HAWAIIAN ELECTRIC CO INC - FORM 8-K - EX-99 - FORWARD-LOOKING STATEMENTS

Attached files

file	filename
8-K - FORM 8-K - HAWAIIAN ELECTRIC CO INC	d8k.htm
EX-13 - HEI'S 2009 ANNUAL REPORT TO SHAREHOLDERS (SELECTED SECTIONS) - HAWAIIAN ELECTRIC CO INC	dex13.htm

HECO Exhibit 99

Forward-Looking Statements

This report and other presentations made by Hawaiian Electric Company, Inc. (HECO) and its subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects and possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HECO and its subsidiaries (collectively, 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 in forward-looking statements and from historical results include, but are not limited to, the following:

•

international, national and local economic conditions, including the state of the Hawaii tourism and construction industries, decisions concerning the extent of the presence of the federal government and military in Hawaii, and the implications and potential impacts of current capital and credit market conditions and federal and state responses to those conditions, such as the Emergency Economic Stabilization Act of 2008 and the American Economic Recovery and Reinvestment Act of 2009;

•

weather and natural disasters, such as hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming (such as more severe storms and rising sea levels);

•

global developments, including terrorist acts, the war on terrorism, continuing U.S. presence in Iraq and Afghanistan, potential conflict or crisis with North Korea and in the Middle East, Iran’s nuclear activities and potential H1N1 and avian flu pandemics;

•

the timing and extent of changes in interest rates;

•

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 impact of potential legislative and regulatory changes;

•

increasing competition in the electric utility industry (e.g., increased self-generation of electricity may have an adverse impact on the Company’s revenues);

•

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 HCEI-related costs; reliance by the Company on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cable, biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

•

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

•

the risk to generation reliability when generation peak reserve margins on Oahu are strained;

•

fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the 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 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;

•

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, regulatory changes resulting from the HCEI, environmental laws and regulations, the regulation of greenhouse gas emissions (GHG), healthcare reform, governmental fees and assessments, 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 (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs);

•

decisions in other proceedings by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions, restrictions and penalties that may arise, for example with respect to environmental conditions or renewable portfolio standards (RPS));

•

increasing operation and maintenance expenses and investment in infrastructure for the Company, resulting in the need for more frequent rate cases;

•

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

•

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

•

changes by securities rating agencies in their ratings of the securities of HECO 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; and

•

other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by 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.

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

HECO incorporates by reference all of 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), included in HEI Exhibit 13 to the Form 8-K dated February 19, 2010 (HEI’s MD&A). The information incorporated by reference should be read in conjunction with HECO’s consolidated financial statements and accompanying notes.

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


December 31, 2009	Payments due by period
(in millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Long-term debt, net	$	—	$	57	$	11	$	991	$	1,059
Interest on long-term debt		58		113		109		773		1,053
Operating leases		4		7		7		11		29
Open purchase order obligations ¹		54		23		—		—		77
Fuel oil purchase obligations (estimate based on January 1, 2010 fuel oil prices)		775		1,565		939		—		3,279
Purchase power obligations– minimum fixed capacity charges		118		234		237		779		1,368
Liabilities for uncertain tax positions		4		1		—		—		5

Total (estimated)	$	1,013	$	2,000	$	1,303	$	2,554	$	6,870

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

The tables above do 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, 2009, the fair value of the assets held in trusts to satisfy the obligations of the Company’s qualified pension plans did not exceed the pension plans’ benefit obligation. Minimum funding requirements for retirement benefit plans have not been included in the tables 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 2010 and 2011.

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, 2009.

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. See discussion of the ECACs in “Electric utility—Certain factors that may affect future results and financial condition—Regulation of electric utility rates” in HEI’s MD&A. HECO and its subsidiaries currently have no hedges against their 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 pension liabilities, the market value of pension 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.

HECO incorporates by reference the section “Other than bank interest rate risk” in HEI’s Quantitative and Qualitative Disclosures about Market Risk,” included in HEI Exhibit 13 to the Form 8-K dated February 19, 2010, 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	2009			2008			2007			2006			2005
(in thousands)
Results of operations
Operating revenues	$	2,026,672		$	2,853,639		$	2,096,958		$	2,050,412		$	1,801,710
Operating expenses		1,912,264			2,723,702			1,996,683			1,933,257			1,688,168

Operating income		114,408			129,937			100,275			117,155			113,542
Other income		19,709			15,049			4,592			9,471			8,643
Interest and other charges		52,676			51,016			50,716			49,684			47,388

Net income		81,441			93,970			54,151			76,942			74,797
Less net income attributable to noncontrolling interest – preferred stock of subsidiaries		915			915			915			915			915

Net income attributable to HECO		80,526			93,055			53,236			76,027			73,882
Preferred stock dividends of HECO		1,080			1,080			1,080			1,080			1,080

Net income for common stock	$	79,446		$	91,975		$	52,156		$	74,947		$	72,802

*At December 31*	2009			2008			2007			2006			2005
(in thousands)
Financial position
Utility plant	$	4,881,767		$	4,586,668		$	4,320,607		$	4,133,883		$	3,930,321
Accumulated depreciation		(1,848,416	)		(1,741,453	)		(1,647,113	)		(1,558,913	)		(1,456,537	)

Net utility plant	$	3,033,351		$	2,845,215		$	2,673,494		$	2,574,970		$	2,473,784

Total assets	$	3,978,392		$	3,856,109		$	3,423,888		$	3,063,134		$	3,081,461

Capitalization:¹
Short-term borrowings from non-affiliates and affiliate	$	—		$	41,550		$	28,791		$	113,107		$	136,165
Long-term debt, net		1,057,815			904,501			885,099			766,185			765,993
Common stock equity		1,306,408			1,188,842			1,110,462			958,203			1,039,259
Cumulative preferred stock–not subject to mandatory redemption		22,293			22,293			22,293			22,293			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		12,000			12,000			12,000			12,000			12,000

Stockholders’ equity		1,340,701			1,223,135			1,144,755			992,496			1,073,552

Total capitalization	$	2,398,516		$	2,169,186		$	2,058,645		$	1,871,788		$	1,975,710

Capital structure ratios (%)¹
Debt		44.1			43.6			44.4			47.0			45.7
Preferred stock and noncontrolling interest		1.4			1.6			1.7			1.8			1.7
Common stock equity		54.5			54.8			53.9			51.2			52.6

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 HEI Exhibit 13 to the Form 8-K dated February 19, 2010, 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 liquidity.

Annual Report of Management on Internal Control Over Financial Reporting

The Board of Directors and Shareholders

Hawaiian Electric Company, Inc.:

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Company’s internal control system was designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of its consolidated financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.

KPMG LLP, an independent registered public accounting firm, has issued an audit report on the Company’s internal control over financial reporting as of December 31, 2009. This report appears on page 6.


/s/ Richard M. Rosenblum	/s/ Tayne S. Y. Sekimura	/s/ Patsy H. Nanbu
Richard M. Rosenblum	Tayne S. Y. Sekimura	Patsy H. Nanbu
President and	Senior Vice President	Controller and
Chief Executive Officer	and Chief Financial Officer	Chief Accounting Officer

February 19, 2010

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors and Shareholders

Hawaiian Electric Company, Inc.:

We have audited Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Hawaiian Electric Company, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying annual report of management on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Hawaiian Electric Company, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 19, 2010 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Honolulu, Hawaii

February 19, 2010

[KPMG LLP letterhead]

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Hawaiian Electric Company, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period 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 audits.

We conducted our audits 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 audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009 in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Honolulu, Hawaii

February 19, 2010

Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries


Years ended December 31	2009			2008			2007
(in thousands)
Operating revenues	$	2,026,672		$	2,853,639		$	2,096,958

Operating expenses
Fuel oil		671,970			1,229,193			774,119
Purchased power		499,804			689,828			536,960
Other operation		248,515			243,249			214,047
Maintenance		107,531			101,624			105,743
Depreciation		144,533			141,678			137,081
Taxes, other than income taxes		191,699			261,823			194,607
Income taxes		48,212			56,307			34,126

		1,912,264			2,723,702			1,996,683

Operating income		114,408			129,937			100,275

Other income
Allowance for equity funds used during construction		12,222			9,390			5,219
Other, net		7,487			5,659			(627	)

		19,709			15,049			4,592

Interest and other charges
Interest on long-term debt		51,820			47,302			45,964
Amortization of net bond premium and expense		3,254			2,530			2,440
Other interest charges		2,870			4,925			4,864
Allowance for borrowed funds used during construction		(5,268	)		(3,741	)		(2,552	)

		52,676			51,016			50,716

Net income		81,441			93,970			54,151
Less net income attributable to noncontrolling interest – preferred stock of subsidiaries		915			915			915

Net income attributable to HECO		80,526			93,055			53,236
Preferred stock dividends of HECO		1,080			1,080			1,080

Net income for common stock	$	79,446		$	91,975		$	52,156

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries


December 31	2009			2008
(in thousands)
Assets
Utility plant, at cost
Land	$	52,530		$	42,541
Plant and equipment		4,696,257			4,277,499
Less accumulated depreciation		(1,848,416	)		(1,741,453	)
Construction in progress		132,980			266,628

Net utility plant		3,033,351			2,845,215

Current assets
Cash and equivalents		73,578			6,901
Customer accounts receivable, net		133,286			166,422
Accrued unbilled revenues, net		84,276			106,544
Other accounts receivable, net		8,449			7,918
Fuel oil stock, at average cost		78,661			77,715
Materials and supplies, at average cost		35,908			34,532
Prepayments and other		16,201			12,626

Total current assets		430,359			412,658

Other long-term assets
Regulatory assets		426,862			530,619
Unamortized debt expense		14,288			14,503
Other		73,532			53,114

Total other long-term assets		514,682			598,236

	$	3,978,392		$	3,856,109

Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	1,306,408		$	1,188,842
Cumulative preferred stock – not subject to mandatory redemption		22,293			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		12,000			12,000

Stockholders’ equity		1,340,701			1,223,135
Long-term debt, net		1,057,815			904,501

Total capitalization		2,398,516			2,127,636

Current liabilities
Short-term borrowings-affiliate		—			41,550
Accounts payable		132,711			122,994
Interest and preferred dividends payable		21,223			15,397
Taxes accrued		156,092			220,046
Other		48,192			55,268

Total current liabilities		358,218			455,255

Deferred credits and other liabilities
Deferred income taxes		180,603			166,310
Regulatory liabilities		288,214			288,602
Unamortized tax credits		56,870			58,796
Retirement benefits liability		296,623			392,845
Other		77,804			54,949

Total deferred credits and other liabilities		900,114			961,502

Contributions in aid of construction		321,544			311,716

	$	3,978,392		$	3,856,109

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries


December 31	2009		2008		2007
(dollars in thousands, except par value)

Common stock equity

Common stock of $6²/3 par value
Authorized: 50,000,000 shares. Outstanding:
2009, 13,786,959 shares and 2008 and 2007, 12,805,843 shares	$	91,931	$	85,387	$	85,387
Premium on capital stock		385,659		299,214		299,214
Retained earnings		827,036		802,590		724,704
Accumulated other comprehensive income, net of income taxes:
Retirement benefit plans		1,782		1,651		1,157

Common stock equity		1,306,408		1,188,842		1,110,462

Cumulative preferred stock not subject to mandatory redemption

Authorized: 5,000,000 shares of $20 par value and 5,000,000 shares of $100 par value.

Outstanding: 2009 and 2008, 1,114,657 shares.


Series	Par Value			Shares Outstanding December 31, 2009 and 2008	2009	2008
(dollars in thousands, except par value and shares outstanding)
C-4¹/4%	$	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-5¹/4%		20	(HECO)	250,000	5,000	5,000
I-5%		20	(HECO)	89,657	1,793	1,793
J-4³/4%		20	(HECO)	250,000	5,000	5,000
K-4.65%		20	(HECO)	175,000	3,500	3,500

				1,114,657	22,293	22,293

Noncontrolling interest - cumulative preferred stock of subsidiaries - not subject to mandatory redemption

Authorized: 2,000,000 shares of $100 par value.

Outstanding: 2009 and 2008, 120,000 shares.


Series	Par Value			Shares Outstanding December 31, 2009 and 2008	2009		2008
(dollars in thousands, except par value and shares outstanding)
G-7⁵/8%	$	100	(HELCO)	70,000		7,000		7,000
H-7⁵/8%		100	(MECO)	50,000		5,000		5,000

				120,000		12,000		12,000

Total stockholders’ equity					$	1,340,701	$	1,223,135

(continued)

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries


December 31	2009		2008
(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	$	—
HELCO, 6.50%, series 2009, due 2039		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

		1,007,900		857,900
Less funds on deposit with trustee		—		3,186

Total obligations to the State of Hawaii		1,007,900		854,714
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		906,260
Less unamortized discount		1,631		1,759

Long-term debt, net		1,057,815		904,501

Total capitalization	$	2,398,516	$	2,127,636

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Statements of Changes in Stockholders’ Equity

Hawaiian Electric Company, Inc. and Subsidiaries


	Common stock			Premium on capital		Retained			Accumulated other comprehensive			Cumulative preferred			Noncontrolling interest: cumulative preferred stock of
(in thousands)	Shares	Amount		stock		earnings			income (loss)			stock			subsidiaries			Total
Balance, December 31, 2006	12,806	$	85,387	$	299,214	$	700,252		$	(126,650	)	$	22,293		$	12,000		$	992,496
Comprehensive income:
Net income	—		—		—		52,156			—			1,080			915			54,151
Retirement benefit plans:
Net gains arising during the period, net of taxes of $9,861	—		—		—		—			15,484			—			—			15,484
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 $5,001	—		—		—		—			7,854			—			—			7,854
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $11,007	—		—		—		—			(17,282	)		—			—			(17,282	)

Comprehensive income	—		—		—		52,156			6,056			1,080			915			60,207

Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes of $77,546	—		—		—		—			121,751			—			—			121,751
Adjustment to initially apply an accounting standard prescribing a “more-likely-than-not” recognition criterion to a tax position	—		—		—		(620	)		—			—			—			(620	)
Common stock dividends	—		—		—		(27,084	)		—			—			—			(27,084	)
Preferred stock dividends	—		—		—		—			—			(1,080	)		(915	)		(1,995	)

Balance, December 31, 2007	12,806		85,387		299,214		724,704			1,157			22,293			12,000			1,144,755
Comprehensive income:
Net income	—		—		—		91,975			—			1,080			915			93,970
Retirement benefit plans:
Net losses arising during the period, net of tax benefits of $100,141	—		—		—		—			(157,226	)		—			—			(157,226	)
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 $3,481	—		—		—		—			5,464			—			—			5,464
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of tax benefits of $96,975	—		—		—		—			152,256			—			—			152,256

Comprehensive income	—		—		—		91,975			494			1,080			915			94,464

Common stock dividends	—		—		—		(14,089	)		—			—			—			(14,089	)
Preferred stock dividends	—		—		—		—			—			(1,080	)		(915	)		(1,995	)

Balance, December 31, 2008	12,806		85,387		299,214		802,590			1,651			22,293			12,000			1,223,135
Comprehensive income:
Net income	—		—		—		79,446			—			1,080			915			81,441
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 asset, net of taxes of $48,251	—		—		—		—			(75,756	)		—			—			(75,756	)

Comprehensive income	—		—		—		79,446			131			1,080			915			81,572

Issuance of common stock, net of expenses	981		6,544		86,445		—			—			—			—			92,989
Common stock dividends	—		—		—		(55,000	)		—			—			—			(55,000	)
Preferred stock dividends	—		—		—		—			—			(1,080	)		(915	)		(1,995	)

Balance, December 31, 2009	13,787	$	91,931	$	385,659	$	827,036		$	1,782		$	22,293		$	12,000		$	1,340,701

See accompanying “Notes to Consolidated Financial Statements.”

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries


Years ended December 31	2009			2008			2007
(in thousands)

Cash flows from operating activities
Net income	$	81,441		$	93,970		$	54,151
Adjustments to reconcile net income
Depreciation of utility plant		144,533			141,678			137,081
Other amortization		10,045			8,619			8,230
Writedown of utility plant		—			—			11,701
Deferred income taxes		14,762			3,882			(31,888	)
Tax credits, net		(1,332	)		1,470			1,992
Allowance for equity funds used during construction		(12,222	)		(9,390	)		(5,219	)
Changes in assets and liabilities
Decrease (increase) in accounts receivable		32,605			(21,313	)		(23,080	)
Decrease (increase) in accrued unbilled revenues		22,268			7,730			(22,079	)
Decrease (increase) in fuel oil stock		(946	)		14,156			(27,559	)
Increase in materials and supplies		(1,376	)		(274	)		(3,718	)
Increase in regulatory assets		(17,597	)		(3,229	)		(1,968	)
Increase (decrease) in accounts payable		9,717			(14,901	)		35,383
Changes in prepaid and accrued income and utility revenue taxes		(61,951	)		28,055			37,455
Other		(2,571	)		(5,445	)		16,108

Net cash provided by operating activities		217,376			245,008			186,590

Cash flows from investing activities
Capital expenditures		(302,327	)		(278,476	)		(209,821	)
Contributions in aid of construction		14,170			17,319			19,011
Other		340			1,157			5,440

Net cash used in investing activities		(287,817	)		(260,000	)		(185,370	)

Cash flows from financing activities
Common stock dividends		(55,000	)		(14,089	)		(27,084	)
Preferred stock dividends of HECO and subsidiaries		(1,995	)		(1,995	)		(1,995	)
Proceeds from issuance of common stock		61,914			—			—
Proceeds from issuance of long-term debt		153,186			19,275			242,538
Repayment of long-term debt		—			—			(126,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(10,464	)		12,759			(84,316	)
Increase (decrease) in cash overdraft		(9,545	)		1,265			(3,544	)
Other		(978	)		—			—

Net cash provided by (used in) financing activities		137,118			17,215			(401	)

Net increase in cash and equivalents		66,677			2,223			819
Cash and equivalents, January 1		6,901			4,678			3,859

Cash and equivalents, December 31	$	73,578		$	6,901		$	4,678

See accompanying “Notes to Consolidated Financial Statements.”

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 own 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; revenues; and variable interest entities (VIEs).

Consolidation

The consolidated financial statements include the accounts of HECO and its subsidiaries (collectively, the Company), but exclude subsidiaries which are VIEs of which 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.

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 ASC Topic 980. 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 electric utilities expect that their regulatory assets would be charged to expense and regulatory liabilities would be credited to income or refunded to ratepayers. 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.

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.

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.

If a power purchase agreement (PPA) falls within the scope of FASB Accounting Standards Codification^TM (ASC) Topic 840 and results in the classification of the agreement as a capital lease, the electric utility would recognize a capital asset and a lease obligation. Currently, none of the PPAs is required to be recorded as a capital asset and long-term lease obligation.

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. Utility plant has lives ranging from 20 to 45 years for production plant, from 25 to 60 years for transmission and distribution plant and from 7 to 45 years for general plant. The composite annual depreciation rate, which includes a component for cost of removal, was 3.8% in 2009, 2008 and 2007.

Cash and 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 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 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 fiscal year, subject to limits and targeted funded status as determined with the consulting actuary. Under a pension tracking mechanism approved by the PUC on an interim basis, HECO generally will make contributions to the pension fund at the minimum level required under the law, 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 generally fund the net periodic pension cost. Future decisions in rate cases could further impact funding amounts.

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 electric utilities must fund OPEB costs as specified in the

OPEB tracking mechanisms, which were approved by the PUC on an interim basis. 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 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. However, the determination of the energy sales to individual customers for billing purposes is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on the meter readings in the beginning of the following month, monthly generation volumes, estimated customer usage by account, line losses and applicable customer rates based on historical values and current rate schedules. As of December 31, 2009, customer accounts receivable include unbilled energy revenues of $84 million on a base of annual revenue of $2.0 billion. Revenue amounts recorded pursuant to a PUC interim order are subject to refund, with interest, pending a final order.

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 ECACs also include a provision requiring a quarterly reconciliation of the amounts collected through the ECACs. See “Energy cost adjustment clauses” in Note 11 for a discussion of the ECACs and Act 162 of the 2006 Hawaii State Legislature.

The Company’s operating revenues include amounts for various revenue taxes. Revenue taxes are generally recorded as an expense in the year the related revenues are recognized. The Company’s payments to the taxing authorities are based on the prior years’ revenues. For 2009, 2008 and 2007, the Company included approximately $181 million, $252 million and $185 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

Repairs and maintenance costs

Repairs 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, as it was in the case of HELCO’s installation of CT-4 and CT-5, AFUDC on the delayed project may be stopped.

The weighted-average AFUDC rate was 8.1% in 2009, 2008 and 2007, 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 written off 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 cost to sell.

Recent accounting pronouncements and interpretations See “Fair Value Measurements” in Note 15.

Noncontrolling interests. In December 2007, the FASB issued a standard that requires the recognition of a noncontrolling interest (i.e., a minority interest) as equity in the consolidated financial statements, separate from the parent’s equity, and requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the income statement. Changes in the parent’s ownership interest that leave control intact are accounted for as capital transactions (i.e., as increases or decreases in ownership), a gain or loss will be recognized when a subsidiary is deconsolidated based on the fair value of the noncontrolling equity investment (not carrying amount), and entities must provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and of the noncontrolling owners. The Company adopted the standard prospectively on January 1, 2009, except for the presentation and disclosure requirements which must be applied retrospectively. Thus, beginning in the first quarter of 2009, “Preferred stock of subsidiaries—not subject to mandatory redemption” is presented as a separate component of “Stockholders’ equity” rather than as “Minority interests” in the mezzanine section between liabilities and equity on the balance sheet, dividends on preferred stock of subsidiaries are deducted from net income to arrive at net income for common stock on the income statement, and a column for “Preferred stock of subsidiaries—not subject to mandatory redemption” has been added to the statement of changes in stockholders’ equity.

Fair value measurements and impairments. In April 2009, the FASB issued three standards providing additional application guidance and enhancing disclosures regarding fair value measurements and impairments of securities.

The first standard relates to determining fair values when there is no active market or where the price inputs being used represent distressed sales. It provides guidelines for making fair value measurements more consistent with the principles presented in an earlier standard by reaffirming that the objective of fair value measurement is to reflect how much an asset would be sold for in an orderly transaction (as opposed to a distressed or forced transaction) at the date of the financial statements under current market conditions. Specifically, it reaffirms the need to use judgment in determining fair values when markets have become inactive.

The second standard relates to fair value disclosures for any financial instruments that are not currently reflected on the balance sheet of companies at fair value. Prior to issuance of this standard, fair values for these assets and liabilities were only disclosed annually. This standard now requires these disclosures on a quarterly basis, providing qualitative and quantitative information about fair value estimates for financial instruments not measured on the balance sheet at fair value.

The third standard provides greater consistency to the timing of impairment recognition and greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold. The measure of impairment in comprehensive income remains fair value. This standard also requires increased and more timely disclosures regarding expected cash flows, credit losses and an aging of securities with unrealized losses.

The Company adopted these standards in the second quarter of 2009 and provided additional disclosures regarding fair value measurements.

In connection with the adoption of the fair value measurement standards, the Company adopted the provisions of Accounting Standards Update 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.

Subsequent events. In May 2009, the FASB established general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued, which provide: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The Company adopted the standards in the second quarter of 2009. See Note 19.

Variable interest entities. In June 2009, the FASB issued a standard that amends the guidance in ASC Topic 810 related to the consolidation of VIEs. The standard eliminates exceptions to consolidating qualifying special-purpose entities (QSPEs), contains new criteria for determining the primary beneficiary, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. The Company will adopt this standard in the first quarter of 2010 and the adoption is not expected to impact HECO’s consolidated financial condition, results of operations or liquidity.

FASB Codification. In June 2009, the FASB issued a standard that establishes the ASC as the single source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Company adopted this standard in the third quarter of 2009 and has eliminated or revised citations for previous standards in this report.

Measuring liabilities at fair value. Accounting Standards Update No. 2009–05 amends Subtopic 820-10, Fair Value Measurements and Disclosures—Overall, and provides clarification that (1) in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value using specified techniques, (2) when estimating the fair value of a liability, a reporting entity is not required to include a separate input, or adjustment to other inputs, relating to the existence of a restriction that prevents the transfer of the liability, and (3) both a quoted price in an active market for the identical liability at the measurement date and the

quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. The Company adopted this guidance in the fourth quarter of 2009 and the adoption did not have an impact on its financial condition, results of operations or liquidity.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2009 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, 2009	Voluntary Liquidation Price		Redemption Price
Series

Cumulative preferred stock of HECO
C, D, E, H, J and K	$	20	$	21
I		20		20

Noncontrolling interest – cumulative preferred stock of subsidiaries
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 each of HELCO and MECO in the respective principal amounts 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 variable interest entities (VIEs). Trust III’s balance sheet as of December 31, 2009 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 2009 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.

Purchase power agreements. As of December 31, 2009, HECO and its subsidiaries had six PPAs for a total of 540 MW of firm capacity, and other PPAs with smaller IPPs and Schedule Q providers (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) that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for 2009 totaled $0.5 billion with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $141 million, $184 million, $57 million and $42 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

An enterprise with an interest in a VIE or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

HECO reviewed its significant PPAs and determined in 2004 that the IPPs at that time had no contractual obligation to provide such information. In March 2004, HECO and its subsidiaries sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of accounting standards for VIEs to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (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 2009, HECO and its subsidiaries 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 the 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 other IPPs, a possible outcome of future analysis is the consolidation of one or more of such IPPs in HECO’s consolidated financial statements. The consolidation of any significant IPP could have a material effect on HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and, if such a consolidated IPP were operating at a loss and had insufficient equity, the potential recognition of such losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply 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.

4. Long-term debt

For special purpose revenue bonds, funds on deposit with trustees represent the undrawn proceeds from the issuance of the special purpose revenue bonds and generally earn interest at market rates. These funds are available only to pay (or reimburse payment of) expenditures in connection with certain authorized construction projects and certain expenses related to the bonds.

On March 27, 2007, the Department of Budget and Finance of the State of Hawaii (the Department) issued (pursuant to a 2005 legislative authorization), at par, Series 2007A SPRBs in the aggregate principal amount of $140 million, with a maturity of March 1, 2037 and a fixed coupon interest rate of 4.65%, and loaned the proceeds to HECO ($100 million), HELCO ($20 million) and MECO ($20 million). Payment of the principal and interest on the SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company. Proceeds were used to finance capital expenditures, including reimbursements to the electric utilities for previously incurred capital expenditures which, in turn, were used primarily to repay short-term borrowings. Proceeds from the Series 2007A SPRBs were fully drawn as of December 31, 2009.

On March 27, 2007, the Department also issued, at par, Refunding Series 2007B SPRBs in the aggregate principal amount of $125 million, with a maturity of May 1, 2026 and a fixed coupon interest rate of 4.60%, and loaned the proceeds to HECO ($62 million), HELCO ($8 million) and MECO ($55 million). Proceeds from the sale were applied, together with other funds provided by the electric utilities, to the redemption at par on May 1, 2007 of the $75 million aggregate principal amount of 6.20% Series 1996A SPRBs (which had an original maturity of May 1, 2026) and to the redemption at a 2% premium on April 27, 2007 of the $50 million aggregate principal amount of 5 7/8% Series 1996B SPRBs (which had an original maturity of December 1, 2026). Payment of the principal and interest on the refunding SPRBs are insured by a surety bond issued by Financial Guaranty Insurance Company.

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 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, 2009, the aggregate payments of principal required on long-term debt are nil during the next two years, $57.5 million in 2012, nil in 2013 and $11.4 million in 2014.

5. Short-term borrowings

There were no short-term borrowings from nonaffiliates at December 31, 2009 and 2008.

At December 31, 2009 and 2008 the Company maintained syndicated credit facilities of $175 million and $250 million, respectively. The facilities are not secured. HECO drew on its facility in June and July 2009; all such borrowings were repaid in August 2009. HECO had no borrowings under its facility in 2008. See Note 13, “Related-party transactions,” concerning borrowings from affiliates.

Credit agreement. Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. On March 14, 2007 the PUC issued a D&O approving HECO’s request to maintain the credit facility for five years (until March 31, 2011), to borrow under the credit facility (including borrowings with maturities in excess of 364 days), to use the proceeds from any borrowings with maturities in excess of 364 days to finance capital expenditures and/or to repay short-term or other borrowings used to finance or refinance capital expenditures and to use an expedited approval process to obtain PUC approval to increase the facility amount, renew the facility, refinance the facility or change other terms of the facility if such changes are required or desirable.

Any draws on the facility bear interest, at the option of HECO, at either the “Adjusted LIBO Rate” plus 40 basis points or the greater of (a) the “Prime Rate” and (b) the sum of the “Federal Funds Rate” plus 50 basis points, as defined in the agreement. The annual fee is 8 basis points on the undrawn commitment amount. The agreement contains provisions for revised pricing in the event of a ratings change. For example, a ratings downgrade of HECO’s Senior Debt Rating (e.g., from BBB+/Baa1 to BBB/Baa2 by S&P and Moody’s, respectively) would result in a commitment fee increase of 2 basis points and an interest rate increase of 10 basis points on any drawn amounts. On the other hand, a ratings upgrade (e.g., from BBB+/Baa1 to A-/A3 by S&P or Moody’s, respectively) would result in a commitment fee decrease of 1 basis point and an interest rate decrease of 10 basis points on any drawn amounts. The agreement does not contain clauses that would affect access to the lines by reason of a ratings downgrade, nor does it have a broad “material adverse change” clause. However, the agreement does contain customary conditions that must be met in order to draw on it, such as the accuracy of certain of its representations at the time of a draw and compliance with its covenants (such as covenants preventing its subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HECO, and restricting HECO’s ability, as well as the ability of any of its subsidiaries, to guarantee indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (ratios of 48% for HELCO and 44% for MECO as of December 31, 2009, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 54% as of December 31, 2009, as calculated under the agreement), if HECO fails to remain a wholly-owned subsidiary of HEI or if any event or condition occurs that results in any “Material Indebtedness” of HECO or any of its significant subsidiaries being subject to acceleration prior to its scheduled maturity. HECO’s syndicated credit facility is maintained to support the issuance of commercial paper, but it may also be drawn for general corporate purposes and capital expenditures.

On May 23, 2007, S&P lowered the long-term corporate credit and unsecured debt ratings on HECO, HELCO and MECO to BBB from BBB+. The pricing for future borrowings under the line of credit facility did not change since the pricing level is “determined by the higher of the two” ratings by S&P and Moody’s, and Moody’s ratings did not change.

Effective December 8, 2008, HECO entered into a 9-month revolving unsecured credit agreement establishing a line of credit facility of $75 million, expiring on September 8, 2009, with Wells Fargo Bank National Association, as Administrative Agent and a lender, and U.S. Bank National Association, Bank of America, N.A. and Bank of Hawaii, as lenders. Major provisions of the credit agreement were substantially the same as provisions in HECO’s existing $175 million credit agreement, except for pricing and except for a provision requiring mandatory prepayments and reductions in the commitment amount in the event of any Debt Issuance or Equity Capital Markets Transaction, as defined by the agreement, in the amount of 100% of the net cash proceeds received (provided, however, for purposes of the agreement, HECO’s receipt of proceeds from special purpose revenue bond financings would not occur until such proceeds are disbursed to HECO by the construction fund trustee in accordance with the indenture pursuant to which the bonds are issued). On August 4, 2009, this credit facility terminated in accordance with its terms based on the completion on July 30, 2009 of the $150 million SPRB offering for the benefit of HECO and HELCO.

6. Regulatory assets and liabilities

In accordance with ASC Topic 980, 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. In the event of unforeseen regulatory actions or other circumstances, 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.

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 their regulatory assets for demand-side management (DSM) program costs. 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. Noted in parentheses are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2009, if different.

Regulatory assets were as follows:


December 31	2009		2008
(in thousands)
Retirement benefit plans (5 years; 2 years remaining for HELCO’s $6 million prepaid pension regulatory asset; 5 years remaining for HECO’s $8 million pension and OPEB tracking mechanisms; indeterminate for remainder)	$	303,927	$	416,680
Income taxes, net (1 to 36 years)		82,046		77,660
Postretirement benefits other than pensions (18 years; 3 years remaining)		5,369		7,159
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 2 to 19 years remaining)		14,878		16,191
Demand-side management program costs, net (1 year)		836		2,571
Vacation earned, but not yet taken (1 year)		6,849		6,654
Other (1 to 50 years)		12,957		3,704

	$	426,862	$	530,619

Regulatory liabilities were as follows:


December 31	2009		2008
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	280,674	$	282,400
Retirement benefit plans (5 years beginning with respective utility’s next rate case; 5 years remaining for HECO’s $4 million regulatory liability)		5,193		4,718
Other (1 to 5 years)		2,347		1,484

	$	288,214	$	288,602

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 interim rate case decisions for HECO, MECO and HELCO in 2007 (see Note 10).

7. Income taxes

The components of income taxes charged to operating expenses were as follows:


Years ended December 31	2009			2008			2007
(in thousands)
Federal:
Current	$	27,857		$	44,759		$	54,767
Deferred		15,621			6,040			(22,853	)
Deferred tax credits, net		(593	)		(1,094	)		(1,154	)

		42,885			49,705			30,760

State:
Current		7,123			6,522			5,073
Deferred		(464	)		(1,391	)		(3,699	)
Deferred tax credits, net		(1,332	)		1,471			1,992

		5,327			6,602			3,366

Total	$	48,212		$	56,307		$	34,126

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $0.4 million, $0.5 million and $3.2 million for 2009, 2008 and 2007, respectively.

A reconciliation between income taxes charged to operating expenses and 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	2009			2008			2007
(in thousands)
Amount at the federal statutory income tax rate	$	45,646		$	52,907		$	32,559
Increase (decrease) resulting from:
State income taxes on operating income, net of effect on federal income taxes		3,463			4,291			2,188
Other		(897	)		(891	)		(621	)

Income taxes charged to operating expenses	$	48,212		$	56,307		$	34,126

Effective income tax rate		37.2	%		37.5	%		38.7	%

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


December 31	2009		2008
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	109,210	$	109,882
Contributions in aid of construction and customer advances		77,766		78,834
Retirement benefits (AOCI)		1,541		—
Other		18,985		16,529

		207,502		205,245

Deferred tax liabilities:
Property, plant and equipment		338,910		313,250
Regulatory assets, excluding amounts attributable to property, plant and equipment		31,947		30,240
Retirement benefits		—		4,728
Change in accounting method related to contributions in aid of construction		8,010		16,020
Retirement benefits in Accumulated Other Comprehensive Income (AOCI)		1,135		1,052
Other		8,103		6,265

		388,105		371,555

Net deferred income tax liability	$	180,603	$	166,310

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.

The Company records interest expense on income taxes in “Interest and other charges.” For 2009, 2008 and 2007, interest expense on income taxes was $0.5 million, $0.5 million and $0.6 million, respectively. The Company will record associated penalties, if any, in “Other, net” under “Other income”. As of December 31, 2009 and 2008, the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet was $2.1 million and $1.7 million, respectively.

As of December 31, 2009, the total amount of liability for uncertain tax positions was $5.3 million and, of this amount, $0.3 million, if recognized, would affect the Company’s effective tax rate. Management concluded that it is reasonably possible that the liability for uncertain tax positions will significantly change within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service and estimates the range of the reasonably possible change to be a decrease of between nil and $4.2 million in 2010.

The changes in total unrecognized tax benefits were as follows:


Years ended December 31	2009			2008
(in millions)
Unrecognized tax benefits, January 1	$	24.2		$	24.4
Additions based on tax positions taken during the year		—			—
Reductions based on tax positions taken during the year		—			—
Additions for tax positions of prior years		0.4			0.1
Reductions for tax positions of prior years		(0.5	)		(0.3	)
Decreases due to tax positions taken		—			—
Settlements		—			—
Lapses of statute of limitations		—			—

Unrecognized tax benefits, December 31	$	24.1		$	24.2

In addition to the liability for uncertain tax positions, the Company’s unrecognized tax benefits include $18.7 million of tax benefits related to refund claims, which did not meet the recognition threshold. Consequently, tax

benefits have not been recorded on these claims and no liability for uncertain tax positions was required to offset these potential benefits.

Tax years 2003 to 2008 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii.

As of December 31, 2009, 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

Cash paid for interest to HEI and non-affiliates (net of AFUDC-Debt) and income taxes was as follows:


Years ended December 31	2009		2008		2007
(in thousands)
Interest	$	43,616	$	48,357	$	47,155

Income taxes	$	24,309	$	91,043	$	26,106

Supplemental disclosures of noncash activities

In 2009, 2008 and 2007, HECO and its subsidiaries capitalized as part of the cost of electric utility plant an allowance for equity funds used during construction amounting to $12 million, $9 million and $5 million, respectively.

In 2009, 2008 and 2007, the estimated fair value of noncash contributions in aid of construction amounted to $12 million, $10 million and $18 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 10% ($199 million), 10% ($295 million) and 9% ($194 million) of their operating revenues from the sale of electricity to various federal government agencies in 2009, 2008 and 2007, respectively.

10. Retirement benefits

Pensions

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, non-contributory 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 Directors’ Plan 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). Health benefits are also provided to dependents of eligible retired employees. The contribution for health benefits paid by the participating employers is based on the retirees’ years of service and retirement dates. Generally, employees are eligible for these benefits if, upon retirement from active employment, they are eligible to receive benefits from the Plan.

In the third quarter 2009, (1) the Company amended the executive life benefit plan to limit it to current participants and to freeze the executive life benefits at current levels and (2) HECO eliminated the electric discount benefit for retirees. The Company’s cost for postretirement benefits other than pensions has been adjusted to reflect the plan amendment, which reduced benefits. The elimination of HECO’s electric discount benefit will generate credits through other benefit costs over the next few years as the total amendment credit is amortized.

Among other provisions, the HECO Benefits Plan provides prescription drug benefits for Medicare-eligible participants who retire after 1998. Retirees who are eligible for the drug benefits are required to pay a portion of the cost each month. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the 2003 Act) expanded Medicare to include for the first time coverage for prescription drugs. The 2003 Act provides that persons eligible for Medicare benefits can enroll in Part D, prescription drug coverage, for a monthly premium. Alternatively, if an employer sponsors a retiree health plan that provides benefits determined to be actuarially equivalent to those covered under the Medicare standard prescription drug benefit, the employer will be paid a subsidy of 28 percent of a participant’s drug costs between $250 and $5,000 (indexed for inflation) if the participant waives coverage under Medicare Part D.

The continuation of the HECO Benefits Plan and the payment of any contribution thereunder is not assumed as a contractual obligation by the participating employers. 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

In September 2006, the FASB issued a standard that requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in stockholders’ equity (using the projected benefit obligation (PBO), rather than the accumulated benefit obligation (ABO), to calculate the funded status of pension plans).

By application filed on December 8, 2005 (AOCI Docket), the electric utilities requested the PUC to permit them to record, as a regulatory asset pursuant to current accounting standards on the effects of regulation, the amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension liability as prescribed by the current accounting standard. The electric utilities updated their application in the AOCI Docket in November 2006 to take into account an accounting standard requiring balance sheet recognition of the funded status of retirement plans. On January 26, 2007, the PUC issued a D&O in the updated AOCI Docket, which denied the electric utilities’ request to record a regulatory asset on the grounds that the electric utilities had not met their burden of proof to show that recording a regulatory asset was warranted, or that there would be adverse consequences if a regulatory asset was not recorded. The PUC also required HECO to submit a pension study (determining whether ratepayers are better off with a well-funded pension plan, a minimally-funded pension plan, or something in between) in its pending 2007 test year rate case, as proposed by the electric utilities in support of their request.

In HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the utilities and the Consumer Advocate proposed adoption of pension and OPEB tracking mechanisms, which are intended to smooth the impact to ratepayers of potential fluctuations in pension and OPEB costs.

In the PUC’s 2007 interim decisions in HELCO’s 2006 test year rate case and HECO and MECO’s 2007 test year rate cases, the PUC allowed the utilities to adopt pension and OPEB tracking mechanisms. 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 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 expenses (except for executive life and nonqualified pension plan expenses, which amounted to $1.5 million in 2009) determined in accordance with U.S. generally accepted accounting principles 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.

In the PUC’s 2007 interim decision on HELCO’s 2006 test year rate case, 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 the PUC’s 2007 interim decisions on HECO and MECO’s 2007 test year rate cases (and in its final decision on HECO’s 2005 test year rate case), the PUC did not 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 (IRC).

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 (or was, in the case of MECO) recovered in rates (as NPPC is recorded in excess of contributions). As of December 31, 2009, MECO did not have any remaining pension asset, and HECO’s pension asset had been reduced to $7 million.

The OPEB tracking mechanisms generally require the electric utilities 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.

As a result of the 2007 interim orders, the electric utilities have 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 $(124) million pre-tax, $249 million pre-tax and $171 million pre-tax at December 31, 2009, December 31, 2008 and December 31, 2007, respectively.

Retirement benefits expense for the electric utilities for 2009, 2008 and 2007 was $32 million, $27 million and $27 million, respectively.

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 2009 and 2008 and the funded status of these plans and amounts related to these plans reflected in the Company’s balance sheet as of December 31, 2009 and 2008 were as follows:



	2009						2008
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Benefit obligation, January 1	$	872,842		$	175,560		$	903,012		$	181,926
Service cost		24,577			4,699			26,902			4,643
Interest cost		56,095			10,648			53,973			10,699
Amendments		109			(13,199	)		—			—
Actuarial (gains) losses		17,203			(3,180	)		(65,390	)		(12,541	)
Benefits paid and expenses		(48,025	)		(8,702	)		(45,655	)		(9,167	)

Benefit obligation, December 31		922,801			165,826			872,842			175,560

Fair value of plan assets, January 1		550,732			104,396			809,901			145,524
Actual return (loss) on plan assets		137,716			26,862			(218,941	)		(40,378	)
Employer contribution		14,759			9,327			5,294			8,402
Benefits paid and expenses		(44,290	)		(7,871	)		(45,522	)		(9,152	)

Fair value of plan assets, December 31		658,917			132,714			550,732			104,396

Accrued benefit liability, December 31		(263,884	)		(33,112	)		(322,110	)		(71,164	)

AOCI, January 1 (excluding impact of PUC D&Os)		366,133			51,404			153,206			15,909
Recognized during year – net recognized transition obligation		—			(1,822	)		—			(3,130	)
Recognized during year – prior service credit		747			92			762			—
Recognized during year – net actuarial losses		(14,697	)		(381	)		(6,577	)		—
Occurring during year – prior service cost		109			(2,477	)		—			—
Occurring during year – net actuarial losses (gains)		(73,094	)		(21,977	)		218,742			38,625
Other adjustments		—			(10,721	)		—			—

		279,198			14,118			366,133			51,404
Cumulative impact of PUC D&Os		(278,582	)		(17,650	)		(365,874	)		(54,365	)

AOCI, December 31		616			(3,532	)		259			(2,961	)

Net actuarial loss		281,698			16,528			369,489			38,886
Prior service gain		(2,500	)		(2,385	)		(3,356	)		—
Net transition obligation		—			(25	)		—			12,518

		279,198			14,118			366,133			51,404
Cumulative impact of PUC D&Os		(278,582	)		(17,650	)		(365,874	)		(54,365	)

AOCI, December 31		616			(3,532	)		259			(2,961	)
Income taxes		(240	)		1,374			(101	)		1,152

AOCI, net of taxes, December 31	$	376		$	(2,158	)	$	158		$	(1,809	)

The Company does not expect any plan assets to be returned to the Company during calendar year 2010.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2009, 2008 and 2007.

The defined benefit pension plans’ ABOs, which do not consider projected pay increases (unlike the PBOs shown in the table above), as of December 31, 2009 and 2008 were $828 million and $783 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. Other factors could cause changes to the required contribution levels. The Company’s current estimate of contributions to the qualified defined benefit plans and all other retirement benefit plans in 2010 is $33 million.

Additional guidance on funding relief for qualified defined benefit pension plans was received in March 2009 including: (1) IRS Notice 2009-22 relating to the application of new asset valuation rules included in the “Worker, Retiree, and Employer Recovery Act of 2008” and (2) publication of a “Special Edition March 2009 employee plans news” relating to yield curve selection for the target liability calculation. Additional guidance on minimum required

contribution determinations for 2010 was released in “Special Edition September 25, 2009 employee plans news” necessitating selection of a different yield curve for 2010 valuations forward from what was used for 2009. As a result, the Company estimates that the cash funding for the qualified defined benefit pension plans in 2010 and 2011 will be about $29 million and $45 million, respectively, which should fully satisfy the minimum required contribution, including requirements of the utilities pension tracking mechanisms and the Plan’s funding policy.

As of December 31, 2009, the benefits expected to be paid under the retirement benefit plans in 2010, 2011, 2012, 2013, 2014 and 2015 through 2019 amounted to $61 million, $63 million, $65 million, $67 million, $71 million and $398 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 net periodic benefit cost.

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	2009		2008		Target		Range		2009		2008		Target		Range
Asset category
Equity securities	68	%	62	%	70	%	65-75	%	67	%	63	%	70	%	65-75	%
Fixed income	32		37		30		25-35	%	33		37		30		25-35	%
Other ¹	—		1		—		—		—		—		—		—

	100	%	100	%	100	%			100	%	100	%	100	%

¹	Other includes alternative investments, which are relatively illiquid in nature and will remain as plan assets until an appropriate liquidation opportunity occurs.

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	2009		2008		2007		2009		2008		2007
Benefit obligation
Discount rate	6.50	%	6.625	%	6.125	%	6.50	%	6.50	%	6.125	%
Rate of compensation increase	3.5		3.5		4.0		NA		3.5		4.0
Net periodic benefit cost (years ended)
Discount rate	6.625		6.125		6.00		6.50		6.125		6.00
Expected return on plan assets	8.25		8.50		8.50		8.25		8.50		8.50
Rate of compensation increase	3.5		4.2		4.0		3.5		4.2		4.0

NA Not applicable

The Company based its selection of an assumed discount rate for 2010 net periodic cost and December 31, 2009 disclosure on a cash flow matching analysis that utilized bond information provided by Standard & Poor’s for all non-callable, high quality bonds (i.e., rated AA- or better) as of December 31, 2009. In selecting the expected rate of return on plan assets of 8.25% for 2010 net periodic benefit cost, 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. The methods of selecting the assumed discount rate and expected return on plan assets at December 31, 2009 did not change from December 31, 2008.

As of December 31, 2009, the assumed health care trend rates for 2010 and future years were as follows: medical, 10.0%, grading down to 5.0% for 2015 and thereafter; dental, 5.0%; and vision, 4.0%. As of December 31, 2008, the assumed health care trend rates for 2009 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2014 and thereafter; dental, 5.00%; and vision, 4.00%.

The components of net periodic benefit cost were as follows:


	Pension benefits									Other benefits
(in thousands)	2009			2008			2007			2009			2008			2007
Service cost	$	24,577		$	26,902		$	25,527		$	4,699		$	4,643		$	4,652
Interest cost		56,095			53,973			51,588			10,648			10,699			10,512
Expected return on plan assets		(50,838	)		(65,191	)		(61,101	)		(8,755	)		(10,789	)		(9,778	)
Amortization of net transition obligation		—			—			1			1,822			3,130			3,130
Amortization of net prior service gain		(747	)		(762	)		(762	)		(92	)		—			—
Amortization of net actuarial loss		14,697			6,577			10,486			381			—			—

Net periodic benefit cost		43,784			21,499			25,739			8,703			7,683			8,516
Impact of PUC D&Os		(10,570	)		5,859			1,195			(132	)		1,038			187

Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	33,214		$	27,358		$	26,934		$	8,571		$	8,721		$	8,703

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefits pension plans that will be amortized from AOCI or regulatory asset into net periodic pension benefit cost over 2010 are $(0.7) million, $6.7 million and nil, respectively. The estimated prior service credit, net actuarial loss and net transitional asset for other benefit plans that will be amortized from AOCI or regulatory asset into net periodic other than pension benefit cost over 2010 are $(0.2) million, de minimis and de minimis, respectively.

The Company recorded pension expense of $25 million, $20 million and $20 million and OPEB expense of $7 million each year in 2009, 2008 and 2007, respectively, and charged the remaining amounts primarily to electric utility plant.

All pension plans had ABOs exceeding plan assets as of December 31, 2009 and 2008. All other benefits plans had APBOs exceeding plan assets as of December 31, 2009 and 2008.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2009, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.1 million and the PBO by $2.1 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the PBO by $2.4 million.

11. Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel for multi-year periods, some through December 31, 2014 (at prices tied to the market prices of crude oil and petroleum products in the Far East and U.S. West Coast). Based on the average price per barrel as of January 1, 2010, the estimated cost of minimum purchases under the fuel supply contracts is $0.8 billion in each of 2010, 2011 and 2012 and a total of $0.9 billion for the period 2013 through 2014. The actual cost of purchases in 2010 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 $0.7 billion, $1.2 billion and $0.8 billion of fuel under contractual agreements in 2009, 2008 and 2007, respectively.

On December 2, 2009, HECO and Chevron Products Company, a division of Chevron USA, Inc. (Chevron) executed an amendment to their existing contract for the purchase/sale of low sulfur fuel oil (LSFO). The amendment modified the pricing formula, which could result in higher prices. The amended agreement terminates on April 30, 2013. On January 28, 2010, the PUC approved the amendment on an interim basis, and allowed HECO to include the costs incurred under the amendment in its ECAC, to the extent such costs are not recovered through HECO’s base rates. The costs recovered as a result of the interim decision are not subject to retroactive disallowance, provided HECO complies with the remaining procedural schedule, which includes additional discovery by the Consumer

Advocate, and there is no evidence of intentional misrepresentation or omission of facts by HECO or Chevron, or any other form of malfeasance.

HECO and Tesoro Hawaii Corporation are exploring whether there may be a mutually beneficial amendment to the terms of their LSFO contract.

Power purchase agreements. As of December 31, 2009, HECO and its subsidiaries had six firm capacity PPAs for a total of 540 megawatts (MW) of firm capacity. Purchases from these six independent power producers (IPPs) and all other IPPs totaled $500 million, $690 million and $537 million for 2009, 2008 and 2007, 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 2010 through 2014 and a total of $0.8 billion in the period from 2015 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 (see “Energy cost adjustment clauses” below). 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.

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

On October 20, 2008, the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State of Hawaii Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an Energy Agreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement). The Energy Agreement provides that the parties pursue a wide range of actions with the purpose of decreasing the State of Hawaii’s dependence on imported fossil fuels through substantial increases in the use of renewable energy and implementation of new programs intended to secure greater energy efficiency and conservation.

The parties recognize that the move toward a more renewable and distributed and intermittent power system will pose increased operating challenges to the utilities and that there is a need to assure that Hawaii preserves a stable electric grid to minimize disruption in service quality and reliability. They further recognize that Hawaii needs a system of utility regulation to transform the utilities from traditional sales-based companies to energy services companies while preserving financially sound utilities.

Many of the actions and programs included in the Energy Agreement require approval of the PUC in proceedings that need to be initiated by the PUC or the utilities.

Among the major provisions of the Energy Agreement most directly affecting HECO and its subsidiaries are the following:

Renewable energy and energy efficiency goals. The Energy Agreement provides for the parties to pursue an overall goal of providing 70% of Hawaii’s electricity and ground transportation energy needs from clean energy sources, including renewable energy and energy efficiency, by 2030. The ground transportation energy needs included in this goal include a contemplated move in Hawaii to electrification of transportation and the use of electric utility capacity in off peak hours to recharge vehicles and batteries. To promote the transportation goals, the Energy

Agreement provides for the parties to evaluate and implement incentives to encourage adoption of electric vehicles, and to lead by example by acquiring hybrid or electric-only vehicles for government and utility fleets.

To help achieve the HCEI goals, the Energy Agreement further provided for the parties to seek amendment to the Hawaii Renewable Portfolio Standards (RPS) law to (1) increase the current renewable energy requirements from 20% to 25% by the year 2020 and to add a further RPS goal of 40% by the year 2030, and (2) require that after 2014 the RPS goal be met solely with renewable energy generation versus including energy savings from energy efficiency measures (although energy savings from energy efficiency measures would be counted toward the achievement of the overall HCEI 70% goal). These changes to the RPS law were enacted in 2009.

In December 2007, the PUC issued a D&O approving a stipulated RPS framework to govern electric utilities’ compliance with the RPS law. In a follow up order in December 2008, the PUC approved a penalty of $20 for every MWh that an electric utility is deficient under Hawaii’s RPS law. The PUC noted, however, that this penalty may be reduced, in the PUC’s discretion, due to events or circumstances that are outside an electric utility’s reasonable control, to the extent the event or circumstance could not be reasonably foreseen and ameliorated, as described in the RPS law and in the RPS Framework. In addition, the PUC ordered that: (1) any penalties assessed against HECO and its subsidiaries for failure to meet the RPS will go into the Public Benefits Fund (PBF) account used to support energy efficiency and DSM programs and services, unless otherwise directed; and (2) the utilities will be prohibited from recovering any RPS penalty costs through rates.

To further encourage the contributions of energy efficiency to the overall HCEI goal, the Energy Agreement provided for the parties to seek establishment of energy efficiency goals through an Energy Efficiency Portfolio Standard. Such an Energy Efficiency Portfolio Standard was enacted as part of Act 155, which provided that the PUC shall establish the standards designed to achieve a reduction of 4,300 gigawatthours of electricity use statewide by 2030. The law also provides that the PUC shall establish interim goals for electricity use reduction to be achieved by 2015, 2020, and 2025, may revise the 2030 standard by rule or order to maximize cost-effective, energy-efficiency programs and technologies and may establish incentives and penalties to encourage achievement of these goals.

Public benefits fund (PBF). To help fund energy efficiency programs, incentives, program administration, customer education, and other related program costs, as expended by the third-party administrator for the energy efficiency programs or by program contractors, which may include the utilities, the Energy Agreement provides that the parties will request that the PUC establish a PBF that is funded by collecting 1% of the utilities’ revenues in years one and two after implementation of a PBF; 1.5% in years three and four; and 2% thereafter. In December 2008, the PUC issued an order directing the utilities to collect revenue equal to 1% of the projected total electric revenue of the utilities, of which 60% was to be collected via the DSM surcharge and 40% via the PBF surcharge. Beginning January 1, 2009, the 1% was assessed on customers of HECO and its subsidiaries. In November 2009, the PUC issued an order that the PBF surcharge for 2010 will collect revenues through a kilowatthour surcharge assessed statewide that is intended to target revenue equal to 1% of the projected total electric revenue, plus revenue taxes.

Clean Energy Infrastructure Surcharge (CEIS). The Energy Agreement provides for the establishment of a CEIS. The CEIS, which will need to be approved by the PUC, is to be designed to expedite cost recovery for a variety of infrastructure that supports greater use of renewable energy or grid efficiency within the utility systems (such as advanced metering, energy storage, interconnections and interfaces). The Energy Agreement provides that the surcharge should be available to recover costs that would normally be expensed in the year incurred and capital costs (including the allowed return on investment, AFUDC, depreciation, applicable taxes and other approved costs), and could also be used to recover costs stranded by clean energy initiatives. On November 28, 2008, HECO and the Consumer Advocate filed a joint letter informing the PUC that the Renewable Energy Infrastructure Program (REIP) Surcharge satisfies the Energy Agreement provision for an implementation procedure for the CEIS recovery mechanism and that no further regulatory action on the CEIS is necessary. An REIP Surcharge was approved by the PUC in December 2009. The utilities need to file for cost inclusion in the surcharge on a project-by-project basis.

Renewable energy projects. HECO and its subsidiaries will continue to negotiate with developers of currently proposed projects (identified in the Energy Agreement) to integrate into its grid approximately 1,100 MW from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave, and others. This includes HECO’s commitment to integrate, with the assistance of the State of Hawaii, up to 400 MW of wind

power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from wind farms proposed by developers to be built on the islands of Lanai and/or Molokai. Utilizing technical resources such as the U.S. Department of Energy national laboratories, HECO, along with the other parties, have committed to work together to evaluate, assess and address the operational challenges for integrating such a large increment of wind into its grid system on Oahu. The State and HECO have agreed to work together to ensure the supporting infrastructure needed for the Oahu grid is in place to reliably accommodate this large increment of wind power, including appropriate additional storage capacity investments and any required utility system connections or interfaces with the cable and the wind farm facilities. This includes work performed by HECO in February 2010 on behalf of the State to conduct a Request for Information (RFI) process for the development of an undersea cable system. The primary objective of the RFI process is to dialogue with and collect information from market participants that have knowledge and experience in alternative business structures and financing mechanisms relevant to the planned development of the undersea cable system. The information collected from experienced undersea cable system developers, equipment suppliers, and project financiers participating in the RFI process, combined with the results from ongoing technical analyses focused on developing the preferred cable system architecture and functional requirements, is intended to guide subsequent activity to develop and issue an invitation to bid or request for proposal for the undersea cable system.

The State has agreed to seek, with HECO and/or developers’ reasonable assistance, federal grant or loan assistance to pay for the undersea cable system. In the event federal funding is unavailable, the State will employ its best effort to fund the undersea cable system through a prudent combination of taxpayer and ratepayer sources. There is no obligation on the part of HECO to fund any of the cost of the undersea cable. However, in the event HECO funds any part of the cost to develop the undersea cable system and assumes any ownership of the cable system, all reasonably incurred capital costs and expenses are intended to be recoverable through the REIP.

Feed-in tariff (FIT). As another method of accelerating the acquisition of renewable energy by the utilities, the Energy Agreement includes support for the parties to develop a FIT system with standardized purchase prices for renewable energy. The PUC was requested to conclude an investigative proceeding by March 2009 to determine the best design for a FIT that supports the HCEI goals, considering such factors as categories of renewables, size or locational limits for projects qualifying for the FIT, what annual limits should apply to the amount of renewables allowed to utilize the FIT, what factors to incorporate into the prices set for FIT payments, and other terms and conditions. Based on these understandings, the Energy Agreement required that the parties request the PUC to suspend the pending intra-governmental wheeling and avoided cost (Schedule Q) dockets for a period of 12 months.

On October 24, 2008, the PUC opened an investigative proceeding to examine the implementation of FITs. The utilities and Consumer Advocate were named as initial parties to the proceeding and 18 other parties were granted intervenor or participant status. On December 23, 2008, the utilities and the Consumer Advocate filed a joint proposal on FITs that called for the establishment of simple, streamlined and broad standard payment rates, which can be offered to as many renewable technologies as feasible. It proposed that the initial FIT be focused on photovoltaics (PV), concentrated solar power, in-line hydropower and wind, with individual project sizes targeted to provide a greater likelihood of more straightforward interconnection, project implementation and use of standardized energy rates and power purchase contracting. The FIT would be regularly reviewed to update tariff pricing to applicable technologies, project sizes and annual targets. A FIT update would be conducted for all islands in the utilities’ service territory not later than two years after initial implementation of the FIT and every three years thereafter.

The FIT joint proposal also recommended that no applications for new net energy metering contracts be accepted once the FIT is formally made available to customers (although existing net energy metering systems under contract would be grandfathered), and no applications for new Schedule Q contracts would be accepted once a FIT is formally made available for the resource type. Schedule Q would continue as an option for qualifying projects of 100 kW and less for which a FIT is not available.

In September 2009, the PUC issued a D&O that sets forth general principles for the FIT, approved the FIT as a mechanism for the procurement of renewable resources and directed the parties to file a stipulated procedural schedule that governs tasks for implementing a FIT, including development of queuing and interconnection procedures, reliability standards and FIT rates. The D&O contemplates that, for the initial FIT, there will be rates for PV, concentrated solar power, onshore wind, and in-line hydropower projects up to 5 MW depending on technology

and location. There will also be a “baseline” FIT rate to encourage other renewable energy technologies. Net energy metering, competitive bidding, negotiated PPAs, Schedule Q, and avoided cost offerings will continue to exist as additional and complementary mechanisms to provide multiple avenues for the procurement of renewable energy. FIT rates will be based on the project cost and reasonable profit of a typical project. The rates will be differentiated by technology or resource, size, and interconnection costs; and will be levelized. The FIT program will be reexamined two years after it first becomes effective and every three years thereafter. The D&O directs the utilities to develop reliability standards for each company, and states that the PUC will direct the companies: (1) to establish FITs in their respective service territories; (2) to file status reports on the progress of the FIT program; and (3) to collaborate with the other parties to craft queuing and interconnection procedures that will minimize delays associated with numerous potential FIT projects and the various interconnection studies they could require.

In January 2010, the utilities and other intervenors filed their respective proposals for the tier 1 and 2 rates under the FIT for consideration by the PUC. Filings of Queuing and Interconnection Procedures and Reliability Standards were made in February 2010. Filing of proposed FIT Tier 3 (with pricing) is due in April 2010.

Net energy metering (NEM). The Energy Agreement also provides that system-wide caps on NEM should be removed after implementation of the FITs. Instead, all distributed generation interconnections, including net metered systems, should be limited on a per-circuit basis to no more than 15% of peak circuit demand, to encourage the development of more cost effective distributed resources while still maintaining safe, reliable service.

In December 2008, HELCO, MECO and the Consumer Advocate filed stipulations to increase their NEM system caps from 1% to 3% of system peak demand (among other changes) and the PUC approved the proposed caps. The PUC directed the utilities and Consumer Advocate to file a proposed plan to address the provisions regarding NEM in the Energy Agreement, which plans were filed in August 2009. In January 2010, a stipulated agreement between the utilities and the Consumer Advocate was filed with the PUC that proposed the removal of the present system-wide cap with the adoption of revised interconnection standards to ensure ongoing reliability and safety, as well as the establishment of Reliability Standards. The proposal included adoption of a 15% per circuit distribution generation trigger for conducting further circuit-level impact studies; removal of individual NEM program caps in favor of more overall system-wide assessments; and use of Locational Value Maps, a component of a formal Clean Energy Scenario Planning framework as an indicator of circuit penetration levels.

Using biofuels. The Energy Agreement includes support of the parties for the development and use of renewable biofuels for electricity generation, including the testing of the technical feasibility of using biofuel or biofuel blends in HECO, HELCO and MECO generating units. The parties agree that use of biofuels in the utilities’ generating units, particularly biofuels from local sources, can contribute to achieving RPS requirements and decreasing greenhouse gas emissions, while avoiding major capital investment for new, replacement generation. In July 2009, HECO and MECO each filed applications for approval of biodiesel fuel supply contracts, the inclusion of the cost of the biodiesel fuel purchased under such contracts in their respective ECACs and, in the case of HECO, the commitment of funds in excess of $2.5 million (estimated at $5.2 million) for the purchase of capital equipment, in connection with proposed demonstration projects to test the use of biofuels to determine, in the case of HECO, the maximum blend of biofuels with low sulfur fuels for use in its steam electric generation units and, in the case of MECO, biodiesel’s potential as a primary fuel in utility scale diesel engines with the objective of evaluating the longer term effects biodiesel will have on efficiency, emissions, storage and handling, operations and other issues. In September 2009, the PUC denied the application of Life of the Land to intervene in the two proceedings, but allowed it to participate with respect to the issue of the environmental sustainability of palm oil base biodiesel. In December 2009, the parties and participant in the respective dockets reached agreement on all of the issues and filed joint motions for approval of a stipulation, which recommends approval of the biofuel fuel supply contract applications.

In December of 2009, HECO also filed an application of a two-year biodiesel supply contract for the supply of biodiesel fuel primarily for use in operating HECO CIP CT-1.

Decoupling rates from sales. In recognition of the need to recover the infrastructure and other investments required to support significantly increased levels of renewable energy and to eliminate the potential conflict between encouraging energy efficiency and conservation and lower sales revenues, the parties to the Energy Agreement agreed that it is appropriate to adopt a regulatory rate-making model, which is subject to PUC approval, under which

HECO, HELCO and MECO revenues would be decoupled from KWH sales. If approved by the PUC, the new regulatory model, which could be similar to the regulatory models currently used in California, would employ a revenue adjustment mechanism to track on an ongoing basis the differences between the amount of revenues allowed in the last rate case and (a) the current costs of providing electric service and (b) a reasonable return on and return of additional capital investment in the electric system. The utilities would also continue to use existing PUC-approved tracking mechanisms for pension and other post-retirement benefits. The utilities would also be allowed an automatic revenue adjustment mechanism to reflect changes in state or federal tax rates.

On October 24, 2008, the PUC opened an investigative proceeding to examine implementing a decoupling mechanism for the utilities. In addition to the utilities and the Consumer Advocate, there are five other parties in the proceeding. The utilities and the Consumer Advocate filed a joint final statement of position in May 2009. Panel hearings at the PUC were completed on July 1, 2009. Briefing by the parties was completed in September 2009. In November 2009, the utilities filed a motion for interim approval of a decoupling mechanism for the utilities.

In its 2009 test year rate case, HECO proposed to establish a revenue balancing account (RBA) to be effective upon the issuance of the interim D&O, but the PUC deferred consideration of the proposal pending the outcome of the decoupling proceeding. The Energy Agreement also contemplated that additional rate cases based on a 2009 test year would be filed by HELCO and MECO in order to provide their respective baselines for implementation of the new regulatory model, but HELCO and MECO were unable to file 2009 test year rate case applications. MECO filed its general rate increase application on September 30, 2009, requesting approval of a revenue increase of 9.7%, or $28.2 million, over revenues at current rates. HELCO’s general rate increase application was filed on December 9, 2009, seeking a revenue increase of 6.0%, or $20.9 million, over revenues at current rates.

ECAC. The Energy Agreement confirms that the existing ECAC will continue, subject to periodic review by the PUC. As part of that review, the parties agree that the PUC will examine whether there are renewable energy projects from which the utilities should have, but did not, purchase energy or whether alternate fuel purchase strategies were appropriately used or not used.

Purchased power surcharge. Pursuant to the Energy Agreement, with PUC approval, a separate surcharge would be established to allow the utilities to pass through all reasonably incurred purchased power costs, including all capacity, operation and maintenance expenses and other non-energy payments.

In December 2008, HECO filed updates to its 2009 test year rate case. The updates proposed the establishment of a purchased power adjustment clause to recover non-energy purchased power costs approved by the PUC, which are currently recovered through base rates, with the purchased power adjustment clause to be adjusted monthly and reconciled quarterly. In their 2010 test year rate cases, MECO and HELCO each proposed the same purchased power adjustment clause proposed by HECO in its 2009 test year rate case.

Other initiatives. The Energy Agreement includes a number of other undertakings intended to accomplish the purposes and goals of the HCEI, subject to PUC approval and including, but not limited to: (a) promoting through specifically proposed steps greater use of solar energy through solar water heating, commercial and residential PV energy installations and concentrated solar power generation; (b) providing for the retirement or placement on reserve standby status of older and less efficient fossil fuel fired generating units as new, renewable generation is installed; (c) improving and expanding “load management” and “demand response” programs that allow the utilities to control customer loads to improve grid reliability and cost management; (d) the filing of PUC applications for approval of the installation of Advanced Metering Infrastructure, coupled with time-of-use or dynamic rate options for customers; (e) supporting prudent and cost effective investments in smart grid technologies, which become even more important as wind and solar generation is added to the grid; (f) delinking prices paid under all new renewable energy contracts from oil prices; and (g) exploring the possibility of establishing lifeline rates designed to provide a cap on rates for those who are unable to pay the full cost of electricity. The utilities’ proposed Lifeline Rate Program, submitted for PUC approval at the end of April 2009, would provide a monthly bill credit to qualified, low-income customers. In December 2009, the Consumer Advocate filed a statement of position on the Lifeline Rate program stating it has no objections to implementing the program on a pilot basis for a period of no less than three years to allow time to evaluate the benefits of the program.

Interim increases. On April 4, 2007, the PUC issued an interim D&O in HELCO’s 2006 test year rate case granting an annual increase of $24.6 million, or 7.58%, which was implemented on April 5, 2007.

On October 22, 2007, the PUC issued, and HECO immediately implemented, an interim D&O in HECO’s 2007 test year rate case, granting an annual increase of $70 million, a 4.96% increase over rates effective at the time of the interim decision ($78 million over rates granted in the final decision in HECO’s 2005 test year rate case).

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

On July 2, 2009, the PUC issued an interim D&O in HECO’s 2009 test year rate case, which approved a rate increase for interim purposes, but directed that adjustments be made to reduce the increase reflected in HECO’s statement of probable entitlement. HECO calculated the interim increase amount at $61.1 million annually, or a 4.7% increase, and submitted the information to the PUC on July 8, 2009. The PUC approved HECO’s calculation and HECO implemented the interim increase on August 3, 2009.

As of December 31, 2009, HECO and its subsidiaries had recognized $281 million of revenues with respect to interim orders ($5 million related to interim orders regarding certain integrated resource planning costs and $276 million related to interim orders regarding 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.

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

In April and December 2007, the PUC issued interim D&Os in the HELCO 2006 and MECO 2007 test year rate cases that reflected for purposes of the interim order the continuation of their ECACs, consistent with agreements reached between the Consumer Advocate and HELCO and MECO, respectively. The Consumer Advocate and MECO agreed that no further changes are required to MECO’s ECAC in order to comply with the requirements of Act 162. In October 2007, the PUC issued an interim D&O in the HECO 2007 test year rate case, which reflected the continuation of HECO’s ECAC for purposes of the interim increase.

Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the utilities’ existing ECACs, but the Energy Agreement confirms the intent of the parties that the existing ECACs will continue, subject to periodic review by the PUC. As part of that periodic review, the parties agree that the PUC will examine whether there are renewable energy projects from which the utility should have, but did not, purchase energy or whether alternate fuel purchase strategies were appropriately used or not used.

Major projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if the PUC disallows cost recovery for all or part of 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 (with capitalized and deferred costs accumulated through December 31, 2009 noted in parentheses) include HECO’s Campbell Industrial Park (CIP) combustion turbine No. 1 (CT-1) and transmission line ($193 million), HECO’s East Oahu Transmission Project ($49 million), HELCO’s ST-7 ($90 million) and HECO’s Customer Information System (CIS) ($24 million).

CIP CT-1 and transmission line. HECO has built a new 110 MW simple cycle combustion turbine (CT) generating unit at CIP and has added an additional 138 kilovolt transmission line to transmit power from generating units at CIP (including the new unit) to the rest of the Oahu electric grid (collectively, the Project). The CT completed all utility requirements for system operation on August 3, 2009. Current plans are for the CT to be run primarily as a “peaking” unit and to be fueled by biodiesel, when a supply of biodiesel fuel becomes available.

In December 2006, HECO filed with the PUC an agreement with the Consumer Advocate in which HECO committed to use 100% biofuels in its new plant and to take the steps necessary for HECO to reach that goal. In May 2007, the PUC issued a D&O approving the Project and the DOH issued the final air permit, which became effective at the end of June 2007. The D&O further stated that no part of the Project costs may be included in HECO’s rate base unless and until the Project is in fact installed, and is used and useful for public utility purposes.

In its 2009 test year rate case, HECO requested inclusion of CIP CT-1 costs in rate base when the unit is placed in service, but the PUC did not grant the request, indicating that the record did not yet demonstrate that the unit would be in service by the end of 2009. Subsequently, CIP CT-1 completed all utility requirements for system operation on August 3, 2009, including synchronizing into the grid and performing all operational tests necessary for commercial operation. In November 2009, HECO filed a motion for a second increase to recover CIP CT-1 costs by allowing HECO to include the costs in its rate base or by allowing HECO to continue to accrue AFUDC on the costs.

In August 2007, HECO entered into a contract with Imperium Services, LLC (Imperium), to supply biodiesel for the planned generating unit, subject to PUC approval. In January 2009, HECO and Imperium amended the contract, Imperium assigned the contract to Imperium Grays Harbor, LLC (Imperium GH), and HECO filed the amended contract with the PUC. In August 2009, the PUC denied approval of the amended HECO contract with Imperium GH and a related terminalling and trucking agreement, indicating that HECO did not satisfy the burden of proof that the contracts, the costs of which will be passed directly to the ratepayers, were reasonable, prudent and in the public interest. The PUC also stated it “remains strongly supportive of biofuels and other renewable energy resources. The commission’s decision herein is not intended to reflect a decision as to the prudency of biodiesel or the proposed biodiesel feedstock.” As a result of the PUC decision, the amended contract was terminated.

In October 2009, a process was established with PUC approval to allow HECO to use CIP CT-1 for critical load purposes, which HECO has done on one occasion.

On October 2, 2009, HECO filed an application with the PUC for approval of a biodiesel supply contract for the CIP CT-1 biodiesel emissions data project and to include the contract costs in HECO’s ECAC. The application also requests that HECO be allowed to use biodiesel blended with no more than 1% petroleum diesel (in addition to 100% biodiesel) to benefit from the federal biofuel blenders’ tax credit if available. On October 6, 2009, HECO purchased approximately 400,000 gallons of biodiesel under the biodiesel supply contract, although the recovery of costs under the contract has not yet been approved by the PUC. Subsequently, testing using biodiesel was completed to determine the appropriate control settings using biodiesel and to obtain data necessary for modification of the unit’s air permit.

On December 21, 2009, HECO entered into a two-year contract with Renewable Energy Group (REG) to supply biodiesel for the generating unit, subject to PUC approval. On December 22, 2009, HECO filed an application with the PUC for approval of the fuel contract with REG and to include the contract costs in HECO’s ECAC.

As of December 31, 2009, HECO’s cost estimate for the Project was $196 million (of which $193 million had been incurred, including $9 million of AFUDC). To the extent actual project costs are higher than the $163 million estimate included in the 2009 test year rate case, HECO plans to seek recovery in a future proceeding. Management believes no adjustment to project costs is required as of December 31, 2009. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service.

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

HECO continued to believe that the proposed reliability project was needed and, in 2003, filed an application with the PUC requesting approval to commit funds (then estimated at $56 million) for an EOTP, revised to use a 46 kV system and a modified route, none of which is in conservation district lands. The environmental review process for the EOTP, as revised, was completed in 2005.

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

As a result of higher than estimated construction costs, an increase in the cost of materials and the overall delay in the project, the project is currently estimated to cost $74 million and HECO plans to construct the EOTP in two phases. The first phase is currently in construction and projected to be completed in 2010. The second phase is projected to be completed in 2013. HECO, however, is evaluating an alternative that might result in faster implementation and lower cost for the second phase. A portion of this alternative has been awarded funding through the Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009. PUC approval is required before the alternative can be implemented.

As of December 31, 2009, the accumulated costs recorded for the EOTP amounted to $49 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $15 million of planning, permitting and construction costs incurred after 2002 and (iii) $22 million for AFUDC. Management believes no adjustment to project costs is required as of December 31, 2009. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

HELCO generating units. In 1991, HELCO began planning to meet increased demand for electricity forecast for 1994. HELCO planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time the units would be converted to a 56 MW (net) dual-train combined-cycle unit. In January 1994, the PUC approved expenditures for CT-4. In 1995, the PUC allowed HELCO to pursue construction of and commit expenditures for CT-5 and ST-7, but noted that such costs are not to be included in rate base until the project is installed and “is used and useful for utility purposes.”

There were a number of environmental and other permitting challenges to construction of the units, including several lawsuits, which resulted in significant delays. However, in 2003, all but one of the parties actively opposing the plant expansion project entered into a settlement agreement with HELCO and several Hawaii regulatory agencies (the Settlement Agreement) intended in part to permit HELCO to complete CT-4 and CT-5. The Settlement Agreement required HELCO to undertake a number of actions, which have been completed or are ongoing. As a result of the final resolution of various proceedings due primarily to the Settlement Agreement, there are no pending lawsuits involving the project.

CT-4 and CT-5 became operational in mid-2004 and currently can be operated as required to meet HELCO’s system needs, but additional efforts have been ongoing to achieve compliance with the night-time noise standard in the Settlement Agreement and/or to modify the standard.

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

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

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

On June 22, 2009, ST-7 was placed into service. As of December 31, 2009, HELCO’s cost estimate for ST-7 was $92 million (of which $90 million had been incurred). HELCO is seeking to recover the costs of ST-7 in HELCO’s 2010 test year rate case.

Management believes no adjustment to project costs is required at December 31, 2009. However, if it becomes probable that the PUC will disallow for rate-making purposes additional CT-4 and CT-5 costs in its final D&O in HELCO’s 2006 rate case or disallow any ST-7 costs in HELCO’s 2010 rate case, HELCO will be required to record an additional write-off.

Customer Information System (CIS) Project. On August 26, 2004, HECO, HELCO and MECO filed a joint application with the PUC for approval of the accounting treatment and recovery of certain costs related to acquiring and implementing a new CIS. The application stated that the new CIS would allow the utilities to (i) more quickly and accurately store, maintain and manage customer-specific information necessary to provide basic customer service functions, such as producing bills, collecting payments, establishing service and fulfilling customer requests in the field, and (ii) have substantially greater capabilities and features than the existing system, enabling the utilities to enhance their operations, including customer service. In a D&O filed on May 3, 2005, the PUC approved the utilities’ request to (i) expend the then-estimated amount of $20.4 million for the new 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 an allowance for funds used during construction 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.

Following a competitive bidding process, HECO signed a contract with Peace Software US Inc. (Peace) in March 2006 to have Peace develop, deliver and implement the new CIS (implementation contract), with a transition to the new CIS originally scheduled to occur in February 2008. The transition did not occur as scheduled. In June 2008, HECO notified Peace that HECO considered Peace to be in material breach of the implementation contract because of Peace’s failure to satisfy the project schedule. In July 2008, HECO notified the PUC that, due to cost overruns and other issues, the total estimated cost of the project had increased to $39.5 million and the transition to the new CIS would be postponed to 2009. In April 2009, HECO notified the PUC that, due to the delays and other issues, a transition to the new CIS was no longer expected to occur in 2009. Through August 2009, HECO attempted to work with Peace to develop a plan to minimize additional delay and complete installation of the new CIS using the Peace software, despite Peace’s failure to cure the breaches identified by HECO in June 2008. However, on August 31, 2009, Peace provided HECO a notice of termination of the implementation contract, alleging that HECO had wrongfully withheld payment of invoices under the contract. Peace filed a lawsuit against HECO the same day in the Hawaii United States District Court. Peace alleges, among other things, that HECO breached the contract by not paying amounts due. HECO contends the lawsuit is without merit. On October 5, 2009, HECO filed its response to the Peace complaint and also filed a counterclaim against Peace for breach of contract and a third-party claim against Peace’s former owner, First Data Corporation, for tortious interference with HECO’s contract.

The CIS project will continue with HECO selecting a new software vendor and system integrator through a competitive bid process. The selections are expected to be made before the end of the second quarter of 2010. As of December 31, 2009, the accumulated deferred and capital costs recorded for the CIS amounted to $24 million.

HECO’s portion of the costs of the CIS project were originally included in HECO’s 2009 rate case, but were removed from that case when HECO no longer expected the system to be in place in 2009. Management believes no adjustment to project costs is required as of December 31, 2009. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

HCEI Projects. While much of the renewable energy infrastructure contemplated by the Energy Agreement will be developed by others (e.g., wind plant developments on Molokai and Lanai producing in aggregate up to 400 MW of wind power would be owned by a third-party developer, and the undersea cable system to bring the power generated by the wind plants to Oahu is currently planned to be owned by the State), the utilities may be making substantial investments in related infrastructure. In the Energy Agreement, the State agreed to support, facilitate and help expedite renewable projects, including expediting permitting processes.

In July 2009, HECO filed an application for the recovery of Big Wind Implementation Studies costs through the REIP Surcharge, which asked the PUC to approve the deferral and recovery of costs for studies and analyses needed to integrate large amounts of wind-generated renewable energy potentially located on the islands of Molokai and Lanai to the Oahu electric grid through a surcharge mechanism. On December 11, 2009, the PUC issued a D&O that allows HECO to defer costs for the Big Wind Implementation Studies for later review for prudence and reasonableness, but refrained from making any decision as to the specific recovery mechanism or the terms of any recovery mechanism (e.g. amortization period or carrying treatment).

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.

HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of responding to 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.

Additionally, current environmental laws may require HECO and its subsidiaries to investigate whether releases from historical operations may have contributed to environmental impacts, and, where appropriate, respond to such releases, even if they were not inconsistent with law or standard industrial practices prevailing at the time when they occurred. Such releases may involve area-wide impacts contributed to by multiple potentially responsible parties.

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

The Participating Parties have conducted subsurface investigations, assessments and preliminary oil removal tasks. A HECO investigation of its operations in the Iwilei Unit in 2003 and subsequent maintenance and inspections have confirmed that its facilities are not releasing petroleum.

The Participating Parties anticipate that that all remedial design work for the Iwilei Unit required under the Enforceable Agreement will be completed in 2010. The Participating Parties will begin implementation of remedial design elements as they are approved by the DOH.

Through December 31, 2009, HECO has accrued a total of $3.3 million for the estimated HECO share of costs for continuing investigative work, remedial activities and monitoring for the Iwilei unit. As of December 31, 2009, the remaining accrual (amounts expensed less amounts expended) for the Iwilei unit was $1.5 million. Because (1) the full scope of work remains to be determined, (2) the final cost allocation method among the PRPs has not yet been established and (3) management cannot estimate the costs to be incurred (if any) for the sites other than the Iwilei unit

(such as its Honolulu power plant located in the Downtown unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material costs may be incurred.

Regional Haze Rule amendments. In June 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule that require emission controls known as best available retrofit technology (BART) for industrial facilities emitting air pollutants that reduce visibility in National Parks by causing or contributing to regional haze. States were to develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. If a state does not develop a BART implementation plan, the EPA is required to develop a federal implementation plan (FIP) by 2011. To date, Hawaii has not developed a BART implementation plan. If any of the utilities’ generating units are ultimately required to install post-combustion control technologies to meet BART emission limits, the resulting capital and operation and maintenance costs could be significant.

Hazardous Air Pollutant (HAP) Control– Steam Electric Generating Units. In February 2008, the federal Circuit Court of Appeals for the District of Columbia vacated the EPA’s Delisting Rule, which had removed coal- and oil-fired electric generating units (EGUs) from the list of sources requiring control under Section 112 of the Clean Air Act. The Supreme Court dismissed appeals of the Circuit Court’s decision.

The EPA is required to develop Maximum Achievable Control Technology (MACT) standards for oil-fired EGU HAP emissions. The Clean Air Act mandates the average of the top performing 12% of existing sources (i.e., units with the lowest HAP emission rates) as the MACT standard for existing sources. The EPA’s issuance of an Information Collection Request (ICR) is the first step in the regulatory process to develop the MACT standards for utility EGUs. Under the current schedule in the ICR, all emissions testing on HECO units identified by EPA must be completed and emissions information submitted to EPA by September 4, 2010.

On October 22, 2009, the EPA filed in the United States District Court for the District of Columbia a proposed consent decree in American Nurses Association, et al. v. Jackson. The consent decree would require the EPA to propose MACT standards for coal- and oil-fired EGUs no later than March 16, 2011 and promulgate final standards no later than November 16, 2011. The EPA is required to respond to any adverse public comments before the consent decree becomes final.

Depending on the MACT standards developed (and the success of a potential challenge, after the MACT standards are issued, that the EPA inappropriately listed oil-fired EGUs initially), costs to comply with the standards could be significant.

Hazardous Air Pollutant (HAP) Control – Reciprocating Internal Combustion Engines (RICE). On February 17, 2010, the EPA issued final MACT standards that regulate HAPs from certain existing diesel compression ignition engines (Compression Ignition RICE). The EPA announced that it will also issue final MACT standards for certain gasoline and propane spark ignition engines (Spark Ignition RICE) by August 10, 2010. The Compression Ignition RICE MACT regulations require installation of pollution control devices on approximately 80 RICE at HECO and its subsidiaries’ facilities. Approximately 20 of HECO and its subsidiaries’ Compression Ignition RICE are required to implement only specified maintenance practices, rather than install pollution control devices. The Compression Ignition RICE MACT rule provides a three-year compliance period after the date of its publication in the Federal Register. Management is currently evaluating the impacts of the final Compression Ignition RICE rule, including capital expenditures and other compliance costs, and is also assessing the potential impacts of the proposed Spark Ignition RICE requirements.

Clean Water Act. Section 316(b) of the federal Clean Water Act requires that the EPA ensure that existing power plant cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. In 2004, the EPA issued a rule establishing design, construction and capacity standards for existing cooling water intake structures, such as those at HECO’s Kahe, Waiau and Honolulu generating stations, and required demonstrated compliance by March 2008. The rule provided a number of compliance options, some of which were far less costly than others. HECO had retained a consultant that was developing a cost effective compliance strategy.

In January 2007, the U.S. Circuit Court of Appeals for the Second Circuit issued a decision that remanded for further consideration and proceedings significant portions of the rule and found other portions to be impermissible, including the EPA’s use of a cost-benefit analysis to determine compliance options. In July 2007, the EPA formally suspended the rule and provided guidance to federal and state permit writers that they should use their “best professional judgment” in determining permit conditions regarding cooling water intake requirements at existing power plants.

On April 1, 2009, the U.S. Supreme Court issued an opinion ruling that it was permissible, but not required, for the EPA to rely on a cost-benefit analysis in developing cooling water intake standards under the Clean Water Act and to allow variances from the standards based on a cost-benefit comparison. Because it remains unclear what form the regulations will take and whether the EPA will retain the cost-benefit portions of the rule, management is unable to predict which compliance options, some of which could entail significant capital expenditures, will be applicable to its facilities. When issued, the applicable final cooling water intake requirements will be incorporated into the National Pollutant Discharge Elimination System permits governing HECO’s Kahe, Waiau and Honolulu Power Plants. It is anticipated that the EPA will issue draft rules in mid-2010.

Global climate change and greenhouse gas (GHG) emissions reduction. National and international concern about climate change and the contribution of GHG emissions to global warming have led to action by the state of Hawaii and federal legislative and regulatory proposals to reduce GHG emissions. Carbon dioxide emissions, including those from the combustion of fossil fuels, comprise the largest percentage of GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. It also establishes a task force, comprised of representatives of state government, business (including the electric utilities), the University of Hawaii and environmental groups, which is charged with preparing a work plan and regulatory approach for “implementing the maximum practically and technically feasible and cost-effective reductions in greenhouse gas emissions from sources or categories of sources of greenhouse gases” to achieve 1990 statewide GHG emission levels. The electric utilities are participating in the Task Force, as well as in initiatives aimed at reducing their GHG emissions, such as those to be undertaken under the Energy Agreement. The Task Force retained a consultant to prepare the work plan, which was submitted to the Hawaii Legislature in December 2009. The Task Force also unanimously recommended that the work plan include the HCEI as a means to meet the Act 234 GHG emission reduction goals, though costs and funding mechanisms would need further exploration and consideration. (For a discussion of the HCEI, see “Hawaii Clean Energy Initiative” above.) Because the regulations implementing Act 234 have not yet been developed or promulgated, management cannot predict the impact of Act 234 on the electric utilities.

In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009 (ACES). Among other things, ACES establishes a declining cap on GHG emissions requiring a 3% emissions reduction by 2012 that increases to 17% by 2020, 42% by 2030, and 83% by 2050. The ACES also establishes a trading and offset scheme for GHG allowances. The trading program combined with the declining cap is known as a “cap and trade” approach to emissions reduction. In September 2009, the U.S. Senate began consideration of the Clean Energy Jobs and American Power Act (S. 1733). S. 1733 also includes cap and trade provisions to reduce GHG emissions. Since then, several other approaches to GHG emission reduction have been either introduced or discussed in the U.S. Senate; however, no legislation has yet been enacted.

In response to the 2007 U.S. Supreme Court decision in Massachusetts v. EPA, which ruled that the Agency has the authority to regulate GHG emissions from motor vehicles under the Clean Air Act (CAA), the EPA has accelerated rulemaking addressing GHG emissions from both mobile and stationary sources. In April 2009, the EPA proposed making the finding that motor vehicle GHG emissions endanger public health or welfare. Management believes the EPA will make the same or similar endangerment finding regarding GHG emissions from stationary sources like the utilities’ generating units. On June 30, 2009, the EPA granted the California Air Resources Board’s request for a waiver from CAA preemption to enforce GHG emission standards for motor vehicles. On September 22, 2009, the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule. The rule requires that sources above certain threshold levels monitor and report GHG emissions beginning in 2010. On September 28, 2009, the EPA and the National Transportation Safety Administration jointly proposed federal GHG emission standards for motor vehicles.

In addition, the Prevention of Significant Deterioration (PSD) permit program of the CAA applies to any pollutant that is “subject to regulation” under the CAA. The PSD program applies to designated air pollutants from new or modified stationary sources, such as utility electrical generation units. Currently, the PSD program does not apply to GHGs. However, on October 27, 2009, the Federal Register published the EPA’s proposed “Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas (GHG) Tailoring Rule” that would create a new emissions threshold for GHG emissions from new and existing facilities. The proposed rule would phase in applicability thresholds for both PSD and Title V programs for sources of GHG emissions. The first phase would last for six years. The EPA would

conduct, if appropriate, another rulemaking by the end of the sixth year to revise applicability and significance level thresholds and other streamlining techniques. States may need to increase fees to cover the increased level of activity caused by this rule. If adopted in its current form, the proposed tailoring rule would require a number of existing HECO, HELCO and MECO facilities that are not currently subject to the Covered Source Permit program to submit an initial Covered Source Permit application to the DOH within one year following the effective date of the final rule. These rules are being proposed and adopted on a parallel track with federal climate change legislation. If comprehensive GHG emission control legislation is not adopted, then these (and other future) EPA rules would likely be finalized and be applicable to the utilities.

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, committing to burn renewable biodiesel in HECO’s CIP generating unit, using biodiesel for startup and shutdown of selected MECO generation units, and pursuing plans to test biofuel blends in other HECO and MECO generating units. HECO seeks to identify and support viable technology for electricity production that will increase energy efficiency and reduce or eliminate GHG emissions. Implementation of actions included in the Energy Agreement under the HCEI can further help achieve reduction or elimination of GHG emissions. Since the specific GHG reductions the electric utilities would have to meet under GHG reduction legislation and rule-making remain unclear, management is unable to evaluate the ultimate impact on the Company’s operations of eventual GHG regulation. However, the Company believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ carbon foot print and meeting GHG reduction goals that will ultimately emerge.

While the timing, extent and ultimate effects of global warming cannot be determined with any certainty, global warming is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the Company’s 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 and financial condition of the Company. For example, severe weather could cause significant harm to the Company’s physical facilities.

Given Hawaii’s unique geographic location and its isolated electric grids, physical risks of the type associated with climate change have been considered by the Company in the planning, design, construction, operation and maintenance of its facilities. To ensure the reliability of each island’s grid, the Company designs and constructs its electric generation system with greater levels of redundancy than is typical for mainland, interconnected systems. Although a major natural disaster could have severe financial implications, such risks have existed since the Company’s inception. The Company makes a concerted effort to consider such physical risks in the design, construction and operation of its facilities, and to prepare for a fast response in the event of an emergency.

The Company is undertaking an adaptation survey of its facilities as a step in developing a longer term strategy for responding to the consequences of global climate change.

BlueEarth Biofuels LLC. In January 2007, HECO and MECO agreed to form a venture with BlueEarth Biofuels LLC (BlueEarth) to develop a biodiesel production facility on MECO property on the island of Maui. BlueEarth Maui Biodiesel LLC (BlueEarth Maui), a joint venture to pursue biodiesel development, was formed in early 2008 between BlueEarth and Uluwehiokama Biofuels Corp. (UBC), a non-regulated subsidiary of HECO. In February 2008, an Operating Agreement and an Investment Agreement were executed between BlueEarth and UBC, under which UBC invested $400,000 in BlueEarth Maui in exchange for a minority ownership interest. MECO began negotiating with BlueEarth Maui for a fuel purchase contract for biodiesel to be used in existing diesel-fired units at MECO’s Maalaea plant. However, negotiations for the biodiesel supply contract stalled based on an inability to reach agreement on various financial and risk allocation issues. In October 2008, BlueEarth filed a civil action in federal district court in Texas against MECO, HECO and others alleging claims based on the parties’ failure to have reached agreement on the biodiesel supply and related land agreements. The lawsuit seeks damages and equitable relief. In April 2009, the venue of the action was transferred to Hawaii. A trial date has been scheduled for April 2011. Work on the project was suspended

because the litigation was filed. The Memorandum of Understanding (MOU) between HECO, MECO and BlueEarth regarding the project has also expired. Although HECO remains committed to supporting development of renewable fuels production, because of the filing of the litigation, the expiration of the MOU, and other factors, HECO and MECO now consider the project terminated and UBC’s investment in the venture was written off in 2009.

Apollo Energy Corporation/Tawhiri Power LLC. HELCO purchases energy generated at the Kamao’a wind farm pursuant to the Restated and Amended Power Purchase Contract for As-Available Energy (the RAC) dated October 13, 2004 between HELCO and Apollo Energy Corporation (Apollo), later assigned to Apollo’s affiliate, Tawhiri Power LLC (Tawhiri). The maximum allowed output of the wind farm is 20.5 MW. By letter to HELCO dated June 15, 2009, Tawhiri requested binding arbitration as provided for under the provisions of the RAC on the issue of HELCO’s curtailment of the wind farm output to 10 MW between October 9, 2007 and July 3, 2008. Tawhiri sought alleged damages for lost production in the amount of $13 million, plus unspecified damages for lost production tax credits, overhead losses, and consultant and legal fees. HELCO responded to Tawhiri’s arbitration request on July 2, 2009, stating, among other points, that the curtailment was justified because Tawhiri failed to meet the low voltage ride-through requirements of the RAC and improperly disconnected from the grid on October 9, 2007. A panel of three neutral arbitrators conducted a hearing which concluded on January 22, 2010. Briefs were filed in February 2010, and a decision is expected in March 2010.

By letter to Tawhiri dated September 23, 2009, HELCO requested binding arbitration as provided for under the provisions of the RAC on three issues related to the Kamao’a switching station under the terms of the RAC: (1) transfer of the title/bill of sale for the switching station to HELCO; (2) transfer of an interest in land for the switching station necessary for HELCO to operate and maintain it; and (3) reimbursements of certain of HELCO’s interconnection costs in connection with the construction of the switching station. HELCO also indicated the Tawhiri RAC would be terminated if Tawhiri did not cure its breaches under the RAC. On October 13, 2009, Tawhiri submitted its response, denying any breaches of the RAC that would justify its termination and stating that the issues related to interconnection costs involve the interpretation of the various orders of the PUC related to the RAC, rather than the interpretation and application of the terms and conditions of the RAC itself. On October 19, 2009, Tawhiri petitioned the PUC for a ruling that the RAC and the PUC’s order approving it required HELCO to reimburse Tawhiri $2.1 million for interconnections costs. The PUC denied Tawhiri’s petition and motion for reconsideration. Tawhiri filed a notice of appeal on January 25, 2010. On February 3, 2010, Tawhiri moved for a stay of the arbitration pending a decision on the appeal. The parties have selected arbitrators and, if no stay is granted, expect an arbitration of this matter in the second quarter of 2010.

In addition to the curtailment and switching station issues, HELCO and Tawhiri have a dispute relating to reconciliation of transmission line losses, which dispute has not yet proceeded to arbitration.

Asset retirement obligation. In July 2009, HECO hired an industrial hygienist to conduct an inspection at HECO’s Honolulu power plant to determine the extent of asbestos and lead-based paint at a non-operating portion of the plant. The inspection indicated that retired Generating Units Nos. 5 and 7 at the plant were now deteriorating, and the industrial hygienist recommended removing the asbestos-containing materials and lead-based paint. Based on prior assessments, HECO believed the timing of the removal of asbestos and lead-based paint was not estimable. The asbestos and lead-based paint, in their current state, do not pose any health risks, as these hazardous materials are confined to a sealed/vacant portion of the plant. Based on the recent study, however, HECO now intends to remove Units Nos. 5 and 7, including abating the asbestos and lead-based paint, over a 5-year period (2010 to 2014). In accordance with accounting principles for asset retirements and environmental obligations, in September 2009 HECO recorded an asset retirement obligation estimated at $23 million.

Collective bargaining agreements. As of December 31, 2009, approximately 56% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. On March 1, 2008, members of the union ratified new collective bargaining and benefit agreements with HECO, HELCO and MECO. The new agreements cover a three-year term, from November 1, 2007 to October 31, 2010, and provide for non-compounded wage increases of 3.5% effective November 1, 2007, 4% effective January 1, 2009 and 4.5% effective January 1, 2010.

Limited insurance. HECO and its subsidiaries purchase insurance to protect themselves against loss or damage to their properties against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $5 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations and financial condition could be materially adversely impacted. Also, certain insurance has substantial “deductibles”, limits on the maximum amounts that may be recovered and exclusions or limitations of coverage for claims related to certain perils. If a series of losses occurred, such as from a series of lawsuits in the ordinary course of business, each of which were subject to the deductible amount, or if the maximum limit of the available insurance were substantially exceeded, HECO, HELCO and MECO could incur losses in amounts that would have a material adverse effect on their results of operations and financial condition.

12. Regulatory restrictions on distributions to parent

As of December 31, 2009, 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 $4.5 million, $4.7 million and $3.4 million for general management and administrative services in 2009, 2008 and 2007, 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 and $41.6 million at December 31, 2009 and 2008, respectively. 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 $0.2 million in 2009 and de minimis in 2008 and 2007.

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 of financial instruments

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 market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided

for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered in determining such fair values.

Fair Value Measurements. 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 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 equivalents and short-term borrowings

The carrying amount approximated fair value because of the short maturity of these instruments.

Long-term debt

Fair value was obtained from a third-party financial services provider based on the current rates offered for debt of the same or similar remaining maturities.

Off-balance sheet financial instruments

Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

The estimated fair values of the financial instruments held or issued by the Company were as follows:


December 31	2009				2008
(in thousands)	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and equivalents	$	73,578	$	73,578	$	6,901	$	6,901

Financial liabilities:
Long-term debt, net, including amounts due within one year		1,057,815		1,018,900		904,501		660,380

Off-balance sheet item:
HECO-obligated preferred securities of trust subsidiary		50,000		48,480		50,000		40,420

Retirement benefit plans

On January 1, 2008, the retirement benefit plans (Plans) adopted new standards for fair value measurements of financial assets and liabilities and for fair value measurements of nonfinancial items that are recognized or disclosed at fair value in the financial statements on a recurring basis.

The Plans’ undivided interest in the HEI Master Pension Trust and the HEI Master Voluntary Employees’ Beneficiary Association (VEBA) Trust (collectively Trusts) at December 31, 2009 was as follows:


(in millions)	Pension benefits			Other benefits
Interest in HEI Master Pension Trust	$	677		$	24
Interest in HEI Master VEBA Trust		—			109

Total	$	677	¹	$	133

¹	The pension benefits fair value does not include accrued income, receivables and cash of $4 million and has not been reduced by payables of $22 million as of December 31, 2009.

Assets held in the Trusts, including the Plans’ undivided interests, 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 at December 31, 2009 were as follows:


	Pension benefits									Other benefits
	December 31, 2009		Fair value measurements using							December 31, 2009		Fair value measurements using
(in millions)	December 31, 2009		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)			Significant unobserv- able inputs (Level 3)		December 31, 2009		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobserv- able inputs (Level 3)
Equity securities	$	405	$	384	$	—		$	21	$	71	$	67	$	—	$	4
Equity index funds		70		70		—			—		46		46		—		—
Fixed income securities		241		32		209			—		8		1		7		—
Pooled and mutual funds		26		—		—			26		5		—		—		5
Other		18		—		(2	)		20		5		—		—		5

Total	$	760	$	486	$	207		$	67	$	135	$	114	$	7	$	14

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.

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, 2009 and 2008.

Equity securities, equity index funds and U.S. Treasury fixed income securities (Level 1). Valued at the closing price reported on the active market on which the individual securities are traded.

Fixed income securities (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, pooled and mutual funds, and other (Level 3). 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 valued at the net asset value per share. Certain other investments are valued based on discounted cash flow analyses. 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 2009, the changes in Level 3 assets were as follows:


	Pension benefits													Other benefits
(in thousands)	Equity invest- ments			Fixed income securities			Pooled and mutual funds		Other			Total		Equity invest- ments			Fixed income securities			Pooled and mutual funds			Other			Total
Balance, January 1	$	11,802		$	(185	)	$	22,824	$	15,200		$	49,641	$	2,223		$	(6	)	$	6,904		$	3,592		$	12,713
Realized gains		19			4			—		120			143		47			—			—			11			58
Unrealized gains related to instruments still held at December 31, 2009		9,024			544			—		5,421			14,989		1,601			18			—			1,624			3,243
Purchases, sales, issuances and settlements, net		(128	)		(4	)		3,589		(810	)		2,647		(2	)		—			(2,229	)		(80	)		(2,311	)

Balance, December 31	$	20,717		$	359		$	26,413	$	19,931		$	67,420	$	3,869		$	12		$	4,675		$	5,147		$	13,703

16. Sale of non-electric utility property

In August 2007, HECO sold land and a building that executives and management had been using as a recreational facility. The sale of the non-electric utility property resulted in an after-tax gain in the third quarter of 2007 of approximately $2.9 million.

17. Consolidating financial information (unaudited)

Consolidating balance sheet


	December 31, 2009
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassi- fications and Elimina- tions		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,075		5,109		4,346		—	—	—		$	52,530
Plant and equipment		2,833,296		995,585		867,376		—	—	—			4,696,257
Less accumulated depreciation		(1,081,441	)	(379,526	)	(387,449	)	—	—	—			(1,848,416	)
Construction in progress		115,644		10,920		6,416		—	—	—			132,980

Net utility plant		1,910,574		632,088		490,689		—	—	—			3,033,351

Investment in wholly owned subsidiaries, at equity		462,006		—		—		—	—	(462,006	)[2]		—

Current assets
Cash and equivalents		70,981		2,006		474		98	19	—			73,578
Advances to affiliates		20,100		—		11,000		—	—	(31,100	)[1]		—
Customer accounts receivable, net		89,365		24,502		19,419		—	—	—			133,286
Accrued unbilled revenues, net		58,022		13,648		12,606		—	—	—			84,276
Other accounts receivable, net		5,967		2,294		1,317		—	—	(1,129	)[1]		8,449
Fuel oil stock, at average cost		49,847		12,640		16,174		—	—	—			78,661
Materials & supplies, at average cost		18,378		4,006		13,524		—	—	—			35,908
Prepayments and other		10,163		4,268		2,614		—	—	(844	)[3]		16,201

Total current assets		322,823		63,364		77,128		98	19	(33,073	)		430,359

Other long-term assets
Regulatory assets		312,953		59,372		54,537		—	—	—			426,862
Unamortized debt expense		9,392		2,679		2,217		—	—	—			14,288
Other		47,502		9,718		16,312		—	—	—			73,532

Total other long-term assets		369,847		71,769		73,066		—	—	—			514,682

	$	3,065,250		767,221		640,883		98	19	(495,079	)	$	3,978,392

Capitalization and liabilities
Capitalization
Common stock equity	$	1,306,408		240,576		221,319		94	17	(462,006	)[2]	$	1,306,408
Cumulative preferred stock – not subject to mandatory redemption		22,293		—		—		—	—	—			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		—		7,000		5,000		—	—	—			12,000

Stockholders’ equity		1,328,701		247,576		226,319		94	17	(462,006	)		1,340,701
Long-term debt, net		672,200		211,248		174,367		—	—	—			1,057,815

Total capitalization		2,000,901		458,824		400,686		94	17	(462,006	)		2,398,516

Current liabilities
Short-term borrowings-affiliate		11,000		20,100		—		—	—	(31,100	)[1]		—
Accounts payable		103,073		17,369		12,269		—	—	—			132,711
Interest and preferred dividends payable		14,186		4,088		2,954		—	—	(5	)[1]		21,223
Taxes accrued		101,288		31,274		24,374		—	—	(844	)[3]		156,092
Other		28,956		8,670		11,684		4	2	(1,124	)[1]		48,192

Total current liabilities		258,503		81,501		51,281		4	2	(33,073	)		358,218

Deferred credits and other liabilities
Deferred income taxes		141,160		25,984		13,459		—	—	—			180,603
Regulatory liabilities		196,284		52,669		39,261		—	—	—			288,214
Unamortized tax credits		31,393		12,886		12,591		—	—	—			56,870
Retirement benefits liability		221,311		35,584		39,728		—	—	—			296,623
Other		36,113		30,207		11,484		—	—	—			77,804

Total deferred credits and other liabilities		626,261		157,330		116,523		—	—	—			900,114

Contributions in aid of construction		179,585		69,566		72,393		—	—	—			321,544

	$	3,065,250		767,221		640,883		98	19	(495,079	)	$	3,978,392

Consolidating balance sheet


	December 31, 2008
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassi- fications and Elimina- tions		HECO Consolidated
Assets
Utility plant, at cost
Land	$	33,213		4,982		4,346		—	—	—		$	42,541
Plant and equipment		2,567,018		874,322		836,159		—	—	—			4,277,499
Less accumulated depreciation		(1,028,501	)	(352,382	)	(360,570	)	—	—	—			(1,741,453	)
Construction in progress		188,754		68,650		9,224		—	—	—			266,628

Net utility plant		1,760,484		595,572		489,159		—	—	—			2,845,215

Investment in wholly owned subsidiaries, at equity		437,033		—		—		—	—	(437,033	)[2]		—

Current assets
Cash and equivalents		2,264		3,148		1,349		123	17	—			6,901
Advances to affiliates		62,000		—		12,000		—	—	(74,000	)[1]		—
Customer accounts receivable, net		109,724		32,108		24,590		—	—	—			166,422
Accrued unbilled revenues, net		74,657		17,876		14,011		—	—	—			106,544
Other accounts receivable, net		3,983		2,217		1,143		—	11	564	[1]		7,918
Fuel oil stock, at average cost		53,546		10,326		13,843		—	—	—			77,715
Materials & supplies, at average cost		16,583		4,366		13,583		—	—	—			34,532
Prepayments and other		6,918		2,311		3,664		—	—	(267	)[3]		12,626

Total current assets		329,675		72,352		84,183		123	28	(73,703	)		412,658

Other long-term assets
Regulatory assets		388,054		77,038		65,527		—	—	—			530,619
Unamortized debt expense		9,802		2,282		2,419		—	—	—			14,503
Other		38,099		7,699		7,197		—	119	—			53,114

Total other long-term assets		435,955		87,019		75,143		—	119	—			598,236

	$	2,963,147		754,943		648,485		123	147	(510,736	)	$	3,856,109

Capitalization and liabilities
Capitalization
Common stock equity	$	1,188,842		221,405		215,382		105	141	(437,033	)[2]	$	1,188,842
Cumulative preferred stock – not subject to mandatory redemption		22,293		—		—		—	—	—			22,293
Noncontrolling interest – cumulative preferred stock of subsidiaries – not subject to mandatory redemption		—		7,000		5,000		—	—	—			12,000

Stockholders’ equity		1,211,135		228,405		220,382		105	141	(437,033	)		1,223,135
Long-term debt, net		582,132		148,030		174,339		—	—	—			904,501

Total capitalization		1,793,267		376,435		394,721		105	141	(437,033	)		2,127,636

Current liabilities
Short-term borrowings-affiliate		53,550		62,000		—		—	—	(74,000	)[1]		41,550
Accounts payable		84,238		27,795		10,961		—	—	—			122,994
Interest and preferred dividends payable		10,242		2,547		2,819		—	—	(211	)[1]		15,397
Taxes accrued		144,366		38,117		37,830		—	—	(267	)[3]		220,046
Other		33,462		9,015		11,992		18	6	775	[1]		55,268

Total current liabilities		325,858		139,474		63,602		18	6	(73,703	)		455,255

Deferred credits and other liabilities
Deferred income taxes		134,359		19,621		12,330		—	—	—			166,310
Regulatory liabilities		202,003		49,843		36,756		—	—	—			288,602
Unamortized tax credits		32,501		13,476		12,819		—	—	—			58,796
Retirement benefits liability		284,826		54,664		53,355		—	—	—			392,845
Other		11,576		35,432		7,941		—	—	—			54,949

Total deferred credits and other liabilities		665,265		173,036		123,201		—	—	—			961,502

Contributions in aid of construction		178,757		65,998		66,961		—	—	—			311,716

	$	2,963,147		754,943		648,485		123	147	(510,736	)	$	3,856,109

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
Less net income attributable to noncontrolling interest – preferred stock 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

Consolidating statement of income


	Year ended December 31, 2008
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions		HECO Consolidated
Operating revenues	$	1,954,772		446,297		452,570		—		—		—		$	2,853,639

Operating expenses
Fuel oil		866,827		109,617		252,749		—		—		—			1,229,193
Purchased power		475,205		176,248		38,375		—		—		—			689,828
Other operation		172,663		33,027		37,559		—		—		—			243,249
Maintenance		68,670		16,796		16,158		—		—		—			101,624
Depreciation		82,208		31,279		28,191		—		—		—			141,678
Taxes, other than income taxes		179,418		40,811		41,594		—		—		—			261,823
Income taxes		33,330		12,097		10,880		—		—		—			56,307

		1,878,321		419,875		425,506		—		—		—			2,723,702

Operating income		76,451		26,422		27,064		—		—		—			129,937

Other income
Allowance for equity funds used during construction		7,088		1,737		565		—		—		—			9,390
Equity in earnings of subsidiaries		37,009		—		—		—		—		(37,009	)[2]		—
Other, net		6,134		1,562		305		(77	)	(347	)	(1,918	)[1]		5,659

		50,231		3,299		870		(77	)	(347	)	(38,927	)		15,049

Interest and other charges
Interest on long-term debt		30,412		7,844		9,046		—		—		—			47,302
Amortization of net bond premium and expense		1,606		436		488		—		—		—			2,530
Other interest charges		4,383		2,001		459		—		—		(1,918	)[1]		4,925
Allowance for borrowed funds used during construction		(2,774	)	(735	)	(232	)	—		—		—			(3,741	)

		33,627		9,546		9,761		—		—		(1,918	)		51,016

Net income (loss)		93,055		20,175		18,173		(77	)	(347	)	(37,009	)		93,970
Less net income attributable to noncontrolling interest – preferred stock of subsidiaries		—		534		381		—		—		—			915

Net income (loss) attributable to HECO		93,055		19,641		17,792		(77	)	(347	)	(37,009	)		93,055
Preferred stock dividends of HECO		1,080		—		—		—		—		—			1,080

Net income (loss) for common stock	$	91,975		19,641		17,792		(77	)	(347	)	(37,009	)	$	91,975

Consolidating statement of income


	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and Elimina- tions		HECO Consolidated
Operating revenues	$	1,385,137		361,411		350,410		—		—		—		$	2,096,958
Operating expenses
Fuel oil		525,555		74,965		173,599		—		—		—			774,119
Purchased power		368,766		134,919		33,275		—		—		—			536,960
Other operation		148,857		32,960		32,230		—		—		—			214,047
Maintenance		62,208		20,700		22,835		—		—		—			105,743
Depreciation		78,972		30,094		28,015		—		—		—			137,081
Taxes, other than income taxes		129,015		33,274		32,318		—		—		—			194,607
Income taxes		17,648		9,534		6,944		—		—		—			34,126

		1,331,021		336,446		329,216		—		—		—			1,996,683

Operating income		54,116		24,965		21,194		—		—		—			100,275

Other income
Allowance for equity funds used during construction		4,404		461		354		—		—		—			5,219
Equity in earnings of subsidiaries		19,907		—		—		—		—		(19,907	)[2]		—
Other, net		7,927		(6,299	)	349		(83	)	(47	)	(2,474	)[1]		(627	)

		32,238		(5,838	)	703		(83	)	(47	)	(22,381	)		4,592

Interest and other charges
Interest on long-term debt		29,310		7,625		9,029		—		—		—			45,964
Amortization of net bond premium and expense		1,539		419		482		—		—		—			2,440
Other interest charges		4,415		2,531		392		—		—		(2,474	)[1]		4,864
Allowance for borrowed funds used during construction		(2,146	)	(234	)	(172	)	—		—		—			(2,552	)

		33,118		10,341		9,731		—		—		(2,474	)		50,716

Net income (loss)		53,236		8,786		12,166		(83	)	(47	)	(19,907	)		54,151
Less net income attributable to noncontrolling interest – preferred stock of subsidiaries		—		534		381		—		—		—			915

Net income (loss) attributable to HECO		53,236		8,252		11,785		(83	)	(47	)	(19,907	)		53,236
Preferred stock dividends of HECO		1,080		—		—		—		—		—			1,080

Net income (loss) for common stock	$	52,156		8,252		11,785		(83	)	(47	)	(19,907	)	$	52,156

Consolidating Statements of Changes in Stockholders’ Equity


(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassi- fications and elimina- tions		HECO consoli- dated
Balance, December 31, 2006	$	980,496		182,099		197,231		265		—		(367,595	)	$	992,496
Comprehensive income:
Net income (loss)		53,236		8,786		12,166		(83	)	(47	)	(19,907	)		54,151
Retirement benefit plans:
Net gains arising during the period, net of taxes of $9,861		15,484		1,262		1,773		—		—		(3,035	)		15,484
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 $5,001		7,854		1,104		903		—		—		(2,007	)		7,854
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of taxes of $11,007		(17,282	)	(2,069	)	(1,733	)	—		—		3,802			(17,282	)

Comprehensive income (loss)		59,292		9,083		13,109		(83	)	(47	)	(21,147	)		60,207

Adjustment to initially apply a PUC interim D&O related to defined benefit retirement plans, net of taxes of $77,546		121,751		18,205		13,506		—		—		(31,711	)		121,751
Adjustment to initially apply an accounting standard prescribing a “more-likely-than-not” recognition criterion to a tax position		(620	)	(33	)	(44	)	—		—		77			(620	)
Common stock dividends		(27,084	)	—		(9,900	)	—		—		9,900			(27,084	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		—		—			(1,995	)
Issuance of common stock		—		—		—		—		435		(435	)		—

Balance, December 31, 2007		1,132,755		208,820		213,521		182		388		(410,911	)		1,144,755
Comprehensive income:
Net income (loss)		93,055		20,175		18,173		(77	)	(347	)	(37,009	)		93,970
Retirement benefit plans:
Net losses arising during the period, net of tax benefits of $100,141		(157,226	)	(24,243	)	(20,329	)	—		—		44,572			(157,226	)
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 $3,481		5,464		760		621		—		—		(1,381	)		5,464
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory asset, net of tax benefits of $96,975		152,256		23,427		19,742		—		—		(43,169	)		152,256

Comprehensive income (loss)		93,549		20,119		18,207		(77	)	(347	)	(36,987	)		94,464

Common stock dividends		(14,089	)	—		(10,965	)	—		—		10,965			(14,089	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		—		—			(1,995	)
Issuance of common stock		—		—		—		—		100		(100	)		—

Balance, December 31, 2008		1,211,135		228,405		220,382		105		141		(437,033	)		1,223,135
Comprehensive income:
Net income (loss)		80,526		16,295		10,605		(11	)	(149	)	(25,825	)		81,441
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 asset, net of taxes of $48,251		(75,756	)	(11,531	)	(8,276	)	—		—		19,807			(75,756	)

Comprehensive income (loss)		80,657		16,307		10,582		(11	)	(149	)	(25,814	)		81,572

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	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		—		—			(1,995	)

Balance, December 31, 2009	$	1,328,701		247,576		226,319		94		17		(462,006	)	$	1,340,701

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
Deferred income taxes		6,539		6,236		1,987		—		—		—			14,762
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		18,835		(10,426	)	1,308		—		—		—			9,717
Changes in prepaid and accrued income and utility revenue taxes		(43,210	)	(6,759	)	(11,982	)	—		—		—			(61,951	)
Changes in other assets and liabilities		15,730		(12,028	)	(4,562	)	(14	)	(4	)	(1,693	)[2]		(2,571	)

Net cash provided by (used in) operating activities		160,030		33,623		28,154		(25	)	(142	)	(4,264	)		217,376

Cash flows from investing activities:
Capital expenditures		(208,904	)	(65,976	)	(27,447	)	—		—		—			(302,327	)
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		(164,860	)	(58,915	)	(24,686	)	—		119		(39,475	)		(287,817	)

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 equivalents		68,717		(1,142	)	(875	)	(25	)	2		—			66,677
Cash and equivalents, beginning of year		2,264		3,148		1,349		123		17		—			6,901

Cash and equivalents, end of year	$	70,981		2,006		474		98		19		—		$	73,578

Consolidating statement of cash flows


	Year ended December 31, 2008
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income	$	93,055		20,175		18,173		(77	)	(347	)	(37,009	)[2]	$	93,970
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings		(37,109	)	—		—		—		—		37,009	[2]		(100	)
Common stock dividends received from subsidiaries		11,065		—		—		—		—		(10,965	)[2]		100
Depreciation of property, plant and equipment		82,208		31,279		28,191		—		—		—			141,678
Other amortization		3,145		743		4,731		—		—		—			8,619
Deferred income taxes		3,457		1,866		(1,441	)	—		—		—			3,882
Tax credits, net		555		696		219		—		—		—			1,470
Allowance for equity funds used during construction		(7,088	)	(1,737	)	(565	)	—		—		—			(9,390	)
Changes in assets and liabilities:
Increase in accounts receivable		(8,921	)	(5,290	)	(1,279	)	—		(11	)	(5,812	)[1]		(21,313	)
Decrease (increase) in accrued unbilled revenues		7,893		(1,081	)	918		—		—		—			7,730
Decrease in fuel oil stock		3,743		2,168		8,245		—		—		—			14,156
Decrease (increase) in materials and supplies		(860	)	38		548		—		—		—			(274	)
Increase in regulatory assets		(151	)	(87	)	(2,991	)	—		—		—			(3,229	)
Increase (decrease) in accounts payable		(13,461	)	5,985		(7,425	)	—		—		—			(14,901	)
Changes in prepaid and accrued income and utility revenue taxes		25,155		2,638		262		—		—		—			28,055
Changes in other assets and liabilities		(7,551	)	(4,089	)	422		2		(41	)	5,812	[2]		(5,445	)

Net cash provided by (used in) operating activities		155,135		53,304		48,008		(75	)	(399	)	(10,965	)		245,008

Cash flows from investing activities:
Capital expenditures		(162,041	)	(84,948	)	(31,487	)	—		—		—			(278,476	)
Contributions in aid of construction		9,928		4,669		2,722		—		—		—			17,319
Advances from (to) affiliates		(25,400	)	—		(10,000	)	—		—		35,400	[1]		—
Other		1,276		—		—		—		(119	)	—			1,157
Investment in consolidated subsidiary		(100	)	—		—		—		—		100	[2]		—

Net cash used in investing activities		(176,337	)	(80,279	)	(38,765	)	—		(119	)	35,500			(260,000	)

Cash flows from financing activities:
Common stock dividends		(14,089	)	—		(10,965	)	—		—		10,965	[2]		(14,089	)
Preferred stock dividends of HECO and subsidiaries		(1,080	)	(534	)	(381	)	—		—		—			(1,995	)
Proceeds from issuance of long-term debt		14,407		2,188		2,680		—		—		—			19,275
Proceeds from issuance of common stock		—		—		—		—		100		(100	)[2]		—
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		22,759		25,400		—		—		—		(35,400	)[1]		12,759
Increase (decrease) in cash overdraft		1,266		—		(1	)	—		—		—			1,265

Net cash provided by (used in) financing activities		23,263		27,054		(8,667	)	—		100		(24,535	)		17,215

Net increase (decrease) in cash and equivalents		2,061		79		576		(75	)	(418	)	—			2,223
Cash and equivalents, beginning of year		203		3,069		773		198		435		—			4,678

Cash and equivalents, end of year	$	2,264		3,148		1,349		123		17		—		$	6,901

Consolidating statement of cash flows


	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income	$	53,236		8,786		12,166		(83	)	(47	)	(19,907	)[2]	$	54,151
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings		(20,008	)	—		—		—		—		19,907	[2]		(101	)
Common stock dividends received from subsidiaries		10,001		—		—		—		—		(9,900	)[2]		101
Depreciation of property, plant and equipment		78,972		30,094		28,015		—		—		—			137,081
Other amortization		3,892		375		3,963		—		—		—			8,230
Writedown of utility plant		—		11,701		—		—		—		—			11,701
Deferred income taxes		(18,748	)	(6,280	)	(6,860	)	—		—		—			(31,888	)
Tax credits, net		1,070		288		634		—		—		—			1,992
Allowance for equity funds used during construction		(4,404	)	(461	)	(354	)	—		—		—			(5,219	)
Changes in assets and liabilities:
Increase in accounts receivable		(19,664	)	(3,710	)	(4,297	)	—		—		4,591	[1]		(23,080	)
Increase in accrued unbilled revenues		(18,315	)	(2,358	)	(1,406	)	—		—		—			(22,079	)
Increase in fuel oil stock		(16,609	)	(2,733	)	(8,217	)	—		—		—			(27,559	)
Decrease (increase) in materials and supplies		(1,764	)	488		(2,442	)	—		—		—			(3,718	)
Decrease (increase) in regulatory assets		2,252		(559	)	(3,661	)	—		—		—			(1,968	)
Increase (decrease) in accounts payable		36,027		(762	)	118		—		—		—			35,383
Changes in prepaid and accrued income and utility revenue taxes		22,186		8,399		6,870		—		—		—			37,455
Changes in other assets and liabilities		11,485		7,100		2,061		6		47		(4,591	)[2]		16,108

Net cash provided by (used in) operating activities		119,609		50,368		26,590		(77	)	—		(9,900	)		186,590

Cash flows from investing activities:
Capital expenditures		(129,045	)	(52,554	)	(28,222	)	—		—		—			(209,821	)
Contributions in aid of construction		10,834		4,952		3,225		—		—		—			19,011
Advances from (to) affiliates		17,800		—		(2,000	)	—		—		(15,800	)[1]		—
Proceeds from sales of assets		5,440		—		—		—		—		—			5,440
Investment in consolidated subsidiary		(435	)	—		—		—		—		435	[2]		—

Net cash used in investing activities		(95,406	)	(47,602	)	(26,997	)	—		—		(15,365	)		(185,370	)

Cash flows from financing activities:
Common stock dividends		(27,084	)	—		(9,900	)	—		—		9,900	[2]		(27,084	)
Preferred stock dividends of HECO and subsidiaries		(1,080	)	(534	)	(381	)	—		—		—			(1,995	)
Proceeds from issuance of long-term debt		147,593		22,625		72,320		—		—		—			242,538
Repayment of long term debt		(62,280	)	(8,020	)	(55,700	)	—		—		—			(126,000	)
Proceeds from issuance of common stock		—		—		—		—		435		(435	)[2]		—
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(82,316	)	(12,800	)	(5,000	)	—		—		15,800	[1]		(84,316	)
Decrease in cash overdraft		(1,161	)	(1,706	)	(677	)	—		—		—			(3,544	)

Net cash provided by (used in) financing activities		(26,328	)	(435	)	662		—		435		25,265			(401	)

Net increase in cash and equivalents		(2,125	)	2,331		255		(77	)	435		—			819
Cash and equivalents, beginning of year		2,328		738		518		275		—		—			3,859

Cash and equivalents, end of year	$	203		3,069		773		198		435		—		$	4,678

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.

HECO has not provided separate financial statements and other disclosures concerning HELCO and MECO because management has concluded that such financial statements and other information are not material to holders of the trust preferred securities issued by HECO Capital Trust III, which trust holds the 2004 junior deferrable debentures issued by HELCO and MECO, which debentures have been fully and unconditionally guaranteed by HECO.

18. Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2009 and 2008 follows:


	Quarters ended								Year ended
2009	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues (1)	$	459,285	$	447,836	$	546,502	$	573,049	$	2,026,672
Operating income (1)		20,249		21,023		36,650		36,486		114,408
Net income for common stock (1)		14,132		15,495		26,514		23,305		79,446


	Quarters ended								Year ended
2008	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues (2)	$	622,494	$	686,647	$	826,124	$	718,374	$	2,853,639
Operating income (2)		34,666		37,388		35,414		22,469		129,937
Net income for common stock (2)		24,585		27,432		25,932		14,026		91,975

Note:

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

(1)	For 2009, amounts included interim rate relief totaling $141 million.

(2)	For 2008, amounts included interim rate relief totaling $108 million. The fourth quarter of 2008 includes a reduction of $1.3 million, net of taxes, of revenues related to prior periods.

19. Subsequent events

The Company has evaluated subsequent events through February 19, 2010, the date the financial statements were issued.

HAWAIIAN ELECTRIC CO INC - FORM 8-K - EX-99 - FORWARD-LOOKING STATEMENTS - February 19, 2010

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