EX-99.2 21 a12-1072_1ex99d2.htm HECO EX-99.2

HECO Exhibit 99.2

This report is filed as an exhibit to the Annual Report on Form 10-K filed by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) on February 17, 2012 (Form 10-K) and contains information concerning HECO and its subsidiaries that is incorporated by reference into the Form 10-K. This report should be read in conjunction with the information in the Form 10-K and, by virtue of its incorporation by reference into the Form 10-K, is an integral part of the Form 10-K.

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Company, Inc. (HECO) and its subsidiaries (collectively, the Company) 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 the Company, the performance of the industry in which it does business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

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

· international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, decisions concerning the extent of the presence of the federal government and military in Hawaii, the implications and potential impacts of U.S. and foreign capital and credit market conditions and federal and state responses to those conditions, and the potential impacts of global developments (including unrest, conflict and the overthrow of governmental regimes in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea or Iran);

· weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming, such 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);

· 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 the cost of such financings, if available;

· the risks inherent in changes in the value of pension and other retirement plan assets;

· 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 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 Company of its commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering (and potential disapproval of actual or proposed) HCEI-related costs; reliance by the Company on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cables, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

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

· 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 Company of its energy cost adjustment clauses (ECACs);

· the impact of fuel price volatility on customer satisfaction and political and regulatory support for the Company;

· 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 Company to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

· new technological developments that could affect the operations and prospects of the Company or their competitors;

· cyber security risks and the potential for cyber incidents, including potential incidents at the Company (including at the power plants) and incidents at data processing centers it uses, to the extent not prevented by intrusion detection and prevention systems, anti-virus software, firewalls and other general information technology controls;

· federal, state, county and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to the Company (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, and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);

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

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· 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, such as with respect to environmental conditions or renewable portfolio standards (RPS));

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

· the risks associated with the geographic concentration of the Company’s business;

· changes in accounting principles applicable to the Company, including the possible adoption of International Financial Reporting Standards or new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of v ariable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;

· changes by securities rating agencies in their ratings of the securities of the Company and the results of financing efforts;

· the final outcome of tax positions taken by the Company;

· the risks of suffering losses and incurring liabilities that are uninsured (e.g., damages to the Company’s transmission and distribution system and losses from business interruption) or underinsured (e.g., losses not covered as a result of insurance deductibles or other exclusions or exceeding policy limits); and

· other risks or uncertainties described elsewhere in this report (e.g., Item 1A. Risk Factors) and in other reports previously and subsequently filed by the Company 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, the Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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

This section supplements, and must be read in conjunction with, the “electric utility” sections and all information related to or including HECO and its subsidiaries in HEI’s Management’s Discussion and Analysis of Financial Condition and Results of Operations (except for HEI’s Selected contractual obligations and commitments table) (HEI’s MD&A) included in the Form 10-K and in conjunction with HECO’s consolidated financial statements and accompanying notes (HECO’s Notes to Consolidated Financial Statements) set forth below.

Selected contractual obligations and commitments. The following table presents aggregated information about total payments due from HECO and its subsidiaries during the indicated periods under the specified contractual obligations and commitments:

December 31, 2011 |  | Payments due by period |
(in millions) |  | Less than 1 year |  | 1-3 years |  | 3-5 years |  | More than 5 years |  | Total |
Long-term debt |  | $ 58 |  | $ 11 |  | $ – |  | $ 991 |  | $1,060 |
Interest on long-term debt |  | 55 |  | 109 |  | 108 |  | 679 |  | 951 |
Operating leases |  | 6 |  | 11 |  | 8 |  | 10 |  | 35 |
Open purchase order obligations ¹ |  | 97 |  | 26 |  | 18 |  | – |  | 141 |
Fuel oil purchase obligations (estimate based on December 31, 2011 fuel oil prices) |  | 1,033 |  | 773 |  | – |  | – |  | 1,806 |
Purchase power obligations–minimum fixed capacity charges |  | 121 |  | 238 |  | 208 |  | 596 |  | 1,163 |
Liabilities for uncertain tax positions |  | 4 |  | – |  | – |  | – |  | 4 |
Total (estimated) |  | $1,374 |  | $1,168 |  | $342 |  | $2,276 |  | $5,160 |

¹ Includes contractual obligations and commitments for capital expenditures and expense amounts.

The table above does not include other categories of obligations and commitments, such as deferred taxes, trade payables, amounts that will become payable in future periods under collective bargaining and other employment agreements and employee benefit plans and potential refunds of amounts collected under interim decision and orders (D&Os) of the PUC. As of December 31, 2011, the fair value of the assets held in trusts to satisfy the obligations of the Company’s retirement benefit plans did not exceed the retirement benefit plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the table above; however, HECO incorporates by reference the section “Retirement benefits” in HEI’s MD&A and Note 10 (“Retirement benefits”) of HECO’s “Notes to Consolidated Financial Statements” (included below in this report) for a discussion of retirement benefit plan obligations, including estimated minimum required contributions for 2012 and 2013.

See Note 11 of HECO’s Notes to Consolidated Financial Statements for a discussion of fuel and power purchase commitments.

Management believes that HECO’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retirement benefits and other cash requirements in the foreseeable future.

Quantitative and Qualitative Disclosures about Market Risk

HECO and its subsidiaries manage various market risks in the ordinary course of business, including credit risk and liquidity risk. HECO and its subsidiaries believe their exposures to these two risks are not material as of December 31, 2011.

HECO and its subsidiaries are exposed to some commodity price risk primarily related to their fuel supply and IPP contracts. HECO and its subsidiaries’ commodity price risk is substantially mitigated so long as they have their current ECACs in their rate schedules. HECO and its subsidiaries currently have no hedges against their

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commodity price risk. Because HECO and its subsidiaries do not have a portfolio of trading assets, they currently have no exposure to market risk from trading activities nor foreign currency exchange rate risk.

HECO and its subsidiaries consider interest rate risk to be a significant market risk as it may affect the discount rate used to determine retirement benefit liabilities, the market value of retirement benefit plans’ assets and the allowed rates of return. Interest rate risk can be defined as the exposure of the Company’s earnings to adverse movements in interest rates.

See the section “Other than bank interest rate risk” in HEI’s “Quantitative and Qualitative Disclosures about Market Risk,” included in the Form 10-K and the discussion in Note 10 of HECO’s Notes to Consolidated Financial Statements.

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31 |  | 2011 |  | 2010 |  | 2009 |  | 2008 |  | 2007 |
(in thousands) |  |  |  |  |  |  |  |  |  |  |
Results of operations |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $2,973,764 |  | $2,367,441 |  | $2,026,672 |  | $2,853,639 |  | $2,096,958 |
Operating expenses |  | 2,818,529 |  | 2,247,600 |  | 1,912,264 |  | 2,723,702 |  | 1,996,683 |
Operating income |  | 155,235 |  | 119,841 |  | 114,408 |  | 129,937 |  | 100,275 |
Other income |  | 4,279 |  | 17,695 |  | 19,709 |  | 15,049 |  | 4,592 |
Interest and other charges |  | 57,533 |  | 58,952 |  | 52,676 |  | 51,016 |  | 50,716 |
Net income |  | 101,981 |  | 78,584 |  | 81,441 |  | 93,970 |  | 54,151 |
Preferred stock dividends of subsidiaries |  | 915 |  | 915 |  | 915 |  | 915 |  | 915 |
Net income attributable to HECO |  | 101,066 |  | 77,669 |  | 80,526 |  | 93,055 |  | 53,236 |
Preferred stock dividends of HECO |  | 1,080 |  | 1,080 |  | 1,080 |  | 1,080 |  | 1,080 |
Net income for common stock |  | $ 99,986 |  | $ 76,589 |  | $ 79,446 |  | $ 91,975 |  | $ 52,156 |
At December 31 |  | 2011 |  | 2010 |  | 2009 |  | 2008 |  | 2007 |
(in thousands) |  |  |  |  |  |  |  |  |  |  |
Financial position |  |  |  |  |  |  |  |  |  |  |
Utility plant |  | $5,242,379 |  | $5,049,900 |  | $4,881,767 |  | $4,586,668 |  | $4,320,607 |
Accumulated depreciation |  | (1,966,894 | ) | (1,941,059 | ) | (1,848,416 | ) | (1,741,453 | ) | (1,647,113 | )
Net utility plant |  | $3,275,485 |  | $3,108,841 |  | $3,033,351 |  | $2,845,215 |  | $2,673,494 |
Total assets |  | $4,671,942 |  | $4,285,680 |  | $3,978,392 |  | $3,856,109 |  | $3,423,888 |
Capitalization:1 |  |  |  |  |  |  |  |  |  |  |
Short-term borrowings |  |  |  |  |  |  |  |  |  |  |
from non-affiliates and affiliate |  | $ – |  | $ – |  | $ – |  | $ 41,550 |  | $ 28,791 |
Current portion of long-term debt |  | 57,500 |  | – |  | – |  | – |  | – |
Long-term debt, net |  | 1,000,570 |  | 1,057,942 |  | 1,057,815 |  | 904,501 |  | 885,099 |
Common stock equity |  | 1,406,084 |  | 1,337,398 |  | 1,306,408 |  | 1,188,842 |  | 1,110,462 |
Cumulative preferred stock–not subject to mandatory redemption |  | 34,293 |  | 34,293 |  | 34,293 |  | 34,293 |  | 34,293 |
Total capitalization |  | $2,498,447 |  | $2,429,633 |  | $2,398,516 |  | $2,169,186 |  | $2,058,645 |
Capital structure ratios (%)1 |  |  |  |  |  |  |  |  |  |  |
Debt |  | 42.3 |  | 43.5 |  | 44.1 |  | 43.6 |  | 44.4 |
Cumulative preferred stock |  | 1.4 |  | 1.4 |  | 1.4 |  | 1.6 |  | 1.7 |
Common stock equity |  | 56.3 |  | 55.1 |  | 54.5 |  | 54.8 |  | 53.9 |

1 Includes current portion of long-term debt, and sinking fund and optional redemption amounts (if any) payable within one year for preferred stock.

HEI owns all of HECO’s common stock. Therefore, per share data is not meaningful.

See Forward-Looking Statements above, the “electric utility” sections and all information related to, or including, HECO and its subsidiaries incorporated by reference from HEI’s MD&A included in the Form 10-K dated February 17, 2012, and Note 11 (“Commitments and contingencies”) of HECO’s “Notes to Consolidated Financial Statements” for discussions of certain contingencies that could adversely affect future results of operations, financial condition and cash flows.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Hawaiian Electric Company, Inc.:

In our opinion, the accompanying consolidated balance sheets and statements of capitalization as of December 31, 2011 and 2010 and the related consolidated statements of income, changes in common stock equity and cash flows for each of the two years in the period ended December 31, 2011 present fairly, in all material respects, the financial position of Hawaiian Electric Company and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of January 1, 2010.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 17, 2012

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder
Hawaiian Electric Company, Inc.:

We have audited the consolidated statements of income, changes in common stock equity, and cash flows of Hawaiian Electric Company, Inc. and subsidiaries for the year ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Hawaiian Electric Company, Inc. and subsidiaries for the year ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Honolulu, Hawaii
February 19, 2010

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Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31 |  | 2011 |  | 2010 |  | 2009 |
(in thousands) |  |  |  |  |  |  |
Operating revenues |  | $2,973,764 |  | $2,367,441 |  | $2,026,672 |
Operating expenses |  |  |  |  |  |  |
Fuel oil |  | 1,265,126 |  | 900,408 |  | 671,970 |
Purchased power |  | 689,652 |  | 548,800 |  | 499,804 |
Other operation |  | 257,065 |  | 251,027 |  | 248,515 |
Maintenance |  | 121,219 |  | 127,487 |  | 107,531 |
Depreciation |  | 142,975 |  | 149,708 |  | 144,533 |
Taxes, other than income taxes |  | 276,504 |  | 222,117 |  | 191,699 |
Income taxes |  | 65,988 |  | 48,053 |  | 48,212 |
|  | 2,818,529 |  | 2,247,600 |  | 1,912,264 |
Operating income |  | 155,235 |  | 119,841 |  | 114,408 |
Other income (deductions) |  |  |  |  |  |  |
Allowance for equity funds used during construction |  | 5,964 |  | 6,016 |  | 12,222 |
Impairment of utility plant |  | (5,496 | ) | – |  | – |
Other, net |  | 3,811 |  | 11,679 |  | 7,487 |
|  | 4,279 |  | 17,695 |  | 19,709 |
Interest and other charges |  |  |  |  |  |  |
Interest on long-term debt |  | 57,532 |  | 57,532 |  | 51,820 |
Amortization of net bond premium and expense |  | 3,081 |  | 2,975 |  | 3,254 |
Other interest charges |  | (582 | ) | 1,003 |  | 2,870 |
Allowance for borrowed funds used during construction |  | (2,498 | ) | (2,558 | ) | (5,268 | )
|  | 57,533 |  | 58,952 |  | 52,676 |
Net income |  | 101,981 |  | 78,584 |  | 81,441 |
Preferred stock dividends of subsidiaries |  | 915 |  | 915 |  | 915 |
Net income attributable to HECO |  | 101,066 |  | 77,669 |  | 80,526 |
Preferred stock dividends of HECO |  | 1,080 |  | 1,080 |  | 1,080 |
Net income for common stock |  | $99,986 |  | $76,589 |  | $ 79,446 |

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

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Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31 |  | 2011 |  | 2010 |
(in thousands) |  |  |  |  |
Assets |  |  |  |  |
Utility plant, at cost |  |  |  |  |
Land |  | $ 51,514 |  | $ 51,364 |
Plant and equipment |  | 5,052,027 |  | 4,896,974 |
Less accumulated depreciation |  | (1,966,894 | ) | (1,941,059 | )
Construction in progress |  | 138,838 |  | 101,562 |
Net utility plant |  | 3,275,485 |  | 3,108,841 |
Current assets |  |  |  |  |
Cash and equivalents |  | 48,806 |  | 122,936 |
Customer accounts receivable, net |  | 183,328 |  | 138,171 |
Accrued unbilled revenues, net |  | 137,826 |  | 104,384 |
Other accounts receivable, net |  | 8,623 |  | 9,376 |
Fuel oil stock, at average cost |  | 171,548 |  | 152,705 |
Materials and supplies, at average cost |  | 43,188 |  | 36,717 |
Prepayments and other |  | 34,602 |  | 55,216 |
Regulatory assets |  | 20,283 |  | 7,349 |
Total current assets |  | 648,204 |  | 626,854 |
Other long-term assets |  |  |  |  |
Regulatory assets |  | 649,106 |  | 470,981 |
Unamortized debt expense |  | 12,786 |  | 14,030 |
Other |  | 86,361 |  | 64,974 |
Total other long-term assets |  | 748,253 |  | 549,985 |
|  | $4,671,942 |  | $4,285,680 |
Capitalization and liabilities |  |  |  |  |
Capitalization (see Consolidated Statements of Capitalization) |  |  |  |  |
Common stock equity |  | $1,406,084 |  | $1,337,398 |
Cumulative preferred stock – not subject to mandatory redemption |  | 34,293 |  | 34,293 |
Commitments and contingencies (see Note 11) |  |  |  |  |
Long-term debt, net |  | 1,000,570 |  | 1,057,942 |
Total capitalization |  | 2,440,947 |  | 2,429,633 |
Current liabilities |  |  |  |  |
Current portion of long-term debt |  | 57,500 |  | – |
Accounts payable |  | 188,580 |  | 178,959 |
Interest and preferred dividends payable |  | 19,483 |  | 20,603 |
Taxes accrued |  | 224,768 |  | 175,960 |
Other |  | 69,353 |  | 56,354 |
Total current liabilities |  | 559,684 |  | 431,876 |
Deferred credits and other liabilities |  |  |  |  |
Deferred income taxes |  | 337,863 |  | 269,286 |
Regulatory liabilities |  | 315,466 |  | 296,797 |
Unamortized tax credits |  | 60,614 |  | 58,810 |
Retirement benefits liability |  | 495,121 |  | 355,844 |
Other |  | 106,044 |  | 108,070 |
Total deferred credits and other liabilities |  | 1,315,108 |  | 1,088,807 |
Contributions in aid of construction |  | 356,203 |  | 335,364 |
|  | $4,671,942 |  | $4,285,680 |

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

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Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31 |  | 2011 |  | 2010 |  | 2009 |
(dollars in thousands, except par value) |  |  |  |  |  |  |
Common stock equity |  |  |  |  |  |  |
Common stock of $6 2/3 par value |  |  |  |  |  |  |
Authorized: 50,000,000 shares. Outstanding: |  |  |  |  |  |  |
2011, 14,233,723 shares, 2010, 13,830,823 shares, and 2009, 13,786,959 shares |  | $ 94,911 |  | $ 92,224 |  | $ 91,931 |
Premium on capital stock |  | 426,921 |  | 389,609 |  | 385,659 |
Retained earnings |  | 884,284 |  | 854,856 |  | 827,036 |
Accumulated other comprehensive income (loss), net of income taxes: |  |  |  |  |  |  |
Retirement benefit plans |  | (32 | ) | 709 |  | 1,782 |
Common stock equity |  | 1,406,084 |  | 1,337,398 |  | 1,306,408 |
Cumulative preferred stock not subject to mandatory redemption Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value. |  |  |  |  |  |  |

Series |  | Par Value |  | Par Value |  | Shares outstanding December 31, 2011 and 2010 |  | 2011 |  | 2010 |
(dollars in thousands, except par value and shares outstanding) |  |  |  |  |  |  |
C-4 1/4% |  | $ 20 |  | (HECO) |  | 150,000 |  | $ 3,000 |  | $ 3,000 |
D-5% |  | 20 |  | (HECO) |  | 50,000 |  | 1,000 |  | 1,000 |
E-5% |  | 20 |  | (HECO) |  | 150,000 |  | 3,000 |  | 3,000 |
H-5 1/4% |  | 20 |  | (HECO) |  | 250,000 |  | 5,000 |  | 5,000 |
I-5% |  | 20 |  | (HECO) |  | 89,657 |  | 1,793 |  | 1,793 |
J-4 3/4% |  | 20 |  | (HECO) |  | 250,000 |  | 5,000 |  | 5,000 |
K-4.65% |  | 20 |  | (HECO) |  | 175,000 |  | 3,500 |  | 3,500 |
G-7 5/8% |  | 100 |  | (HELCO) |  | 70,000 |  | 7,000 |  | 7,000 |
H-7 5/8% |  | 100 |  | (MECO) |  | 50,000 |  | 5,000 |  | 5,000 |
|  |  |  |  |  | 1,234,657 |  | 34,293 |  | 34,293 |

(continued)

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

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Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31 |  | 2011 |  | 2010 |
(in thousands) |  |  |  |  |
Long-term debt |  |  |  |  |
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds (subsidiary obligations unconditionally guaranteed by HECO): |  |  |  |  |
HECO, 6.50%, series 2009, due 2039 |  | $ 90,000 |  | $ 90,000 |
HELCO, 6.50%, series 2009, due 2039 |  | 60,000 |  | 60,000 |
HECO, 4.60%, refunding series 2007B, due 2026 |  | 62,000 |  | 62,000 |
HELCO, 4.60%, refunding series 2007B, due 2026 |  | 8,000 |  | 8,000 |
MECO, 4.60%, refunding series 2007B, due 2026 |  | 55,000 |  | 55,000 |
HECO, 4.65%, series 2007A, due 2037 |  | 100,000 |  | 100,000 |
HELCO, 4.65%, series 2007A, due 2037 |  | 20,000 |  | 20,000 |
MECO, 4.65%, series 2007A, due 2037 |  | 20,000 |  | 20,000 |
HECO, 4.80%, refunding series 2005A, due 2025 |  | 40,000 |  | 40,000 |
HELCO, 4.80%, refunding series 2005A, due 2025 |  | 5,000 |  | 5,000 |
MECO, 4.80%, refunding series 2005A, due 2025 |  | 2,000 |  | 2,000 |
HECO, 5.00%, refunding series 2003B, due 2022 |  | 40,000 |  | 40,000 |
HELCO, 5.00%, refunding series 2003B, due 2022 |  | 12,000 |  | 12,000 |
HELCO, 4.75%, refunding series 2003A, due 2020 |  | 14,000 |  | 14,000 |
HECO, 5.10%, series 2002A, due 2032 |  | 40,000 |  | 40,000 |
HECO, 5.70%, refunding series 2000, due 2020 |  | 46,000 |  | 46,000 |
MECO, 5.70%, refunding series 2000, due 2020 |  | 20,000 |  | 20,000 |
HECO, 6.15%, refunding series 1999D, due 2020 |  | 16,000 |  | 16,000 |
HELCO, 6.15%, refunding series 1999D, due 2020 |  | 3,000 |  | 3,000 |
MECO, 6.15%, refunding series 1999D, due 2020 |  | 1,000 |  | 1,000 |
HECO, 6.20%, series 1999C, due 2029 |  | 35,000 |  | 35,000 |
HECO, 5.75%, refunding series 1999B, due 2018 |  | 30,000 |  | 30,000 |
HELCO, 5.75%, refunding series 1999B, due 2018 |  | 11,000 |  | 11,000 |
MECO, 5.75%, refunding series 1999B, due 2018 |  | 9,000 |  | 9,000 |
HELCO, 5.50%, refunding series 1999A, due 2014 |  | 11,400 |  | 11,400 |
HECO, 4.95%, refunding series 1998A, due 2012 |  | 42,580 |  | 42,580 |
HELCO, 4.95%, refunding series 1998A, due 2012 |  | 7,200 |  | 7,200 |
MECO, 4.95%, refunding series 1998A, due 2012 |  | 7,720 |  | 7,720 |
HECO, 5.65%, series 1997A, due 2027 |  | 50,000 |  | 50,000 |
HELCO, 5.65%, series 1997A, due 2027 |  | 30,000 |  | 30,000 |
MECO, 5.65%, series 1997A, due 2027 |  | 20,000 |  | 20,000 |
HECO, 5.45%, series 1993, due 2023 |  | 50,000 |  | 50,000 |
HELCO, 5.45%, series 1993, due 2023 |  | 20,000 |  | 20,000 |
MECO, 5.45%, series 1993, due 2023 |  | 30,000 |  | 30,000 |
Total obligations to the State of Hawaii |  | 1,007,900 |  | 1,007,900 |
Other long-term debt – unsecured: |  |  |  |  |
6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034 |  | 51,546 |  | 51,546 |
Total long-term debt |  | 1,059,446 |  | 1,059,446 |
Less unamortized discount |  | 1,376 |  | 1,504 |
Less current portion long-term debt |  | 57,500 |  | – |
Long-term debt, net |  | 1,000,570 |  | 1,057,942 |
Total capitalization |  | $2,440,947 |  | $2,429,633 |

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

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Consolidated Statements of Changes in Common Stock Equity

Hawaiian Electric Company, Inc. and Subsidiaries

|  | Common stock |  | Premium on capital |  | Retained |  | Accumulated other comprehensive |  |
(in thousands) |  | Shares |  | Amount |  | stock |  | earnings |  | income (loss) | Total |
Balance, December 31, 2008 |  | 12,806 |  | $ 85,387 |  | $299,214 |  | $802,590 |  | $ 1,651 |  | $1,188,842 |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income for common stock |  | – |  | – |  | – |  | 79,446 |  | – |  | 79,446 |
Retirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |  |
Net transition asset arising during the period, net of taxes of $4,172 |  | – |  | – |  | – |  | – |  | 6,549 |  | 6,549 |
Prior service credit arising during the period, net of taxes of $922 |  | – |  | – |  | – |  | – |  | 1,446 |  | 1,446 |
Net gains arising during the period, net of taxes of $36,990 |  | – |  | – |  | – |  | – |  | 58,081 |  | 58,081 |
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost,net of tax benefits of $6,250 |  | – |  | – |  | – |  | – |  | 9,811 |  | 9,811 |
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,251 |  | – |  | – |  | – |  | – |  | (75,756 | ) | (75,756 | )
Other comprehensive income |  |  |  |  |  |  |  |  |  | 131 |  |  |
Comprehensive income |  |  |  |  |  |  |  |  |  |  |  | 79,577 |
Issuance of common stock, net of expenses |  | 981 |  | 6,544 |  | 86,445 |  | – |  | – |  | 92,989 |
Common stock dividends |  | – |  | – |  | – |  | (55,000 | ) | – |  | (55,000 | )
Balance, December 31, 2009 |  | 13,787 |  | 91,931 |  | 385,659 |  | 827,036 |  | 1,782 |  | 1,306,408 |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income for common stock |  | – |  | – |  | – |  | 76,589 |  | – |  | 76,589 |
Retirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |  |
Prior service credit arising during the period, net of taxes of $3,001 |  | – |  | – |  | – |  | – |  | 4,712 |  | 4,712 |
Net losses arising during the period, net of tax benefits of $27,408 |  | – |  | – |  | – |  | – |  | (43,031 | ) | (43,031 | )
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,387 |  | – |  | – |  | – |  | – |  | 3,747 |  | 3,747 |
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $21,336 |  | – |  | – |  | – |  | – |  | 33,499 |  | 33,499 |
Other comprehensive loss |  |  |  |  |  |  |  |  |  | (1,073 | ) |  |
Comprehensive income |  |  |  |  |  |  |  |  |  |  |  | 75,516 |
Issuance of common stock, net of expenses |  | 44 |  | 293 |  | 3,950 |  | – |  | – |  | 4,243 |
Common stock dividends |  | – |  | – |  | – |  | (48,769 | ) | – |  | (48,769 | )
Balance, December 31, 2010 |  | 13,831 |  | 92,224 |  | 389,609 |  | 854,856 |  | 709 |  | 1,337,398 |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income for common stock |  | – |  | – |  | – |  | 99,986 |  | – |  | 99,986 |
Retirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |  |
Prior service credit arising during the period, net of taxes of $4,408 |  | – |  | – |  | – |  | – |  | 6,921 |  | 6,921 |
Net losses arising during the period, net of tax benefits of $74,346 |  | – |  | – |  | – |  | – |  | (116,726 | ) | (116,726 | )
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $5,332 |  | – |  | – |  | – |  | – |  | 8,372 |  | 8,372 |
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $64,134 |  | – |  | – |  | – |  | – |  | 100,692 |  | 100,692 |
Other comprehensive loss |  |  |  |  |  |  |  |  |  | (741 | ) |  |
Comprehensive income |  |  |  |  |  |  |  |  |  |  |  | 99,245 |
Issuance of common stock, net of expenses |  | 403 |  | 2,687 |  | 37,312 |  | – |  | – |  | 39,999 |
Common stock dividends |  | – |  | – |  | – |  | (70,558 | ) | – |  | (70,558 | )
Balance, December 31, 2011 |  | 14,234 |  | $94,911 |  | $426,921 |  | $884,284 |  | $(32 | ) | $1,406,084 |

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

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Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31 |  | 2011 |  | 2010 |  | 2009 |
(in thousands) |  |  |  |  |  |  |
Cash flows from operating activities |  |  |  |  |  |  |
Net income |  | $101,981 |  | $ 78,584 |  | $ 81,441 |
Adjustments to reconcile net income to net cash provided by operating activities |  |  |  |  |  |  |
Depreciation of utility plant |  | 142,975 |  | 149,708 |  | 144,533 |
Other amortization |  | 17,378 |  | 7,725 |  | 10,045 |
Impairment of utility plant |  | 9,215 |  | – |  | – |
Changes in deferred income taxes |  | 69,091 |  | 95,685 |  | 14,762 |
Changes in tax credits, net |  | 2,087 |  | 2,841 |  | (1,332 | )
Allowance for equity funds used during construction |  | (5,964 | ) | (6,016 | ) | (12,222 | )
Change in cash overdraft |  | (2,688 | ) | (141 | ) | – |
Changes in assets and liabilities |  |  |  |  |  |  |
Decrease (increase) in accounts receivable |  | (44,404 | ) | (5,812 | ) | 32,605 |
Decrease (increase) in accrued unbilled revenues |  | (33,442 | ) | (20,108 | ) | 22,268 |
Increase in fuel oil stock |  | (18,843 | ) | (74,044 | ) | (946 | )
Increase in materials and supplies |  | (6,471 | ) | (809 | ) | (1,376 | )
Increase in regulatory assets |  | (40,132 | ) | (2,936 | ) | (17,597 | )
Increase (decrease) in accounts payable |  | (35,815 | ) | 25,392 |  | (6,165 | )
Changes in prepaid and accrued income taxes and revenue taxes |  | 69,736 |  | (10,170 | ) | (61,951 | )
Contributions to defined benefit pension and other postretirement benefit plans |  | (73,176 | ) | (31,068 | ) | (24,086 | )
Other |  | 9,866 |  | 38,958 |  | 21,515 |
Net cash provided by operating activities |  | 161,394 |  | 247,789 |  | 201,494 |
Cash flows from investing activities |  |  |  |  |  |  |
Capital expenditures |  | (226,022 | ) | (174,344 | ) | (286,445 | )
Contributions in aid of construction |  | 23,534 |  | 22,555 |  | 14,170 |
Other |  | 77 |  | 1,327 |  | 340 |
Net cash used in investing activities |  | (202,411 | ) | (150,462 | ) | (271,935 | )
Cash flows from financing activities |  |  |  |  |  |  |
Common stock dividends |  | (70,558 | ) | (48,769 | ) | (55,000 | )
Preferred stock dividends of HECO and subsidiaries |  | (1,995 | ) | (1,995 | ) | (1,995 | )
Proceeds from issuance of common stock |  | 40,000 |  | 4,250 |  | 61,914 |
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 |  | – |  | – |  | (10,464 | )
Decrease in cash overdraft |  | – |  | – |  | (9,545 | )
Other |  | (560 | ) | (1,455 | ) | (978 | )
Net cash provided by (used in) financing activities |  | (33,113 | ) | (47,969 | ) | 137,118 |
Net increase (decrease) in cash and cash equivalents |  | (74,130 | ) | 49,358 |  | 66,677 |
Cash and cash equivalents, January 1 |  | 122,936 |  | 73,578 |  | 6,901 |
Cash and cash equivalents, December 31 |  | $48,806 |  | $122,936 |  | $ 73,578 |

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

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Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General. Hawaiian Electric Company, Inc. (HECO) and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the Public Utilities Commission of the State of Hawaii (PUC). HECO also owns the following non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which was formed to invest in renewable energy projects; Uluwehiokama Biofuels Corp. (UBC), which was formed to invest in a new biodiesel refining plant to be built on the island of Maui, which project has been terminated; and HECO Capital Trust III, which is a financing entity.

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

Material estimates that are particularly susceptible to significant change include the amounts reported for property, plant and equipment; pension and other postretirement benefit obligations; contingencies and litigation; income taxes; regulatory assets and liabilities; and revenues.

Consolidation. The consolidated financial statements include the accounts of HECO and its subsidiaries (collectively, the Company), but exclude subsidiaries which are variable interest entities (VIEs) when the Company is not the primary beneficiary. Investments in companies over which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method. The Company is a wholly-owned subsidiary of Hawaiian Electric Industries, Inc. (HEI). All material intercompany accounts and transactions have been eliminated in consolidation.

See Note 3 for information regarding unconsolidated VIEs. In June 2009, the Financial Accounting Standards Board (FASB) issued a standard that eliminated exceptions to consolidating qualifying special-purpose entities, contained new criteria for determining the primary beneficiary, and increased the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. The Company adopted this standard as of January 1, 2010 and the adoption did not impact the Company’s financial condition, results of operations or liquidity, but did require additional disclosures.

Regulation by the Public Utilities Commission of the State of Hawaii (PUC). HECO, HELCO and MECO are regulated by the PUC and account for the effects of regulation under FASB Accounting Standards Codification TM (ASC) Topic 980, “Regulated Operations.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes HECO and its subsidiaries’ operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that its regulatory assets would be charged to expense and regulatory liabilities would be credited to income or refunded to ratepayers immediately. In the event of unforeseen regulatory actions or other circumstances, however, management believes that a material adverse effect on the Company’s results of operations and financial position may result if regulatory assets have to be charged to expense without an offsetting credit for regulatory liabilities or if regulatory liabilities are required to be refunded to ratepayers immediately.

Equity method. Investments in up to 50%-owned affiliates over which the Company has the ability to exercise significant influence over the operating and financing policies and investments in unconsolidated subsidiaries (e.g. HECO Capital Trust III) are accounted for under the equity method, whereby the investment is carried at cost, plus (or minus) the Company’s equity in undistributed earnings (or losses) and minus distributions since acquisition. Equity in earnings or losses is reflected in other income. Equity method investments are evaluated for other-than-temporary impairment. Also see “Variable interest entities” below.

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Utility plant. Utility plant is reported at cost. Self-constructed plant includes engineering, supervision, administrative and general costs and an allowance for the cost of funds used during the construction period. These costs are recorded in construction in progress and are transferred to utility plant when construction is completed and the facilities are either placed in service or become useful for public utility purposes. Costs for betterments that make utility plant more useful, more efficient, of greater durability or of greater capacity are also capitalized. Upon the retirement or sale of electric utility plant, generally no gain or loss is recognized. The cost of the plant retired is charged to accumulated depreciation. Amounts collected from customers for cost of removal (expected to exceed salvage value in the future) are included in regulatory liabilities.

Depreciation. Depreciation is computed primarily using the straight-line method over the estimated lives of the assets being depreciated. Utility plant additions in the current year are depreciated beginning January 1 of the following year in accordance with rate-making. Utility plant has lives ranging from 20 to 88 years for production plant, from 25 to 65 years for transmission and distribution plant and from 5 to 50 years for general plant. The composite annual depreciation rate, which includes a component for cost of removal, was 3.2% in 2011, 3.5% in 2010 and 3.8% in 2009.

Leases. HECO and its subsidiaries have entered into lease agreements for the use of equipment and office space. The provisions of some of the lease agreements contain renewal options.

Operating lease expense was $6 million, $6 million and $7 million in 2011, 2010 and 2009, respectively. Future minimum lease payments are $6 million each year for 2012, 2013, 2014, $5 million for 2015, $3 million for 2016 and $10 million thereafter.

Cash and cash equivalents. The Company considers cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper of non-affiliates and liquid investments (with original maturities of three months or less) to be cash and cash equivalents.

Accounts receivable. Accounts receivable are recorded at the invoiced amount. The Company generally assesses a late payment charge on balances unpaid from the previous month. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. On a monthly basis, the Company adjusts its allowance, with a corresponding charge (credit) on the statement of income, based on its historical write-off experience. Account balances are charged off against the allowance after collection efforts have been exhausted and the potential for recovery is considered remote.

Retirement benefits. Pension and other postretirement benefit costs are charged primarily to expense and electric utility plant. Funding for the Company’s qualified pension plans (Plans) is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plans on the advice of an enrolled actuary. The participating employers contribute amounts to a master pension trust for the Plans in accordance with the funding requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA), including changes promulgated by the Pension Protection Act of 2006, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost during the year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the PUC, HECO generally will make contributions to the pension fund at the greater of the minimum level required under the law or net periodic pension cost less pension asset, until its pension asset (existing at the time of the PUC decision and determined based on the cumulative fund contributions in excess of the cumulative net periodic pension cost recognized) is reduced to zero, at which time HECO would fund the pension cost as specified in the pension tracking mechanism. HELCO and MECO will also generally fund the greater of the minimum level required under the law or net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

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Certain health care and/or life insurance benefits are provided to eligible retired employees and the employees’ beneficiaries and covered dependents. The Company generally funds the net periodic postretirement benefit costs other than pensions and the amortization of the regulatory asset for postretirement benefits other than pensions (OPEB), while maximizing the use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The Company must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC. Future decisions in rate cases could further impact funding amounts.

The Company recognizes on its balance sheet the funded status of its defined benefit pension and other postretirement benefit plans, as adjusted by the impact of decisions of the PUC.

Financing costs. The Company uses the straight-line method to amortize long-term debt financing costs and premiums or discounts over the term of the related debt. Unamortized financing costs and premiums or discounts on long-term debt retired prior to maturity are classified as regulatory assets (costs and premiums) or liabilities (discounts) and are amortized on a straight-line basis over the remaining original term of the retired debt. The method and periods for amortizing financing costs, premiums and discounts, including the treatment of these items when long-term debt is retired prior to maturity, have been established by the PUC as part of the rate-making process.

The Company uses the straight-line method to amortize the fees and related costs paid to secure a firm commitment under its line-of-credit arrangements.

Contributions in aid of construction. The Company receives contributions from customers for special construction requirements. As directed by the PUC, contributions are amortized on a straight-line basis over 30 to 51 years as an offset against depreciation expense.

Electric utility revenues. Electric utility revenues are based on rates authorized by the PUC and include revenues applicable to energy consumed in the accounting period but not yet billed to the customers. Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers.

The rate schedules of the Company include energy cost adjustment clauses (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 rate schedules of HECO include a purchased power adjustment clause (PPAC) under which HECO recovers purchase power expenses through a surcharge mechanism. The amounts collected through the ECACs and PPAC are required to be reconciled quarterly.

The Company’s operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. However, the Company’s revenue tax payments to the taxing authorities are based on the prior years’ revenues. For 2011, 2010 and 2009, the Company included approximately $264 million, $211 million and $181 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Power purchase agreements. If a power purchase agreement (PPA) falls within the scope of Accounting Standards Codification (ASC) Topic 840, “Leases,” and results in the classification of the agreement as a capital lease, the Company would recognize a capital asset and a lease obligation. Currently, none of the PPAs are required to be recorded as a capital lease.

The Company evaluates PPAs to determine if the PPAs are VIEs, if the Company is the primary beneficiary and if consolidation is required. See Note 3.

Repairs and maintenance costs. R epairs and maintenance costs for overhauls of generating units are generally expensed as they are incurred.

Allowance for Funds Used During Construction (AFUDC). AFUDC is an accounting practice whereby the costs of debt and equity funds used to finance plant construction are credited on the statement of income and charged to construction in progress on the balance sheet. If a project under construction is delayed for an extended period of time, AFUDC on the delayed project may be stopped after assessing the causes of the delay and probability of recovery.

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The weighted-average AFUDC rate was 8.0% in 2011 and 8.1% in 2010 and 2009, and reflected quarterly compounding.

Environmental expenditures. The Company is subject to numerous federal and state environmental statutes and regulations. In general, environmental contamination treatment costs are charged to expense, unless it is probable that the PUC would allow such costs to be recovered in future rates, in which case such costs would be capitalized as regulatory assets. Also, environmental costs are capitalized if the costs extend the life, increase the capacity, or improve the safety or efficiency of property; the costs mitigate or prevent future environmental contamination; or the costs are incurred in preparing the property for sale. Environmental costs are either capitalized or charged to expense when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated.

Income taxes. The Company is included in the consolidated income tax returns of HECO’s parent, HEI. However, income tax expense has been computed for financial statement purposes as if HECO and its subsidiaries filed separate consolidated HECO income tax returns.

Deferred income tax assets and liabilities are established for the temporary differences between the financial reporting bases and the tax bases of the Company’s assets and liabilities at federal and state tax rates expected to be in effect when such deferred tax assets or liabilities are realized or settled. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.

Federal and state investment tax credits are deferred and amortized over the estimated useful lives of the properties which qualified for the credits.

Governmental tax authorities could challenge a tax return position taken by management. If the Company’s position does not prevail, the Company’s results of operations and financial condition may be adversely affected as the related deferred or current income tax asset might be impaired and written down or an unanticipated tax liability might be incurred.

The Company uses a “more-likely-than-not” recognition threshold and measurement standard for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

Impairment of long-lived assets and long-lived assets to be disposed of. The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell.

Recent accounting pronouncements and interpretations

Fair value measurements. In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. generally accepted accounting principles (GAAP) and IFRSs,” which represents the converged guidance of the FASB and the International Accounting Standards Board (the Boards) on fair value measurement. This ASU includes the Boards’ common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The Boards have concluded the common requirements will result in greater comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards.

The Company will prospectively adopt this standard in the first quarter of 2012 and does not expect it to have a material impact on the Company’s results of operations, financial condition or liquidity.

Comprehensive income. In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” and in December 2011, the FASB issued ASU No. 2011-12, which amended ASU No. 2011-05. ASU No. 2011-05, as amended, eliminates the option to present components of other comprehensive income as part of the statement of changes in shareholders’ equity. All items of net income and other

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comprehensive income are required to be presented in either a single continuous statement of comprehensive income or in two separate, but consecutive, statements—a net income statement and a total comprehensive income statement.

The Company expects to retrospectively adopt this standard during the first quarter of 2012 using a two-statement approach.

Reclassifications. Certain reclassifications have been made to prior years’ financial statements to conform to the 2011 presentation, which did not affect previously reported results of operations.

2. Cumulative preferred stock

The following series of cumulative preferred stock are redeemable only at the option of the respective company at the following prices in the event of voluntary liquidation or redemption:

December 31, 2011 |  | Voluntary liquidation price |  | Redemption price |
Series |  |  |  |  |
C, D, E, H, J and K (HECO) |  | $ 20 |  | $ 21 |
I (HECO) |  | 20 |  | 20 |
G (HELCO) |  | 100 |  | 100 |
H (MECO) |  | 100 |  | 100 |

HECO is obligated to make dividend, redemption and liquidation payments on the preferred stock of either of its subsidiaries if the respective subsidiary is unable to make such payments, but such obligation is subordinated to any obligation to make payments on HECO’s own preferred stock.

3. 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 HELCO and MECO each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. 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 sheet as of December 31, 2011 consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statement for 2011 consisted of $3.4 million of interest income received from the 2004 Debentures; $3.3 million of distributions to holders of the Trust Preferred Securities; and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

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Power purchase agreements. As of December 31, 2011, the Company had six PPAs totaling 548 MW of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 90% of the 548 MW of firm capacity is pursuant 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 2011 totaled $690 million with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $133 million, $310 million, $59 million and $62 million, respectively.

Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (e.g., HPOWER), and thus excluded from the scope of accounting standards for VIEs. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of accounting standards for VIEs.

Since 2004, HECO has continued its efforts to obtain from the IPPs the information necessary to make the determinations required under accounting standards for VIEs. In each year from 2005 to 2011, the Company sent letters to the identified IPPs requesting the required information. All of these IPPs declined to provide the necessary information, except that Kalaeloa provided the information pursuant to the amendments to its PPA (see below) and an entity owning a wind farm provided information as required under its PPA. Management has concluded that the consolidation of two entities owning wind farms was not required as HELCO and MECO do not have variable interests in the entities because the PPAs do not require them to absorb any variability of the entities.

If the requested information is ultimately received from the remaining IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs in the Company’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on the Company’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If the Company determines it is required to consolidate the financial statements of such an IPP and the consolidation has a material effect, the Company would retrospectively apply accounting standards for VIEs.

Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: (1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, (2) a fuel additives cost component, and (3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA. Kalaeloa also has a steam delivery cogeneration contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978.

Pursuant to the current accounting standards for VIEs, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not have the power to direct the activities that most significantly impact Kalaeloa’s economic performance nor the obligation to absorb Kalaeloa’s expected losses, if any, that could potentially be significant to Kalaeloa. Thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO could potentially absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates.

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4. Long-term debt

On July 30, 2009 the Department also issued, at par, Series 2009 SPRBs in the aggregate principal amount of $150 million, with a maturity of July 1, 2039 and a fixed coupon interest rate of 6.50%, and loaned the proceeds to HECO ($90 million) and HELCO ($60 million). HECO and HELCO drew the full amount of the proceeds from the issuance of the SPRBs in 2009 as reimbursement for previously incurred capital expenditures, and used the proceeds principally to repay short-term borrowings. Payment of the principal and interest on the SPRBs are not insured.

At December 31, 2011, the aggregate payments of principal required on long-term debt are $58 million in 2012, nil in 2013, $11 million in 2014 and nil in 2015 and 2016.

5. Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2011 and 2010.

At December 31, 2011 and 2010 the Company maintained syndicated credit facilities of $175 million. HECO had no borrowings under its facilities in 2011 or 2010. The facility is not collateralized. See Note 13, “Related-party transactions,” concerning borrowings from affiliates.

Credit agreement. Effective December 5, 2011, HECO and a syndicate of eight financial institutions entered into an amendment to their revolving unsecured credit agreement. The amendment revised the pricing of HECO’s $175 million line of credit facility (with a letter of credit sub-facility). The credit agreement, as amended, has a term which expires on December 5, 2016. Any draws on the facility bear interest at the “Adjusted LIBO Rate”, as defined in the agreement, plus 150 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 50 basis points per annum, as defined in the agreement. Annual fees on undrawn commitments are 25 basis points. The amended agreement contains provisions for revised pricing in the event of a long-term 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 that must be met in order to draw on it, including compliance with its covenants, and among other things provides that it is an event of default if HEI ceases to own HECO.

The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes.

6. Regulatory assets and liabilities

In accordance with ASC Topic 980, “Regulated Operations,” the Company’s financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Continued accounting under ASC Topic 980 generally requires that rates are established by an independent, third-party regulator; rates are designed to recover the costs of providing service; and it is reasonable to assume that rates can be charged to and collected from customers. Management believes its operations currently satisfy the ASC Topic 980 criteria. If events or circumstances should change so that those criteria are no longer satisfied, the Company expects that the regulatory assets would be charged to expense and the regulatory liabilities would be credited to income or refunded to ratepayers immediately. In the event of unforeseen regulatory actions or other circumstances, management believes that a material adverse effect on the Company’s financial condition, results of operations and/or liquidity may result if regulatory assets have to be charged to expense or if regulatory liabilities are required to be refunded to ratepayers immediately.

Regulatory assets represent deferred costs expected to be fully recovered through rates over PUC-authorized periods. Generally, HECO and its subsidiaries do not earn a return on their regulatory assets; however, they have been allowed to recover interest on certain regulatory assets and to include certain regulatory assets in rate base.

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Regulatory liabilities represent amounts included in rates and collected from ratepayers for costs expected to be incurred in the future. For example, the regulatory liability for cost of removal in excess of salvage value represents amounts that have been collected from ratepayers for costs that are expected to be incurred in the future to retire utility plant. Generally, HECO and its subsidiaries include regulatory liabilities in rate base or are required to apply interest to certain regulatory liabilities. Noted in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2011, if different.

Regulatory assets were as follows:

December 31 |  | 2011 | 2010
(in thousands) |  |  |  |  |
Retirement benefit plans (balance primarily varies with plans’ funded statuses) |  | $523,640 |  | $356,591 |
Income taxes, net (1 to 48 years) |  | 83,386 |  | 82,615 |
Decoupling revenue balancing account (1 year) |  | 20,780 |  | – |
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 1 to 17 years remaining) |  | 12,267 |  | 13,589 |
Vacation earned, but not yet taken (1 year) |  | 8,161 |  | 7,349 |
Postretirement benefits other than pensions (18 years; 1 year remaining) |  | 1,861 |  | 3,579 |
Other (1 to 50 years; 1 to 48 years remaining) |  | 19,294 |  | 14,607 |
|  | $669,389 |  | $478,330 |

Regulatory liabilities were as follows:

December 31 |  | 2011 | 2010
(in thousands) |  |  |  |  |
Cost of removal in excess of salvage value (1 to 60 years) |  | $294,817 |  | $277,341 |
Retirement benefit plans (5 years beginning with respective utility’s |  | 20,000 |  | 18,617 |
next rate case; primarily 5 years remaining) |  |  |  |  |
Other (5 years; 1 to 5 years remaining) |  | 649 |  | 839 |
|  | $315,466 |  | $296,797 |

The regulatory asset and liability relating to retirement benefit plans was created as a result of pension and OPEB tracking mechanisms adopted by the PUC in rate case decisions for HECO, MECO and HELCO in 2007 (see Note 10).

7. Income taxes

The components of income taxes attributable to net income were as follows:

Years ended December 31 |  | 2011 | 2010 | 2009
(in thousands) |  |  |  |  |  |  |
Federal: |  |  |  |  |  |  |
Current |  | $(10,819 | ) | $(40,780 | ) | $27,321 |
Deferred |  | 64,645 |  | 83,472 |  | 15,789 |
Deferred tax credits, net |  | – |  | (901 | ) | (593 | )
|  | 53,826 |  | 41,791 |  | 42,517 |
State: |  |  |  |  |  |  |
Current |  | 1,226 |  | (10,879 | ) | 7,025 |
Deferred |  | 4,445 |  | 13,114 |  | (433 | )
Deferred tax credits, net |  | 2,087 |  | 2,840 |  | (1,333 | )
|  | 7,758 |  | 5,075 |  | 5,259 |
Total |  | $61,584 |  | $46,866 |  | $47,776 |

Total income tax expense incorporates the income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income. These tax benefits amounted to $4.4 million, $1.2 million and $0.4 million for 2011, 2010 and 2009, respectively.

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A reconciliation of the amount of income taxes computed at the federal statutory rate of 35% on income before income taxes and preferred stock dividends of HECO and subsidiaries follows:

December 31 |  | 2011 | 2010 | 2009
(in thousands) |  |  |  |  |  |  |
Amount at the federal statutory income tax rate |  | $ 57,248 |  | $ 43,908 |  | $ 45,226 |
Increase (decrease) resulting from: |  |  |  |  |  |  |
State income taxes on operating income, net of effect on federal income taxes |  | 5,042 |  | 3,300 |  | 3,419 |
Other |  | (706 | ) | (342 | ) | (869 | )
Total |  | $ 61,584 |  | $ 46,866 |  | $ 47,776 |
Effective income tax rate |  | 37.7 | % | 37.4 | % | 37.0 | %

The tax effects of book and tax basis differences that give rise to deferred tax assets and liabilities were as follows:

December 31 |  | 2011 | 2010
(in thousands) |  |  |  |  |
Deferred tax assets: |  |  |  |  |
Other |  | $ 13,295 |  | $ 12,686 |
|  | 13,295 |  | 12,686 |
Deferred tax liabilities: |  |  |  |  |
Property, plant and equipment |  | 254,105 |  | 189,277 |
Change in accounting method related to repairs |  | 48,566 |  | 46,702 |
Regulatory assets, excluding amounts attributable to property, plant and equipment |  | 32,343 |  | 32,074 |
Retirement benefits |  | 2,976 |  | 3,846 |
Other |  | 13,168 |  | 10,073 |
|  | 351,158 |  | 281,972 |
Net deferred income tax liability |  | $337,863 |  | $269,286 |

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. Based upon historical taxable income and projections for future taxable income, management believes it is more likely than not the Company will realize substantially all of the benefits of the deferred tax assets. In 2011, the net deferred income tax liability continued to increase primarily as a result of accelerated tax deductions taken for bonus depreciation (resulting from the 2010 Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act).

In 2010, interest income on income tax refunds was reflected in “Other income—Other, net” in the amount of $9.6 million, which resulted from the settlement with the IRS of appealed issues for the tax years 1996 to 2006 and was due in large part to a change in the method of allocating overhead costs to self-constructed assets. In 2011, 2010 and 2009, interest expense/(credit adjustments to interest expense) on income taxes was reflected in “Interest and other charges” in the amount of $(1.0) million, $(1.3) million and $0.5 million, respectively. The credit adjustments to interest expense were primarily due to the resolution of tax issues with the Internal Revenue Service (IRS). As of December 31, 2011 and 2010, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet in “Interest and preferred dividends payable” was $0.3 million and $0.8 million, respectively.

As of December 31, 2011, the total amount of liability for uncertain tax positions was $3.7 million and, if recognized, would not affect the Company’s effective tax rate. The Company’s unrecognized tax benefits are primarily the result of temporary differences relating to the deductibility of costs incurred to repair generation property. The Company believes that it is reasonably possible that the IRS may issue guidance on the deductibility of these repair costs and this guidance will eliminate much of the uncertainty in 2012. Management has concluded that it is reasonably possible that the liability for uncertain tax positions may reverse within the next 12 months.

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The changes in total unrecognized tax benefits were as follows:

Years ended December 31 |  | 2011 | 2010
(in millions) |  |  |  |  |
Unrecognized tax benefits, January 1 |  | $ 14.2 |  | $ 24.1 |
Additions based on tax positions taken during the year |  | – |  | 10.9 |
Additions for tax positions of prior years |  | – |  | 1.4 |
Reductions based on tax positions taken during the year |  | (0.6 | ) | – |
Reductions for tax positions of prior years |  | (8.8 | ) | (16.2 | )
Settlements |  | – |  | (6.0 | )
Lapses of statute of limitations |  | (1.1 | ) | – |
Unrecognized tax benefits, December 31 |  | $ 3.7 |  | $14.2 |

The 2011 reduction in unrecognized tax benefits was primarily due to the IRS’s issuance of guidance on the deductibility of costs of repairs to utility transmission and distribution (T&D) property (Revenue Procedure 2011-43, issued in August 2011), including a “safe harbor” method under which taxpayers could transition and minimize the uncertainty of the repairs expense deduction for T&D property. The Company intends to elect the “safe harbor” method in its 2011 tax return, which resulted in the reduction of associated unrecognized tax benefits for 2011.

Tax years 2007 to 2010 currently remain subject to examination by the IRS. Tax years 2005 to 2010 remain subject to examination by the Department of Taxation of the State of Hawaii.

As of December 31, 2011, the disclosures above present the Company’s accrual for potential tax liabilities and related interest. Based on information currently available, the Company believes this accrual has adequately provided for potential income tax issues with federal and state tax authorities and related interest, and that the ultimate resolution of tax issues for all open tax periods will not have a material adverse effect on its results of operations, financial condition or liquidity.

8. Cash flows

Supplemental disclosures of cash flow information

Years ended December 31 |  | 2011 | 2010 | 2009
(in thousands) |  |  |  |  |  |  |
Interest paid to non-affiliates |  | $57,581 |  | $56,184 |  | $43,616 |
Income taxes paid/(refunded) |  | $(22,980 | ) | $(7,277 | ) | $24,309 |

Supplemental disclosures of noncash activities

In 2011, 2010 and 2009, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $6 million, $6 million and $12 million, respectively.

In 2011, 2010 and 2009, the estimated fair value of noncash contributions in aid of construction was $7 million, $7 million and $12 million, respectively.

In 2011, 2010 and 2009, the amount of unpaid invoices and other non-cash items related to property, plant and equipment was $45 million, $21 million and $16 million, respectively.

In December 2009, HECO sold $93 million of its common stock to HEI. HECO received $62 million of cash from HEI and reduced its intercompany note payable to HEI by $31 million in a noncash transaction.

9. Major customers

HECO and its subsidiaries received approximately 11% ($316 million), 10% ($242 million) and 10% ($199 million) of their operating revenues from the sale of electricity to various federal government agencies in 2011, 2010 and 2009, respectively.

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10. Retirement benefits

Defined benefit plans. Substantially all of the employees of HECO, HELCO and MECO participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (the Plan). The Plan is a qualified, noncontributory defined benefit pension plan and includes benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plan is subject to the provisions of ERISA. In addition, some current and former executives and directors participate in noncontributory, nonqualified plans (collectively, Supplemental Plans). In general, benefits are based on the employees’ or directors’ years of service and compensation.

The continuation of the Plan and the Supplemental Plans and the payment of any contribution thereunder are not assumed as contractual obligations by the participating employers. The Supplemental Plan for directors has been frozen since 1996. The HEI Supplemental Executive Retirement Plan (noncontributory, nonqualified, defined benefit plan) was frozen as of December 31, 2008. No participants have accrued any benefits under these plans after the respective plan’s freeze and the plans will be terminated at the time all remaining benefits have been paid.

Each participating employer reserves the right to terminate its participation in the applicable plans at any time. If a participating employer terminates its participation in the Plan, the interest of each affected participant would become 100% vested to the extent funded. Upon the termination of the Plan, assets would be distributed to affected participants in accordance with the applicable allocation provisions of ERISA and any excess assets that exist would be paid to the participating employers. Participants’ benefits in the Plan are covered up to certain limits under insurance provided by the Pension Benefit Guaranty Corporation.

To determine pension costs for HECO, HELCO and MECO under the Plan and the Supplemental Plans, it is necessary to make complex calculations and estimates based on numerous assumptions, including the assumptions identified below.

Postretirement benefits other than pensions. The Company provides eligible employees health and life insurance benefits upon retirement under the Postretirement Welfare Benefits Plan for Employees of Hawaiian Electric Company, Inc. and participating employers (HECO Benefits Plan). Eligibility of employees and dependents are based on eligibility to retire at termination, the retirement date and the date of hire. The plan was amended in 2011, changing eligibility for certain bargaining unit employees hired prior to May 1, 2011, based on new minimum age and service requirements effective January 1, 2012, per the collective bargaining agreement, and certain management employees hired prior to May 1, 2011 based on new eligibility minimum age and service requirements effective January 1, 2012. The minimum age and service requirements for management and bargaining unit employees hired May 1, 2011 and thereafter have increased and their dependents are not eligible to receive postretirement benefits. Employees may be eligible to receive benefits from the HEI/HECO Pension Plan but may not be eligible for postretirement welfare benefits if the different eligibility requirements are not met.

The executive death benefit plan was frozen on September 10, 2009 to participants and benefit levels as of that date. The electric discount was eliminated for management employees and retirees of HECO in August 2009, HELCO in November 2010, and MECO in August 2010, and for bargaining unit employees and retirees on January 31, 2011 per the collective bargaining agreement. The Company’s cost for OPEB has been adjusted to reflect the plan amendment, which reduced benefits. The elimination of the electric discount benefit will generate credits through other benefit costs over the next few years as the total amendment credit is amortized.

Each participating employer reserves the right to terminate its participation in the plan at any time.

Balance sheet recognition of the funded status of retirement plans. Employers must recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in shareholders’ equity (using the projected benefit obligation (PBO), to calculate the funded status).

The PUC allowed the utilities to adopt pension and OPEB tracking mechanisms in recent rate cases. The amount of the net periodic pension cost (NPPC) and net periodic benefits costs (NPBC) to be recovered in rates is established by the PUC in each rate case. Under the utilities’ tracking mechanisms, any actual costs determined in accordance with U.S. generally accepted accounting principles (GAAP) that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will then be amortized over 5 years beginning with the respective utility’s next rate case. Accordingly, all retirement benefit

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expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.6 million in 2011) determined in accordance with U.S. GAAP will be recovered.

Under the tracking mechanisms, amounts that would otherwise be recorded in AOCI (excluding amounts for executive life and nonqualified pension plans), which amounts include the prepaid pension asset, net of taxes, as well as other pension and OPEB charges, are allowed to be reclassified as a regulatory asset, as those costs will be recovered in rates through the NPPC and NPBC in the future. The Company has reclassified to a regulatory asset charges for retirement benefits that would otherwise be recorded in AOCI (amounting to the elimination of a potential charge/(credit) to AOCI of $165 million pretax and $55 million pretax for 2011 and 2010, respectively).

In 2007, the PUC allowed HELCO to record a regulatory asset in the amount of $12.8 million (representing HELCO’s prepaid pension asset and reflecting the accumulated pension contributions to its pension fund in excess of accumulated NPPC), which is included in rate base, and allowed recovery of that asset over a period of five years. HELCO is required to make contributions to the pension trust in the amount of the actuarially calculated NPPC that would be allowed without penalty by the tax laws.

In 2007, the PUC declined to allow HECO and MECO to include their pension assets (representing the accumulated contributions to their pension fund in excess of accumulated NPPC), in their rate bases. However, under the tracking mechanisms, HECO and MECO are required to fund only the minimum level required under the law until their pension assets are reduced to zero, at which time HECO and MECO will make contributions to the pension trust in the amount of the actuarially calculated NPPC, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitations on deductible contributions imposed by the Internal Revenue Code.

The PUC’s exclusion of HECO’s and MECO’s pension assets from rate base does not allow HECO and MECO to earn a return on the pension asset, but this exclusion does not result in the exclusion of any pension benefit costs from their rates. The pension asset is to be (and has been, in the case of MECO) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2011 HECO’s pension asset had been reduced to $3 million.

The OPEB tracking mechanisms generally require the Company to make contributions to the OPEB trust in the amount of the actuarially calculated NPBC, except when limited by material, adverse consequences imposed by federal regulations.

Retirement benefits expense for 2011, 2010 and 2009 was $34 million, $39 million and $32 million, respectively.

Retirement benefit plan changes. On March 11, 2011, the Company’s bargaining unit employees ratified a new benefit agreement, which included changes to retirement benefits. Changes to retirement benefits for employees commencing employment after April 30, 2011 include a modified defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries) (with a lower payment formula than the formula in the plan for employees hired before May 1, 2011) and the addition of a 50% match by the applicable employer on the first 6% of employee elective deferrals by such employees through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP)). In addition, new eligibility rules and contribution levels applicable to existing and new employees were adopted for postretirement welfare benefits. In general, defined pension benefits are based on the employees’ years of service and compensation.

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Defined benefit and pension and other postretirement benefit plans information. The changes in the obligations and assets of the Company’s retirement benefit plans and the changes in AOCI (gross) for 2011 and 2010 and the funded status of these plans and amounts related to these plans reflected in the Company’s consolidated balance sheet as of December 31, 2011 and 2010 were as follows:

|  | 2011 | 2010
(in thousands) |  | Pension benefits | Other benefits | Pension benefits | Other benefits
Benefit obligation, January 1 |  | $1,072,404 |  | $174,745 |  | $ 922,801 |  | $165,826 |
Service cost |  | 33,627 |  | 4,238 |  | 27,576 |  | 4,584 |
Interest cost |  | 59,077 |  | 9,228 |  | 58,868 |  | 10,080 |
Amendments |  | – |  | (11,329 | ) | – |  | (7,713 | )
Actuarial losses |  | 91,539 |  | 16,137 |  | 113,857 |  | 11,323 |
Benefits paid and expenses |  | (52,704 | ) | (8,779 | ) | (50,698 | ) | (9,355 | )
Benefit obligation, December 31 |  | 1,203,943 |  | 184,240 |  | 1,072,404 |  | 174,745 |
Fair value of plan assets, January 1 |  | 742,080 |  | 148,868 |  | 658,917 |  | 132,714 |
Actual return (loss) on plan assets |  | (8,711 | ) | (2,286 | ) | 106,552 |  | 20,963 |
Employer contribution |  | 71,246 |  | 1,930 |  | 27,164 |  | 3,904 |
Benefits paid and expenses |  | (52,330 | ) | (7,748 | ) | (50,553 | ) | (8,713 | )
Fair value of plan assets, December 31 |  | 752,285 |  | 140,764 |  | 742,080 |  | 148,868 |
Accrued benefit liability, December 31 |  | (451,658 | ) | (43,476 | ) | (330,324 | ) | (25,877 | )
AOCI, January 1 (excluding impact of PUC D&Os) |  | 341,697 |  | 8,209 |  | 279,198 |  | 14,118 |
Recognized during year – net recognized transition asset |  | – |  | 8 |  | – |  | 8 |
Recognized during year – prior service credit |  | 747 |  | 1,505 |  | 747 |  | 409 |
Recognized during year – net actuarial losses |  | (15,752 | ) | (212 | ) | (7,300 | ) | – |
Occurring during year – prior service cost |  | – |  | (11,329 | ) | – |  | (7,713 | )
Occurring during year – net actuarial losses |  | 161,864 |  | 29,209 |  | 69,052 |  | 1,387 |
|  | 488,556 |  | 27,390 |  | 341,697 |  | 8,209 |
Cumulative impact of PUC D&Os |  | (486,710 | ) | (29,183 | ) | (340,187 | ) | (10,880 | )
AOCI, December 31 |  | 1,846 |  | (1,793 | ) | 1,510 |  | (2,671 | )
Net actuarial loss |  | 489,561 |  | 46,911 |  | 343,449 |  | 17,915 |
Prior service gain |  | (1,005 | ) | (19,513 | ) | (1,752 | ) | (9,689 | )
Net transition obligation |  | – |  | (8 | ) | – |  | (17 | )
|  | 488,556 |  | 27,390 |  | 341,697 |  | 8,209 |
Cumulative impact of PUC D&Os |  | (486,710 | ) | (29,183 | ) | (340,187 | ) | (10,880 | )
AOCI/Loss, December 31 |  | 1,846 |  | (1,793 | ) | 1,510 |  | (2,671 | )
Income taxes (benefits) |  | (719 | ) | 698 |  | (587 | ) | 1,039 |
AOCI/Loss, net of taxes, December 31 |  | $ 1,127 |  | $ (1,095 | ) | $ 923 |  | $ (1,632 | )

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2011, 2010 and 2009.

The defined benefit pension plans with accumulated benefit obligations (ABOs), which do not consider projected pay increases (unlike the PBOs shown in the table above), in excess of plan assets as of December 31, 2011 and 2010, had aggregate ABOs of $1.1 billion and $956 million, respectively, and plan assets of $752 million and $742 million, respectively.

The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels, more conservative assumptions must be used to value obligations under the pension plan and restrictions on participant benefit accruals may be placed on the plan. The HEI Retirement Plan has fallen below these thresholds and the minimum required contribution estimated for 2012 incorporates the more conservative assumptions required. Other factors could cause changes to the required contribution levels.

Effective April 1, 2011, accelerated distribution options (the $50,000 single sum distribution option and a Social Security level income option) under the HEI Retirement Plan became subject to partial restrictions because the funded status of the HEI Retirement Plan was deemed to be less than 80%. Generally, while the partial

25

restrictions are in effect, a retiring participant may only elect an accelerated distribution option for 50% of the participant’s total benefit. The partial restrictions are expected to continue through 2012.

The Company estimates that the cash funding for the qualified defined benefit pension plan in 2012 and 2013 will be $102 million and $87 million, respectively, which should fully satisfy the minimum required contributions to that Plan, including requirements of the pension tracking mechanism and the Plan’s funding policy. The Company’s current estimate of contributions to the qualified defined benefit plans and all other retirement benefit plans in 2012 is $104 million.

As of December 31, 2011, the benefits expected to be paid under the retirement benefit plans in 2012, 2013, 2014, 2015, 2016 and 2017 through 2021 amounted to $64 million, $67 million, $70 million, $73 million, $76 million and $430 million, respectively.

The Company has determined the market-related value of retirement benefit plan assets by calculating the difference between the expected return and the actual return on the fair value of the plan assets, then amortizing the difference over future years – 0% in the first year and 25% in years two to five – and finally adding or subtracting the unamortized differences for the past four years from fair value. The method includes a 15% range around the fair value of such assets (i.e., 85% to 115% of fair value). If the market-related value is outside the 15% range, then the amount outside the range will be recognized immediately in the calculation of annual NPBC.

A primary goal of the plans is to achieve long-term asset growth sufficient to pay future benefit obligations at a reasonable level of risk. The investment policy target for defined benefit pension and OPEB plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by asset class, geographic region, market capitalization and investment style.

The weighted-average asset allocation of defined benefit retirement plans was as follows:

|  | Pension benefits | Other benefits
|  |  |  |  |  | Investment policy |  |  |  |  | Investment policy
December 31 |  | 2011 | 2010 | Target | Range | 2011 | 2010 | Target | Range
Asset category |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities |  | 68 | % | 71 | % | 70 | % | 65-75% |  | 69 | % | 70 | % | 70 | % | 65-75% |
Fixed income |  | 32 |  | 29 |  | 30 |  | 25-35% |  | 31 |  | 30 |  | 30 |  | 25-35% |
|  | 100 | % | 100 | % | 100 | % |  |  | 100 | % | 100 | % | 100 | % |  |

See Note 15 for additional disclosures about the fair value of the retirement benefit plans’ assets.

The following weighted-average assumptions were used in the accounting for the plans:

| Pension benefits | Other benefits
December 31 | 2011 | 2010 | 2009 | 2011 | 2010 | 2009
Benefit obligation Discount rate | 5.19% | 5.68% | 6.50% | 4.90% | 5.60% | 6.50%
Rate of compensation increase | 3.5 | 3.5 | 3.5 | NA | NA | NA
Net periodic benefit cost (years ended) Discount rate | 5.68 | 6.50 | 6.625 | 5.60 | 6.50 | 6.50
Expected return on plan assets | 8.00 | 8.25 | 8.25 | 8.00 | 8.25 | 8.25
Rate of compensation increase | 3.5 | 3.5 | 3.5 | NA | NA | 3.5

NA Not applicable

The Company based its selection of an assumed discount rate for 2012 NPBC and December 31, 2011 disclosure on a cash flow matching analysis that utilized bond information provided by Bloomberg for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2011. In selecting the expected rate of return on plan assets of 7.75% for 2012 NPBC, the Company considered economic forecasts for the types of investments held by the plans (primarily equity and fixed income investments), the Plans’ asset allocations and the past performance of the plans’ assets.

As of December 31, 2011, the assumed health care trend rates for 2012 and future years were as follows: medical, 8.5%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%. As of December 31,

26

2010, the assumed health care trend rates for 2011 and future years were as follows: medical, 9%, grading down to 5% for 2019 and thereafter; dental, 5%; and vision, 4%.

The components of NPBC were as follows:

|  | Pension benefits | Other benefits
(in thousands) |  | 2011 | 2010 | 2009 | 2011 | 2010 | 2009
Service cost |  | $33,627 |  | $27,576 |  | $24,577 |  | $4,238 |  | $4,584 |  | $4,699 |
Interest cost |  | 59,077 |  | 58,868 |  | 56,095 |  | 9,228 |  | 10,080 |  | 10,648 |
Expected return on plan assets |  | (61,615 | ) | (61,491 | ) | (50,838 | ) | (10,508 | ) | (10,960 | ) | (8,755 | )
Amortization of net transition obligation |  | – |  | – |  | – |  | (8 | ) | (8 | ) | 1,822 |
Amortization of net prior service gain |  | (747 | ) | (747 | ) | (747 | ) | (1,505 | ) | (409 | ) | (92 | )
Amortization of net actuarial loss |  | 15,752 |  | 7,300 |  | 14,697 |  | 212 |  | – |  | 381 |
Net periodic benefit cost |  | 46,094 |  | 31,506 |  | 43,784 |  | 1,657 |  | 3,287 |  | 8,703 |
Impact of PUC D&Os |  | (3,516 | ) | 10,207 |  | (10,570 | ) | 2,674 |  | 5,400 |  | (132 | )
Net periodic benefit cost (adjusted for impact of PUC D&Os) |  | $42,578 |  | $41,713 |  | $33,214 |  | $4,331 |  | $8,687 |  | $8,571 |

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefit pension plans that will be amortized from AOCI or regulatory assets into net periodic pension benefit cost during 2012 are $(0.7) million, $23.5 million and nil, respectively. The estimated prior service cost/(gain), net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI or regulatory assets into net periodic other than pension benefit cost during 2012 are $(1.8) million, $1.8 million and nil, respectively.

The Company recorded pension expense of $31 million, $32 million and $25 million and OPEB expense of $3 million, $7 million and $7 million each year in 2011, 2010 and 2009, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans and other benefit plans had ABO exceeding plan assets as of December 31, 2011 and December 31, 2010.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2011, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the accumulated postretirement benefit obligation (APBO) by $4.4 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the APBO by $5.0 million.

Defined contribution plans information. Changes to retirement benefits for employees commencing employment after April 30, 2011 include a reduction of benefits provided through the defined benefit plan and the addition of a 50% match by the applicable employer on the first 6% of employee deferrals through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan).

For 2011, the Company’s expense for its defined contribution pension plan under the HEIRSP Plan was de minimis.

11. Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil, diesel fuel and biodiesel for multi-year periods, some through December 31, 2014. Fossil fuel prices are tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast and the biodiesel price is tied to the market prices of animal fat feedstocks in the U.S. Midwest. Based on the average price per barrel as of December 31, 2011, the estimated cost of minimum purchases under the fuel supply contracts is $1.0 billion in 2012, $0.5 billion in 2013 and $0.3 billion in 2014. The actual cost of purchases in 2012 and future years could vary substantially from this estimate as a result of changes in market prices, quantities actually purchased and/or other factors. HECO and its subsidiaries purchased $1.3 billion, $1.0 billion and $0.7 billion of fuel under contractual agreements in 2011, 2010 and 2009, respectively.

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HECO and Chevron Products Company (Chevron), a division of Chevron USA, Inc., are parties to an amended contract for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on April 30, 2013.

HECO and Tesoro Hawaii Corporation (Tesoro) are parties to an amended LSFO supply contract (LSFO contract). The term of the amended agreement runs through April 30, 2013 and may automatically renew for annual terms thereafter unless earlier terminated by either party.

The energy charge for energy purchased from Kalaeloa under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for fuel oil under a Facility Fuel Supply Contract (fuel contract) between them. Kalaeloa and Tesoro have negotiated a proposed amendment to the pricing formula in their fuel contract. The amendment could result in higher fuel prices for Kalaeloa, which would in turn increase the energy charge paid by HECO to Kalaeloa. HECO consented to the amendment on September 7, 2010.

The costs incurred under the utilities’ fuel contracts are included in their respective ECACs, to the extent such costs are not recovered through the utilities’ base rates.

Power purchase agreements. As of December 31, 2011, HECO and its subsidiaries had six firm capacity PPAs for a total of 548 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $0.7 billion, $0.5 billion and $0.5 billion for 2011, 2010 and 2009, respectively. The PUC allows rate recovery for energy and firm capacity payments to IPPs under these agreements. Assuming that each of the agreements remains in place for its current term and the minimum availability criteria in the PPAs are met, aggregate minimum fixed capacity charges are expected to be approximately $0.1 billion per year for 2012 through 2016 and a total of $0.6 billion in the period from 2017 through 2030.

In general, HECO and its subsidiaries base their payments under the PPAs upon available capacity and actually supplied energy and they are generally not required to make payments for capacity if the contracted capacity is not available, and payments are reduced, under certain conditions, if available capacity drops below contracted levels. In general, the payment rates for capacity have been predetermined for the terms of the agreements. Energy payments will vary over the terms of the agreements. HECO and its subsidiaries pass on changes in the fuel component of the energy charges to customers through the ECAC in their rate schedules. HECO and its subsidiaries do not operate, or participate in the operation of, any of the facilities that provide power under the agreements. Title to the facilities does not pass to HECO or its subsidiaries upon expiration of the agreements, and the agreements do not contain bargain purchase options for the facilities.

Purchase power adjustment clause. The final decision and order (D&O) for the HECO 2009 test year rate case approved a purchased power adjustment clause (PPAC). HECO purchased power capacity, operation and maintenance (O&M) and other non-energy costs previously recovered through base rates are now recovered in the PPAC, and subject to approval by the PUC, such costs resulting from new purchased power agreements can be added to the PPAC outside of a rate case. Purchased energy costs will continue to be recovered through the ECAC to the extent they are not recovered through base rates. HELCO will also implement a PPAC pursuant to the final D&O issued in its 2010 test year rate case.

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

Renewable energy projects. HECO and its subsidiaries continue to negotiate with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave and others. This includes HECO’s plan to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a windfarm proposed to be built on the island of Lanai. The State and HECO are working together to ensure the supporting infrastructure needed is in place to reliably accommodate this large increment of wind power, including any required

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utility system connections or interfaces with the cable and the windfarm facility. In December 2009, the PUC allowed HECO to defer the costs of studies for this large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million for the stage 1 studies through the REIP surcharge. Additionally, in July 2011, the PUC directed HECO to file a draft Request for Proposal (RFP) for 200 MW or more of renewable energy to be delivered to Oahu from any of the Hawaiian islands. In October 2011, HECO filed the draft RFP with the PUC. In November 2011, HECO and MECO filed their application to seek PUC approval to defer for later recovery approximately $0.6 million for additional studies to address whether an inter-island cable system that ties the Oahu, Maui, Molokai and Lanai electrical systems would be operationally beneficial and cost-effective.

Interim increases. As of December 31, 2011, HECO and its subsidiaries had recognized $40 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

Major projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. 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 by the Consumer Advocate in HECO’s 2009 test year rate case, the PUC ordered independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project (EOTP), Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) project, and Customer Information System Project. The PUC confirmed that any revenue requirements arising from project costs being audited shall either remain interim and subject to refund until audit completion, or remain within regulatory deferral accounts. In the Interim D&O in the 2011 test year rate case, issued in July 2011, the PUC approved the portion of the settlement agreement in that proceeding allowing HECO to defer the portion of costs that are in excess of the prior PUC approved amounts and related depreciation for HECO’s EOTP Phase 1 ($43 million) and the CIP CT-1 project ($32 million) until completion of an independently conducted regulatory audit. In the interim order in HECO’s 2011 test year rate case, the PUC approved the accrual of a carrying charge on the cost of such projects not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory audits are completed and allowed the remaining project costs that were not deferred to be included in electric rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates. The PUC did not approve the agreement to defer expenses (subject to a limit to which the parties had agreed) associated with the yet-to-be completed Customer Information System. Pursuant to the PUC’s order in HECO’s 2009 test year rate case, HECO and the Consumer Advocate submitted proposals for the scope, timing, management and structure for the regulatory audits for the PUC’s review and consideration, however, the PUC has not yet issued a schedule or requirements for the regulatory audits.

Campbell Industrial Park combustion turbine No. 1 and transmission line. HECO’s incurred costs for this project, which was placed in service in 2009, were $195 million, including $9 million of AFUDC. HECO’s current rates reflect recovery of project costs of $163 million. See “Major projects” above regarding the regulatory audit process that must be completed in connection with determining recovery of the remaining costs for this project. Management believes no adjustment to project costs is required as of December 31, 2011.

East Oahu Transmission Project. 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 2007, the PUC approved HECO’s request to expend funds for a revised EOTP using different routes requiring the construction of subtransmission lines in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2), but did not address the

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issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs.

Phase 1 was placed in service on June 29, 2010. As of December 31, 2011, HECO’s incurred costs for Phase 1 of this project was $59 million (as a result of higher costs and the project delays), including (i) $12 million of pre-2003 planning and permitting costs, (ii) $24 million of planning, permitting and construction costs incurred after the denial of the permit and (iii) $23 million for AFUDC. The interim D&O issued in HECO’s 2011 test year rate case reflects approximately $16 million of EOTP Phase 1 costs and related depreciation expense in determining revenue requirements. See “Major projects” above regarding the regulatory audit that is to be conducted before the PUC determines the recoverability of the remaining costs for EOTP Phase 1.

On February 3, 2012, HECO, the Consumer Advocate and the Department of Defense (parties in the HECO 2011 test year rate case proceeding) signed a settlement agreement, subject to PUC approval, regarding the EOTP Phase 1 project costs. The parties agreed that, in lieu of a regulatory audit, HECO would write-off $9.5 million of gross plant in service costs associated with EOTP Phase 1, and associated adjustments in the accumulated depreciation, deferred depreciation expense, accumulated deferred income taxes, unamortized state investment tax credits and carrying charges. In deciding to enter into the agreement HECO took into account a number of considerations, including (1) the significant passage of time since the initial costs for the EOTP Phase 1 project were incurred, (2) the significant resources that would be required by the PUC, HECO and the other parties to conduct a fair and meaningful regulatory audit of project costs, and (3) additional carrying charges that would be accrued to the project cost during a lengthy audit process. The settlement agreement does not address the costs that are being deferred in connection with the CIP CT-1 project or the Customer Information System Project.

The settlement agreement resulted in an after-tax charge to net income in the fourth quarter of 2011 of approximately $6 million. The parties agreed to stipulate, subject to PUC approval, to an additional annual interim increase of $5 million to be effective March 1, 2012, based on additional revenue requirements reflecting all remaining EOTP costs not previously included in rates or agreed to be written off (an increase of approximately $31 million to rate base) and offset by other minor adjustments to the interim increase that became effective on July 26, 2011. The agreement allows HECO to continue to defer depreciation expense and accrue carrying charges related to the costs not yet included in rates. For accounting purposes, HECO will recognize the equity portion of the carrying charge when it is allowed in electric rates.

In April 2010, HECO proposed a modification of Phase 2 of the EOTP 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 December 31, 2011, HECO’s incurred costs for the Modified Phase 2 project amounted to $8 million (total cost $11 million less $3 million received in Smart Grid Investment funding). Management believes no adjustment to project costs of EOTP Phase 1 or Modified Phase 2 is required as of December 31, 2011.

Customer Information System Project. In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million (including $18 million for capital and deferred costs) for a new Customer Information System (CIS), provided that no part of the project costs may be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.

The CIS project is proceeding with the implementation of a new software system. As of December 31, 2011, HECO’s total deferred and capital cost estimate for the CIS was $57 million (of which $43 million was recorded). The PUC has ordered that this project undergo a regulatory audit, which likely will not be planned until the CIS project is complete and the CIS is operational. Management believes no adjustment to CIS project costs is required as of December 31, 2011.

Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative, regulatory and governmental

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

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at HECO’s 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 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.

On December 21, 2011, the EPA issued the final rule establishing the EPA’s National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs). The final rule, known as the Mercury and Air Toxics Standards (MATS), applies to the 14 EGUs at HECO’s Honolulu, Kahe and Waiau power plants. MATS establishes the Maximum Achievable Control Technology standards for the control of hazardous air pollutants emissions from new and existing EGUs. The final rule is under review and a compliance plan and schedule are under development. Depending on the specifics of the compliance plan, MATS may require significant capital and annual expenditures for the installation and operation of emission control equipment on HECO’s EGUs. The CAA requires that facilities come into compliance with the MATS limits within 3 years of the final rule, although facilities may be granted two 1-year extensions to install emission control technology. In view of the isolated nature of HECO’s electrical system and the potential requirement to install control equipment on all HECO EGUs while maintaining system reliability, the MATS compliance schedule poses a significant challenge to HECO.

Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the specifics of the MATS compliance plan, the tightening of the National Ambient Air Quality Standards, and the Regional Haze rule under the CAA, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs, but such amounts are not determinable at this time. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire 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, HECO and its subsidiaries believe the costs of responding to their releases identified to date will not have a material adverse effect, individually or in the aggregate, on its consolidated results of operations, financial condition or liquidity.

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

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The Company is 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 its GHG emissions, such as those being implemented under the Energy Agreement. Because the regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the Company, but compliance costs could be significant.

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

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

I n 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 stationary source

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facilities. States may need to increase fees to cover the increased level of activity caused by this rule. E ffective January 2, 2011, under the Prevention of Significant Deterioration program, permitting 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 DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generation units, and testing biofuel blends in other HECO and MECO generating units. M anagement is unable to evaluate the ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the Company’s carbon footprint and meeting GHG reduction goals that will ultimately emerge.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the Company. For example, severe weather could cause significant harm to the Company’s physical facilities.

Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on its earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials. In September 2009, HECO recorded an estimated ARO of $23 million related to removing retired generating units at its Honolulu power plant, including abating asbestos and lead-based paint. The obligation was subsequently increased in June 2010, due to an increase in the estimated costs of the removal project. In August 2010, HECO recorded a similar estimated ARO of $12 million related to removing retired generating units at HECO’s Waiau power plant.

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

(in thousands) |  | 2011 | 2010
Balance, January 1 |  | $ 48,630 |  | $ 23,746 |
Accretion expense |  | 2,202 |  | 2,519 |
Liabilities incurred |  | 256 |  | 11,949 |
Liabilities settled |  | (835 | ) | (725 | )
Revisions in estimated cash flows |  | 618 |  | 11,141 |
Balance, December 31 |  | $ 50,871 |  | $ 48,630 |

Collective bargaining agreements. As of December 31, 2011, approximately 53% of the Company’s employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the Company. On March 11, 2011, the utilities’ bargaining unit employees ratified a new collective bargaining agreement and a new benefit agreement. The new collective bargaining agreement covers a term from January 1, 2011 to October 31, 2013 and provides for non-compounded wage increases (1.75%, 2.5%, and 3.0% for 2011, 2012 and 2013, respectively). The new benefit agreement covers a term from January 1, 2011 to October 31, 2014 and includes changes to medical, dental and vision plans with increased employee contributions and changes to retirement benefits for employees.

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12. Regulatory restrictions on distributions to parent

As of December 31, 2011, net assets (assets less liabilities and preferred stock) of approximately $588 million were not available for transfer to HEI in the form of dividends, loans or advances without regulatory approval.

13. Related-party transactions

HEI charged HECO and its subsidiaries $4.9 million, $5.0 million and $4.5 million for general management and administrative services in 2011, 2010 and 2009, respectively. The amounts charged by HEI to its subsidiaries are allocated primarily on the basis of actual labor hours expended in providing such services.

HECO’s short-term borrowings from HEI fluctuate during the year, and totaled nil at December 31, 2011 and 2010. The interest charged on short-term borrowings from HEI is based on the lower of HEI’s or HECO’s effective weighted average short-term external borrowing rate. If both HEI and HECO do not have short-term external borrowings, the interest is based on the average of the effective rate for 30-day dealer-placed commercial paper quoted by the Wall Street Journal.

Borrowings among HECO and its subsidiaries are eliminated in consolidation. Interest charged by HEI to HECO was de minimis in 2011, nil in 2010 and $0.2 million in 2009.

14. Significant group concentrations of credit risk

HECO and its utility subsidiaries are regulated operating electric public utilities engaged in the generation, purchase, transmission, distribution and sale of electricity on the islands of Oahu, Hawaii, Maui, Lanai and Molokai in the State of Hawaii. HECO and its utility subsidiaries provide the only electric public utility service on the islands they serve. HECO and its utility subsidiaries grant credit to customers, all of whom reside or conduct business in the State of Hawaii.

15. 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 but have not been considered in making such estimates.

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

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

Level 2: Inputs to the valuation methodology include quoted prices for similar assets or liabilities in active markets; inputs to the valuation methodology include quoted prices for identical or similar assets or liabilities in markets that are not active; or inputs to the valuation methodology that

33

are derived principally from or can be corroborated by observable market data by correlation or other means.

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

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

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 estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and 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 certain of the Company’s financial instruments were as follows:

December 31 |  | 2011 | 2010
(in thousands) |  | Carrying amount | Estimated fair value | Carrying amount | Estimated fair value
Financial assets: |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $48,806 |  | $48,806 |  | $122,936 |  | $122,936 |
Financial liabilities: |  |  |  |  |  |  |  |  |
Long-term debt, net, including amounts due within one year |  | 1,058,070 |  | 1,095,133 |  | 1,057,942 |  | 1,020,550 |
Off-balance sheet item: |  |  |  |  |  |  |  |  |
HECO-obligated preferred securities of trust subsidiary |  | 50,000 |  | 50,000 |  | 50,000 |  | 52,500 |

Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of AROs (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 11).

34

Retirement benefit plans.

Assets held in various trusts for the retirement benefit plans (Plans) are measured at fair value on a recurring basis (including items that are required to be measured at fair value and items for which the fair value option has been elected) and were as follows:

|  | Pension benefits | Other benefits
|  |  |  | Fair value measurements using |  |  | Fair value measurements using
|  |  |  | Quoted prices in active markets for identical assets |  | Significant other observable inputs |  | Significant unobserv- able inputs |  |  |  | Quoted prices in active markets for identical assets |  | Significant other observable inputs |  | Significant unobserv- able inputs |
(in millions) |  | December 31 |  | (Level 1) |  | (Level 2) |  | (Level 3) |  | December 31 |  | (Level 1) |  | (Level 2) |  | (Level 3) |
2011 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities |  | $425 |  | $425 |  | $ – |  | $ – |  | $ 73 |  | $ 73 |  | $ – |  | $ – |
Equity index funds |  | 82 |  | 82 |  | – |  | – |  | 15 |  | 15 |  | – |  | – |
Fixed income securities |  | 283 |  | 98 |  | 185 |  | – |  | 43 |  | 37 |  | 6 |  | – |
Pooled and mutual funds |  | 87 |  | 1 |  | 86 |  | – |  | 13 |  | – |  | 13 |  | – |
Total |  | 877 |  | $606 |  | $271 |  | $ – |  | 144 |  | $125 |  | $ 19 |  | $ – |
Receivables and payables, net |  | (37) |  |  |  |  |  |  |  | (1) |  |  |  |  |  |  |
Fair value of plan assets |  | $840 |  |  |  |  |  |  |  | $143 |  |  |  |  |  |  |
2010 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity securities |  | $453 |  | $453 |  | $ – |  | $ – |  | $ 80 |  | $ 80 |  | $ – |  | $ – |
Equity index funds |  | 80 |  | 80 |  | – |  | – |  | 14 |  | 14 |  | – |  | – |
Fixed income securities |  | 238 |  | 55 |  | 183 |  | – |  | 8 |  | 2 |  | 6 |  | – |
Pooled and mutual funds |  | 78 |  | 9 |  | 69 |  | – |  | 49 |  | 39 |  | 10 |  | – |
Total |  | 849 |  | $597 |  | $252 |  | $ – |  | 151 |  | $135 |  | $ 16 |  | $ – |
Receivables and payables, net |  | (17) |  |  |  |  |  |  |  | – |  |  |  |  |  |  |
Fair value of plan assets |  | $832 |  |  |  |  |  |  |  | $151 |  |  |  |  |  |  |

The fair values of the financial instruments shown in the table above represent the Company’s best estimates of the amounts that would be received upon sale of those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Those fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects the Company’s judgments about the assumptions that market participants would use in pricing the asset or liability. Those judgments are developed by the Company based on the best information available in the circumstances.

In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of ASU No. 2009-12, “Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent),” which allows for the estimation of the fair value of investments in investment companies for which the investment does not have a readily determinable fair value, using net asset value per share or its equivalent as a practical expedient.

The Company used the following valuation methodologies for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2011 and 2010.

Equity securities, equity index funds, U.S. Treasury fixed income securities and public mutual funds (Level 1). Valued at the closing price reported on the active market on which the individual securities are traded or the published net asset value (NAV) of the fund.

Fixed income securities, equity securities, pooled securities and mutual funds (Level 2). Fixed income securities, other than those issued by the U.S. Treasury, are valued based on yields currently available on comparable securities of issuers with similar credit ratings. Equity securities and pooled and mutual funds include commingled equity funds and other closed funds, respectively, that are not open to public investment and are

35

valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses.

Other (Level 3). The venture capital and limited partnership interests are valued at historical cost, modified by revaluation of financial assets and financial liabilities at fair value through profit or loss.

For 2011 and 2010, the changes in Level 3 assets were as follows:

| 2011 | 2010
(in thousands) | Pension benefits | Other benefits | Pension benefits | Other benefits
Balance, January 1 | $141 | $ 5 | $ 67,420 | $ 13,703
Realized and unrealized gains | 92 | 3 | 6,650 | 1,445
Purchases and settlements, net | (16) | (1) | (317) | (3,854)
Transfer in or out of Level 3 | – | – | (73,612) | (11,289)
Balance, December 31 | $217 | $ 7 | $ 141 | $ 5

16. Consolidating financial information (unaudited)

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 3 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.

36

Consolidating balance sheet

| December 31, 2011
(in thousands) | HECO | HELCO | MECO | RHI | UBC | Reclassi- fications and Elimina- tions |  | HECO Consolidated
Assets |  |  |  |  |  |  |  |
Utility plant, at cost |  |  |  |  |  |  |  |
Land | $ 43,316 | 5,182 | 3,016 | – | – | – |  | $ 51,514
Plant and equipment | 3,091,908 | 1,048,599 | 911,520 | – | – | – |  | 5,052,027
Less accumulated depreciation | (1,141,839) | (414,769) | (410,286) | – | – | – |  | (1,966,894)
Construction in progress | 117,625 | 8,144 | 13,069 | – | – | – |  | 138,838
Net utility plant | 2,111,010 | 647,156 | 517,319 | – | – | – |  | 3,275,485
Investment in wholly owned subsidiaries, at equity | 517,216 | – | – | – | – | (517,216) | [2] | –
Current assets |  |  |  |  |  |  |  |
Cash and equivalents | 44,819 | 3,383 | 496 | 82 | 26 | – |  | 48,806
Advances to affiliates | – | 46,150 | 18,500 | – | – | (64,650) | [1] | –
Customer accounts receivable, net | 130,190 | 28,602 | 24,536 | – | – | – |  | 183,328
Accrued unbilled revenues, net | 103,328 | 18,499 | 15,999 | – | – | – |  | 137,826
Other accounts receivable, net | 8,987 | 1,186 | 3,008 | – | – | (4,558) | [1] | 8,623
Fuel oil stock, at average cost | 128,037 | 19,217 | 24,294 | – | – | – |  | 171,548
Materials & supplies, at average cost | 25,096 | 4,700 | 13,392 | – | – | – |  | 43,188
Prepayments and other | 21,135 | 6,575 | 7,033 | – | – | (141) | [3] | 34,602
Regulatory assets | 18,038 | 1,115 | 1,130 | – | – | – |  | 20,283
Total current assets | 479,630 | 129,427 | 108,388 | 82 | 26 | (69,349) |  | 648,204
Other long-term assets |  |  |  |  |  |  |  |
Regulatory assets | 478,851 | 86,394 | 83,861 | – | – | – |  | 649,106
Unamortized debt expense | 8,446 | 2,464 | 1,876 | – | – | – |  | 12,786
Other | 58,672 | 11,843 | 15,846 | – | – | – |  | 86,361
Total other long-term assets | 545,969 | 100,701 | 101,583 | – | – | – |  | 748,253
| $ 3,653,825 | 877,284 | 727,290 | 82 | 26 | (586,565) |  | $ 4,671,942
Capitalization and liabilities |  |  |  |  |  |  |  |
Capitalization |  |  |  |  |  |  |  |
Common stock equity | $ 1,406,084 | 281,055 | 236,054 | 81 | 26 | (517,216) | [2] | $ 1,406,084
Cumulative preferred stock–not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | – | – | – |  | 34,293
Long-term debt, net | 629,757 | 204,110 | 166,703 | – | – | – |  | 1,000,570
Total capitalization | 2,058,134 | 492,165 | 407,757 | 81 | 26 | (517,216) |  | 2,440,947
Current liabilities |  |  |  |  |  |  |  |
Current portion of long-term debt | 42,580 | 7,200 | 7,720 | – | – | – |  | 57,500
Short-term borrowings-affiliate | 64,650 | – | – | – | – | (64,650) | [1] | –
Accounts payable | 140,044 | 29,616 | 18,920 | – | – | – |  | 188,580
Interest and preferred dividends payable | 12,648 | 4,074 | 2,762 | – | – | (1) | [1] | 19,483
Taxes accrued | 152,315 | 37,638 | 34,956 | – | – | (141) | [3] | 224,768
Other | 50,828 | 9,478 | 13,603 | 1 | – | (4,557) | [1] | 69,353
Total current liabilities | 463,065 | 88,006 | 77,961 | 1 | – | (69,349) |  | 559,684
Deferred credits and other liabilities |  |  |  |  |  |  |  |
Deferred income taxes | 236,890 | 61,044 | 39,929 | – | – | – |  | 337,863
Regulatory liabilities | 215,401 | 62,049 | 38,016 | – | – | – |  | 315,466
Unamortized tax credits | 34,877 | 12,951 | 12,786 | – | – | – |  | 60,614
Retirement benefits liability | 368,245 | 62,036 | 64,840 | – | – | – |  | 495,121
Other | 72,418 | 22,391 | 11,235 | – | – | – |  | 106,044
Total deferred credits and other liabilities | 927,831 | 220,471 | 166,806 | – | – | – |  | 1,315,108
Contributions in aid of construction | 204,795 | 76,642 | 74,766 | – | – | – |  | 356,203
| $ 3,653,825 | 877,284 | 727,290 | 82 | 26 | (586,565) |  | $ 4,671,942

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Consolidating balance sheet

| December 31, 2010
(in thousands) | HECO | HELCO | MECO | RHI | UBC | Reclassi- fications and Elimina- tions |  | HECO Consolidated
Assets |  |  |  |  |  |  |  |
Utility plant, at cost |  |  |  |  |  |  |  |
Land | $ 43,240 | 5,108 | 3,016 | – | – | – |  | $ 51,364
Plant and equipment | 2,984,887 | 1,030,520 | 881,567 | – | – | – |  | 4,896,974
Less accumulated depreciation | (1,134,423) | (408,704) | (397,932) | – | – | – |  | (1,941,059)
Construction in progress | 78,934 | 9,828 | 12,800 | – | – | – |  | 101,562
Net utility plant | 1,972,638 | 636,752 | 499,451 | – | – | – |  | 3,108,841
Investment in wholly owned subsidiaries, at equity | 500,801 | – | – | – | – | (500,801) | [2] | –
Current assets |  |  |  |  |  |  |  |
Cash and equivalents | 121,019 | 1,229 | 594 | 89 | 5 | – |  | 122,936
Advances to affiliates | – | 30,950 | 29,500 | – | – | (60,450) | [1] | –
Customer accounts receivable, net | 93,474 | 23,484 | 21,213 | – | – | – |  | 138,171
Accrued unbilled revenues, net | 71,712 | 16,018 | 16,654 | – | – | – |  | 104,384
Other accounts receivable, net | 11,536 | 3,319 | 668 | – | – | (6,147) | [1] | 9,376
Fuel oil stock, at average cost | 121,280 | 15,751 | 15,674 | – | – | – |  | 152,705
Materials & supplies, at average cost | 18,890 | 4,498 | 13,329 | – | – | – |  | 36,717
Prepayments and other | 36,974 | 9,825 | 8,417 | – | – | – |  | 55,216
Regulatory assets | 5,294 | 1,064 | 991 | – | – | – |  | 7,349
Total current assets | 480,179 | 106,138 | 107,040 | 89 | 5 | (66,597) |  | 626,854
Other long-term assets |  |  |  |  |  |  |  |
Regulatory assets | 352,038 | 61,051 | 57,892 | – | – | – |  | 470,981
Unamortized debt expense | 9,240 | 2,681 | 2,109 | – | – | – |  | 14,030
Other | 41,236 | 8,257 | 15,481 | – | – | – |  | 64,974
Total other long-term assets | 402,514 | 71,989 | 75,482 | – | – | – |  | 549,985
| $ 3,356,132 | 814,879 | 681,973 | 89 | 5 | (567,398) |  | $ 4,285,680
Capitalization and liabilities |  |  |  |  |  |  |  |
Capitalization |  |  |  |  |  |  |  |
Common stock equity | $ 1,337,398 | 270,573 | 230,137 | 86 | 5 | (500,801) | [2] | $ 1,337,398
Cumulative preferred stock–not subject to mandatory redemption | 22,293 | 7,000 | 5,000 | – | – | – |  | 34,293
Long-term debt, net | 672,268 | 211,279 | 174,395 | – | – | – |  | 1,057,942
Total capitalization | 2,031,959 | 488,852 | 409,532 | 86 | 5 | (500,801) |  | 2,429,633
Current liabilities |  |  |  |  |  |  |  |
Short-term borrowings-affiliate | 60,450 | – | – | – | – | (60,450) | [1] | –
Accounts payable | 135,739 | 22,888 | 20,332 | – | – | – |  | 178,959
Interest and preferred dividends payable | 13,648 | 4,196 | 2,762 | – | – | (3) | [1] | 20,603
Taxes accrued | 116,840 | 31,229 | 27,891 | – | – | – |  | 175,960
Other | 35,784 | 13,065 | 13,646 | 3 | – | (6,144) | [1] | 56,354
Total current liabilities | 362,461 | 71,378 | 64,631 | 3 | – | (66,597) |  | 431,876
Deferred credits and other liabilities |  |  |  |  |  |  |  |
Deferred income taxes | 198,753 | 44,971 | 25,562 | – | – | – |  | 269,286
Regulatory liabilities | 201,587 | 56,190 | 39,020 | – | – | – |  | 296,797
Unamortized tax credits | 33,661 | 12,857 | 12,292 | – | – | – |  | 58,810
Retirement benefits liability | 271,499 | 39,811 | 44,534 | – | – | – |  | 355,844
Other | 66,898 | 28,739 | 12,433 | – | – | – |  | 108,070
Total deferred credits and other liabilities | 772,398 | 182,568 | 133,841 | – | – | – |  | 1,088,807
Contributions in aid of construction | 189,314 | 72,081 | 73,969 | – | – | – |  | 335,364
| $ 3,356,132 | 814,879 | 681,973 | 89 | 5 | (567,398) |  | $ 4,285,680

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Consolidating statement of income

| Year ended December 31, 2011
(in thousands) | HECO | HELCO | MECO | RHI | UBC | Reclassi- fications and Elimina- tions |  | HECO Consolidated
Operating revenues | $2,110,249 | 444,266 | 419,249 | – | – | – |  | $2,973,764
Operating expenses |  |  |  |  |  |  |  |
Fuel oil | 909,172 | 121,839 | 234,115 | – | – | – |  | 1,265,126
Purchased power | 522,503 | 137,453 | 29,696 | – | – | – |  | 689,652
Other operation | 183,633 | 36,318 | 37,114 | – | – | – |  | 257,065
Maintenance | 81,583 | 19,668 | 19,968 | – | – | – |  | 121,219
Depreciation | 89,324 | 32,767 | 20,884 | – | – | – |  | 142,975
Taxes, other than income taxes | 196,170 | 41,028 | 39,306 | – | – | – |  | 276,504
Income taxes | 37,652 | 16,863 | 11,473 | – | – | – |  | 65,988
| 2,020,037 | 405,936 | 392,556 | – | – | – |  | 2,818,529
Operating income | 90,212 | 38,330 | 26,693 | – | – | – |  | 155,235
Other income (deductions) |  |  |  |  |  |  |  |
Allowance for equity funds used during construction | 4,572 | 592 | 800 | – | – | – |  | 5,964
Equity in earnings of subsidiaries | 44,616 | – | – | – | – | (44,616) | [2] | –
Impairment of utility plant | (5,496) | – | – | – | – | – |  | (5,496)
Other, net | 2,845 | 569 | 433 | (5) | (4) | (27) | [1] | 3,811
| 46,537 | 1,161 | 1,233 | (5) | (4) | (44,643) |  | 4,279
Interest and other charges |  |  |  |  |  |  |  |
Interest on long-term debt | 36,522 | 11,938 | 9,072 | – | – | – |  | 57,532
Amortization of net bond premium and expense | 2,023 | 554 | 504 | – | – | – |  | 3,081
Other interest charges | (921) | 62 | 304 | – | – | (27) | [1] | (582)
Allowance for borrowed funds used during construction | (1,941) | (248) | (309) | – | – | – |  | (2,498)
| 35,683 | 12,306 | 9,571 | – | – | (27) |  | 57,533
Net income (loss) | 101,066 | 27,185 | 18,355 | (5) | (4) | (44,616) |  | 101,981
Preferred stock of subsidiaries | – | 534 | 381 | – | – | – |  | 915
Net income (loss) attributable to HECO | 101,066 | 26,651 | 17,974 | (5) | (4) | (44,616) |  | 101,066
Preferred stock dividends of HECO | 1,080 | – | – | – | – | – |  | 1,080
Net income (loss) for common stock | $ 99,986 | 26,651 | 17,974 | (5) | (4) | (44,616) |  | $ 99,986

39

Consolidating statement of income

| Year ended December 31, 2010
(in thousands) | HECO | HELCO | MECO | RHI | UBC | Reclassi- fications and Elimina- tions |  | HECO Consolidated
Operating revenues | $1,649,608 | 372,633 | 345,200 | – | – | – |  | $2,367,441
Operating expenses |  |  |  |  |  |  |  |
Fuel oil | 631,159 | 93,480 | 175,769 | – | – | – |  | 900,408
Purchased power | 412,382 | 113,031 | 23,387 | – | – | – |  | 548,800
Other operation | 180,095 | 34,273 | 36,659 | – | – | – |  | 251,027
Maintenance | 76,792 | 23,800 | 26,895 | – | – | – |  | 127,487
Depreciation | 86,932 | 36,483 | 26,293 | – | – | – |  | 149,708
Taxes, other than income taxes | 155,084 | 34,664 | 32,369 | – | – | – |  | 222,117
Income taxes | 32,307 | 10,341 | 5,405 | – | – | – |  | 48,053
| 1,574,751 | 346,072 | 326,777 | – | – | – |  | 2,247,600
Operating income | 74,857 | 26,561 | 18,423 | – | – | – |  | 119,841
Other income |  |  |  |  |  |  |  |
Allowance for equity funds used during construction | 4,956 | 507 | 553 | – | – | – |  | 6,016
Equity in earnings of subsidiaries | 25,600 | – | – | – | – | (25,600) | [2] | –
Other, net | 9,190 | 2,356 | 231 | (8) | (12) | (78) | [1] | 11,679
| 39,746 | 2,863 | 784 | (8) | (12) | (25,678) |  | 17,695
Interest and other charges |  |  |  |  |  |  |  |
Interest on long-term debt | 36,522 | 11,938 | 9,072 | – | – | – |  | 57,532
Amortization of net bond premium and expense | 1,942 | 537 | 496 | – | – | – |  | 2,975
Other interest charges | 553 | 65 | 463 | – | – | (78) | [1] | 1,003
Allowance for borrowed funds used during construction | (2,083) | (258) | (217) | – | – | – |  | (2,558)
| 36,934 | 12,282 | 9,814 | – | – | (78) |  | 58,952
Net income (loss) | 77,669 | 17,142 | 9,393 | (8) | (12) | (25,600) |  | 78,584
Preferred stock of subsidiaries | – | 534 | 381 | – | – | – |  | 915
Net income (loss) attributable to HECO | 77,669 | 16,608 | 9,012 | (8) | (12) | (25,600) |  | 77,669
Preferred stock dividends of HECO | 1,080 | – | – | – | – | – |  | 1,080
Net income (loss) for common stock | $ 76,589 | 16,608 | 9,012 | (8) | (12) | (25,600) |  | $ 76,589

40

Consolidating statement of income

| Year ended December 31, 2009
(in thousands) | HECO | HELCO | MECO | RHI | UBC | Reclassi- fications and Elimina- tions |  | HECO Consolidated
Operating revenues | $1,384,885 | 343,943 | 297,844 | – | – | – |  | $2,026,672
Operating expenses |  |  |  |  |  |  |  |
Fuel oil | 460,070 | 74,403 | 137,497 | – | – | – |  | 671,970
Purchased power | 367,110 | 112,640 | 20,054 | – | – | – |  | 499,804
Other operation | 174,573 | 36,998 | 36,944 | – | – | – |  | 248,515
Maintenance | 65,910 | 21,391 | 20,230 | – | – | – |  | 107,531
Depreciation | 82,031 | 33,005 | 29,497 | – | – | – |  | 144,533
Taxes, other than income taxes | 131,367 | 32,219 | 28,113 | – | – | – |  | 191,699
Income taxes | 32,538 | 9,527 | 6,147 | – | – | – |  | 48,212
| 1,313,599 | 320,183 | 278,482 | – | – | – |  | 1,912,264
Operating income | 71,286 | 23,760 | 19,362 | – | – | – |  | 114,408
Other income |  |  |  |  |  |  |  |
Allowance for equity funds used during construction | 9,945 | 1,621 | 656 | – | – | – |  | 12,222
Equity in earnings of subsidiaries | 25,825 | – | – | – | – | (25,825) | [2] | –
Other, net | 6,591 | 1,126 | 350 | (11) | (149) | (420) | [1] | 7,487
| 42,361 | 2,747 | 1,006 | (11) | (149) | (26,245) |  | 19,709
Interest and other charges |  |  |  |  |  |  |  |
Interest on long-term debt | 33,109 | 9,639 | 9,072 | – | – | – |  | 51,820
Amortization of net bond premium and expense | 2,174 | 602 | 478 | – | – | – |  | 3,254
Other interest charges | 2,135 | 673 | 482 | – | – | (420) | [1] | 2,870
Allowance for borrowed funds used during construction | (4,297) | (702) | (269) | – | – | – |  | (5,268)
| 33,121 | 10,212 | 9,763 | – | – | (420) |  | 52,676
Net income (loss) | 80,526 | 16,295 | 10,605 | (11) | (149) | (25,825) |  | 81,441
Preferred stock dividends of subsidiaries | – | 534 | 381 | – | – | – |  | 915
Net income (loss) attributable to HECO | 80,526 | 15,761 | 10,224 | (11) | (149) | (25,825) |  | 80,526
Preferred stock dividends of HECO | 1,080 | – | – | – | – | – |  | 1,080
Net income (loss) for common stock | $ 79,446 | 15,761 | 10,224 | (11) | (149) | (25,825) |  | $ 79,446

41

Consolidating Statements of Changes in Common Stock Equity

(in thousands) |  | HECO |  | HELCO |  | MECO |  | RHI |  | UBC |  | Reclassi- fications and Elimina- tions |  | HECO Consoli- dated |
Balance, December 31, 2008 |  | $1,188,842 |  | 221,405 |  | 215,382 |  | 105 |  | 141 |  | (437,033 | ) | $1,188,842 |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) for common stock |  | 79,446 |  | 15,761 |  | 10,224 |  | (11 | ) | (149 | ) | (25,825 | ) | 79,446 |
Retirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net transition asset arising during the period, net of taxes of $4,172 |  | 6,549 |  | – |  | – |  | – |  | – |  | – |  | 6,549 |
Prior service credit arising during the period, net of taxes of $922 |  | 1,446 |  | – |  | – |  | – |  | – |  | – |  | 1,446 |
Net gains arising during the period, net of taxes of $36,990 |  | 58,081 |  | 9,942 |  | 6,928 |  | – |  | – |  | (16,870 | ) | 58,081 |
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $6,250 |  | 9,811 |  | 1,601 |  | 1,325 |  | – |  | – |  | (2,926 | ) | 9,811 |
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $48,251 |  | (75,756 | ) | (11,531 | ) | (8,276 | ) | – |  | – |  | 19,807 |  | (75,756 | )
Comprehensive income (loss) |  | 79,577 |  | 15,773 |  | 10,201 |  | (11 | ) | (149 | ) | (25,814 | ) | 79,577 |
Issuance of common stock, net of expenses |  | 92,989 |  | 3,398 |  | – |  | – |  | 25 |  | (3,423 | ) | 92,989 |
Common stock dividends |  | (55,000 | ) | – |  | (4,264 | ) | – |  | – |  | 4,264 |  | (55,000 | )
Balance, December 31, 2009 |  | 1,306,408 |  | 240,576 |  | 221,319 |  | 94 |  | 17 |  | (462,006 | ) | 1,306,408 |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) for common stock |  | 76,589 |  | 16,608 |  | 9,012 |  | (8 | ) | (12 | ) | (25,600 | ) | 76,589 |
Retirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Prior service credit arising during the period, net of taxes of $3,001 |  | 4,712 |  | 2,679 |  | 2,033 |  | – |  | – |  | (4,712 | ) | 4,712 |
Net gains arising during the period, net of tax benefits of $27,408 |  | (43,031 | ) | (6,131 | ) | (5,601 | ) | – |  | – |  | 11,732 |  | (43,031 | )
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $2,387 |  | 3,747 |  | 759 |  | 566 |  | – |  | – |  | (1,325 | ) | 3,747 |
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $21,336 |  | 33,499 |  | 2,617 |  | 2,959 |  | – |  | – |  | (5,576 | ) | 33,499 |
Comprehensive income (loss) |  | 75,516 |  | 16,532 |  | 8,969 |  | (8 | ) | (12 | ) | (25,481 | ) | 75,516 |
Issuance of common stock, net of expenses |  | 4,243 |  | 22,948 |  | 2,850 |  | – |  | – |  | (25,798 | ) | 4,243 |
Common stock dividends |  | (48,769 | ) | (9,483 | ) | (3,001 | ) | – |  | – |  | 12,484 |  | (48,769 | )
Balance, December 31, 2010 |  | $1,337,398 |  | 270,573 |  | 230,137 |  | 86 |  | 5 |  | (500,801 | ) | $1,337,398 |
Comprehensive income: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) for common stock |  | 99,986 |  | 26,651 |  | 17,974 |  | (5 | ) | (4 | ) | (44,616 | ) | 99,986 |
Retirement benefit plans: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Prior service credit arising during the period, net of taxes of $4,408 |  | 6,921 |  | 1,419 |  | 1,239 |  | – |  | – |  | (2,658 | ) | 6,921 |
Net gains arising during the period, net of tax benefits of $74,346 |  | (116,726 | ) | (18,224 | ) | (16,816 | ) | – |  | – |  | 35,040 |  | (116,726 | )
Less: amortization of transition obligation, prior service credit and net losses recognized during the period in net periodic benefit cost, net of tax benefits of $5,332 |  | 8,372 |  | 1,324 |  | 1,158 |  | – |  | – |  | (2,482 | ) | 8,372 |
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of tax benefits of $64,134 |  | 100,692 |  | 15,436 |  | 14,366 |  | – |  | – |  | (29,802 | ) | 100,692 |
Comprehensive income (loss) |  | 99,245 |  | 26,606 |  | 17,921 |  | (5 | ) | (4 | ) | (44,518 | ) | 99,245 |
Issuance of common stock, net of expenses |  | 39,999 |  | – |  | – |  | – |  | 25 |  | (25 | ) | 39,999 |
Common stock dividends |  | (70,558 | ) | (16,124 | ) | (12,004 | ) | – |  | – |  | 28,128 |  | (70,558 | )
Balance, December 31, 2011 |  | $1,406,084 |  | 281,055 |  | 236,054 |  | 81 |  | 26 |  | (517,216 | ) | $1,406,084 |

42

Consolidating statement of cash flows

|  | Year ended December 31, 2011
(in thousands) |  | HECO |  | HELCO |  | MECO |  | RHI |  | UBC |  | Elimination addition to (deduction from) cash flows |  | HECO Consolidated |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) |  | $ 101,066 |  | 27,185 |  | 18,355 |  | (5 | ) | (4 | ) |  | (44,616 | ) [2] | $ 101,981 |  |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity in earnings |  | (44,716 | ) | – |  | – |  | – |  | – |  |  | 44,616 | [2] | (100 | ) |
Common stock dividends received from subsidiaries |  | 28,228 |  | – |  | – |  | – |  | – |  |  | (28,128 | ) [2] | 100 |  |
Depreciation of property, plant and equipment |  | 89,324 |  | 32,767 |  | 20,884 |  | – |  | – |  |  | – |  | 142,975 |  |
Other amortization |  | 9,890 |  | 2,528 |  | 4,960 |  | – |  | – |  |  | – |  | 17,378 |  |
Impairment of utility plant |  | 9,215 |  | – |  | – |  | – |  | – |  |  | – |  | 9,215 |  |
Changes in deferred income taxes |  | 38,548 |  | 16,101 |  | 14,442 |  | – |  | – |  |  | – |  | 69,091 |  |
Changes in tax credits, net |  | 1,464 |  | 117 |  | 506 |  | – |  | – |  |  | – |  | 2,087 |  |
Allowance for equity funds used during construction |  | (4,572 | ) | (592 | ) | (800 | ) | – |  | – |  |  | – |  | (5,964 | ) |
Decrease in cash overdraft |  | – |  | (2,527 | ) | (161 | ) | – |  | – |  |  | – |  | (2,688 | ) |
Changes in assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Increase in accounts receivable |  | (34,167 | ) | (2,985 | ) | (5,663 | ) | – |  | – |  |  | (1,589 | ) [1] | (44,404 | ) |
Decrease (Increase) in accrued unbilled revenues |  | (31,616 | ) | (2,481 | ) | 655 |  | – |  | – |  |  | – |  | (33,442 | ) |
Increase in fuel oil stock |  | (6,757 | ) | (3,466 | ) | (8,620 | ) | – |  | – |  |  | – |  | (18,843 | ) |
Increase in materials and supplies |  | (6,206 | ) | (202 | ) | (63 | ) | – |  | – |  |  | – |  | (6,471 | ) |
Increase in regulatory assets |  | (31,774 | ) | (2,025 | ) | (6,333 | ) | – |  | – |  |  | – |  | (40,132 | ) |
Increase (decrease) in accounts payable |  | (34,515 | ) | 4,391 |  | (5,691 | ) | – |  | – |  |  | – |  | (35,815 | ) |
Changes in prepaid and accrued income taxes and revenue taxes |  | 51,593 |  | 9,641 |  | 8,502 |  | – |  | – |  |  | – |  | 69,736 |  |
Contributions to defined benefit pension and other postretirement benefit plans |  | (54,183 | ) | (9,191 | ) | (9,802 | ) | – |  | – |  |  | – |  | (73,176 | ) |
Changes in other assets and liabilities |  | 16,312 |  | (7,174 | ) | (859 | ) | (2 | ) | – |  |  | 1,589 | [2] | 9,866 |  |
Net cash provided by (used in) operating activities |  | 97,134 |  | 62,087 |  | 30,312 |  | (7 | ) | (4 | ) |  | (28,128 | ) | 161,394 |  |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  | (160,528 | ) | (34,230 | ) | (31,264 | ) | – |  | – |  |  | – |  | (226,022 | ) |
Contributions in aid of construction |  | 15,003 |  | 6,271 |  | 2,260 |  | – |  | – |  |  | – |  | 23,534 |  |
Advances from (to) affiliates |  | – |  | (15,200 | ) | 11,000 |  | – |  | – |  |  | 4,200 | [1] | – |  |
Other |  | 77 |  | – |  | – |  | – |  | – |  |  | – |  | 77 |  |
Investment in consolidated subsidiary |  | (25 | ) | – |  | – |  | – |  | – |  |  | 25 | [2] | – |  |
Net cash used in investing activities |  | (145,473 | ) | (43,159 | ) | (18,004 | ) | – |  | – |  |  | 4,225 |  | (202,411 | ) |
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common stock dividends |  | (70,558 | ) | (16,124 | ) | (12,004 | ) | – |  | – |  |  | 28,128 | [2] | (70,558 | ) |
Preferred stock dividends of HECO and subsidiaries |  | (1,080 | ) | (534 | ) | (381 | ) | – |  | – |  |  | – |  | (1,995 | ) |
Proceeds from issuance of common stock |  | 40,000 |  | – |  | – |  | – |  | 25 |  |  | (25 | ) [2] | 40,000 |  |
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |  | 4,200 |  | – |  | – |  | – |  | – |  |  | (4,200 | ) [1] | – |  |
Other |  | (423 | ) | (116 | ) | (21 | ) | – |  | – |  |  | – |  | (560 | ) |
Net cash provided by (used in) financing activities |  | (27,861 | ) | (16,774 | ) | (12,406 | ) | – |  | 25 |  |  | 23,903 |  | (33,113 | ) |
Net increase (decrease) in cash and cash equivalents |  | (76,200 | ) | 2,154 |  | (98 | ) | (7 | ) | 21 |  |  | – |  | (74,130 | ) |
Cash and cash equivalents, beginning of year |  | 121,019 |  | 1,229 |  | 594 |  | 89 |  | 5 |  |  | – |  | 122,936 |  |
Cash and cash equivalents, end of year |  | $ 44,819 |  | 3,383 |  | 496 |  | 82 |  | 26 |  |  | – |  | $ 48,806 |  |

43

Consolidating statement of cash flows

|  | Year ended December 31, 2010
(in thousands) |  | HECO |  | HELCO |  | MECO |  | RHI |  | UBC |  | Elimination addition to (deduction from) cash flows |  | HECO Consolidated |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) |  | $ 77,669 |  | 17,142 |  | 9,393 |  | (8 | ) | (12 | ) |  | (25,600 | ) [2] | $ 78,584 |  |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity in earnings |  | (25,700 | ) | – |  | – |  | – |  | – |  |  | 25,600 | [2] | (100 | ) |
Common stock dividends received from subsidiaries |  | 12,584 |  | – |  | – |  | – |  | – |  |  | (12,484 | ) [2] | 100 |  |
Depreciation of property, plant and equipment |  | 86,932 |  | 36,483 |  | 26,293 |  | – |  | – |  |  | – |  | 149,708 |  |
Other amortization |  | 4,958 |  | 3,410 |  | (643 | ) | – |  | – |  |  | – |  | 7,725 |  |
Changes in deferred income taxes |  | 62,089 |  | 20,939 |  | 12,657 |  | – |  | – |  |  | – |  | 95,685 |  |
Changes in tax credits, net |  | 2,796 |  | 100 |  | (55 | ) | – |  | – |  |  | – |  | 2,841 |  |
Allowance for equity funds used during construction |  | (4,956 | ) | (507 | ) | (553 | ) | – |  | – |  |  | – |  | (6,016 | ) |
Decrease in cash overdraft |  | – |  | – |  | (141 | ) | – |  | – |  |  | – |  | (141 | ) |
Changes in assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Increase in accounts receivable |  | (9,678 | ) | (7 | ) | (1,145 | ) | – |  | – |  |  | 5,018 | [1] | (5,812 | ) |
Increase in accrued unbilled revenues |  | (13,690 | ) | (2,370 | ) | (4,048 | ) | – |  | – |  |  | – |  | (20,108 | ) |
Decrease (increase) in fuel oil stock |  | (71,433 | ) | (3,111 | ) | 500 |  | – |  | – |  |  | – |  | (74,044 | ) |
Decrease (increase) in materials and supplies |  | (512 | ) | (492 | ) | 195 |  | – |  | – |  |  | – |  | (809 | ) |
Increase in regulatory assets |  | (812 | ) | (1,652 | ) | (472 | ) | – |  | – |  |  | – |  | (2,936 | ) |
Increase in accounts payable |  | 21,378 |  | 1,438 |  | 2,576 |  | – |  | – |  |  | – |  | 25,392 |  |
Changes in prepaid and accrued income taxes and revenue taxes |  | (8,647 | ) | (22 | ) | (1,501 | ) | – |  | – |  |  | – |  | (10,170 | ) |
Contributions to defined benefit pension and other postretirement benefit plans |  | (21,003 | ) | (4,981 | ) | (5,084 | ) | – |  | – |  |  | – |  | (31,068 | ) |
Changes in other assets and liabilities |  | 38,009 |  | 62 |  | 5,908 |  | (1 | ) | (2 | ) |  | (5,018 | ) [2] | 38,958 |  |
Net cash provided by (used in) operating activities |  | 149,984 |  | 66,432 |  | 43,880 |  | (9 | ) | (14 | ) |  | (12,484 | ) | 247,789 |  |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  | (112,448 | ) | (35,146 | ) | (26,750 | ) | – |  | – |  |  | – |  | (174,344 | ) |
Contributions in aid of construction |  | 14,030 |  | 6,359 |  | 2,166 |  | – |  | – |  |  | – |  | 22,555 |  |
Advances from (to) affiliates |  | 20,100 |  | (30,950 | ) | (18,500 | ) | – |  | – |  |  | 29,350 | [1] | – |  |
Other |  | 1,327 |  | – |  | – |  | – |  | – |  |  | – |  | 1,327 |  |
Investment in consolidated subsidiary |  | (25,800 | ) | – |  | – |  | – |  | – |  |  | 25,800 | [2] | – |  |
Net cash used in investing activities |  | (102,791 | ) | (59,737 | ) | (43,084 | ) | – |  | – |  |  | 55,150 |  | (150,462 | ) |
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common stock dividends |  | (48,769 | ) | (9,483 | ) | (3,001 | ) | – |  | – |  |  | 12,484 | [2] | (48,769 | ) |
Preferred stock dividends of HECO and subsidiaries |  | (1,080 | ) | (534 | ) | (381 | ) | – |  | – |  |  | – |  | (1,995 | ) |
Proceeds from issuance of common stock |  | 4,250 |  | 22,950 |  | 2,850 |  | – |  | – |  |  | (25,800 | ) [2] | 4,250 |  |
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |  | 49,450 |  | (20,100 | ) | – |  | – |  | – |  |  | (29,350 | ) [1] | – |  |
Other |  | (1,006 | ) | (305 | ) | (144 | ) | – |  | – |  |  | – |  | (1,455 | ) |
Net cash provided by (used in) financing activities |  | 2,845 |  | (7,472 | ) | (676 | ) | – |  | – |  |  | (42,666 | ) | (47,969 | ) |
Net increase (decrease) in cash and cash equivalents |  | 50,038 |  | (777 | ) | 120 |  | (9 | ) | (14 | ) |  | – |  | 49,358 |  |
Cash and cash equivalents, beginning of year |  | 70,981 |  | 2,006 |  | 474 |  | 98 |  | 19 |  |  | – |  | 73,578 |  |
Cash and cash equivalents, end of year |  | $ 121,019 |  | 1,229 |  | 594 |  | 89 |  | 5 |  |  | – |  | $ 122,936 |  |

44

Consolidating statement of cash flows

|  | Year ended December 31, 2009
(in thousands) |  | HECO |  | HELCO |  | MECO |  | RHI |  | UBC |  | Elimination addition to (deduction from) cash flows |  | HECO Consolidated |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ 80,526 |  | 16,295 |  | 10,605 |  | (11 | ) | (149 | ) |  | (25,825 | ) [2] | $ 81,441 |  |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity in earnings |  | (25,925 | ) | – |  | – |  | – |  | – |  |  | 25,825 | [2] | (100 | ) |
Common stock dividends received from subsidiaries |  | 4,364 |  | – |  | – |  | – |  | – |  |  | (4,264 | ) [2] | 100 |  |
Depreciation of property, plant and equipment |  | 82,031 |  | 33,005 |  | 29,497 |  | – |  | – |  |  | – |  | 144,533 |  |
Other amortization |  | 4,177 |  | 3,421 |  | 2,447 |  | – |  | – |  |  | – |  | 10,045 |  |
Changes in deferred income taxes |  | 6,539 |  | 6,236 |  | 1,987 |  | – |  | – |  |  | – |  | 14,762 |  |
Changes in tax credits, net |  | (464 | ) | (443 | ) | (425 | ) | – |  | – |  |  | – |  | (1,332 | ) |
Allowance for equity funds used during construction |  | (9,945 | ) | (1,621 | ) | (656 | ) | – |  | – |  |  | – |  | (12,222 | ) |
Changes in assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Decrease in accounts receivable |  | 18,375 |  | 7,529 |  | 4,997 |  | – |  | 11 |  |  | 1,693 | [1] | 32,605 |  |
Decrease in accrued unbilled revenues |  | 16,635 |  | 4,228 |  | 1,405 |  | – |  | – |  |  | – |  | 22,268 |  |
Decrease (increase) in fuel oil stock |  | 3,699 |  | (2,314 | ) | (2,331 | ) | – |  | – |  |  | – |  | (946 | ) |
Decrease (increase) in materials and supplies |  | (1,795 | ) | 360 |  | 59 |  | – |  | – |  |  | – |  | (1,376 | ) |
Increase in regulatory assets |  | (9,542 | ) | (3,860 | ) | (4,195 | ) | – |  | – |  |  | – |  | (17,597 | ) |
Increase (decrease) in accounts payable |  | 2,744 |  | (8,877 | ) | (32 | ) | – |  | – |  |  | – |  | (6,165 | ) |
Changes in prepaid and accrued income taxes and revenue taxes |  | (43,210 | ) | (6,759 | ) | (11,982 | ) | – |  | – |  |  | – |  | (61,951 | ) |
Contributions to defined benefit pension and other postretirement benefit plans |  | (8,581 | ) | (7,793 | ) | (7,712 | ) | – |  | – |  |  | – |  | (24,086 | ) |
Changes in other assets and liabilities |  | 24,311 |  | (4,235 | ) | 3,150 |  | (14 | ) | (4 | ) |  | (1,693 | ) [2] | 21,515 |  |
Net cash provided by (used in) operating activities |  | 143,939 |  | 35,172 |  | 26,814 |  | (25 | ) | (142 | ) |  | (4,264 | ) | 201,494 |  |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  | (192,813 | ) | (67,525 | ) | (26,107 | ) | – |  | – |  |  | – |  | (286,445 | ) |
Contributions in aid of construction |  | 5,348 |  | 7,061 |  | 1,761 |  | – |  | – |  |  | – |  | 14,170 |  |
Advances from (to) affiliates |  | 38,500 |  | – |  | 1,000 |  | – |  | – |  |  | (39,500 | ) [1] | – |  |
Other |  | 221 |  | – |  | – |  | – |  | 119 |  |  | – |  | 340 |  |
Investment in consolidated subsidiary |  | (25 | ) | – |  | – |  | – |  | – |  |  | 25 | [2] | – |  |
Net cash provided by (used in) investing activities |  | (148,769 | ) | (60,464 | ) | (23,346 | ) | – |  | 119 |  |  | (39,475 | ) | (271,935 | ) |
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common stock dividends |  | (55,000 | ) | – |  | (4,264 | ) | – |  | – |  |  | 4,264 | [2] | (55,000 | ) |
Preferred stock dividends of HECO and subsidiaries |  | (1,080 | ) | (534 | ) | (381 | ) | – |  | – |  |  | – |  | (1,995 | ) |
Proceeds from issuance of long-term debt |  | 90,000 |  | 63,186 |  | – |  | – |  | – |  |  | – |  | 153,186 |  |
Proceeds from issuance of common stock |  | 61,914 |  | – |  | – |  | – |  | 25 |  |  | (25 | ) [2] | 61,914 |  |
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less |  | (11,464 | ) | (38,500 | ) | – |  | – |  | – |  |  | 39,500 | [1] | (10,464 | ) |
Increase (decrease) in cash overdraft |  | (9,847 | ) | – |  | 302 |  | – |  | – |  |  | – |  | (9,545 | ) |
Other |  | (976 | ) | (2 | ) | – |  | – |  | – |  |  | – |  | (978 | ) |
Net cash provided by (used in) financing activities |  | 73,547 |  | 24,150 |  | (4,343 | ) | – |  | 25 |  |  | 43,739 |  | 137,118 |  |
Net increase (decrease) in cash and cash equivalents |  | 68,717 |  | (1,142 | ) | (875 | ) | (25 | ) | 2 |  |  | – |  | 66,677 |  |
Cash and cash equivalents, January 1 |  | 2,264 |  | 3,148 |  | 1,349 |  | 123 |  | 17 |  |  | – |  | 6,901 |  |
Cash and cash equivalents, December 31 |  | $ 70,981 |  | 2,006 |  | 474 |  | 98 |  | 19 |  |  | – |  | $ 73,578 |  |

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Explanation of reclassifications and eliminations on consolidating schedules:

[1] Eliminations of intercompany receivables and payables and other intercompany transactions.

[2] Elimination of investment in subsidiaries, carried at equity.

[3] Reclassification of accrued income taxes for financial statement presentation.

17. Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2011 and 2010 follows:

|  | Quarters ended |  | Year ended |
2011 |  | March 31 |  | June 30 |  | Sept. 30 |  | Dec. 31 |  |  | Dec. 31 |
(in thousands) |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues (1) |  | $644,301 |  | $727,652 |  | $818,907 |  | $782,904 |  |  | $2,973,764 |
Operating income (1) |  | 32,719 |  | 30,540 |  | 49,999 |  | 41,977 |  |  | 155,235 |
Net income for common stock (1), (2) |  | 19,189 |  | 17,024 |  | 37,959 |  | 25,814 |  |  | 99,986 |

|  | Quarters ended |  | Year ended |
2010 |  | March 31 |  | June 30 |  | Sept. 30 |  | Dec. 31 |  |  | Dec. 31 |
(in thousands) |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $546,712 |  | $582,094 |  | $622,223 |  | $616,412 |  |  | $2,367,441 |
Operating income |  | 30,407 |  | 30,850 |  | 36,114 |  | 22,470 |  |  | 119,841 |
Net income for common stock (3) |  | 18,052 |  | 17,642 |  | 21,980 |  | 18,915 |  |  | 76,589 |

Note: HEI owns all of HECO’s common stock, therefore per share data is not meaningful.

(1) In the fourth quarter of 2011, HECO recorded an adjustment of $6 million to revenues related to the third quarter of 2011, which decreased net income for the fourth quarter of 2011 by $3 million.

(2) In the fourth quarter of 2011 HECO recorded an impairment charge of $6 million (net of taxes) of a transmission project.

(3) The fourth quarter of 2010 includes $6 million of interest income (net of taxes), due to a federal tax settlement.

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