period and once the FHLB of Seattle reaches and maintains certain thresholds, it may not redeem or repurchase capital stock or pay dividends on its stock.and begin paying dividends. ASB does not believe that the Federal Housing Finance Agency’s classification of the FHLB of SeattleConsents will affect the FHLB of Seattle’s ability to meet ASB’s liquidity and funding needs. ASB did not receivereceived no cash dividends on its $97.8$98 million of FHLB of Seattle stock in 2009 or the first nine monthsquarters of 2010.2011 or 2010
Periodically and as conditions warrant, ASB reviews its investment in the stock of FHLB of Seattle for impairment.
Commitments and contingenciescontingencies.. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”
Recent accounting pronouncements and interpretationsinterpretations.. See Note 12 of HEI’s “Notes to Consolidated Financial Statements.”
FINANCIAL CONDITION
Liquidity and capital resources.
(in millions) |
| September 30, |
| December 31, |
| % change |
|
| March 31, |
| December 31, |
| % change |
| ||||
Total assets |
| $ | 4,804 |
| $ | 4,941 |
| (3 | ) |
| $ | 4,858 |
| $ | 4,797 |
| 1 |
|
Available-for-sale investment and mortgage-related securities |
| 570 |
| 433 |
| 32 |
|
| 671 |
| 678 |
| (1 | ) | ||||
Loans receivable, net |
| 3,467 |
| 3,670 |
| (6 | ) |
| 3,554 |
| 3,498 |
| 2 |
| ||||
Deposit liabilities |
| 3,959 |
| 4,059 |
| (2 | ) |
| 4,035 |
| 3,975 |
| 2 |
| ||||
Other bank borrowings |
| 247 |
| 298 |
| (17 | ) |
| 245 |
| 237 |
| 3 |
|
As of September 30, 2010,March 31, 2011, ASB was one of Hawaii’s largest financial institutions based on assets of $4.8$4.9 billion and deposits of $4.0 billion.
In July 2010, Moody’s affirmed ASB’s counterparty credit rating of A3 and changed ASB’s outlook to “stable” from “negative” based on ASB’s better than expected asset quality and earnings performance in the last several periods. In April 2007, S&P raised ASB’s long-term/short-term counterparty credit ratings to BBB/A-2 from BBB-/A-3 and in July 2010 maintained the rating following its annual review of ASB.
As of September 30, 2010,March 31, 2011, ASB’s unused FHLB borrowing capacity was approximately $1.4$1.3 billion. As of September 30, 2010,March 31, 2011, ASB had commitments to borrowers for undisbursed loan funds, loan commitments and unused lines and letters of credit of $1.2 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.
As of September 30, 2010March 31, 2011 and December 31, 2009,2010, ASB had $4.5$61.0 million and $4.0$58.9 million of loans on nonaccrual status, respectively, or 1.7% of net loans outstanding. As of March 31, 2011 and December 31, 2010, ASB had $5.8 million and $4.3 million, respectively, of real estate acquired in settlement of loans.
For the first nine monthsquarter of 2010,2011, net cash provided by ASB’s operating activities was $89$29 million. Net cash providedused during the same period by ASB’s investing activities was $34$65 million, primarily due to purchases of investment and mortgage-related securities of $109 million and a net decrease in loans receivable of $70 million, offset by repayments of investment and mortgage-related securities of $351 million, a net decrease in loans receivable of $171 million and proceeds from the sale of real estate acquired in settlement of loans of $3 million, offset by purchases of investment and mortgage-related securities of $485 million and additions to premises and equipment of $6$115 million. Net cash usedprovided in financing activities during this period was $199$50 million, primarily due to net decreasesincreases in deposit
liabilities and retail repurchase agreements of $100$60 million and $51$7 million, respectively, offset by a decrease in mortgage escrow deposits of $5$4 million and the payment of $43$14 million in common stock dividends.
FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of September 30, 2010,March 31, 2011, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.3%9.1% (5.0%), a Tier-1 risk-based capital ratio of 13.1%12.5% (6.0%) and a total risk-based capital ratio of 14.2%13.5% (10.0%). OTS approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI.HEI (through ASHI).
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 6390 to 65,92, HEI’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated intoin Part II, Item 7A of HEI’s 20092010 Form 10-K by reference to HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 19, 2010 and page 3, HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 20092010 Form 10-K by reference to Exhibit 99 to HECO’s Current Report on Form 8-K dated February 19, 2010.99.2.
ASB’s interest-rate risk sensitivity measures as of September 30, 2010March 31, 2011 and December 31, 20092010 constitute “forward-looking statements” and were as follows:
|
| September 30, 2010 |
| December 31, 2009 |
|
| March 31, 2011 |
| December 31, 2010 |
| ||||||||||||||||
|
| Change in |
| NPV |
| NPV ratio |
| Change in |
| NPV |
| NPV ratio |
| |||||||||||||
Change in interest |
| Gradual | �� | Instantaneous change |
| Gradual |
| Instantaneous change |
| |||||||||||||||||
Change in interest rates |
| Change |
| NPV |
| NPV ratio |
| Change |
| NPV |
| NPV ratio |
| |||||||||||||
(basis points) |
| Gradual change |
| Instantaneous change |
| Gradual change |
| Instantaneous change |
| |||||||||||||||||
+300 |
| 0.6 | % | 11.65 |
| (144 | ) | (0.3 | )% | 10.92 | % | (245 | ) |
| (1.7 | )% | 11.76 | % | (217 | ) | (1.3 | )% | 12.04 | % | (196 | ) |
+200 |
| 0.1 |
| 12.40 |
| (69 | ) | (0.3 | ) | 11.86 |
| (151 | ) |
| (1.5 | ) | 12.59 |
| (134 | ) | (1.3 | ) | 12.84 |
| (116 | ) |
+100 |
| — |
| 12.93 |
| (16 | ) | (0.2 | ) | 12.72 |
| (65 | ) |
| (0.9 | ) | 13.33 |
| (60 | ) | (0.8 | ) | 13.52 |
| (48 | ) |
Base |
| — |
| 13.09 |
| — |
| — |
| 13.37 |
| — |
|
| — |
| 13.93 |
| — |
| — |
| 14.00 |
| — |
|
-100 |
| (0.7 | ) | 12.85 |
| (24 | ) | (0.9 | ) | 13.53 |
| 16 |
|
| (0.4 | ) | 14.12 |
| 19 |
| (0.6 | ) | 14.04 |
| 4 |
|
-200 |
|
| ** |
| ** |
| ** |
| ** |
| ** |
| ** | |||||||||||||
-300 |
|
| ** |
| ** |
| ** |
| ** |
| ** |
| ** |
* Change from base case in basis points (bp).
**For September 30, 2010 and December 31, 2009, the -200 and -300 bp scenarios were not performed because they would have resulted in negative Treasury interest rates.
ASB’s net interest income (NII) sensitivity as of September 30, 2010March 31, 2011 was slightly assetmore sensitive for rising rates compared to December 31, 2009 due to faster prepayment expectations2010 as higher rates and changes in balance sheet mix.
asset mix reduced maturing or repricing cash flows within the one-year horizon. ASB’s base net present value (NPV) ratio as of September 30, 2010March 31, 2011 decreased slightly compared to December 31, 2009 primarily due to the decline in the level of interest rates and changes in balance sheet mix.
2010. ASB’s NPV ratio sensitivity measure as of September 30, 2010 decreasedMarch 31, 2011 increased compared to December 31, 20092010 in the rising interest rate scenarios primarily due to the flatteningincrease in duration of the yield curve and shift in assets to shorter durationmortgage-related loans and investments.
The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results (see pages 63-65 of HEI Exhibit 13 to HEI’s Current Report on Form 8-K dated February 19, 2010 for a more detailed description of key modeling assumptions used in the NII sensitivity analysis).results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies
for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the
twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.
Item 4. Controls and Procedures
HEI:
Changes in Internal Control over Financial Reporting
During the thirdfirst quarter of 2010,2011, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2010March 31, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of September 30, 2010.March 31, 2011. Based on their evaluations, as of September 30, 2010,March 31, 2011, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:
(1) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and
(2) is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
HECO:
Changes in Internal Control over Financial Reporting
During the thirdfirst quarter of 2010,2011, there was no change in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of September 30, 2010March 31, 2011 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Richard M. Rosenblum, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of September 30, 2010.March 31, 2011. Based on their evaluations, as of September 30, 2010,March 31, 2011, 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.
The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 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.
For information about Risk Factors, see pages 3028 to 3937 of HEI’s 20092010 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on pages v and vi of HEI’s 20092010 Form 10-K, as updated on pages iv and v herein.
A. Ratio of earnings to fixed charges.
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| Nine months ended |
| Years ended December 31 |
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| Three months ended |
| Years ended December 31 |
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| 2010 |
| 2009 |
| 2009 |
| 2008 |
| 2007 |
| 2006 |
| 2005 |
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| 2011 |
| 2010 |
| 2010 |
| 2009 |
| 2008 |
| 2007 |
| 2006 |
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HEI and Subsidiaries |
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Excluding interest on ASB deposits |
| 2.93 |
| 2.49 |
| 2.29 |
| 2.06 |
| 1.78 |
| 2.08 |
| 2.31 |
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| 2.89 |
| 2.76 |
| 2.89 |
| 2.29 |
| 2.06 |
| 1.78 |
| 2.08 |
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Including interest on ASB deposits |
| 2.66 |
| 2.05 |
| 1.95 |
| 1.71 |
| 1.52 |
| 1.73 |
| 1.98 |
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| 2.70 |
| 2.48 |
| 2.64 |
| 1.95 |
| 1.71 |
| 1.52 |
| 1.73 |
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HECO and Subsidiaries |
| 2.86 |
| 2.92 |
| 2.99 |
| 3.48 |
| 2.43 |
| 3.14 |
| 3.23 |
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| 2.85 |
| 2.72 |
| 2.88 |
| 2.99 |
| 3.48 |
| 2.43 |
| 3.14 |
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See HEI Exhibit 12.1 and HECO Exhibit 12.2.
HEI Exhibit |
| Hawaiian Electric Industries |
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HEI Exhibit 4.2 | Letter Amendment effective April 29, 2011, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee | |
HEI Exhibit 12.1 | Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, three months ended March 31, 2011 and 2010 and years ended December 31, 2010, 2009, 2008, 2007 and 2006 | |
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) |
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HEI Exhibit 31.2 |
| Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer) |
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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 |
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HEI Exhibit 32.2 |
| Written Statement of James A. Ajello (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002 |
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HEI Exhibit 101.INS |
| XBRL Instance Document |
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HEI Exhibit 101.SCH |
| XBRL Taxonomy Extension Schema Document |
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HEI Exhibit 101.CAL |
| XBRL Taxonomy Extension Calculation Linkbase Document |
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HEI Exhibit 101.DEF |
| XBRL Taxonomy Extension Definition Linkbase Document |
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HEI Exhibit 101.LAB |
| XBRL Taxonomy Extension Label Linkbase Document |
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HEI Exhibit 101.PRE |
| XBRL Taxonomy Extension Presentation Linkbase Document |
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HECO Exhibit 12.2 |
| Hawaiian Electric Company, Inc. and Subsidiaries |
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HECO Exhibit 31.3 |
| Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer) |
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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) |
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HECO Exhibit 32.3 |
| Written Statement of Richard M. Rosenblum (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 |
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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) | ||||
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By | /s/ Constance H. Lau |
| By | /s/ Richard M. Rosenblum | ||
| Constance H. Lau |
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| Richard M. Rosenblum | ||
| President and Chief Executive Officer |
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| President and Chief Executive Officer | ||
| (Principal Executive Officer of HEI) |
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| (Principal Executive Officer of HECO) | ||
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By | /s/ James A. Ajello |
| By | /s/ Tayne S. Y. Sekimura | ||
| James A. Ajello |
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| Tayne S. Y. Sekimura | ||
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| Senior Vice President | ||
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| and Chief Financial Officer | ||
| (Principal Financial Officer of HEI) |
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| (Principal Financial Officer of HECO) | ||
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By | /s/ David M. Kostecki |
| By | /s/ Patsy H. Nanbu | ||
| David M. Kostecki |
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| Patsy H. Nanbu | ||
| Vice President-Finance, Controller |
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| Controller | ||
| and Chief Accounting Officer |
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| (Principal Accounting Officer of HECO) | ||
| (Principal Accounting Officer of HEI) |
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Date: |
| Date: |