Hawaiian Electric Company, Inc. PFD SER E 5% (HAWEL) 8-K Results of Operations and Financial Condition

HECO Exhibit 99.1

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:

• the effects of international, national and local economic conditions, including the state of the Hawaii tourist and construction industries and decisions concerning the extent of the presence of the federal government and military in Hawaii;

• the effects of weather and natural disasters, such as hurricanes, earthquakes, tsunamis and the potential effects of global warming;

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

• the timing and extent of changes in interest rates;

• the ability of the Company to access the credit markets to obtain financing;

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

• changes in assumptions used to calculate retirement benefits costs and changes in funding requirements;

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

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

• increased risk to generation reliability as generation peak reserve margins on Oahu continue to be strained;

• fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);

• 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 HECO and its subsidiaries or their competitors;

• federal, state and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HECO and its subsidiaries (including changes in taxation, environmental laws and regulations, the potential regulation of greenhouse gas emissions and governmental fees and assessments); and decisions by the Public Utilities Commission of the State of Hawaii (PUC) in rate cases (including decisions on ECACs) and other proceedings and by other agencies and courts on land use, environmental and other permitting issues (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 for the Company , resulting in the need for more frequent rate cases;

• the risks associated with the geographic concentration of HECO’s business;

• the effects of changes in accounting principles applicable to HECO and its subsidiaries, including the adoption of new accounting principles (such as the effects of Statement of Financial Accounting Standards (SFAS) No. 158 regarding employers’ accounting for defined benefit pension and other postretirement plans and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48 regarding uncertainty in income taxes), continued regulatory accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and the possible effects of applying FIN 46R, “Consolidation of Variable Interest Entities,” and Emerging Issues Task Force Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” to PPAs with independent power producers;

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

• the final outcome of tax positions taken by HECO and its subsidiaries;

• the risks of suffering losses and incurring liabilities that are uninsured; and

• other risks or uncertainties described elsewhere in this report and in other periodic reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by 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, HECO and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

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 HECO and its subsidiaries in HEI’s MD&A (except for HEI’s Selected contractual obligations and commitments table), included in HEI Exhibit 13 to the Form 8-K dated February 21, 2008.

Selected contractual obligations and commitments. The following table presents HECO and subsidiaries-aggregated information as of December 31, 2007 about total payments due during the indicated periods under the specified contractual obligations and commercial commitments:

December 31, 2007	Payment due by period
(in millions)	1 year or less		2-3 years		4-5 years		More than 5 years		Total
Long-term debt, net	$	—	$	—	$	58	$	800	$	858
Operating leases		6		6		5		15		32
Open purchase order obligations		86		29		1		—		116
Fuel oil purchase obligations (estimate based on January 1, 2008 fuel oil prices)		898		1,793		1,795		1,793		6,279
Purchase power obligations– minimum fixed capacity charges		119		237		234		1,015		1,605
Liabilities for uncertain tax positions (FIN 48 liability)		—		4		1		—		5
Total (estimated)	$	1,109	$	2,069	$	2,094	$	3,623	$	8,895

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, but management believes their exposures to these two risks are not material as of December 31, 2007.

HECO and its subsidiaries are exposed to some commodity price risk primarily related to its 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, included in HEI Exhibit 13 to the Form 8-K dated February 21, 2008. 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 are not exposed to market risk from trading activities.

See “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 21, 2008, and Note 10 of HECO’s “Notes to Consolidated Financial Statements.” Based upon short-term borrowings outstanding as of December 31, 2007 of $29 million and a hypothetical 10% increase/decrease in interest rates, annual interest expense would have increased/decreased on those short-term borrowings by $0.2 million.

2

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2007			2006			2005			2004			2003
(in thousands)
Income statement data
Operating revenues	$	2,096,958		$	2,050,412		$	1,801,710		$	1,546,875		$	1,393,038
Operating expenses		1,996,683			1,933,257			1,688,168			1,425,583			1,268,200
Operating income		100,275			117,155			113,542			121,292			124,838
Other income		4,592			9,471			8,643			8,926			6,170
Income before interest and other charges		104,867			126,626			122,185			130,218			131,008
Interest and other charges		51,631			50,599			48,303			47,961			51,017
Income before preferred stock dividends of HECO		53,236			76,027			73,882			82,257			79,991
Preferred stock dividends of HECO		1,080			1,080			1,080			1,080			1,080
Net income for common stock	$	52,156		$	74,947		$	72,802		$	81,177		$	78,911
At December 31	2007			2006			2005			2004			2003
(in thousands)
Balance sheet data
Utility plant	$	4,320,607		$	4,133,883		$	3,930,321		$	3,709,857		$	3,531,299
Accumulated depreciation		(1,647,113	)		(1,558,913	)		(1,456,537	)		(1,361,703	)		(1,290,929	)
Net utility plant	$	2,673,494		$	2,574,970		$	2,473,784		$	2,348,154		$	2,240,370
Total assets	$	3,423,888		$	3,063,134		$	3,081,461		$	2,879,615		$	2,687,798
Capitalization:1
Short-term borrowings from non-affiliates and affiliate	$	28,791		$	113,107		$	136,165		$	88,568		$	6,000
Long-term debt, net		885,099			766,185			765,993			752,735			699,420
Preferred stock not subject to mandatory redemption		34,293			34,293			34,293			34,293			34,293
HECO-obligated preferred securities of subsidiary trusts		—			—			—			—			100,000
Common stock equity		1,110,462			958,203			1,039,259			1,017,104			944,443
Total capitalization	$	2,058,645		$	1,871,788		$	1,975,710		$	1,892,700		$	1,784,156
Capital structure ratios (%)1
Debt		44.4			47.0			45.7			44.5			39.6
Preferred stock		1.7			1.8			1.7			1.8			1.9
HECO-obligated preferred securities of subsidiary trusts		—			—			—			—			5.6
Common stock equity		53.9			51.2			52.6			53.7			52.9

¹ Includes amounts due within one year, short-term borrowings from nonaffiliates and affiliate, and sinking fund and optional redemption payments.

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

See Note 11, “Commitments and Contingencies,” in HECO’s “Notes to Consolidated Financial Statements” for a discussion of certain contingencies that could adversely affect the Company’s future results of operations and financial condition.

3

Annual Report of Management on Internal Control Over Financial Reporting

The Board of Directors and Shareholder

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, 2007 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, 2007.

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, 2007. This report appears on page 5.

/s/ T. Michael May	/s/ Tayne S. Y. Sekimura	/s/ Patsy H. Nanbu
T. Michael May	Tayne S. Y. Sekimura	Patsy H. Nanbu
President and Chief Executive Officer	Senior Vice President, Finance & Administration and Chief Financial Officer	Controller and Chief Accounting Officer

February 21, 2008

4

[KPMG LLP letterhead]

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

The Board of Directors and Shareholder

Hawaiian Electric Company, Inc.:

We have audited Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2007, 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, 2007, 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 statements of capitalization of Hawaiian Electric Company, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 21, 2008 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Honolulu, Hawaii

February 21, 2008

5

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder

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, 2007 and 2006, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 1 and 7 to the consolidated financial statements, the Company changed its method of accounting for income taxes in 2007.

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, 2007, 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 21, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Honolulu, Hawaii

February 21, 2008

6

Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2007			2006			2005
(in thousands)
Operating revenues	$	2,096,958		$	2,050,412		$	1,801,710
Operating expenses
Fuel oil		774,119			781,740			639,650
Purchased power		536,960			506,893			458,120
Other operation		214,047			186,449			172,962
Maintenance		105,743			90,217			82,242
Depreciation		137,081			130,164			122,870
Taxes, other than income taxes		194,607			190,413			167,295
Income taxes		34,126			47,381			45,029
		1,996,683			1,933,257			1,688,168
Operating income		100,275			117,155			113,542
Other income
Allowance for equity funds used during construction		5,219			6,348			5,105
Other, net		(627	)		3,123			3,538
		4,592			9,471			8,643
Income before interest and other charges		104,867			126,626			122,185
Interest and other charges
Interest on long-term debt		45,964			43,109			43,063
Amortization of net bond premium and expense		2,440			2,198			2,212
Other interest charges		4,864			7,256			4,133
Allowance for borrowed funds used during construction		(2,552	)		(2,879	)		(2,020	)
Preferred stock dividends of subsidiaries		915			915			915
		51,631			50,599			48,303
Income before preferred stock dividends of HECO		53,236			76,027			73,882
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	52,156		$	74,947		$	72,802
Consolidated Statements of Retained Earnings Hawaiian Electric Company, Inc. and Subsidiaries
Years ended December 31	2007			2006			2005
(in thousands)
Retained earnings, January 1	$	700,252		$	654,686		$	632,779
Net income for common stock		52,156			74,947			72,802
Adjustment to initially apply Fin 48		(620	)		—			—
Common stock dividends		(27,084	)		(29,381	)		(50,895	)
Retained earnings, December 31	$	724,704		$	700,252		$	654,686

See accompanying “Notes to Consolidated Financial Statements.”

7

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2007			2006
(in thousands)
Assets
Utility plant, at cost
Land	$	38,161		$	35,242
Plant and equipment		4,131,226			4,002,929
Less accumulated depreciation		(1,647,113	)		(1,558,913	)
Plant acquisition adjustment, net		41			93
Construction in progress		151,179			95,619
Net utility plant		2,673,494			2,574,970
Current assets
Cash and equivalents		4,678			3,859
Customer accounts receivable, net		146,112			125,524
Accrued unbilled revenues, net		114,274			92,195
Other accounts receivable, net		6,915			4,423
Fuel oil stock, at average cost		91,871			64,312
Materials and supplies, at average cost		34,258			30,540
Prepayments and other		9,490			9,695
Total current assets		407,598			330,548
Other long-term assets
Regulatory assets		284,990			112,349
Unamortized debt expense		15,635			13,722
Other		42,171			31,545
Total other long-term assets		342,796			157,616
	$	3,423,888		$	3,063,134
Capitalization and liabilities
Capitalization(see Consolidated Statements of Capitalization)
Common stock equity	$	1,110,462		$	958,203
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
Long-term debt, net		885,099			766,185
Total capitalization		2,029,854			1,758,681
Current liabilities
Short-term borrowings-nonaffiliates		28,791			113,107
Accounts payable		137,895			102,512
Interest and preferred dividends payable		14,719			10,645
Taxes accrued		189,637			152,182
Other		57,799			43,120
Total current liabilities		428,841			421,566
Deferred credits and other liabilities
Deferred income taxes		162,113			118,055
Regulatory liabilities		261,606			240,619
Unamortized tax credits		58,419			57,879
Other		183,318			189,606
Total deferred credits and other liabilities		665,456			606,159
Contributions in aid of construction		299,737			276,728
	$	3,423,888		$	3,063,134

See accompanying “Notes to Consolidated Financial Statements.”

8

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2007		2006			2005
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value Authorized: 50,000,000 shares. Outstanding: 2007, 2006 and 2005, 12,805,843 shares	$	85,387	$	85,387		$	85,387
Premium on capital stock		299,214		299,214			299,212
Retained earnings		724,704		700,252			654,686
Accumulated other comprehensive income (loss), net of income tax benefits:
Retirement benefit plans		1,157		(126,650	)		(26	)
Common stock equity		1,110,462		958,203		$	1,039,259
Cumulative preferred stock not subject to mandatory redemption Authorized: 5,000,000 shares of $20 par value and 7,000,000 shares of $100 par value. Outstanding: 2007 and 2006, 1,234,657 shares.

Series	Par Value				Shares Outstanding December 31, 2007 and 2006	2007		2006
(dollars in thousands, except par value and shares outstanding)
C-4 1/4%	$	20	(HECO	)	150,000		3,000		3,000
D-5%		20	(HECO	)	50,000		1,000		1,000
E-5%		20	(HECO	)	150,000		3,000		3,000
H-5 1/4%		20	(HECO	)	250,000		5,000		5,000
I-5%		20	(HECO	)	89,657		1,793		1,793
J-4 3/4%		20	(HECO	)	250,000		5,000		5,000
K-4.65%		20	(HECO	)	175,000		3,500		3,500
G-7 5/8%		100	(HELCO	)	70,000		7,000		7,000
H-7 5/8%		100	(MECO	)	50,000		5,000		5,000
					1,234,657	$	34,293	$	34,293

(continued)

See accompanying “Notes to Consolidated Financial Statements.”

9

Consolidated Statements of Capitalization,continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2007		2006
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
HECO, 4.60%, refunding series 2007B, due 2026	$	62,000	$	—
HELCO, 4.60%, refunding series 2007B, due 2026		8,000		—
MECO, 4.60%, refunding series 2007B, due 2026		55,000		—
HECO, 4.65%, series 2007A, due 2037		100,000		—
HELCO, 4.65%, series 2007A, due 2037		20,000		—
MECO, 4.65%, series 2007A, due 2037		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 7/8%, series 1996B, refunded in 2007		—		14,000
HELCO, 5 7/8%, series 1996B, refunded in 2007		—		1,000
MECO, 5 7/8%, series 1996B, refunded in 2007		—		35,000
HECO, 6.20%, series 1996A, refunded in 2007		—		48,000
HELCO, 6.20%, series 1996A, refunded in 2007		—		7,000
MECO, 6.20%, series 1996A, refunded in 2007		—		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
		857,900		717,900
Less funds on deposit with trustee		22,461		—
Total obligations to the State of Hawaii		835,439		717,900
Other long-term debt – unsecured: 6.50 %, series 2004, Junior subordinated deferrable interest debentures, due 2034		51,546		51,546
Total long-term debt		886,985		769,446
Less unamortized discount		1,886		3,261
Long-term debt, net		885,099		766,185
Total capitalization	$	2,029,854	$	1,758,681

See accompanying “Notes to Consolidated Financial Statements.”

10

Consolidated Statements of Changes in Common Stock Equity

Hawaiian Electric Company, Inc. and Subsidiaries

	Common stock			Premium on capital stock			Retained earnings			Accumulated other comprehensive income (loss)			Total
(in thousands)	Shares	Amount
Balance, December 31, 2004	12,806	$	85,387	$	299,213		$	632,779		$	(275	)	$	1,017,104
Comprehensive income:
Net income	—		—		—			72,802			—			72,802
Minimum pension liability adjustment, net of taxes of $158	—		—		—			—			249			249
Comprehensive income	—		—		—			72,802			249			73,051
Common stock dividends	—		—		—			(50,895	)		—			(50,895	)
Other	—		—		(1	)		—			—			(1	)
Balance, December 31, 2005	12,806		85,387		299,212			654,686			(26	)		1,039,259
Comprehensive income:
Net income	—		—		—			74,947			—			74,947
Minimum pension liability adjustment, net of taxes of $18	—		—		—			—			26			26
Comprehensive income	—		—		—			74,947			26			74,973
Adjustment to initially apply SFAS No. 158, net of tax benefits of $80,666	—		—		—			—			(126,650	)		(126,650	)
Common stock dividends	—		—		—			(29,381	)		—			(29,381	)
Other	—		—		2			—			—			2
Balance, December 31, 2006	12,806		85,387		299,214			700,252			(126,650	)		958,203
Comprehensive income:
Net income	—		—		—			52,156			—			52,156
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			58,212
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 FIN 48	—		—		—			(620	)		—			(620	)
Common stock dividends	—		—		—			(27,084	)		—			(27,084	)
Balance, December 31, 2007	12,806	$	85,387	$	299,214		$	724,704		$	1,157		$	1,110,462

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Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2007			2006			2005
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	53,236		$	76,027		$	73,882
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		137,081			130,164			122,870
Other amortization		8,230			7,932			8,479
Writedown of utility plant		11,701			—			—
Deferred income taxes		(31,888	)		(9,671	)		19,086
Tax credits, net		1,992			3,810			3,471
Allowance for equity funds used during construction		(5,219	)		(6,348	)		(5,105	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(23,080	)		8,709			(30,150	)
Increase in accrued unbilled revenues		(22,079	)		(874	)		(12,293	)
Decrease (increase) in fuel oil stock		(27,559	)		21,138			(26,880	)
Increase in materials and supplies		(3,718	)		(3,566	)		(3,206	)
Increase in regulatory assets		(1,968	)		(6,123	)		(5,036	)
Increase (decrease) in accounts payable		35,383			(19,689	)		28,186
Increase in taxes accrued		37,455			18,599			27,658
Decrease (increase) in prepaid pension benefit cost		—			20,064			(300	)
Other		16,108			(12,641	)		(15,944	)
Net cash provided by operating activities		185,675			227,531			184,718
Cash flows from investing activities
Capital expenditures		(209,821	)		(195,072	)		(217,610	)
Contributions in aid of construction		19,011			19,707			21,083
Proceeds from sales of assets		5,440			407			1,680
Net cash used in investing activities		(185,370	)		(174,958	)		(194,847	)
Cash flows from financing activities
Common stock dividends		(27,084	)		(29,381	)		(50,895	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Proceeds from issuance of long-term debt		242,538			—			59,462
Repayment of long-term debt		(126,000	)		—			(47,000	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(84,316	)		(23,058	)		47,597
Other		(3,544	)		4,662			1,861
Net cash provided by (used in) financing activities		514			(48,857	)		9,945
Net increase (decrease) in cash and equivalents		819			3,716			(184	)
Cash and equivalents, January 1		3,859			143			327
Cash and equivalents, December 31	$	4,678		$	3,859		$	143

See accompanying “Notes to Consolidated Financial Statements.”

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Notes to Consolidated Financial Statements

Hawaiian Electric Company, Inc. and Subsidiaries

1. Summary of significant accounting policies

General

Hawaiian Electric Company, Inc. (HECO) and its wholly-owned operating subsidiaries, Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO), are electric public utilities in the business of generating, purchasing, transmitting, distributing and selling electric energy on all major islands in Hawaii other than Kauai, and are regulated by the Public Utilities Commission of the State of Hawaii (PUC). HECO also owns non-regulated subsidiaries: Renewable Hawaii, Inc. (RHI), which will invest in renewable energy projects, Uluwehiokama Biofuels Corp. (UBC), which will partly own a new biodiesel refining plant to be built on the island of Maui by 2009 and will direct its profits into a trust to be created for the purpose of funding biofuels development in Hawaii, and HECO Capital Trust III, which is an unconsolidated 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 variable-interest entities 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 the application of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 46(R).

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 Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the actions of regulators can affect the timing of recognition of revenues, expenses, assets and liabilities. Management believes its operations currently satisfy the SFAS No. 71 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, 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.

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

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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 Emerging Issues Task Force (EITF) Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease” and results in the classification of the agreement as a capital lease, the Company would recognize a capital asset and a 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 2007 and 3.9% in 2006 and 2005.

Cash and equivalents

The Company considers cash on hand, deposits in banks, money market accounts, certificates of deposit, short-term commercial paper 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. The Company adjusts its allowance on a monthly basis, 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 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, and considering the deductibility of contributions under the Internal Revenue Code. The Company generally funds at least the net periodic pension cost as calculated using SFAS No. 87 “Employers’ Accounting for Pensions” during the fiscal year, subject to limits and targeted funded status as determined with the consulting actuary. Under pension tracking mechanisms approved by the PUC on an interim basis, HECO and MECO generally will make contributions to the pension fund at the minimum level required under the law, until the pension assets (existing at the time of the PUC decisions and determined based on the cumulative fund contributions in excess of the cumulative net periodic pension cost recognized) are reduced to zero, at which time HECO and MECO would fund the pension cost as specified in the pension tracking mechanism. HELCO 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 as calculated using SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and the amortization of the regulatory asset for postretirement benefits other than pensions (OPEB), while maximizing the use of the most tax advantaged funding vehicles, subject to cash flow requirements and reviews of the funded status with the consulting actuary. The Company must fund OPEB costs as specified in the OPEB tracking mechanisms, which were approved by the PUC on an interim basis. Future decisions in rate cases could further impact funding amounts.

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Effective December 31, 2006, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” and recognized 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 financing costs and premiums or discounts over the term of the related long-term debt. Unamortized financing costs and discounts or premiums 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, 2007, customer accounts receivable include unbilled energy revenues of $114 million on a base of annual revenue of $2.1 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 2007, 2006 and 2005, the Company included approximately $185 million, $182 million and $159 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 2007, 8.4% in 2006 and 8.5% in 2005, and reflected quarterly compounding.

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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. 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 enacted 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.

Effective January 1, 2007, the Company adopted FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” and uses a “more-likely-than-not” recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

Impairment of long-lived assets and long-lived assets to be disposed of

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

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Recent accounting pronouncements and interpretations

Fair value measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 applies to fair value measurements that are already required or permitted under existing accounting pronouncements with some exceptions. SFAS No. 157 retains the exchange price notion in defining fair value and clarifies that the exchange price is the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability. It emphasizes that fair value is a market-based, not an entity-specific, measurement based upon the assumptions that market participants would use in pricing an asset or liability. As a basis for considering assumptions in fair value measurements, SFAS No. 157 establishes a hierarchy that gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). SFAS No. 157 expands disclosures about the use of fair value, including disclosure of the level within the hierarchy in which the fair value measurements fall and the effect of the measurements on earnings (or changes in net assets) for the period. The Company adopted SFAS No. 157 on January 1, 2008. The adoption of SFAS No. 157 had no impact on the Company’s financial statements, but will impact the Company’s fair value measurement disclosures in future periods.

The fair value option for financial assets and financial liabilities. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment of FASB Statement No. 115.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value, which should improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Company adopted SFAS No. 159 on January 1, 2008 and the adoption had no impact on the Company’s financial statements as the Company did not choose to measure additional items at fair value.

Business combinations. In December 2007, the FASB issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R requires an acquiring entity to recognize all the assets acquired and liabilities assumed at the acquisition-date fair value with limited exceptions. Under SFAS No. 141R, acquisition costs will generally be expensed as incurred, noncontrolling interests will be valued at acquisition-date fair value, and acquired contingent liabilities will be recorded at acquisition-date fair value and subsequently measured at the higher of such amount or the amount determined under existing guidance for non-acquired contingencies. The Company must adopt SFAS No. 141R for all business combinations for which the acquisition date is on or after January 1, 2009. Because the impact of adopting SFAS No. 141R will be dependent on future acquisitions, if any, management cannot predict such impact.

Noncontrolling interests. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” SFAS No. 160 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 be clearly identified and presented on the face of the income statement. Under SFAS No. 160, 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 must adopt SFAS No. 160 on January 1, 2009 prospectively, except for the presentation and disclosure requirements which must be applied retrospectively. Management has not yet determined what impact, if any, the adoption of SFAS No. 160 will have on the Company’s financial statements.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2007 presentation.

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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, 2007	Voluntary Liquidation Price		Redemption Price
Series
C, D, E, H, J and K (HECO)	$	20	$	21
I (HECO)		20		20
G (HELCO)		100		100
H (MECO)		100		100

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

3. Unconsolidated variable interest entities

HECO Capital Trust III.HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by each of MECO and HELCO in the respective principal amounts of $10 million, (iii) making distributions on the trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are redeemable at the issuer’s option without premium beginning on March 18, 2009. The 2004 Debentures, together with the obligations of HECO, 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 FIN 46R. Trust III’s balance sheet as of December 31, 2007 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 2007 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, 2007, HECO and its subsidiaries had six PPAs for a total of 540 MW of firm capacity, and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers that supplied as-available energy. Approximately 91% of the 540 MW of firm capacity is under PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for 2007 totaled $537 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $137 million, $193 million, $70 million and $38 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and

18

municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

Under FIN 46R, an enterprise with an interest in a VIE or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information.

HECO 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 FIN 46R to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPOWER) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of FIN 46R, and HECO was unable to apply FIN 46R to these IPPs.

As required under FIN 46R, HECO has continued after 2004 its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006, 2007 and 2008, HECO and its subsidiaries sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs declined to provide necessary information, except that Kalaeloa provided the information pursuant to the amendments to the PPA (see below) and Kaheawa Wind Power, LLC (KWP) provided information as required under the PPA. Management has concluded that MECO does not have to consolidate KWP (which began selling power to MECO in June 2006 from its 30 MW windfarm) as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.

If the requested information is ultimately received from the other IPPs, a possible outcome of future analysis is the consolidation of 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 FIN 46R in accordance with SFAS No. 154, “Accounting Changes and Error Corrections.”

Kalaeloa Partners, L.P. In October 1988, HECO entered into a PPA with Kalaeloa, subsequently approved by the PUC, which provided that HECO would purchase 180 MW of firm capacity for a period of 25 years beginning in May 1991. In October 2004, HECO and Kalaeloa entered into amendments to the PPA, subsequently approved by the PUC, which together effectively increased the firm capacity from 180 MW to 208 MW. The energy payments that HECO makes to Kalaeloa include: 1) a fuel component, with a fuel price adjustment based on the cost of low sulfur fuel oil, 2) a fuel additives cost component, and 3) a non-fuel component, with an adjustment based on changes in the Gross National Product Implicit Price Deflator. The capacity payments that HECO makes to Kalaeloa are fixed in accordance with the PPA.

Kalaeloa is a Delaware limited partnership formed on October 13, 1988 for the purpose of designing, constructing, owning and operating a 200 MW cogeneration facility on Oahu, which includes two 75 MW oil-fired combustion turbines, two waste heat recovery steam generators, a 50 MW turbine generator and other electrical, mechanical and control equipment. The two combustion turbines were upgraded during 2004 resulting in an increase in the facility’s nominal output rating to approximately 220 MW. Kalaeloa has a PPA with HECO (described above) and a steam delivery contract with another customer, the term of which coincides with the PPA. The facility has been certified by the Federal Energy Regulatory Commission as a Qualifying Facility under the Public Utility Regulatory Policies Act of 1978 (PURPA).

Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not absorb the majority of Kalealoa’s expected losses nor receive a

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majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor affecting the level of expected losses HECO would absorb is the fact that HECO’s exposure to fuel price variability is limited to the remaining term of the PPA as compared to the facility’s remaining useful life. Although HECO absorbs fuel price variability for the remaining term of the PPA, the PPA does not currently expose HECO to losses as the fuel and fuel related energy payments under the PPA have been approved by the PUC for recovery from customers through base electric rates and through HECO’s ECAC to the extent the fuel and fuel related energy payments are not included in base energy rates.

Apollo Energy Corporation. In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total allowed capacity of 20.5 MW. In December 2005, Apollo assigned the PPA to a subsidiary, which voluntarily, unilaterally and irrevocably waived and relinquished its right and benefit under the PPA to collect the floor rate for the entire term of the PPA. The 20.5 MW facility began commercial operations in April 2007. Based on information available, management concluded that HELCO does not have to consolidate Apollo as HELCO does not have a variable interest in Apollo because the PPA does not require HELCO to absorb any variability of Apollo.

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 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 will be used to finance capital expenditures, including reimbursements to the electric utilities for previously incurred capital expenditures which, in turn, will be used primarily to repay short-term borrowings. As of December 31, 2007, approximately $22 million of proceeds from the Series 2007A SPRBs had not yet been drawn and were held by the construction fund trustee. HECO, HELCO and MECO’s long-term debt will increase from time to time as these remaining proceeds are drawn down.

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.

At December 31, 2007, the aggregate payments of principal required on long-term debt are nil during the next four years and $57.5 million in 2012.

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5. Short-term borrowings

Short-term borrowings from nonaffiliates at December 31, 2007 and 2006 had a weighted average interest rate of 5.4%, and consisted entirely of commercial paper.

At December 31, 2007 and 2006 the Company maintained a syndicated credit facility of $175 million. The facility is not secured. There were no borrowings under any line of credit during 2007 and 2006.

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) 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 47% for HELCO and 45% for MECO as of December 31, 2007, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in its agreement, or meet other requirements will result in an event of default. For example, under the agreement, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (ratio of 54% as of December 31, 2007, 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+ and stated that the downgrade “is the result of sustained weak bondholder protection parameters compounded by the financial pressure that continuous need for regulatory relief, driven by heightened capital expenditure requirements, is creating for the next few years.” 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.

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6. Regulatory assets and liabilities

In accordance with SFAS No. 71, the Company’s financial statements reflect assets, liabilities, revenues and expenses based on current cost-based rate-making regulations. Continued accounting under SFAS No. 71 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 SFAS No. 71 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, the Company does not earn a return on its regulatory assets, however, it has been allowed to recover interest on its regulatory assets for demand-side management 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 parenthesis are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2007, if different.

Regulatory assets were as follows:

December 31	2007		2006
(in thousands)
Retirement benefit plans (5 years for HELCO’s $10 million prepaid pension regulatory asset, indeterminate for remainder)	$	169,814	$	—
Income taxes, net (1 to 36 years)		74,605		73,178
Postretirement benefits other than pensions (18 years; 5 years)		8,949		10,738
Unamortized expense and premiums on retired debt and equity issuances (14 to 30 years; 1 to 21 years)		17,510		14,909
Demand-side management program costs, net (1 year)		4,113		4,521
Vacation earned, but not yet taken (1 year)		5,997		5,759
Other (1 to 20 years)		4,002		3,244
	$	284,990	$	112,349

The regulatory asset 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).

Regulatory liabilities were as follows:

December 31	2007		2006
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	259,765	$	239,049
Other (5 years; 2 to 5 years)		1,841		1,570
	$	261,606	$	240,619

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7. Income taxes

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,” which prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate resolution with tax authorities) for the financial statement recognition and measurement of an income tax position taken or expected to be taken in a tax return. The Company adopted FIN 48 in the first quarter of 2007.

As a result of the implementation of FIN 48, the Company reclassified certain deferred tax liabilities to a liability for uncertain tax positions (FIN 48 liability) and reduced retained earnings by $0.6 million as of January 1, 2007 for the cumulative effect of adoption of FIN 48.

The Company records interest on income taxes in “Interest and other charges.” For 2007, 2006 and 2005, interest (income) expense on income taxes was $0.6 million, ($0.3) million and ($0.7) million, respectively.

The Company will record penalties, if any, in “Other, net” under “Other income”. As of December 31, 2007 and January 1, 2007 (implementation date), the total amount of accrued interest related to uncertain tax positions and recognized on the balance sheet was $1.2 million and $.6 million, respectively.

As of December 31, 2007, the total amount of FIN 48 liability was $5.5 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 FIN 48 liability will significantly change within the next 12 months due to the resolution of issues under examination by the Internal Revenue Service. Management cannot estimate the range of the reasonably possible change.

The changes in total unrecognized tax benefits were as follows:

Year ended December 31	2007
(in millions)
Unrecognized tax benefits, January 1	$	23.6
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		0.8
Reductions for tax positions of prior years		—
Decreases due to tax positions taken		—
Settlements		—
Lapses of statute of limitations		—
Unrecognized tax benefits, December 31	$	24.4

In addition to the FIN 48 liability, the unrecognized tax benefits include $18.9 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 FIN 48 liability was required to offset these potential benefits.

Tax years 2003 to 2006 currently remain subject to examination by the Internal Revenue Service and Department of Taxation of the State of Hawaii.

The Company’s effective federal and state income tax rate for 2007 was 37%, compared to an effective tax rate for 2006 of 38%. The lower effective tax rate was primarily due to domestic production activities deductions related to the generation of electricity and the impact of state tax credits (including the acceleration of the state tax credits associated with the write-off of a portion of CT-4 and CT-5 costs) recognized against a smaller income tax expense base.

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

December 31	2007			2006			2005
(in thousands)
Federal:
Current	$	54,767		$	50,208		$	23,799
Deferred		(22,853	)		(7,000	)		17,497
Deferred tax credits, net		(1,154	)		(1,259	)		(1,351	)
		30,760			41,949			39,945
State:
Current		5,073			2,889			(1,407	)
Deferred		(3,699	)		(1,267	)		3,020
Deferred tax credits, net		1,992			3,810			3,471
		3,366			5,432			5,084
Total	$	34,126		$	47,381		$	45,029

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $3.2 million, $0.9 million and $0.4 million for 2007, 2006 and 2005, 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 follows:

December 31	2007			2006			2005
(in thousands)
Amount at the federal statutory income tax rate	$	32,559		$	44,024		$	41,989
State income taxes on operating income, net of effect on federal income taxes		2,188			3,530			3,305
Other		(621	)		(173	)		(265	)
Income taxes charged to operating expenses	$	34,126		$	47,381		$	45,029

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

December 31	2007		2006
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	101,075	$	93,014
Retirement benefits in AOCI		—		80,665
Contributions in aid of construction and customer advances		76,342		38,582
Other		21,753		9,534
		199,170		221,795
Deferred tax liabilities:
Property, plant and equipment		287,231		279,539
Regulatory assets, excluding amounts attributable to property, plant and equipment		29,050		28,495
Retirement benefits		15,590		26,862
Change in accounting method		23,036		—
Retirement benefits in AOCI		736		—
Other		5,640		4,954
		361,283		339,850
Net deferred income tax liability	$	162,113	$	118,055

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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. Based upon historical taxable income, projections for future taxable income and available tax planning strategies, management believes it is more likely than not the Company will realize substantially all of the benefits of the deferred tax assets.

As of December 31, 2007, the FIN 48 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 (net of AFUDC-Debt) and income taxes was as follows:

Years ended December 31	2007		2006		2005
(in thousands)
Interest	$	47,155	$	47,206	$	46,221
Income taxes	$	26,106	$	52,782	$	20,554

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $5.2 million, $6.3 million and $5.1 million in 2007, 2006 and 2005, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $17.7 million, $13.5 million and $11.8 million in 2007, 2006 and 2005, respectively.

9. Major customers

HECO and its subsidiaries received approximately 9% ($193 million), 10% ($197 million) and 10% ($176 million), of their operating revenues from the sale of electricity to various federal government agencies in 2007, 2006 and 2005, respectively.

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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 the ERISA. In addition, some current and former executives and directors participate in noncontributory, nonqualified plans (collectively, Supplemental/Excess/Directors Plans). In general, benefits are based on the employees’ years of service and compensation.

The continuation of the Plan and the Supplemental/Excess/Directors 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, and no participants have accrued any benefits after that time. The plan 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/Excess/Directors 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.

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) was signed into law on December 8, 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 (to be 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.

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” which requires employers to recognize on their balance sheets the funded status of defined benefit pension and other postretirement benefit plans with an offset to AOCI in stockholders’ equity (using the projected benefit obligation, rather than the accumulated benefit obligation, to calculate the funded status of pension plans).

By application filed on December 8, 2005 (AOCI Docket), the Company had requested the PUC to permit it to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension

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liability as prescribed by SFAS No. 87. The Company updated its application in the AOCI Docket in November 2006 to take into account SFAS No. 158. On January 26, 2007, the PUC issued a D&O in the updated AOCI Docket, which denied the Company’s request to record a regulatory asset on the grounds that the Company had not met its 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 Company in support of their request.

In HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the Company 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. Under the tracking mechanisms, any costs determined under SFAS Nos. 87 and 106, as amended, that are over/under amounts allowed in rates are charged/credited to a regulatory asset/liability. The regulatory asset/liability for each utility will be amortized over 5 years beginning with the respective utility’s next rate case.

The pension tracking mechanisms generally require the Company to fund only the minimum level required under the law until the existing pension assets are reduced to zero, at which time the Company would make contributions to the pension trust in the amount of the actuarially calculated net periodic pension costs, except when limited by the ERISA minimum contribution requirements or the maximum contribution limitation on deductible contributions imposed by the Internal Revenue code. The OPEB tracking mechanisms generally require the Company to make contributions to the OPEB trust in the amount of the actuarially calculated net periodic benefit costs, except when limited by material, adverse consequences imposed by federal regulations.

A pension funding study was filed in the HECO rate case in May 2007. The conclusions in the study were consistent with the funding practice proposed with the pension tracking mechanism.

In its 2007 interim decisions for HELCO’s 2006, HECO’s 2007 and MECO’s 2007 test year rate cases, the PUC approved the adoption of the proposed pension and OPEB tracking mechanisms on an interim basis (subject to the PUC’s final D&Os) and established the amount of net periodic benefit costs to be recovered in rates by each utility.

Under HELCO’s interim order, a regulatory asset (representing HELCO’s $12.8 million prepaid pension asset as of December 31, 2006 prior to the adoption of SFAS No. 158) was allowed to be recovered (and is being amortized) over a period of five years and was allowed to be included in HELCO’s rate base, net of deferred income taxes. On October 25, 2007, however, the PUC issued an amended proposed final D&O for HECO’s 2005 test year rate case, which when issued in final form, would reverse the portion of the interim D&O related to the inclusion of HECO’s approximately $50 million pension asset, net of deferred income taxes, in rate base, and would require a refund of revenues associated with that reversal, including interest, retroactive to September 28, 2005 (the date the interim increase became effective). In 2007, HECO accrued $16 million for the potential customer refunds, including interest, reducing 2007 net income by $9 million. In the settlement agreement and interim PUC decision in HECO’s 2007 test year rate case, HECO’s pension asset was not included in HECO’s rate base and amortization of the pension asset was not included as part of the pension tracking mechanism adopted in the proceeding on an interim basis. The issue of whether to amortize HECO’s prepaid pension asset ($51 million at December 31, 2007), if allowed to be included in rate base by the PUC, has thus been deferred until HECO’s next rate case proceeding. Similarly, in the settlement agreement and interim PUC decision in MECO’s 2007 test year rate case, MECO’s pension asset ($1 million as of December 31, 2007) was not included in MECO’s rate base and amortization of the pension asset was not included as part of the pension tracking mechanism adopted in the proceeding on an interim basis.

As a result of the 2007 interim orders, the Company has reclassified to a regulatory asset charges for retirement benefits that would otherwise be recorded in accumulated other comprehensive income pursuant to SFAS No. 158 (amounting to the elimination of a potential charge to AOCI at December 31, 2007 of $171 million pre-tax, compared to a retirement benefits pre-tax charge of $207 million at December 31, 2006).

Retirement benefits expense for the Company for 2007, 2006 and 2005 was $27 million, $22 million and $13 million, respectively.

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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 2007 and 2006 and the funded status of these plans and amounts related to these plans reflected in the Company’s balance sheet as of December 31, 2007 and 2006 were as follows:

	2007						2006
(in thousands)	Pension benefits			Other benefits			Pension benefits			Other benefits
Benefit obligation, January 1	$	877,365		$	186,359		$	859,080		$	185,839
Service cost		25,527			4,652			26,719			4,965
Interest cost		51,588			10,512			48,348			10,337
Amendments		—			—			116			—
Actuarial gain		(7,084	)		(10,671	)		(14,925	)		(5,350	)
Benefits paid and expenses		(44,384	)		(8,926	)		(41,973	)		(9,432	)
Benefit obligation, December 31		903,012			181,926			877,365			186,359
Fair value of plan assets, January 1		784,163			133,815			730,101			117,352
Actual return on plan assets		67,378			11,390			95,909			15,656
Employer contribution		2,846			9,293			—			9,789
Benefits paid and expenses		(44,486	)		(8,974	)		(41,847	)		(8,982	)
Fair value of plan assets, December 31		809,901			145,524			784,163			133,815
Accrued benefit liability, December 31		(93,111	)		(36,402	)		(93,202	)		(52,544	)
AOCI, January 1		176,057			31,258			45			—
Recognized during year – net recognized transition obligation		(1	)		(3,130	)		(2	)		(3,130	)
Recognized during year – prior service (cost)/credit		762			—			770			—
Recognized during year – net actuarial losses		(10,486	)		—			(10,699	)		(388	)
Occurring during year – prior service cost		—			—			115			—
Occurring during year – net actuarial gains		(13,126	)		(12,219	)		(46,367	)		(11,248	)
Other adjustments		—			—			232,195			46,024
		153,206			15,909			176,057			31,258
Impact of PUC D&Os		(152,888	)		(18,120	)		—			—
AOCI, December 31		318			(2,211	)		176,057			31,258
Net actuarial loss		157,324			260			180,937			12,480
Prior service gain		(4,118	)		—			(4,881	)		—
Net transition obligation		—			15,649			1			18,778
		153,206			15,909			176,057			31,258
Impact of PUC D&Os		(152,888	)		(18,120	)		—			—
AOCI, December 31		318			(2,211	)		176,057			31,258
Income tax benefits		(124	)		860			(68,503	)		(12,162	)
AOCI, net of taxes, December 31	$	194		$	(1,351	)	$	107,554		$	19,096

The Company does not expect any plan assets to be returned to the Company during calendar year 2008.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2007, 2006 and 2005.

The defined benefit pension plans’ accumulated benefit obligations, which do not consider projected pay increases (unlike the projected benefit obligations shown in the table above), as of December 31, 2007 and 2006 were $794 million and $769 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

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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 expected long-term rate of return assumption of 8.5% was based on the plans’ asset allocation, projected asset class returns provided by the plans’ actuarial consultant and the past performance of the plans’ assets.

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

	Pension benefits								Other benefits
					Investment policy								Investment policy
December 31	2007		2006		Target		Range		2007		2006		Target		Range
Asset category
Equity securities	72	%	72	%	70	%	65-75	%	70	%	71	%	70	%	65-75	%
Fixed income	27		27		30		25-35	%	30		29		30		25-35	%
Other1	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.

The Company’s current estimate of contributions to the retirement benefit plans in 2008 is $14 million.

As of December 31, 2007, the benefits expected to be paid under the retirement benefit plans in 2008, 2009, 2010, 2011, 2012 and 2013 through 2017 amounted to $57 million, $59 million, $61 million, $63 million, $66 million and $370 million, respectively.

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

	Pension benefits						Other benefits
December 31	2007		2006		2005		2007		2006		2005
Benefit obligation
Discount rate	6.125	%	6.00	%	5.75	%	6.125	%	6.00	%	5.75	%
Expected return on plan assets	8.5		8.5		9.0		8.5		8.5		9.0
Rate of compensation increase	4.0		4.0		4.6		4.0		4.0		4.6
Net periodic benefit cost (years ended)
Discount rate	6.00		5.75		6.00		6.00		5.75		6.00
Expected return on plan assets	8.5		9.0		9.0		8.5		9.0		9.0
Rate of compensation increase	4.0		4.6		4.6		4.0		4.6		4.6

As of December 31, 2007, the assumed health care trend rates for 2008 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2013 and thereafter; dental, 5.00%; and vision, 4.00%. As of December 31, 2006, the assumed health care trend rates for 2007 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2012 and thereafter; dental, 5.00%; and vision, 4.00%.

The components of net periodic benefit cost were as follows:

	Pension benefits									Other benefits
Years ended December 31	2007			2006			2005			2007			2006			2005
(in thousands)
Service cost	$	25,527		$	26,719		$	23,832		$	4,652		$	4,965		$	5,098
Interest cost		51,588			48,348			46,817			10,512			10,337			10,818
Expected return on plan assets		(61,101	)		(64,467	)		(67,078	)		(9,778	)		(9,758	)		(9,704	)
Amortization of net transition obligation		1			2			2			3,130			3,130			3,130
Amortization of net prior service gain		(762	)		(770	)		(770	)		—			—			—
Amortization of net actuarial loss		10,486			10,699			4,735			—			388			395
Net periodic benefit cost		25,739			20,531			7,538			8,516			9,062			9,737
Impact of PUC D&Os		1,195			—			—			187			—			—
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	26,934		$	20,531		$	7,538		$	8,703		$	9,062		$	9,737

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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 2008 are $(0.8) million, $6.6 million and nil, respectively. The estimated prior service cost, net actuarial loss and net transitional obligation for other benefit plans that will be amortized from AOCI or regulatory asset into net periodic other than pension benefit cost over 2008 are nil, nil and $3.1 million, respectively.

The Company recorded pension expense of $20 million, $15 million and $6 million and OPEB expense of $7 million each year in 2007, 2006 and 2005, respectively, and charged the remaining amounts primarily to electric utility plant.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for pension plans with an accumulated benefit obligation in excess of plan assets were $4 million, $3 million and nil, respectively, as of December 31, 2007 and December 31, 2006.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2007, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.2 million and the postretirement benefit obligation by $3.1 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.2 million and the postretirement benefit obligation by $3.5 million.

11. Commitments and contingencies

Fuel contracts. HECO and its subsidiaries have contractual agreements to purchase minimum quantities of fuel oil and diesel fuel through December 31, 2014 (at prices tied to the market prices of petroleum products in Singapore and Los Angeles). Based on the average price per barrel as of January 1, 2008, the estimated cost of minimum purchases under the fuel supply contracts is $0.9 billion per year for 2008 through 2012 and a total of $1.8 billion for the period 2013 through 2014. The actual cost of purchases in 2008 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 $795 million, $755 million and $662 million of fuel under contractual agreements in 2007, 2006 and 2005, respectively.

Power purchase agreements (PPAs).As of December 31, 2007, 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 $537 million, $507 million and $458 million for 2007, 2006 and 2005, 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 2008 through 2012 and a total of $1.0 billion in the period from 2013 through 2030.

In general, HECO and its subsidiaries base their payments under the PPAs upon available capacity and 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.

Interim increases.On September 27, 2005, the PUC issued an interim decision and order (D&O) in HECO’s 2005 test year rate case granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or a net increase of $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges), which was implemented on September 28, 2005.

On October 25, 2007, the PUC issued an amended proposed final D&O in HECO’s 2005 test year rate case, authorizing an increase of 3.74%, or $45.7 million (or a net increase of $34 million or 2.7%), in annual revenues. The amended proposed final D&O, when issued in final form, would reverse the portion of the interim D&O related to the

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inclusion of HECO’s approximately $50 million pension asset, net of deferred income taxes, in rate base, and would require a refund of the revenues associated with that reversal, including interest, retroactive to September 28, 2005 (the date the interim increase became effective), amounting to $16 million through December 31, 2007 ($9 million, net of tax benefits). Interest on the refund amount would continue to accrue until the amount is refunded to customers.

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

On October 22, 2007, the PUC issued, and HECO immediately implemented, an interim D&O in HECO’s 2007 test year rate case, granting HECO an increase of $69.997 million in annual revenues over current effective rates at the time of the interim decision.

On December 21, 2007, the PUC issued, and MECO immediately implemented, an interim D&O in MECO’s 2007 test year rate case, granting MECO an increase of $13.2 million in annual revenues, or a 3.7% increase.

Through December 31, 2007, HECO and its subsidiaries had recognized $150 million of revenues with respect to interim orders ($14 million related to interim orders regarding certain integrated resource planning costs and $136 million related to interim orders with respect to HECO’s interim surcharge to recover DG fuel and fuel trucking costs and general rate increase requests, not including revenues of $16 million for which a reserve, including interest, has been accrued to reflect the PUC’s proposed final D&O in the 2005 HECO rate case), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final D&Os.

Energy cost adjustment clauses. On June 19, 2006, the PUC issued an order in HECO’s 2005 test year rate case indicating that the record in the pending case had not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the public utility and its customers, (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means, such as through fuel hedging contracts, (4) preserve, to the extent reasonably possible, the public utility’s financial integrity, and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already had reviewed the automatic fuel rate adjustment clause in rate cases, Act 162 required that these five specific factors be addressed in the record. In October 2007, the PUC issued an amended proposed final D&O in HECO’s 2005 test year rate case in which the PUC stated it would not require the parties in the rate case proceeding to file a stipulated procedural schedule on this issue, but that it expects HECO and HELCO to develop information relating to the Act 162 factors for examination during their next rate case proceedings.

The ECAC provisions of Act 162 were reviewed in the HELCO rate case based on a 2006 test year and are being reviewed in the HECO and MECO rate cases based on 2007 test years. In the HELCO 2006 test year rate case, the filed testimony of the Consumer Advocate’s consultant concluded that HELCO’s ECAC provides a fair sharing of the risks of fuel cost changes between HELCO and its ratepayers in a manner that preserves the financial integrity of HELCO without the need for frequent rate filings. On April 4, 2007 the PUC issued an interim D&O in the HELCO 2006 test year rate case which reflected the continuation of HELCO’s ECAC, consistent with a settlement agreement reached between HELCO and the Consumer Advocate.

In an order issued on August 24, 2007, the PUC added as an issue to be addressed in HECO’s 2007 test year rate case whether HECO’s ECAC complies with the requirements of Act 162 as codified in the Hawaii Revised Statutes (HRS). On September 6, 2007, HECO, the Consumer Advocate and the DOD (the parties) executed and filed an agreement on most of the issues in HECO’s 2007 test year rate case proceeding. In the settlement agreement, the parties agreed that the ECAC should continue in its present form for purposes of an interim rate increase and stated that they are continuing discussions with respect to the final design of the ECAC to be proposed for approval in the final D&O in this proceeding. On October 22, 2007 the PUC issued an interim D&O in HECO’s 2007 test year rate case which reflected the continuation of HECO’s ECAC for purposes of the interim increase, consistent with the agreement reached among the parties. The parties will file proposed findings of fact and conclusions of law on all issues in this proceeding, including the ECAC, and the schedule for that filing is being determined. The parties have agreed that their

31

resolution of the ECAC issue will not affect their agreement regarding revenue requirements in the proceeding. Management cannot predict the ultimate effect of the required Act 162 analysis on the continuation of the Company’s existing ECACs.

In an order issued on June 19, 2007, the PUC approved a procedural order for MECO’s 2007 test year rate case and required MECO and the Consumer Advocate (the parties) to address an additional issue of whether MECO’s ECAC complies with the requirements of Act 162 as codified in the HRS. In its direct testimony, the Consumer Advocate concluded that the ECAC’s fixed efficiency factors are an effective means of sharing the operating and performance risks between MECO’s ratepayers and shareholders and that MECO’s ECAC provides a fair sharing of the risks of fuel cost changes between MECO and its ratepayers in a manner that preserves the financial integrity of MECO without the need for frequent rate filings. On December 7, 2007, the parties filed a stipulated settlement letter for this proceeding in which the parties agreed, among other things, that no further changes are required to MECO’s ECAC in order to comply with the requirements of Act 162. On December 21, 2007 the PUC issued an interim D&O in MECO’s 2007 test year rate case which reflected the continuation of MECO’s ECAC for purposes of the interim increase, consistent with the agreement reached among the parties.

On April 23, 2007, the PUC issued an order denying HECO’s proposal to recover $2.4 million, including revenue taxes, of distributed generation fuel and trucking and low sulfur fuel oil (LFSO) trucking costs since January 1, 2006 through the reconciliation process for the ECAC. However, the PUC allowed HECO to establish and implement a new and separate interim surcharge to recover its additional DG and LFSO costs on a going forward basis. HECO implemented an interim surcharge to recover such costs incurred from May 1, 2007.

HELCO power situation. In 1991, HELCO began planning to meet increased electric generation demand forecast for 1994. It planned to install at its Keahole power plant two 20 MW combustion turbines (CT-4 and CT-5), followed by an 18 MW heat recovery steam generator (ST-7), at which time these units would be converted to a 56 MW (net) dual-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 CT-4, CT-5 and ST-7, resulting in significant delays in the installation and operation of these generating units. However, in 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposed the settlement) entered into a settlement agreement with HELCO and several Hawaii regulatory agencies, intended in part to permit HELCO to complete CT-4 and CT-5 (Settlement Agreement). The Settlement Agreement required HELCO to undertake a number of actions including expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction emissions control equipment, assisting the Department of Hawaiian Home Lands in installing solar water heating in its housing projects, supporting the Keahole Defense Coalition’s participation in certain PUC cases, and cooperating with neighbors and community groups (including adding a Hot Line service). While certain of these actions have been completed, and required payments to other parties to the settlement agreement were timely made, a number of these actions are ongoing.

As a result of the final resolution of various proceedings due primarily to the Settlement Agreement, CT-4 and CT-5 became operational in mid-2004, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work is ongoing to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate CT-4 and CT-5 as required to meet its system needs. Construction of a noise barrier was substantially completed in December 2007, and installation of other noise mitigation measures are planned. Subsequent testing will determine whether current restrictions on the operations of these units may be eliminated or eased.

HELCO’s plans for ST-7 are progressing. In November 2003, HELCO filed a boundary amendment petition (to reclassify the Keahole plant site from conservation land use to urban land use) with the State of Hawaii Land Use Commission, which boundary amendment was approved in October 2005. In May 2006, HELCO obtained the County of Hawaii rezoning to a “General Industrial” classification, and in June 2006, received approval for a covered source permit amendment to include selective catalytic reduction with the installation of ST-7. Management believes that any other required permits will be obtained and anticipates an in-service date for ST-7 in mid-2009. HELCO has commenced engineering, design and certain construction work for ST-7. HELCO’s current cost estimate for ST-7 is

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approximately $92 million, of which approximately $9 million has been incurred through December 31, 2007. HELCO has made about $32 million in additional commitments for materials, equipment and outside services, a substantial portion of which are subject to cancellation charges.

CT-4 and CT-5 costs incurred and allowed. HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $110 million. The $110 million of costs was reclassified from construction in progress to plant and equipment in 2004 ($103 million) and 2005 ($7 million) and depreciated beginning January 1, 2005 and 2006, respectively, and HELCO sought recovery of these costs as part of its 2006 test year rate case.

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

In April 2007, the PUC issued an interim D&O granting HELCO a 7.58% increase in rates, which reflects the settlement agreement reached between HELCO and the Consumer Advocate, including the agreement to write-off a portion of CT-4 and CT-5 costs. However, the interim order does not commit the PUC to accept any of the amounts in the interim increase in its final order. If it becomes probable that the PUC, in its final order, will disallow additional costs incurred for CT-4 and CT-5 for ratemaking purposes, HELCO will be required to record an additional write-off.

East Oahu Transmission Project (EOTP).HECO transmits bulk power to the Honolulu/East Oahu area over two major transmission corridors (Northern and Southern). HECO had planned to construct a partial underground/partial overhead 138 kilovolt (kV) line from the Kamoku substation to the Pukele substation, which serves approximately 16% of Oahu’s electrical load, including Waikiki, in order to close the gap between the Southern and Northern corridors and provide a third transmission line to the Pukele substation. In total, this additional transmission capacity would benefit an area that comprises approximately 56% of the power demand on Oahu. However, in June 2002, an application for a permit which would have allowed construction in the originally planned route through conservation district lands was denied.

HECO continued to believe that the proposed reliability project (the East Oahu Transmission Project) was needed and, in December 2003, filed an application with the PUC requesting approval to commit funds (currently estimated at $74 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervener status to an environmental organization and three elected officials (collectively treated as one party), and a more limited participant status to four community organizations. The environmental review process for the revised EOTP was completed and the PUC issued a Finding of No Significant Impact in April 2005.

In written testimony filed in June 2005, the 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 in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, and the related allowance for funds used during construction (AFUDC) of $5 million. In rebuttal testimony filed in August 2005, HECO contested the consultant’s recommendation, emphasizing that the originally proposed 138 kV line would have been a more comprehensive and robust solution to the transmission concerns the project addressed. The PUC held an evidentiary hearing on HECO’s application in November 2005, and post-hearing briefing was completed in March 2006. Just prior to the November 2005 evidentiary hearing, the PUC approved that part of a stipulation between HECO and the Consumer Advocate providing that (i) this proceeding should determine whether HECO should be given approval to expend funds for the EOTP, but with the understanding that no part of the EOTP costs may be recovered from ratepayers unless and until the PUC grants HECO recovery in a rate case (which is consistent with other projects) and (ii) the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs is reserved to, and may be raised in, the next HECO rate case (or other proceeding) in which HECO seeks approval to recover the EOTP costs. In October 2007, the PUC issued a final D&O approving HECO’s request to expend funds for a revised EOTP using a 46 kV system, 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.

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Subject to obtaining other construction permits, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases. The first phase is currently projected to be completed in 2010 and the projected completion date of the second phase is being evaluated.

As of December 31, 2007, the accumulated costs recorded for the EOTP amounted to $33 million, including (i) $12 million of planning and permitting costs incurred prior to 2003, (ii) $6 million of planning and permitting costs incurred after 2002 and (iii) $15 million for AFUDC. Management believes no adjustment to project costs is required as of December 31, 2007. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HECO may be required to write off a material portion or all of the project costs incurred in its efforts to put the project into service whether or not it is completed.

Environmental regulation. 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 identify petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, the Company believes the costs of responding to releases identified to date will not have a material adverse effect, individually or in the aggregate, on its consolidated financial statements.

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.In 1995, the Department of Health of the State of Hawaii (DOH) issued letters indicating that it had identified a number of parties, including HECO, who appeared to be potentially responsible for historical subsurface petroleum contamination and/or operated their facilities upon petroleum-contaminated land at or near Honolulu Harbor in the Iwilei district of Honolulu. Certain of the identified parties formed a work group to determine the nature and extent of any contamination and appropriate response actions, as well as to identify additional potentially responsible parties (PRPs). The U.S. Environmental Protection Agency (EPA) became involved in the investigation in June 2000. Later in 2000, the DOH issued notices to additional PRPs. The parties in the work group and some of the new PRPs (collectively, the Participating Parties) entered into a joint defense agreement and signed a voluntary response agreement with the DOH. The Participating Parties agreed to fund investigative and remediation work using an interim cost allocation method (subject to a final allocation) and have organized a limited liability company to perform the work.

In 2001, management developed and expensed a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of $1.1 million. Since 2001, subsurface investigation and assessment have been conducted and several preliminary oil removal tasks have been performed at the Iwilei Unit in accordance with notices of interest issued by the EPA and the DOH.

In 2003, HECO and other Participating Parties with active operations in the Iwilei area investigated their operations to evaluate whether their facilities were active sources of petroleum contamination in the area. HECO’s investigation concluded that its facilities were not then releasing petroleum. Routine maintenance and inspections of HECO facilities since then confirm that they are not currently releasing petroleum.

During 2006 and the beginning of 2007, the PRPs developed analyses of various remedial alternatives for two of the four remedial subunits of the Iwilei Unit. The DOH will use the analyses to make a final determination of which remedial alternatives the PRPs will be required to implement. The DOH is scheduled to complete the final remediation determinations for all remedial subunits of the Iwilei Unit by the end of the first quarter of 2008. HECO management developed an estimate of HECO’s share of the costs associated with implementing the PRP recommended remedial approaches for the two subunits covered by the analyses of $1.2 million, which was expensed in 2006. Subsequently, based on the estimated costs for the remaining two subunits, as well as updated estimates for total remediation costs, HECO management expensed an additional $0.6 million in the third quarter of 2007.

As of December 31, 2007, the remaining accrual (amounts expensed less amounts expended) related to the Honolulu Harbor investigation was $1.8 million. Because (1) the full scope of additional investigative work, remedial

34

activities and monitoring remain 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, which is located in the “Downtown” unit of the Honolulu Harbor site), the cost estimate may be subject to significant change and additional material investigative and remedial costs may be incurred.

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 adopt BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, which it has not done to date, HECO, HELCO and MECO will evaluate the plan’s impacts, if any. 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.

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. Effective September 9, 2004, the EPA issued a rule, which established location and technology-based design, construction and capacity standards for existing cooling water intake structures. These standards applied to HECO’s Kahe, Waiau and Honolulu generating stations, unless the utility could demonstrate that at each facility implementation of these standards would result in costs either significantly higher than projected costs the EPA considered in establishing the standards for the facility (cost-cost test) or significantly greater than the benefits of meeting the standards (cost-benefit test). In either case, the EPA would then make a case-by-case determination of an appropriate performance standard. The regulation also would have allowed restoration of aquatic organism populations in lieu of meeting the standards. The rule required covered facilities to demonstrate compliance by March 2008. HECO had retained a consultant that was developing a cost effective compliance strategy and a preliminary assessment of technologies and operational measures under the rule.

On January 25, 2007, the U.S. Circuit Court for the Second Circuit issued a decision in Riverkeeper, Inc. v. EPA that remanded for further consideration and proceedings significant portions of the rule and found other portions of the rule to be impermissible. In particular, the court determined that restoration and the cost-benefit test provisions of the rule were impermissible under the Clean Water Act. It also remanded the best technology available determination to permit the EPA to provide a reasoned explanation for its decision or a new determination. It remanded the cost-cost test for the EPA’s further consideration based on the best technology available determination and to afford adequate notice. Although the EPA has decided not to request the U.S. Supreme Court to review the Court of Appeal’s decision, several utilities have sought Supreme Court review. If the Court of Appeal’s decision stands, the ruling reduces the compliance options available to HECO. In addition, the EPA has not issued a schedule for rulemaking, which would be necessary to comply with the Court’s decision. On July 9, 2007, the EPA formally suspended the rule. In the suspension announcement, the EPA 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. Currently, this guidance does not affect the HECO facilities subject to the cooling water intake requirements because none of the facilities are subject to permit renewal until mid-2009. Due to the uncertainties raised by the Court’s decision as well as the need for further rulemaking by the EPA, management is unable to predict which compliance options, some of which could entail significant capital expenditures to implement, will be applicable to its facilities.

Collective bargaining agreements.As of December 31, 2007, approximately 58% of the Company’s employees are members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, Unit 8, which is the only union representing employees of the Company. Four-year collective bargaining and benefit agreements with the union covered a term from November 1, 2003 to October 31, 2007 and have been extended to March 3, 2008. These collective bargaining agreements provided for non-compounded wage increases (3% on November 1, 2003; 1.5% on November 1, 2004, May 1, 2005, November 1, 2005 and May 1, 2006; and 3% on November 1, 2006). Negotiations for new agreements began in the third quarter of 2007 and are continuing.

35

Limited insurance. HECO and its subsidiaries purchase insurance coverages to protect themselves against loss of or damage to their properties and against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s overhead and underground transmission and distribution systems (with the exception of substation buildings and contents) have a replacement value roughly estimated at $4 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 its results of operations and financial condition.

12. Regulatory restrictions on distributions to parent

As of December 31, 2007, net assets (assets less liabilities and preferred stock) of approximately $495 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 $3.4 million, $3.4 million and $3.3 million for general management and administrative services in 2007, 2006 and 2005, 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 borrowings from HEI fluctuate during the year, and totaled nil at December 31, 2007 and 2006. The interest charged on short-term borrowings from HEI is based on the rate HEI pays on its commercial paper borrowings, provided HEI’s commercial paper rating is equal to or better than HECO’s rating. If HEI’s commercial paper rating falls below HECO’s, or if HEI has no commercial paper borrowings, interest is based on HECO’s short-term external borrowing rate, or quoted rates from the Wall Street Journal for 30-day dealer-placed commercial paper.

Interest charged by HEI to HECO totaled nil, nil and $0.4 million in 2007, 2006 and 2005, respectively.

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 developed 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

36

liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates and have not been considered.

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

Cash and 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

The fair values of off-balance sheet financial instruments were estimated based on quoted market prices of comparable instruments.

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

December 31	2007				2006
(in thousands)	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and equivalents	$	4,678	$	4,678	$	3,859	$	3,859
Financial liabilities:
Short-term borrowings from nonaffiliates		28,791		28,791		113,107		113,107
Long-term debt, net, including amounts due within one year		885,099		904,092		766,185		800,975
Off-balance sheet item:
HECO-obligated preferred securities of trust subsidiary		50,000		46,200		50,000		50,800

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.

37

17. Consolidating financial information (unaudited)

Consolidating balance sheet

	December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	28,833		4,982		4,346		—	—	—		$	38,161
Plant and equipment		2,504,389		830,237		796,600		—	—	—			4,131,226
Less accumulated depreciation		(988,732	)	(324,517	)	(333,864	)	—	—	—			(1,647,113	)
Plant acquisition adjustment, net		—		—		41		—	—	—			41
Construction in progress		114,227		26,262		10,690		—	—	—			151,179
Net utility plant		1,658,717		536,964		477,813		—	—	—			2,673,494
Investment in wholly owned subsidiaries, at equity		410,911		—		—		—	—	(410,911	)[2]		—
Current assets
Cash and equivalents		203		3,069		773		198	435	—			4,678
Advances to affiliates		36,600		—		2,000		—	—	(38,600	)[1]		—
Customer accounts receivable, net		98,129		26,554		21,429		—	—	—			146,112
Accrued unbilled revenues, net		82,550		16,795		14,929		—	—	—			114,274
Other accounts receivable, net		6,657		2,481		3,025		—	—	(5,248	)[1]		6,915
Fuel oil stock, at average cost		57,289		12,494		22,088		—	—	—			91,871
Materials & supplies, at average cost		15,723		4,404		14,131		—	—	—			34,258
Prepayments and other		6,946		1,239		1,305		—	—	—			9,490
Total current assets		304,097		67,036		79,680		198	435	(43,848	)		407,598
Other long-term assets
Regulatory assets		209,034		40,663		35,293		—	—	—			284,990
Unamortized debt expense		10,555		2,458		2,622		—	—	—			15,635
Other		30,449		5,671		6,051		—	—	—			42,171
Total other long-term assets		250,038		48,792		43,966		—	—	—			342,796
	$	2,623,763		652,792		601,459		198	435	(454,759	)	$	3,423,888
Capitalization and liabilities
Capitalization
Common stock equity	$	1,110,462		201,820		208,521		182	388	(410,911	) [2]	$	1,110,462
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—	—			34,293
Long-term debt, net		567,657		145,811		171,631		—	—	—			885,099
Total capitalization		1,700,412		354,631		385,152		182	388	(410,911	)		2,029,854
Current liabilities
Short-term borrowings-nonaffiliates		28,791		—		—		—	—	—			28,791
Short-term borrowings-affiliate		2,000		36,600		—		—	—	(38,600	)[1]		—
Accounts payable		97,699		21,810		18,386		—	—	—			137,895
Interest and preferred dividends payable		9,774		2,370		2,738		—	—	(163	)[1]		14,719
Taxes accrued		119,032		35,380		35,225		—	—	—			189,637
Other		41,792		9,835		11,194		16	47	(5,085	)[1]		57,799
Total current liabilities		299,088		105,995		67,543		16	47	(43,848	)		428,841
Deferred credits and other liabilities
Deferred income taxes		130,573		17,791		13,749		—	—	—			162,113
Regulatory liabilities		180,725		46,460		34,421		—	—	—			261,606
Unamortized tax credits		32,664		12,941		12,814		—	—	—			58,419
Other		103,876		51,972		27,470		—	—	—			183,318
Total deferred credits and other liabilities		447,838		129,164		88,454		—	—	—			665,456
Contributions in aid of construction		176,425		63,002		60,310		—	—	—			299,737
	$	2,623,763		652,792		601,459		198	435	(454,759	)	$	3,423,888

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Consolidating balance sheet

	December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	25,919		4,977		4,346		—	—		$	35,242
Plant and equipment		2,428,155		807,474		767,300		—	—			4,002,929
Less accumulated depreciation		(953,187	)	(298,590	)	(307,136	)	—	—			(1,558,913	)
Plant acquisition adjustment, net		—		—		93		—	—			93
Construction in progress		80,298		9,745		5,576		—	—			95,619
Net utility plant		1,581,185		523,606		470,179		—	—			2,574,970
Investment in wholly owned subsidiaries, at equity		367,595		—		—		—	(367,595	)[2]		—
Current assets
Cash and equivalents		2,328		738		518		275	—			3,859
Advances to affiliates		54,400		—		—		—	(54,400	)[1]		—
Customer accounts receivable, net		81,912		24,228		19,384		—	—			125,524
Accrued unbilled revenues, net		64,235		14,437		13,523		—	—			92,195
Other accounts receivable, net		3,210		1,097		773		—	(657	)[1]		4,423
Fuel oil stock, at average cost		40,680		9,761		13,871		—	—			64,312
Materials & supplies, at average cost		13,959		4,892		11,689		—	—			30,540
Prepayments and other		7,537		1,463		695		—	—			9,695
Total current assets		268,261		56,616		60,453		275	(55,057	)		330,548
Other long-term assets
Regulatory assets		82,116		15,349		14,884		—	—			112,349
Unamortized debt expense		9,323		2,282		2,117		��	—			13,722
Other		23,507		4,340		3,698		—	—			31,545
Total other long-term assets		114,946		21,971		20,699		—	—			157,616
	$	2,331,987		602,193		551,331		275	(422,652	)	$	3,063,134
Capitalization and liabilities
Capitalization
Common stock equity	$	958,203		175,099		192,231		265	(367,595	)[2]	$	958,203
Cumulative preferred stock-not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,240		131,046		153,899		—	—			766,185
Total capitalization		1,461,736		313,145		351,130		265	(367,595	)		1,758,681
Current liabilities
Short-term borrowings-nonaffiliates		113,107		—		—		—	—			113,107
Short-term borrowings-affiliate		—		49,400		5,000		—	(54,400	)[1]		—
Accounts payable		61,672		22,572		18,268		—	—			102,512
Interest and preferred dividends payable		7,269		1,907		1,717		—	(248	)[1]		10,645
Taxes accrued		96,846		26,981		28,355		—	—			152,182
Other		27,012		5,971		10,536		10	(409	)[1]		43,120
Total current liabilities		305,906		106,831		63,876		10	(55,057	)		421,566
Deferred credits and other liabilities
Deferred income taxes		92,805		13,285		11,965		—	—			118,055
Regulatory liabilities		164,617		43,596		32,406		—	—			240,619
Unamortized tax credits		32,359		13,126		12,394		—	—			57,879
Other		110,473		52,274		26,859		—	—			189,606
Total deferred credits and other liabilities		400,254		122,281		83,624		—	—			606,159
Contributions in aid of construction		164,091		59,936		52,701		—	—			276,728
	$	2,331,987		602,193		551,331		275	(422,652	)	$	3,063,134

39

Consolidating statement of income

	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and Eliminations		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
Income before interest and other charges		86,354		19,127		21,897		(83	)	(47	)	(22,381	)		104,867
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	)
Preferred stock dividends of subsidiaries		—		—		—		—		—		915	[3]		915
		33,118		10,341		9,731		—		—		(1,559	)		51,631
Income before preferred stock dividends of HECO		53,236		8,786		12,166		(83	)	(47	)	(20,822	)		53,236
Preferred stock dividends of HECO		1,080		534		381		—		—		(915	)[3]		1,080
Net income for common stock	$	52,156		8,252		11,785		(83	)	(47	)	(19,907	)	$	52,156
Consolidating statement of retained earnings
	Year ended December 31, 2007
(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	700,252		92,836		111,536		(516	)	—		(203,856	)[2]	$	700,252
Net income for common stock		52,156		8,252		11,785		(83	)	(47	)	(19,907	)[2]		52,156
Adjustment to initially apply FIN 48		(620	)	(44	)	(33	)	—		—		77	[2]		(620	)
Common stock dividends		(27,084	)	—		(9,900	)	—		—		9,900	[2]		(27,084	)
Retained earnings, end of period	$	724,704		101,044		113,388		(599	)	(47	)	(213,786	)	$	724,704

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Consolidating statement of income

	Year ended December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and Eliminations		HECO Consolidated
Operating revenues	$	1,365,593		339,554		345,265		—		—		$	2,050,412
Operating expenses
Fuel oil		516,239		85,229		180,272		—		—			781,740
Purchased power		358,115		122,324		26,454		—		—			506,893
Other operation		126,300		29,907		30,242		—		—			186,449
Maintenance		56,732		19,669		13,816		—		—			90,217
Depreciation		74,798		29,722		25,644		—		—			130,164
Taxes, other than income taxes		126,849		31,553		32,011		—		—			190,413
Income taxes		31,215		4,339		11,827		—		—			47,381
		1,290,248		322,743		320,266		—		—			1,933,257
Operating income		75,345		16,811		24,999		—		—			117,155
Other income
Allowance for equity funds used during construction		4,059		195		2,094		—		—			6,348
Equity in earnings of subsidiaries		25,583		—		—		—		(25,583	)[2]		—
Other, net		4,387		503		1,176		(153	)	(2,790	)[1]		3,123
		34,029		698		3,270		(153	)	(28,373	)		9,471
Income before interest and other charges		109,374		17,509		28,269		(153	)	(28,373	)		126,626
Interest and other charges
Interest on long-term debt		26,967		7,233		8,909		—		—			43,109
Amortization of net bond premium and expense		1,378		411		409		—		—			2,198
Other interest charges		6,818		2,474		754		—		(2,790	)[1]		7,256
Allowance for borrowed funds used during construction		(1,816	)	(90	)	(973	)	—		—			(2,879	)
Preferred stock dividends of subsidiaries		—		—		—		—		915	[3]		915
		33,347		10,028		9,099		—		(1,875	)		50,599
Income before preferred stock dividends of HECO		76,027		7,481		19,170		(153	)	(26,498	)		76,027
Preferred stock dividends of HECO		1,080		534		381		—		(915	)[3]		1,080
Net income for common stock	$	74,947		6,947		18,789		(153	)	(25,583	)	$	74,947
Consolidating statement of retained earnings
	Year ended December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	654,686		88,763		99,269		(363	)	(187,669	)[2]	$	654,686
Net income for common stock		74,947		6,947		18,789		(153	)	(25,583	)[2]		74,947
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396	[2]		(29,381	)
Retained earnings, end of period	$	700,252		92,836		111,536		(516	)	(203,856	)	$	700,252

41

Consolidating statement of income

	Year ended December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and Eliminations		HECO Consolidated
Operating revenues	$	1,204,220		294,411		303,079		—		—		$	1,801,710
Operating expenses
Fuel oil		420,521		65,272		153,857		—		—			639,650
Purchased power		339,120		102,744		16,256		—		—			458,120
Other operation		117,818		26,427		28,717		—		—			172,962
Maintenance		52,547		16,504		13,191		—		—			82,242
Depreciation		70,687		27,177		25,006		—		—			122,870
Taxes, other than income taxes		112,082		27,205		28,008		—		—			167,295
Income taxes		26,144		7,535		11,350		—		—			45,029
		1,138,919		272,864		276,385		—		—			1,688,168
Operating income		65,301		21,547		26,694		—		—			113,542
Other income
Allowance for equity funds used during construction		4,031		174		900		—		—			5,105
Equity in earnings of subsidiaries		30,952		—		—		—		(30,952	)[2]		—
Other, net		4,254		526		626		(176	)	(1,692	)[1]		3,538
		39,237		700		1,526		(176	)	(32,644	)		8,643
Income before interest and other charges		104,538		22,247		28,220		(176	)	(32,644	)		122,185
Interest and other charges
Interest on long-term debt		26,886		7,256		8,921		—		—			43,063
Amortization of net bond premium and expense		1,379		413		420		—		—			2,212
Other interest charges		3,966		1,474		385		—		(1,692	)[1]		4,133
Allowance for borrowed funds used during construction		(1,575	)	(53	)	(392	)	—		—			(2,020	)
Preferred stock dividends of subsidiaries		—		—		—		—		915	[3]		915
		30,656		9,090		9,334		—		(777	)		48,303
Income before preferred stock dividends of HECO		73,882		13,157		18,886		(176	)	(31,867	)		73,882
Preferred stock dividends of HECO		1,080		534		381		—		(915	)[3]		1,080
Net income for common stock	$	72,802		12,623		18,505		(176	)	(30,952	)	$	72,802
Consolidating statement of retained earnings
	Year ended December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	632,779		85,861		94,492		(187	)	(180,166	)[2]	$	632,779
Net income for common stock		72,802		12,623		18,505		(176	)	(30,952	)[2]		72,802
Common stock dividends		(50,895	)	(9,721	)	(13,728	)	—		23,449	[2]		(50,895	)
Retained earnings, end of period	$	654,686		88,763		99,269		(363	)	(187,669	)	$	654,686

42

Consolidating Statements of Changes in Common Stock Equity

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO consolidated
Balance, December 31, 2004	$	1,017,104		186,505		189,413		294		—		(376,212	)	$	1,017,104
Comprehensive income:
Net income (loss)		72,802		12,623		18,505		(176	)	—		(30,952	)		72,802
Minimum pension liability adjustment, net of taxes of $158		249		—		—		—		—		—			249
Comprehensive income (loss)		73,051		12,623		18,505		(176	)			(30,952	)		73,051
Common stock dividends		(50,895	)	(9,721	)	(13,728	)	—		—		23,449			(50,895	)
Other		(1	)	—		—		—		—		—			(1	)
Balance, December 31, 2005		1,039,259		189,407		194,190		118		—		(383,715	)		1,039,259
Comprehensive income:
Net income (loss)		74,947		6,947		18,789		(153	)	—		(25,583	)		74,947
Minimum pension liability adjustment, net of taxes of $18		26		—		—		—		—		—			26
Comprehensive income (loss)		74,973		6,947		18,789		(153	)	—		(25,583	)		74,973
Adjustment to initially apply SFAS No. 158, net of tax benefits of $80,666		(126,650	)	(18,381	)	(14,226	)	—		—		32,607			(126,650	)
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		—		9,396			(29,381	)
Issuance of common stock		—		—		—		300		—		(300	)		—
Other		2		—		—		—		—		—			2
Balance, December 31, 2006		958,203		175,099		192,231		265		—		(367,595	)		958,203
Comprehensive income:
Net income (loss)		52,156		8,252		11,785		(83	)	(47	)	(19,907	)		52,156
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)		58,212		8,549		12,728		(83	)	(47	)	(21,147	)		58,212
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 FIN 48		(620	)	(33	)	(44	)	—		—		77			(620	)
Common stock dividends		(27,084	)	—		(9,900	)	—		—		9,900			(27,084	)
Issuance of common stock		—		—		—		—		435		(435	)		—
Balance, December 31, 2007	$	1,110,462		201,820		208,521		182		388		(410,911	)	$	1,110,462

43

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:
Income before preferred stock dividends of HECO	$	53,236		8,786		12,166		(83	)	(47	)	(20,822	)[2]	$	53,236
Adjustments to reconcile income before preferred stock dividends of HECO 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
Increase in taxes accrued		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	)	—		(10,815	)		185,675
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		(1,080	)	(534	)	(381	)	—		—		915	[2]		(1,080	)
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	)
Other		(1,161	)	(1,706	)	(677	)	—		—		—			(3,544	)
Net cash provided by (used in) financing activities		(26,328	)	(435	)	662		—		435		26,180			514
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

44

Consolidating statement of cash flows

	Year ended December 31, 2006
(in thousands)	HECO			HELCO		MECO		RHI		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	76,027		7,481		19,170		(153	)	(26,498	)[2]	$	76,027
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(25,684	)	—		—		—		25,583	[2]		(101	)
Common stock dividends received from subsidiaries		9,497		—		—		—		(9,396	)[2]		101
Depreciation of property, plant and equipment		74,798		29,722		25,644		—		—			130,164
Other amortization		3,898		582		3,452		—		—			7,932
Deferred income taxes		(7,666	)	(155	)	(1,850	)	—		—			(9,671	)
Tax credits, net		1,997		620		1,193		—		—			3,810
Allowance for equity funds used during construction		(4,059	)	(195	)	(2,094	)	—		—			(6,348	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		6,960		(901	)	1,401		—		1,249	[1]		8,709
Decrease (increase) in accrued unbilled revenues		(1,534	)	238		422		—		—			(874	)
Decrease (increase) in fuel oil stock		23,629		(1,893	)	(598	)	—		—			21,138
Decrease (increase) in materials and supplies		169		(1,688	)	(2,047	)	—		—			(3,566	)
Increase in regulatory assets		(1,652	)	(1,519	)	(2,952	)	—		—			(6,123	)
Increase (decrease) in accounts payable		(25,171	)	3,069		2,413		—		—			(19,689	)
Increase in taxes accrued		12,792		2,729		3,078		—		—			18,599
Decrease in prepaid pension benefit cost		14,237		2,617		3,210		—		—			20,064
Changes in other assets and liabilities		(13,081	)	2,610		(921	)	—		(1,249	)[2]		(12,641	)
Net cash provided by (used in) operating activities		145,157		43,317		49,521		(153	)	(10,311	)		227,531
Cash flows from investing activities:
Capital expenditures		(94,141	)	(44,217	)	(56,714	)	—		—			(195,072	)
Contributions in aid of construction		10,760		4,587		4,360		—		—			19,707
Advances from (to) affiliates		(4,700	)	—		5,250		—		(550	)[1]		—
Proceeds from sales of assets		407		—		—		—		—			407
Investment in consolidated subsidiary		(300	)	—		—		—		300	[2]		—
Net cash used in investing activities		(87,974	)	(39,630	)	(47,104	)	—		(250	)		(174,958	)
Cash flows from financing activities:
Common stock dividends		(29,381	)	(2,874	)	(6,522	)	—		9,396	[2]		(29,381	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		915	[2]		(1,080	)
Proceeds from issuance of common stock		—		—		—		300		(300	)[2]		—
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(28,308	)	(300	)	5,000		—		550	[1]		(23,058	)
Other		3,906		756		—		—		—			4,662
Net cash provided by (used in) financing activities		(54,863	)	(2,952	)	(1,903	)	300		10,561			(48,857	)
Net increase in cash and equivalents		2,320		735		514		147		—			3,716
Cash and equivalents, beginning of year		8		3		4		128		—			143
Cash and equivalents, end of year	$	2,328		738		518		275		—		$	3,859

45

Consolidating statement of cash flows

	Year ended December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Income before preferred stock dividends of HECO	$	73,882		13,157		18,886		(176	)	(31,867	)[2]	$	73,882
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,053	)	—		—		—		30,952	[2]		(101	)
Common stock dividends received from subsidiaries		23,550		—		—		—		(23,449	)[2]		101
Depreciation of property, plant and equipment		70,687		27,177		25,006		—		—			122,870
Other amortization		4,350		913		3,216		—		—			8,479
Deferred income taxes		13,381		1,557		4,148		—		—			19,086
Tax credits, net		1,722		1,588		161		—		—			3,471
Allowance for equity funds used during construction		(4,031	)	(174	)	(900	)	—		—			(5,105	)
Changes in assets and liabilities:
Increase in accounts receivable		(20,265	)	(5,222	)	(4,485	)	—		(178	)[1]		(30,150	)
Increase in accrued unbilled revenues		(7,114	)	(1,777	)	(3,402	)	—		—			(12,293	)
Increase in fuel oil stock		(24,889	)	(63	)	(1,928	)	—		—			(26,880	)
Increase in materials and supplies		(2,588	)	(474	)	(144	)	—		—			(3,206	)
Decrease (increase) in regulatory assets		(2,472	)	443		(3,007	)	—		—			(5,036	)
Increase in accounts payable		20,261		1,973		5,952		—		—			28,186
Increase in taxes accrued		19,088		5,951		2,619		—		—			27,658
Decrease (increase) in prepaid pension benefit cost		(1,412	)	367		745		—		—			(300	)
Changes in other assets and liabilities		(11,788	)	(1,943	)	(2,397	)	6		178	[2]		(15,944	)
Net cash provided by (used in) operating activities		121,309		43,473		44,470		(170	)	(24,364	)		184,718
Cash flows from investing activities:
Capital expenditures		(128,127	)	(52,107	)	(37,376	)	—		—			(217,610	)
Contributions in aid of construction		13,439		3,141		4,503		—		—			21,083
Advances from (to) affiliates		(14,850	)	—		2,500		—		12,350	[1]		—
Proceeds from sales of assets		1,680		—		—		—		—			1,680
Net cash used in investing activities		(127,858	)	(48,966	)	(30,373	)	—		12,350			(194,847	)
Cash flows from financing activities:
Common stock dividends		(50,895	)	(9,721	)	(13,728	)	—		23,449	[2]		(50,895	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		915	[2]		(1,080	)
Proceeds from issuance of long-term debt		52,462		5,000		2,000		—		—			59,462
Repayment of long-term debt		(40,000	)	(5,000	)	(2,000	)	—		—			(47,000	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		45,097		14,850		—		—		(12,350	)[1]		47,597
Other		964		898		(1	)	—		—			1,861
Net cash provided by (used in) financing activities		6,548		5,493		(14,110	)	—		12,014			9,945
Net decrease in cash and equivalents		(1	)	—		(13	)	(170	)	—			(184	)
Cash and equivalents, beginning of year		9		3		17		298		—			327
Cash and equivalents, end of year	$	8		3		4		128		—		$	143

46

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 preferred stock dividends of Hawaii Electric Light Company, Inc. and Maui Electric Company, Limited 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 2007 and 2006 follows:

	Quarters ended								Year ended Dec. 31
2007	March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues(1),(2)	$	446,797	$	491,249	$	561,720	$	597,192	$	2,096,958
Operating income(1),(2)		19,503		21,222		20,736		38,814		100,275
Net income for common stock(1),(2),(3)		453		10,650		12,875		28,178		52,156
	Quarters ended								Year ended Dec. 31
2006	March 31		June 30		Sept. 30		Dec. 31
(in thousands)
Operating revenues(4),(5)	$	473,971	$	503,350	$	568,236	$	504,855	$	2,050,412
Operating income(4),(5)		31,562		28,502		32,736		24,355		117,155
Net income for common stock(4),(5)		20,988		17,286		23,666		13,007		74,947

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

(1) For 2007, amounts include interim rate relief for HECO (2005 test year; 2007 test year since October 22, 2007), HELCO (2006 test year since April 5, 2007) and MECO (2007 test year since December 21, 2007).

(2) The third quarter of 2007 includes a $9 million, net of tax benefits, reserve accrued for the potential refund (with interest) of a portion of HECO’s 2005 test year interim rate increase.

(3) The first quarter of 2007 includes a $7 million, net of tax benefits, write-off of plant in service costs at HELCO as part of a settlement in HELCO’s 2006 test year rate case.

(4) The fourth quarter of 2006 includes an adjustment for quarterly rate schedule tariff reconciliation that relates to prior quarters.

(5) For 2006, amounts include interim rate relief for HECO (2005 test year).

47