HECO Exhibit 99.4

Selected Financial Data

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2006			2005			2004			2003			2002
(in thousands)
Income statement data
Operating revenues	$	2,050,412		$	1,801,710		$	1,546,875		$	1,393,038		$	1,252,929
Operating expenses		1,933,257			1,688,168			1,425,583			1,268,200			1,117,772
Operating income		117,155			113,542			121,292			124,838			135,157
Other income		9,471			8,643			8,926			6,170			7,095
Income before interest and other charges		126,626			122,185			130,218			131,008			142,252
Interest and other charges		50,599			48,303			47,961			51,017			50,967
Income before preferred stock dividends of HECO		76,027			73,882			82,257			79,991			91,285
Preferred stock dividends of HECO		1,080			1,080			1,080			1,080			1,080
Net income for common stock	$	74,947		$	72,802		$	81,177		$	78,911		$	90,205
At December 31	2006			2005			2004			2003			2002
(in thousands)
Balance sheet data
Utility plant	$	4,133,883		$	3,930,321		$	3,709,857		$	3,531,299		$	3,381,316
Accumulated depreciation		(1,558,913	)		(1,456,537	)		(1,361,703	)		(1,290,929	)		(1,205,336	)
Net utility plant	$	2,574,970		$	2,473,784		$	2,348,154		$	2,240,370		$	2,175,980
Total assets	$	3,063,134		$	3,081,461		$	2,879,615		$	2,687,798		$	2,599,004
Capitalization:1
Short-term borrowings from non-affiliates and affiliate	$	113,107		$	136,165		$	88,568		$	6,000		$	5,600
Long-term debt, net		766,185			765,993			752,735			699,420			705,270
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			100,000
Common stock equity		958,203			1,039,259			1,017,104			944,443			923,256
Total capitalization	$	1,871,788		$	1,975,710		$	1,892,700		$	1,784,156		$	1,768,419
Capital structure ratios (%)1
Debt		47.0			45.7			44.5			39.6			40.2
Preferred stock		1.8			1.7			1.8			1.9			1.9
HECO-obligated preferred securities of subsidiary trusts		—			—			—			5.6			5.7
Common stock equity		51.2			52.6			53.7			52.9			52.2

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.

1

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, 2006 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, 2006.

KPMG LLP, an independent registered public accounting firm, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting as of December 31, 2006. This report appears on page 3.

/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	Financial Vice President and Chief Financial Officer	Controller and Chief Accounting Officer

February 28, 2007

2

[KPMG 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 management’s assessment, included in the accompanying annual report of management on internal control over financial reporting, that Hawaiian Electric Company, Inc. maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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, management’s assessment that Hawaiian Electric Company, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also, in our opinion, Hawaiian Electric Company, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related consolidated statements of income, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Honolulu, Hawaii

February 28, 2007

3

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, 2006 and 2005, and the related consolidated statements of income, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 2006. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Hawaiian Electric Company, Inc.’s internal control over financial reporting as of December 31, 2006, 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 28, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Honolulu, Hawaii

February 28, 2007

4

Consolidated Financial Statements

Consolidated Statements of Income

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2006			2005			2004
(in thousands)
Operating revenues	$	2,050,412		$	1,801,710		$	1,546,875
Operating expenses
Fuel oil		781,740			639,650			483,423
Purchased power		506,893			458,120			398,836
Other operation		186,449			172,962			157,198
Maintenance		90,217			82,242			77,313
Depreciation		130,164			122,870			114,920
Taxes, other than income taxes		190,413			167,295			143,834
Income taxes		47,381			45,029			50,059
		1,933,257			1,688,168			1,425,583
Operating income		117,155			113,542			121,292
Other income
Allowance for equity funds used during construction		6,348			5,105			5,794
Other, net		3,123			3,538			3,132
		9,471			8,643			8,926
Income before interest and other charges		126,626			122,185			130,218
Interest and other charges
Interest on long-term debt		43,109			43,063			42,543
Amortization of net bond premium and expense		2,198			2,212			2,289
Other interest charges		7,256			4,133			4,756
Allowance for borrowed funds used during construction		(2,879	)		(2,020	)		(2,542	)
Preferred stock dividends of subsidiaries		915			915			915
		50,599			48,303			47,961
Income before preferred stock dividends of HECO		76,027			73,882			82,257
Preferred stock dividends of HECO		1,080			1,080			1,080
Net income for common stock	$	74,947		$	72,802		$	81,177
Consolidated Statements of Retained Earnings Hawaiian Electric Company, Inc. and Subsidiaries
Years ended December 31	2006			2005			2004
(in thousands)
Retained earnings, January 1	$	654,686		$	632,779		$	563,215
Net income for common stock		74,947			72,802			81,177
Common stock dividends		(29,381	)		(50,895	)		(11,613	)
Retained earnings, December 31	$	700,252		$	654,686		$	632,779

See accompanying “Notes to Consolidated Financial Statements.”

5

Consolidated Balance Sheets

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2006			2005
(in thousands)
Assets
Utility plant, at cost
Land	$	35,242		$	33,034
Plant and equipment		4,002,929			3,749,386
Less accumulated depreciation		(1,558,913	)		(1,456,537	)
Plant acquisition adjustment, net		93			145
Construction in progress		95,619			147,756
Net utility plant		2,574,970			2,473,784
Current assets
Cash and equivalents		3,859			143
Customer accounts receivable, net		125,524			123,895
Accrued unbilled revenues, net		92,195			91,321
Other accounts receivable, net		4,423			14,761
Fuel oil stock, at average cost		64,312			85,450
Materials and supplies, at average cost		30,540			26,974
Prepayments and other		9,695			114,902
Total current assets		330,548			457,446
Other long-term assets
Regulatory assets		112,349			110,718
Unamortized debt expense		13,722			14,361
Other		31,545			25,152
Total other long-term assets		157,616			150,231
	$	3,063,134		$	3,081,461
Capitalization and liabilities
Capitalization (see Consolidated Statements of Capitalization)
Common stock equity	$	958,203		$	1,039,259
Cumulative preferred stock, not subject to mandatory redemption		34,293			34,293
Long-term debt, net		766,185			765,993
Total capitalization		1,758,681			1,839,545
Current liabilities
Short-term borrowings-nonaffiliates		113,107			136,165
Accounts payable		102,512			122,201
Interest and preferred dividends payable		10,645			9,990
Taxes accrued		152,182			133,583
Other		43,120			37,132
Total current liabilities		421,566			439,071
Deferred credits and other liabilities
Deferred income taxes		118,055			208,374
Regulatory liabilities		240,619			219,204
Unamortized tax credits		57,879			55,327
Other		189,606			63,677
Total deferred credits and other liabilities		606,159			546,582
Contributions in aid of construction		276,728			256,263
	$	3,063,134		$	3,081,461

See accompanying “Notes to Consolidated Financial Statements.”

6

Consolidated Statements of Capitalization

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2006			2005			2004
(dollars in thousands, except par value)
Common stock equity
Common stock of $6 2/3 par value Authorized: 50,000,000 shares. Outstanding: 2006, 2005 and 2004, 12,805,843 shares	$	85,387		$	85,387		$	85,387
Premium on capital stock		299,214			299,212			299,213
Retained earnings		700,252			654,686			632,779
Accumulated other comprehensive loss, net of income tax benefits
Minimum pension liability		—			(26	)		(275	)
Defined benefit pension and postretirement benefit plans (adjustment to initially apply SFAS No. 158)		(126,650	)		—			—
Common stock equity		958,203			1,039,259			1,017,104
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: 2006 and 2005, 1,234,657 shares.

Series	Par Value			Shares Outstanding December 31, 2006 and 2005	2006		2005
(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.”

7

Consolidated Statements of Capitalization, continued

Hawaiian Electric Company, Inc. and Subsidiaries

December 31	2006		2005
(in thousands)
Long-term debt
Obligations to the State of Hawaii for the repayment of Special Purpose Revenue Bonds:
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, due 2026		14,000		14,000
HELCO, 5 7/8%, series 1996B, due 2026		1,000		1,000
MECO, 5 7/8%, series 1996B, due 2026		35,000		35,000
HECO, 6.20%, series 1996A, due 2026		48,000		48,000
HELCO, 6.20%, series 1996A, due 2026		7,000		7,000
MECO, 6.20%, series 1996A, due 2026		20,000		20,000
HECO, 5.45%, series 1993, due 2023		50,000		50,000
HELCO, 5.45%, series 1993, due 2023		20,000		20,000
MECO, 5.45%, series 1993, due 2023		30,000		30,000
Total obligations to the State of Hawaii		717,900		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		769,446		769,446
Less unamortized discount		3,261		3,453
Long-term debt, net		766,185		765,993
Total capitalization	$	1,758,681	$	1,839,545

See accompanying “Notes to Consolidated Financial Statements.”

8

Consolidated Statements of Cash Flows

Hawaiian Electric Company, Inc. and Subsidiaries

Years ended December 31	2006			2005			2004
(in thousands)
Cash flows from operating activities
Income before preferred stock dividends of HECO	$	76,027		$	73,882		$	82,257
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Depreciation of utility plant		130,164			122,870			114,920
Other amortization		7,932			8,479			8,780
Deferred income taxes		(9,671	)		19,086			20,784
Tax credits, net		3,810			3,471			5,212
Allowance for equity funds used during construction		(6,348	)		(5,105	)		(5,794	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		8,709			(30,150	)		(14,174	)
Increase in accrued unbilled revenues		(874	)		(12,293	)		(18,656	)
Decrease (increase) in fuel oil stock		21,138			(26,880	)		(14,958	)
Increase in materials and supplies		(3,566	)		(3,206	)		(2,535	)
Increase in regulatory assets		(6,123	)		(5,036	)		(2,424	)
Increase (decrease) in accounts payable		(19,689	)		28,186			21,638
Increase in taxes accrued		18,599			27,658			12,622
Decrease (increase) in prepaid pension benefit cost		20,064			(300	)		(25,097	)
Other		(12,641	)		(15,944	)		(13,725	)
Net cash provided by operating activities		227,531			184,718			168,850
Cash flows from investing activities
Capital expenditures		(195,072	)		(217,610	)		(201,236	)
Contributions in aid of construction		19,707			21,083			8,522
Investment in unconsolidated subsidiary		—			—			(1,546	)
Distributions from unconsolidated subsidiaries		—			—			3,093
Proceeds from sales of assets		407			1,680			650
Net cash used in investing activities		(174,958	)		(194,847	)		(190,517	)
Cash flows from financing activities
Common stock dividends		(29,381	)		(50,895	)		(11,613	)
Preferred stock dividends		(1,080	)		(1,080	)		(1,080	)
Proceeds from issuance of long-term debt		—			59,462			53,097
Repayment of long-term debt		—			(47,000	)		(103,093	)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		(23,058	)		47,597			82,568
Other		4,662			1,861			1,957
Net cash provided by (used in) financing activities		(48,857	)		9,945			21,836
Net increase (decrease) in cash and equivalents		3,716			(184	)		169
Cash and equivalents, January 1		143			327			158
Cash and equivalents, December 31	$	3,859		$	143		$	327

See accompanying “Notes to Consolidated Financial Statements.”

9

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 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 FASB Interpretation 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 income 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. See Note 6 for additional information regarding regulatory assets and liabilities.

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 are reflected in other income.

10

Utility plant

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

If a power purchase agreement (PPA) falls within the scope of 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 3.9% in 2006, 2005 and 2004.

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 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. The PUC requires the Company to fund its pension and postretirement benefit costs. The Company’s policy is to fund qualified pension plan costs in amounts that will not be less than the minimum funding requirements of the Employee Retirement Income Security Act of 1974 and will not exceed the maximum tax-deductible amounts. 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. 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, 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.

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. See Note 10 for the impacts of adoption.

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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 or liabilities 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, 2006, customer accounts receivable include unbilled energy revenues of $92 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 HECO, HELCO and MECO 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. In 2004 PUC decisions approving their fuel supply contracts, the PUC affirmed HECO, HELCO and MECO’s right to include in their respective ECACs the stated costs incurred pursuant to their respective new fuel supply contracts, to the extent that these costs are not included in their respective base rates, and restated its intention to examine the need for continued use of ECACs in rate cases. See “Energy cost adjustment clauses” in Note 11.

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. Payments to the taxing authorities by the Company are based on the prior years’ revenues. For 2006, 2005 and 2004, the Company included approximately $182 million, $159 million and $136 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

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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, AFUDC may be stopped.

The weighted-average AFUDC rate was 8.4% in 2006, 8.5% in 2005 and 8.6% in 2004, and reflected quarterly compounding.

Environmental expenditures

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

Income taxes

The Company is included in the consolidated income tax returns of HECO’s parent, HEI. 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

Accounting for certain hybrid financial instruments. In March 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, and clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. The Company adopted SFAS No. 155 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

Accounting for servicing of financial assets. In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 156 requires an entity to recognize, in certain situations, a servicing asset or servicing liability when it undertakes an obligation to service a financial asset, requires all separately recognized servicing assets and liabilities to be initially measured at fair value (if practicable), permits alternative subsequent measurement methods for each class of servicing assets and liabilities, permits a limited one-time reclassification of available-for-sale securities to trading securities at adoption, requires separate presentation of servicing assets and liabilities subsequently measured at fair value in the balance sheet and requires additional disclosures. SFAS No. 156 must be adopted by the beginning of the first fiscal year that begins after September 15, 2006. The Company adopted SFAS No. 156 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

Accounting for uncertainty in income taxes. In June 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation prescribes a “more-likely-than-not” recognition threshold and measurement attribute (the largest amount of benefit that is greater than 50% likely of being realized upon ultimate resolution with tax authorities) for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The Company adopted FIN No. 48 in the first quarter of 2007. The Company anticipates reclassifying certain deferred tax liabilities to a liability for tax uncertainties. Further, although management’s analysis of the impact of adoption of FIN No. 48 is ongoing, management does not expect the adjustment to retained earnings as of January 1, 2007 for the cumulative effect of adoption of FIN No. 48 to be material.

Cash flows relating to income taxes generated by a leveraged lease transaction. In July 2006, the FASB issued FASB Staff Position (FSP) No. 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” which requires a recalculation of the rate of return and the allocation of income to positive investment years from the inception of the lease if there is a change or projected change in the timing of cash flows relating to income taxes generated by the leveraged lease. The amounts comprising the net leveraged lease investment would be adjusted to the recalculated amounts, and the change in the net investment would be recognized as a gain or loss in the year in which the projected cash flows and/or assumptions change. FSP No. 13-2 is effective for fiscal years beginning after December 15, 2006. The Company adopted FSP No. 13-2 on January 1, 2007 and the impact of adoption had no impact on the Company’s results of operations, financial condition or liquidity.

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Fair value measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. SFAS No. 157 applies to fair value measurements that are already required or permitted under existing accounting pronouncements with some exceptions. SFAS No. 157 retains the exchange price notion in defining fair value and clarifies that the exchange price is the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability. It emphasizes that fair value is a market-based, not an entity-specific, measurement based upon the assumptions that market participants would use in pricing an asset or liability. As a basis for considering assumptions in fair value measurements, SFAS No. 157 establishes a hierarchy that gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). SFAS No. 157 expands disclosures about the use of fair value, including disclosure of the level within the hierarchy in which the fair value measurements fall and the effect of the measurements on earnings (or changes in net assets) for the period. SFAS No. 157 must be adopted by the first quarter of the fiscal year beginning after November 15, 2007. The Company plans to adopt SFAS No. 157 on January 1, 2008. Management has not yet determined what impact, if any, the adoption of SFAS No. 157 will have on the Company’s financial statements.

Effects of prior year misstatements. In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” which provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. In order to evaluate whether an error is material based on all relevant quantitative and qualitative factors, SAB No. 108 requires the quantification of misstatements using both the income-statement (rollover) and balance sheet (iron curtain) approaches. If the Company does not elect to restate its financial statements for the material misstatements that arise in connection with application of the guidance in SAB No. 108, then for fiscal years ending after November 15, 2006, it must recognize the cumulative effect of applying SAB No. 108 in the current year beginning balances of the affected assets and liabilities with a corresponding adjustment to the current year opening balance in retained earnings. The Company adopted SAB No. 108 in the fourth quarter of 2006 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity.

Planned major maintenance activities. In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” which eliminates the accrue-in-advance method of accounting for planned major maintenance activities. As a result of the elimination, three methods are currently permitted: (1) direct expensing, (2) built-in overhaul, and (3) deferral. FSP AUG AIR-1 must be adopted by the first fiscal year beginning after December 15, 2006. The Company adopted FSP AUG AIR-1 on January 1, 2007 and the adoption had no impact on the Company’s results of operations, financial condition or liquidity because the Company has used and continues to use the direct expensing method.

Defined benefit pension and other postretirement plans. 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. Employers must recognize actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS Nos. 87 and 106 when recognizing a plan’s funded status, with the offset to accumulated other comprehensive income (AOCI) in stockholders’ equity. SFAS No. 158 was required to be adopted in fiscal years ending after December 15, 2006. Accordingly, the Company adopted SFAS No. 158 on December 31, 2006.

The Company updated its application in the AOCI Docket to take into account SFAS No. 158 in seeking PUC approval to record as a regulatory asset the amount that would otherwise be charged against stockholders’ equity, but the application was denied. See Note 10 for the impacts of adoption.

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

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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. SFAS No. 159 must be adopted by January 1, 2008. Management has not yet determined when it will adopt SFAS No. 159 or what impact, if any, the adoption of SFAS No. 159 will have on the Company’s financial statements.

Reclassifications

Certain reclassifications have been made to prior years’ financial statements to conform to the 2006 presentation.

2. Cumulative preferred stock

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

December 31, 2006	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

Trust financing entities. HECO Capital Trust I (Trust I) was a financing entity, which issued, in 1997, $50 million of 8.05% Cumulative Quarterly Income Preferred Securities, Series 1997 (1997 Trust Preferred Securities) to the public. In March 2004, HECO, HELCO and MECO borrowed the proceeds of the sale of HECO Capital Trust III’s 2004 Trust Preferred Securities and, in April 2004, applied the proceeds, along with other corporate funds, to redeem the 1997 Trust Preferred Securities. HECO Capital Trust II (Trust II) was a financing entity, which issued, in 1998, $50 million of 7.30% Cumulative Quarterly Income Preferred Securities, Series 1998 (1998 Trust Preferred Securities) to the public. In April 2004, the electric utilities used funds primarily from short-term borrowings from HEI and from the issuance of commercial paper by HECO to redeem the 1998 Trust Preferred Securities. Trust I and Trust II, each a Delaware statutory trust, were consolidated subsidiaries of HECO through December 31, 2003. Since HECO, as the common security holder, did not absorb the majority of the variability of the trusts, HECO was not the primary beneficiary and, in accordance with FIN 46R, did not consolidate the trusts as of January 1, 2004. Trust I and Trust II were dissolved and terminated in 2004.

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

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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, MECO and HELCO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of MECO and HELCO 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, 2006 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 2006 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, 2006, HECO and its subsidiaries had six purchase power agreements (PPAs) for a total of 540 megawatts (MW) of firm capacity, and other PPAs with smaller 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 2006 totaled $507 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $133 million, $181 million, $72 million and $44 million, respectively. The primary business activities of these IPPs are the generation and sale of power to HECO and its subsidiaries (and municipal waste disposal in the case of HPOWER). Current financial information about the size, including total assets and revenues, for many of these IPPs is not publicly available.

Under FIN 46R, an enterprise with an interest in a VIE or potential VIE created before December 31, 2003 (and not thereafter materially modified) is not required to apply FIN 46R to that entity if the enterprise is unable to obtain, after making an exhaustive effort, the necessary information. HECO has reviewed its significant PPAs and determined that the IPPs had no contractual obligation to provide such information. In March 2004, HECO and its subsidiaries sent letters to all of their IPPs, except the Schedule Q providers, requesting the information that they need to determine the applicability of FIN 46R to the respective IPP, and subsequently contacted most of the IPPs to explain and repeat its request for information. (HECO and its subsidiaries excluded their Schedule Q providers from the scope of FIN 46R because their variable interest in the provider would not be significant to the utilities and they did not participate significantly in the design of the provider.) Some of the IPPs provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (HPOWER) as defined under FIN 46R, and thus excluded from the scope of FIN 46R. Other IPPs, including the three largest, declined to provide the information necessary for HECO to determine the applicability of FIN 46R, and HECO was unable to apply FIN 46R to these IPPs.

As required under FIN 46R, HECO continued after 2004 its efforts to obtain from the IPPs the information necessary to make the determinations required under FIN 46R. In January 2005, 2006 and 2007, HECO and its subsidiaries again sent letters to the IPPs that were not excluded from the scope of FIN 46R, requesting the information required to determine the applicability of FIN 46R to the respective IPP. All of these IPPs again declined to provide the necessary information, except that Kalaeloa and Kaheawa Wind Power, LLC (KWP) have now provided their information (see below).

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

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

Pursuant to the provisions of FIN 46R, HECO is deemed to have a variable interest in Kalaeloa by reason of the provisions of HECO’s PPA with Kalaeloa. However, management has concluded that HECO is not the primary beneficiary of Kalaeloa because HECO does not absorb the majority of Kalealoa’s expected losses nor receive a majority of Kalaeloa’s expected residual returns and, thus, HECO has not consolidated Kalaeloa in its consolidated financial statements. A significant factor which affected 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.

Kaheawa Wind Power, LLC. In December 2004, MECO executed a new PPA with Kaheawa Wind Power, LLC (KWP), which completed the installation of a 30 MW windfarm on Maui and began selling power to MECO in June 2006. Management concluded that MECO does not have to consolidate KWP as MECO does not have a variable interest in KWP because the PPA does not require MECO to absorb variability of KWP.

Apollo Energy Corporation. In October 2004, HELCO and Apollo Energy Corporation (Apollo) executed a restated and amended PPA which enables Apollo to repower its 7 MW facility, and install additional capacity, for a total allowed capacity of 20.5 MW (targeted for commercial operation in April 2007). In December 2005, Apollo assigned the PPA to Tawhiri Power LLC (Tawhiri), a subsidiary of Apollo. In February 2007, Tawhiri 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. 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.

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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.

In January 2005, the Department of Budget and Finance of the State of Hawaii issued, at par, Refunding Series 2005A SPRB in the aggregate principal amount of $47 million with a maturity of January 1, 2025 and a fixed coupon interest rate of 4.80% and loaned the proceeds from the sale to HECO, HELCO and MECO. The proceeds of such bonds, along with additional funds, were applied to redeem at a 1% premium a like principal amount of SPRB bearing a higher interest coupon (HECO’s, HELCO’s, and MECO’s aggregate $47 million of 6.60% Series 1995A SPRB with original maturity of January 1, 2025) in February 2005.

At December 31, 2006, the aggregate payments of principal required on long-term debt during the next five years are nil in each year.

5. Short-term borrowings

Short-term borrowings from nonaffiliates at December 31, 2006 and 2005 had a weighted average interest rate of 5.4% and 4.5%, respectively, and consisted entirely of commercial paper.

At December 31, 2006 the Company maintained a syndicated credit facility of $175 million. At December 31, 2005 the Company maintained bilateral bank lines of credit which totaled $180 million. There were no borrowings under any line of credit during 2006 and 2005.

Credit agreements. Effective April 3, 2006, HECO entered into a revolving unsecured credit agreement establishing a line of credit facility of $175 million with a syndicate of eight financial institutions. The agreement has an initial term which expires on March 29, 2007. On August 30, 2006, HECO filed an application with the PUC requesting approval to maintain the $175 million credit facility for five years, which, if approved by the PUC, will automatically extend the termination date of the credit facility from March 29, 2007 to March 31, 2011. 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 43% for MECO as of December 31, 2006, 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, 2006, 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.

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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 income 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 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. 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 accrue and recover interest on its regulatory assets for integrated resource planning costs. Noted in parenthesis are the original PUC authorized amortization or recovery periods and the remaining amortization or recovery periods as of December 31, 2006, if different.

Regulatory assets were as follows:

December 31	2006		2005
(in thousands)
Income taxes, net (1 to 36 years)	$	73,178	$	70,743
Postretirement benefits other than pensions (18 years; 6 years)		10,738		12,528
Unamortized expense and premiums on retired debt and equity issuances (13 to 30 years; 1 to 22 years)		14,909		16,081
Integrated resource planning costs, net (1 year)		4,521		2,395
Vacation earned, but not yet taken (1 year)		5,759		5,669
Other (1 to 20 years)		3,244		3,302
	$	112,349	$	110,718

Regulatory liabilities were as follows:

December 31	2006		2005
(in thousands)
Cost of removal in excess of salvage value (1 to 60 years)	$	239,049	$	217,493
Other (5 years; 1 to 5 years)		1,570		1,711
	$	240,619	$	219,204

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7. Income taxes

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

December 31	2006			2005			2004
(in thousands)
Federal:
Current	$	50,208		$	23,799		$	25,763
Deferred		(7,000	)		17,497			21,973
Deferred tax credits, net		(1,259	)		(1,351	)		(1,446	)
		41,949			39,945			46,290
State:
Current		2,889			(1,407	)		(1,777	)
Deferred		(1,267	)		3,020			334
Deferred tax credits, net		3,810			3,471			5,212
		5,432			5,084			3,769
Total	$	47,381		$	45,029		$	50,059

Income tax benefits related to nonoperating activities, included in “Other, net” on the consolidated statements of income, amounted to $0.9 million, $0.4 million and $0.6 million for 2006, 2005 and 2004, 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	2006			2005			2004
(in thousands)
Amount at the federal statutory income tax rate	$	44,024		$	41,989		$	46,978
State income taxes on operating income, net of effect on federal income taxes		3,530			3,305			2,450
Other		(173	)		(265	)		631
Income taxes charged to operating expenses	$	47,381		$	45,029		$	50,059

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

December 31	2006		2005
(in thousands)
Deferred tax assets:
Cost of removal in excess of salvage value	$	93,014	$	85,292
Retirement benefits in AOCI		80,665		18
Contributions in aid of construction and customer advances		38,582		38,406
Other		9,534		8,784
		221,795		132,500
Deferred tax liabilities:
Property, plant and equipment		279,539		272,467
Regulatory assets, excluding amounts attributable to property, plant and equipment		28,495		27,588
Retirement benefits		26,862		36,423
Other		4,954		4,396
		339,850		340,874
Net deferred income tax liability	$	118,055	$	208,374

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, 2006, $(0.1) million, net of tax effects, was accrued for potential tax issues and related interest. Although not probable, adverse developments on potential tax issues could result in additional charges to net income in the future. Based on information currently available, the Company believes it has adequately provided for potential income tax issues with federal 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	2006		2005		2004
(in thousands)
Interest	$	47,206	$	46,221	$	46,041
Income taxes	$	52,782	$	20,554	$	26,914

Supplemental disclosures of noncash activities

The allowance for equity funds used during construction, which was charged primarily to construction in progress, amounted to $6.3 million, $5.1 million and $5.8 million in 2006, 2005 and 2004, respectively.

The estimated fair value of noncash contributions in aid of construction amounted to $13.5 million, $11.8 million and $4.9 million in 2006, 2005 and 2004, respectively.

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9. Major customers

HECO and its subsidiaries received approximately 10%, or $197 million, $176 million and $148 million, of their operating revenues from the sale of electricity to various federal government agencies in 2006, 2005 and 2004, respectively.

10. Retirement benefits

Pensions

Substantially all of the employees of HECO, HELCO and MECO participate in the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries (the Plan). The Plan is a qualified, non-contributory defined benefit pension plan and includes benefits for union employees determined in accordance with the terms of the collective bargaining agreements between the utilities and their respective unions. The Plan is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (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 Plan and the Supplemental/Excess/Directors Plans were adopted with the expectation that they will continue indefinitely, but the continuation of these plans and the payment of any contribution thereunder is not assumed as a contractual obligation 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.

The participating employers contribute amounts to a master pension trust for the Plan in accordance with the funding requirements of ERISA and considering the deductibility of contributions under the Internal Revenue Code. The funding of the Plan is based on actuarial assumptions adopted by the Pension Investment Committee administering the Plan on the advice of an enrolled actuary.

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 if the participant waives coverage under Medicare Part D.

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The HECO Benefits Plan was adopted with the expectation that it will continue indefinitely, but the continuation of the 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), HECO, HELCO and MECO had requested the PUC to permit them to record, as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” the amount that would otherwise be charged against stockholders’ equity as a result of recording a minimum pension liability as prescribed by SFAS No. 87. HECO, HELCO and MECO updated their 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 HECO, HELCO and MECO’s request to record a regulatory asset on the grounds that HECO, HELCO and MECO had not met their burden of proof to show that recording a regulatory asset was warranted, or that there would be adverse consequences if a regulatory asset was not recorded. The PUC also required HECO to submit a pension study (determining whether ratepayers are better off with a well-funded pension plan, a minimally-funded pension plan, or something in between) by May 31, 2007 in its pending 2007 test year rate case, as proposed by HECO, HELCO and MECO in support of their request.

The incremental effect of applying SFAS No. 158 on individual line items in the Company’s balance sheet as of December 31, 2006 was as follows:

(in thousands)	Before SFAS No. 158 adoption			Pension benefits adjustments			Other benefits adjustments			After SFAS No. 158 adoption
Prepayments and other	$	95,949		$	(86,254	)	$	—		$	9,695
Total current assets		416,802			(86,254	)		—			330,548
Total assets		3,149,388			(86,254	)		—			3,063,134
Other liabilities		68,587			89,761			31,258			189,606
Deferred income taxes		198,704			(68,487	)		(12,162	)		118,055
Total deferred credits and other liabilities		565,789			21,274			19,096			606,159
Accumulated other comprehensive loss		(26	)		(107,528	)		(19,096	)		(126,650	)
Total stockholders’ equity		1,084,827			(107,528	)		(19,096	)		958,203

Although there is not an immediate impact on net income due to the D&O in the updated AOCI Docket, HECO, HELCO and MECO were required by SFAS No. 158 to record substantial charges against stockholder’s equity, and their reported returns on rate base and returns on average common equity will be higher than if there were no charge against stockholder’s equity. Consolidated debt to capitalization and interest coverage ratios of the Company were also adversely affected. These effects could adversely affect security ratings and increase the difficulty or expense of obtaining future financing. HECO, HELCO and MECO will continue to seek a return on their pension assets (i.e., accumulated contributions in excess of accumulated net periodic pension costs) by including such assets (net of related deferred income taxes) in rate base in their respective rate cases. HECO, HELCO and MECO will also propose to restore equity for all AOCI charges for rate making purposes in their respective rate cases.

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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 for 2005 and the funded status of these plans and the unrecognized and recognized amounts related to these plans and reflected in the Company’s balance sheet as of December 31, 2005 were as follows:

(in thousands)	Pension benefits			Other benefits
Benefit obligation, January 1, 2005	$	802,059		$	195,176
Service cost		23,832			5,098
Interest cost		46,817			10,818
Actuarial (gain) loss		26,760			(16,778	)
Benefits paid and expenses		(40,388	)		(8,475	)
Benefit obligation, December 31, 2005		859,080			185,839
Fair value of plan assets, January 1, 2005		712,257			107,547
Actual return on plan assets		50,605			7,726
Employer contribution (including company payments for nonqualified plans)		7,627			10,554
Benefits paid and expenses		(40,388	)		(8,475	)
Fair value of plan assets, December 31, 2005		730,101			117,352
Funded status		(128,979	)		(68,487	)
Unrecognized net actuarial loss		238,002			24,116
Unrecognized net transition obligation		4			21,907
Unrecognized prior service gain		(5,767	)		—
Net amount recognized, December 31, 2005	$	103,260		$	(22,464	)
Amounts recognized in the balance sheet consist of:
Prepaid benefit cost	$	106,445		$	—
Accrued benefit liability		(3,230	)		(22,464	)
Accumulated other comprehensive income		45			—
Net amount recognized, December 31, 2005	$	103,260		$	(22,464	)

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The changes in the obligations and assets of the Company’s retirement benefit plans and the changes in AOCI (gross) for 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, 2006 were as follows:

(in thousands)	Pension benefits			Other benefits
Benefit obligation, January 1, 2006	$	859,080		$	185,839
Service cost		26,719			4,965
Interest cost		48,348			10,337
Amendments		116			—
Actuarial gain		(14,925	)		(5,350	)
Benefits paid and expenses		(41,973	)		(9,432	)
Benefit obligation, December 31, 2006		877,365			186,359
Fair value of plan assets, January 1, 2006		730,101			117,352
Actual return on plan assets		95,909			15,656
Employer contribution		—			9,789
Benefits paid and expenses		(41,847	)		(8,982	)
Fair value of plan assets, December 31, 2006		784,163			133,815
Accrued benefit liability, December 31, 2006		(93,202	)		(52,544	)
AOCI, January 1, 2006		45			—
Recognized during year – net recognized transition obligation		(2	)		(3,130	)
Recognized during year – prior service credit		770			—
Recognized during year – net actuarial losses		(10,699	)		(388	)
Occurring during year – prior service cost		115			—
Occurring during year – net actuarial gains		(46,367	)		(11,248	)
Other adjustments		232,195			46,024
AOCI, December 31, 2006		176,057			31,258
Net actuarial loss		110,535			7,625
Prior service gain		(2,982	)		—
Net transition obligation		1			11,471
AOCI, net of taxes, December 31, 2006	$	107,554		$	19,096

The Company does not expect any plan assets to be returned to the Company during calendar year 2007.

The dates used to determine retirement benefit measurements for the defined benefit plans were December 31 of 2006, 2005 and 2004.

The defined benefit pension plans’ accumulated benefit obligations, which do not consider projected pay increases, as of December 31, 2006 and 2005 were $769 million and $728 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 retirement defined benefit plans reflects the philosophy that long-term growth can best be achieved by prudent investments in equity securities while balancing overall fund volatility by an appropriate allocation to fixed income securities. In order to reduce the level of portfolio risk and volatility in returns, efforts have been made to diversify the plans’ investments by: asset class, geographic region, market capitalization and investment style.

The expected long-term rate of return assumption of 8.5% was based on the Plan’s target asset allocation and projected asset class returns provided by the plans’ actuarial consultant.

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

	Pension benefits								Other benefits
					Investment policy								Investment policy
December 31	2006		2005		Target		Range		2006		2005		Target		Range
Asset category
Equity securities	72	%	69	%	70	%	65-75	%	71	%	68	%	70	%	65-75	%
Fixed income	27		29		30		25-35	%	29		31		30		25-35	%
Other 1	1		2		—		—		—		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 2007 is $11 million.

As of December 31, 2006, the benefits expected to be paid under the retirement benefit plans in 2007, 2008, 2009, 2010, 2011 and 2012 through 2016 amounted to $54 million, $56 million, $59 million, $60 million, $63 million and $355 million, respectively.

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

	Pension benefits						Other benefits
December 31	2006		2005		2004		2006		2005		2004
Benefit obligation
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
Net periodic benefit cost (years ended)
Discount rate	5.75		6.00		6.25		5.75		6.00		6.25
Expected return on plan assets	9.0		9.0		9.0		9.0		9.0		9.0
Rate of compensation increase	4.6		4.6		4.6		4.6		4.6		4.6

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%. As of December 31, 2005, the assumed health care trend rates for 2006 and future years were as follows: medical, 10.00%, grading down to 5.00% for 2011 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	2006			2005			2004			2006			2005			2004
(in thousands)
Service cost	$	26,719		$	23,832		$	21,446		$	4,965		$	5,098		$	4,407
Interest cost		48,348			46,817			45,776			10,337			10,818			10,503
Expected return on plan assets		(64,467	)		(67,078	)		(66,681	)		(9,758	)		(9,704	)		(9,553	)
Amortization of unrecognized net (2006) transition obligation		2			2			2			3,130			3,130			3,129
Amortization of net (2006) prior service gain		(770	)		(770	)		(744	)		—			—			—
Amortization of net actuarial loss		10,699			4,735			217			388			395			—
Net periodic benefit cost	$	20,531		$	7,538		$	16		$	9,062		$	9,737		$	8,486

The estimated prior service credit, net actuarial loss and net transition obligation for defined benefits pension plans that will be amortized from AOCI into net periodic pension benefit cost over 2007 are $(0.8) million, $10.5 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 into net periodic other than pension benefit cost over 2007 are nil, nil and $3.1 million, respectively.

27

Of the net periodic pension benefit costs, the Company recorded expense of $15 million, $6 million, $0.1 million in 2006, 2005 and 2004, respectively, and charged the remaining amounts primarily to electric utility plant. Of the net periodic other than pension benefit costs, the Company expensed $7 million, $7 million and $6 million in 2006, 2005 and 2004, 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, 2006 and $3 million, $3 million and nil, respectively, as of December 31, 2005.

The health care cost trend rate assumptions can have a significant effect on the amounts reported for other benefits. As of December 31, 2006, a one-percentage-point increase in the assumed health care cost trend rates would have increased the total service and interest cost by $0.3 million and the postretirement benefit obligation by $3.6 million, and a one-percentage-point decrease would have reduced the total service and interest cost by $0.3 million and the postretirement benefit obligation by $4.0 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, 2007, the estimated cost of minimum purchases under the fuel supply contracts is $539 million for 2007, $540 million for 2008, $539 million each year for 2009, 2010 and 2011, and a total of $1.6 billion for the period 2012 through 2014. The actual cost of purchases in 2007 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 $755 million, $662 million and $490 million of fuel under contractual agreements in 2006, 2005 and 2004, respectively.

Power purchase agreements (PPAs). As of December 31, 2006, HECO and its subsidiaries had six firm capacity PPAs for a total of 540 MW of firm capacity. Purchases from these six IPPs and all other IPPs totaled $507 million, $458 million and $399 million for 2006, 2005 and 2004, 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 $118 million in 2007, $119 million in 2008, $116 million in 2009, $118 million in 2010 and 2011 and a total of $1.1 billion in the period from 2012 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.

28

Interim increases. On September 27, 2005, the PUC issued an Interim Decision and Order (D&O) granting a general rate increase on Oahu of 4.36%, or $53.3 million (3.33%, or $41.1 million excluding the transfer of certain costs from a surcharge line item on electric bills into base electricity charges). The tariff changes implementing the interim rate increase were effective September 28, 2005.

As of December 31, 2006, HECO and its subsidiaries had recognized $79 million of such revenues with respect to interim orders ($14 million related to interim orders regarding certain integrated resource planning costs and $65 million related to the interim order with respect to Oahu’s general rate increase request based on a 2005 test year), which revenues are subject to refund, with interest, if and to the extent they exceed the amounts allowed in final orders.

Energy cost adjustment clauses. On June 19, 2006, the PUC issued an order in HECO’s pending rate case based on a 2005 test year, indicating that the record in the pending case has not been developed for the purpose of addressing the factors in Act 162, signed into law by the Governor of Hawaii on June 2, 2006. Act 162 states that any automatic fuel rate adjustment clause requested by a public utility in an application filed with the PUC shall be designed, as determined in the PUC’s discretion, to (1) fairly share the risk of fuel cost changes between the public utility and its customers, (2) provide the public utility with sufficient incentive to reasonably manage or lower its fuel costs and encourage greater use of renewable energy, (3) allow the public utility to mitigate the risk of sudden or frequent fuel cost changes that cannot otherwise reasonably be mitigated through other commercially available means, such as through fuel hedging contracts, (4) preserve, to the extent reasonably possible, the public utility’s financial integrity, and (5) minimize, to the extent reasonably possible, the public utility’s need to apply for frequent applications for general rate increases to account for the changes to its fuel costs. While the PUC already reviews the automatic fuel rate adjustment clause in rate cases, Act 162 requires that these five specific factors be addressed in the record. The PUC’s order requested the parties in the rate case proceeding to meet informally to determine a procedural schedule to address the issues relating to HECO’s ECAC that are raised by Act 162. The parties in the rate case proceeding are HECO, the Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii (Consumer Advocate), and the federal Department of Defense (DOD).

On June 30, 2006, HECO and the Consumer Advocate filed a stipulation requesting that the PUC not review the Act 162 ECAC issues in the pending rate case based on a 2005 test year since HECO’s application was filed and the record in the proceeding was completed before Act 162 was signed into law, and the settlement agreement entered into by the parties in the rate case included a provision allowing the existing ECAC to be continued. On August 7, 2006, an amended stipulation was filed in substantially the same form as the June 30, 2006 stipulation, but also included the DOD. Management cannot predict whether the PUC will accept the disposition of the Act 162 issue proposed in the amended stipulation or, if not, the procedural steps or procedural schedule that will be adopted to address the issues that are raised by Act 162 or the timing of the PUC’s issuance of a final D&O in HECO’s pending rate case based on a 2005 test year.

The ECAC provisions of Act 162 will be reviewed in the HELCO rate case based on a 2006 test year and 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.

Management cannot predict the ultimate outcome or the effect of these Act 162 issues on the operation of the ECAC.

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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.” As a result of the final resolution of the proceedings described below, CT-4 and CT-5 are now operational, there are no pending lawsuits involving the project, and work on ST-7 is proceeding. In May 2006, HELCO filed a rate increase application based on a 2006 test year seeking to recover, among other things, CT-4 and CT-5 costs.

Historical context. Installation of CT-4 and CT-5 was significantly delayed as a result of land use and environmental permitting delays and related administrative proceedings and lawsuits. However, in 2003, the parties opposing the plant expansion project (other than Waimana Enterprises, Inc. (Waimana), which did not participate in the settlement discussions and opposed the settlement) entered into a settlement agreement with HELCO and several Hawaii regulatory agencies, intended in part to permit HELCO to complete CT-4 and CT-5 (Settlement Agreement). Subsequently, HELCO installed CT-4 and CT-5 and put them into limited commercial operation in May and June 2004, respectively. HELCO met the Board of Land and Natural Resources’ (BLNR’s) construction deadline of July 31, 2005. Noise mitigation equipment has been installed on CT-4 and CT-5 and additional noise mitigation work is ongoing to ensure compliance with the night-time noise standard applicable to the plant. Currently, HELCO can operate the generating units at Keahole as required to meet its system needs.

Waimana filed four appeals to the Hawaii Supreme Court from judgments of the Third Circuit Court involving (i) vacating a November 2002 Final Judgment which had halted construction, (ii) upholding the BLNR 2003 construction period extension, (iii) upholding the BLNR’s approval of a revocable permit allowing HELCO to use brackish well water as the primary source of water for operating the Keahole plant and (iv) upholding the BLNR’s approval of the long-term lease allowing HELCO to use brackish well water.

The Hawaii Supreme Court has either dismissed or issued favorable decisions on all four of these appeals.

In addition to the Supreme Court appeals, one Circuit Court matter had remained open, but it was inactive after the mediation that resulted in the Settlement Agreement. With all appeals resolved, the stipulation to dismiss this case was filed on October 5, 2006 and the case was dismissed with prejudice on October 6, 2006. Full implementation of the Settlement Agreement was conditioned on obtaining final dispositions, which have now been obtained, of all litigation pending at the time of the Settlement Agreement.

The Settlement Agreement required HELCO to undertake a number of actions including expediting efforts to obtain the permits and approvals necessary for installation of ST-7 with selective catalytic reduction emissions control equipment, assisting the Department of Hawaiian Home Lands in installing solar water heating in its housing projects, supporting the Keahole Defense Coalition’s participation in certain PUC cases, and cooperating with neighbors and community groups (including a Hot Line service). Many of these actions had commenced well before all of the litigation was resolved.

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 HELCO has commenced engineering, design and certain construction work for ST-7. HELCO’s current cost estimate for ST-7 is approximately $92 million, of which approximately $0.8 million has been incurred through December 31, 2006.

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CT-4 and CT-5 costs incurred; management’s evaluation. As of December 31, 2006, HELCO’s capitalized costs incurred in its efforts to put CT-4 and CT-5 into service and to support existing units (excluding costs for pre-air permit facilities) amounted to approximately $110 million, including $43 million for equipment and material purchases, $47 million for planning, engineering, permitting, site development and other costs and $20 million for allowance for funds used during construction (AFUDC) up to November 30, 1998, after which date HELCO has not accrued AFUDC. 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 of the year following the reclassification.

HELCO’s electric rates will not change as a result of including CT-4 and CT-5 in plant and equipment unless and until the PUC grants rate relief in the HELCO rate case filed in May 2006 based on a 2006 test year, in part to recover CT-4 and CT-5 costs. At this time, management continues to believe that no adjustment to costs incurred to put CT-4 and CT-5 into service is required as of December 31, 2006. However, if it becomes probable that the PUC will disallow some or all of the incurred costs for rate-making purposes, HELCO may be required to write off a material portion of these costs.

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

HECO continues to believe that the proposed reliability project (the East Oahu Transmission Project) is needed. In December 2003, HECO filed an application with the PUC requesting approval to commit funds (currently estimated at $62 million; see costs incurred below) for a revised EOTP using a 46 kV system. In March 2004, the PUC granted intervenor status to an environmental organization and three elected officials (collectively treated as one party) and a more limited participant status to four community organizations. The environmental review process for the revised EOTP was completed and the PUC issued a Finding of No Significant Impact in April 2005. Subject to obtaining PUC approval and other construction permits, HECO plans to construct the revised project, none of which is in conservation district lands, in two phases. The first phase is currently projected to be completed in 2008 or 2009, subject to the timing of the PUC approval, and the completion date of the second phase is being evaluated.

As of December 31, 2006, the accumulated costs recorded for the EOTP amounted to $30 million, including (i) $12 million of planning and permitting costs incurred prior to the denial in 2002 of the approval necessary for the partial underground/partial overhead 138 kV line, (ii) $5 million of planning and permitting costs incurred after 2002 and (iii) $13 million for AFUDC. 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 before 2003, and the related 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.

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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. Management believes no adjustment to project costs is required as of December 31, 2006. 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 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 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 a preliminary estimate of HECO’s share of costs for continuing investigative work, remedial activities and monitoring at the Iwilei Unit of approximately $1.1 million (which was expensed in 2001 and of which $0.8 million has been expended through December 31, 2006). 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.

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During 2006 and the beginning of 2007, the PRPs developed analyses of various remedial alternatives for two of the four remedial subunits of the Iwilei Unit. The DOH will use the analyses to make a final determination of which remedial alternatives the PRPs will be required to implement. The DOH is scheduled to complete the final remediation determinations for all remedial subunits of the Iwilei Unit by the end of 2007 or first quarter of 2008. HECO management developed an estimate of HECO’s share of the costs associated with implementing the PRP recommended remedial approaches for the two subunits covered by the analyses of approximately $1.2 million, (which was expensed in 2006). As of December 31, 2006, the remaining accrual (amounts expensed less amounts expended) related to the Honolulu Harbor investigation was $1.5 million. Because (1) the full scope of additional investigative work, remedial 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.

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.

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 must develop BART implementation plans and schedules in accordance with the amended regional haze rule by December 2007. After Hawaii adopts its plan, HECO, HELCO and MECO will evaluate its impacts, if any, on them. If any generating units are ultimately required to install post-combustion control technologies to meet BART emission limits, the resulting capital and operations and maintenance costs could be significant.

Clean Water Act. 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 HECO 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 that remanded for further consideration and proceedings significant portions of the rule and found other portions of the rule to be impermissible. In particular, the court determined that restoration and the cost-benefit test were impermissible under the Clean Water Act. It also remanded the best technology available determination to permit the EPA to provide a reasoned explanation for its decision or a new determination. It remanded the cost-cost test for the EPA’s further consideration based on the best technology available determination and to afford adequate notice. The EPA has yet to announce whether it plans to request a rehearing by the court of appeals or appeal the decision to the U.S. Supreme Court. If it stands, the court’s decision reduces the compliance options available to HECO. The EPA has not issued a schedule for rulemaking, which would be necessary to comply with the court’s decision. 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.

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Collective bargaining agreements. As of December 31, 2006, 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. The current collective bargaining and benefit agreements cover a four-year term, from November 1, 2003 to October 31, 2007, and provide for non-compounded wage increases (3% on November 1, 2003; 1.5% on November 1, 2004, May 1, 2005, November 1, 2005 and May 1, 2006; and 3% on November 1, 2006). Negotiations for new agreements are expected to begin in the third quarter of 2007.

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 $3.5 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster should occur, and if the PUC were not to allow the Company 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, 2006, net assets (assets less liabilities and preferred stock) of approximately $431 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, $3.3 million and $3.2 million for general management and administrative services in 2006, 2005 and 2004, 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, 2006 and 2005. 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, $0.4 million and $0.5 million in 2006, 2005 and 2004, 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.

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15. Fair value of financial instruments

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	2006				2005
(in thousands)	Carrying Amount		Estimated fair value		Carrying amount		Estimated fair value
Financial assets:
Cash and equivalents	$	3,859	$	3,859	$	143	$	143
Financial liabilities:
Short-term borrowings from nonaffiliates		113,107		113,107		136,165		136,165
Long-term debt, net, including amounts due within one year		766,185		800,975		765,993		804,485
Off-balance sheet item:
HECO-obligated preferred securities of trust subsidiary		50,000		50,800		50,000		51,400

Limitations

The Company makes fair value estimates at a specific point in time, based on relevant market information and information about the financial instrument. 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 significant portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

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16. Consolidating financial information (unaudited)

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

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Consolidating balance sheet

	December 31, 2005
(in thousands)	HECO			HELCO		MECO		RHI	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	25,699		3,018		4,317		—	—		$	33,034
Plant and equipment		2,304,142		766,714		678,530		—	—			3,749,386
Less accumulated depreciation		(898,351	)	(275,444	)	(282,742	)	—	—			(1,456,537	)
Plant acquisition adjustment, net		—		—		145		—	—			145
Construction in progress		108,060		11,414		28,282		—	—			147,756
Net utility plant		1,539,550		505,702		428,532		—	—			2,473,784
Investment in wholly owned subsidiaries, at equity		383,715		—		—		—	(383,715	) [2]		—
Current assets
Cash and equivalents		8		3		4		128	—			143
Advances to affiliates		49,700		—		5,250		—	(54,950	) [1]		—
Customer accounts receivable, net		81,870		21,652		20,373		—	—			123,895
Accrued unbilled revenues, net		62,701		14,675		13,945		—	—			91,321
Other accounts receivable, net		10,212		2,772		1,185		—	592	[1]		14,761
Fuel oil stock, at average cost		64,309		7,868		13,273		—	—			85,450
Materials & supplies, at average cost		14,128		3,204		9,642		—	—			26,974
Prepayments and other		89,982		15,929		8,991		—	—			114,902
Total current assets		372,910		66,103		72,663		128	(54,358	)		457,446
Other long-term assets
Regulatory assets		81,682		14,596		14,440		—	—			110,718
Unamortized debt expense		9,778		2,362		2,221		—	—			14,361
Other		17,816		3,696		3,640		—	—			25,152
Total other long-term assets		109,276		20,654		20,301		—	—			150,231
	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461
Capitalization and liabilities
Capitalization
Common stock equity	$	1,039,259		189,407		194,190		118	(383,715	) [2]	$	1,039,259
Cumulative preferred stock–not subject to mandatory redemption		22,293		7,000		5,000		—	—			34,293
Long-term debt, net		481,132		131,009		153,852		—	—			765,993
Total capitalization		1,542,684		327,416		353,042		118	(383,715	)		1,839,545
Current liabilities
Short-term borrowings-nonaffiliates		136,165		—		—		—	—			136,165
Short-term borrowings-affiliate		5,250		49,700		—		—	(54,950	) [1]		—
Accounts payable		86,843		19,503		15,855		—	—			122,201
Interest and preferred dividends payable		7,217		1,311		1,664		—	(202	) [1]		9,990
Taxes accrued		84,054		24,252		25,277		—	—			133,583
Other		24,971		3,566		7,791		10	794	[1]		37,132
Total current liabilities		344,500		98,332		50,587		10	(54,358	)		439,071
Deferred credits and other liabilities
Deferred income taxes		160,351		25,147		22,876		—	—			208,374
Regulatory liabilities		148,898		40,535		29,771		—	—			219,204
Unamortized tax credits		31,209		12,693		11,425		—	—			55,327
Other		21,522		31,781		10,374		—	—			63,677
Total deferred credits and other liabilities		361,980		110,156		74,446		—	—			546,582
Contributions in aid of construction		156,287		56,555		43,421		—	—			256,263
	$	2,405,451		592,459		521,496		128	(438,073	)	$	3,081,461

37

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

38

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

39

Consolidating statement of income

	Year ended December 31, 2004
(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and Eliminations		HECO Consolidated
Operating revenues	$	1,053,100		241,630		252,145		—		—		$	1,546,875
Operating expenses
Fuel oil		335,281		38,072		110,070		—		—			483,423
Purchased power		295,963		91,024		11,849		—		—			398,836
Other operation		106,138		24,572		26,488		—		—			157,198
Maintenance		47,847		15,145		14,321		—		—			77,313
Depreciation		69,467		21,163		24,290		—		—			114,920
Taxes, other than income taxes		97,974		22,391		23,469		—		—			143,834
Income taxes		29,484		8,204		12,371		—		—			50,059
		982,154		220,571		222,858		—		—			1,425,583
Operating income		70,946		21,059		29,287		—		—			121,292
Other income
Allowance for equity funds used during construction		5,226		162		406		—		—			5,794
Equity in earnings of subsidiaries		31,746		—		—		—		(31,746	) [2]		—
Other, net		3,652		210		(43	)	(53	)	(634	) [1]		3,132
		40,624		372		363		(53	)	(32,380	)		8,926
Income before interest and other charges		111,570		21,431		29,650		(53	)	(32,380	)		130,218
Interest and other charges
Interest on long-term debt		26,566		7,184		8,793		—		—			42,543
Amortization of net bond premium and expense		1,464		403		422		—		—			2,289
Other interest charges		3,595		1,083		712		—		(634	) [1]		4,756
Allowance for borrowed funds used during construction		(2,312	)	(75	)	(155	)	—		—			(2,542	)
Preferred stock dividends of subsidiaries		—		—		—		—		915	[3]		915
		29,313		8,595		9,772		—		281			47,961
Income before preferred stock dividends of HECO		82,257		12,836		19,878		(53	)	(32,661	)		82,257
Preferred stock dividends of HECO		1,080		534		381		—		(915	) [3]		1,080
Net income for common stock	$	81,177		12,302		19,497		(53	)	(31,746	)	$	81,177
Consolidating statement of retained earnings
	Year ended December 31, 2004
(in thousands)	HECO			HELCO		MECO		RHI		Reclassifications and Eliminations		HECO Consolidated
Retained earnings, beginning of period	$	563,215		74,629		92,909		(134	)	(167,404	) [2]	$	563,215
Net income for common stock		81,177		12,302		19,497		(53	)	(31,746	) [2]		81,177
Common stock dividends		(11,613	)	(1,070	)	(17,914	)	—		18,984	[2]		(11,613	)
Retained earnings, end of period	$	632,779		85,861		94,492		(187	)	(180,166	)	$	632,779

40

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

41

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

42

Consolidating statement of cash flows

	Year ended December 31, 2004
(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	$	82,257		12,836		19,878		(53	)	(32,661	) [2]	$	82,257
Adjustments to reconcile income before preferred stock dividends of HECO to net cash provided by operating activities:
Equity in earnings		(31,931	)	—		—		—		31,746	[2]		(185	)
Common stock dividends received from subsidiaries		19,169		—		—		—		(18,984	) [2]		185
Depreciation of property, plant and equipment		69,467		21,163		24,290		—		—			114,920
Other amortization		4,290		776		3,714		—		—			8,780
Deferred income taxes		10,304		3,969		6,511		—		—			20,784
Tax credits, net		2,315		2,435		462		—		—			5,212
Allowance for equity funds used during construction		(5,226	)	(162	)	(406	)	—		—			(5,794	)
Changes in assets and liabilities:
Increase in accounts receivable		(6,560	)	(2,371	)	(3,935	)	—		(1,308	) [1]		(14,174	)
Increase in accrued unbilled revenues		(14,387	)	(2,201	)	(2,068	)	—		—			(18,656	)
Increase in fuel oil stock		(7,360	)	(4,279	)	(3,319	)	—		—			(14,958	)
Increase in materials and supplies		(1,209	)	(194	)	(1,132	)	—		—			(2,535	)
Decrease (increase) in regulatory assets		(560	)	657		(2,521	)	—		—			(2,424	)
Increase (decrease) in accounts payable		17,159		6,937		(2,458	)	—		—			21,638
Increase in taxes accrued		6,404		1,778		4,440		—		—			12,622
Increase in prepaid pension benefit cost		(16,733	)	(4,799	)	(3,565	)	—		—			(25,097	)
Changes in other assets and liabilities		(10,891	)	(1,236	)	(2,899	)	(7	)	1,308	[2]		(13,725	)
Net cash provided by (used in) operating activities		116,508		35,309		36,992		(60	)	(19,899	)		168,850
Cash flows from investing activities:
Capital expenditures		(123,795	)	(49,324	)	(28,117	)	—		—			(201,236	)
Contributions in aid of construction		4,134		2,796		1,592		—		—			8,522
Advances from (to) affiliates		(24,050	)	—		17,750		—		6,300	[1]		—
Investment in unconsolidated subsidiary		(1,846	)	—		—		—		300	[2]		(1,546	)
Distributions from unconsolidated subsidiaries		3,093		—		—		—		—			3,093
Proceeds from sales of assets		650		—		—		—		—			650
Net cash used in investing activities		(141,814	)	(46,528	)	(8,775	)	—		6,600			(190,517	)
Cash flows from financing activities:
Common stock dividends		(11,613	)	(1,070	)	(17,914	)	—		18,984	[2]		(11,613	)
Preferred stock dividends		(1,080	)	(534	)	(381	)	—		915	[2]		(1,080	)
Proceeds from issuance of common stock		—		—		—		300		(300	) [2]		—
Proceeds from issuance of long-term debt		33,097		10,000		10,000		—		—			53,097
Repayment of long-term debt		(63,093	)	(20,000	)	(20,000	)	—		—			(103,093	)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less		64,818		24,050		—		—		(6,300	) [1]		82,568
Other		3,177		(1,228	)	8		—		—			1,957
Net cash provided by (used in) financing activities		25,306		11,218		(28,287	)	300		13,299			21,836
Net increase (decrease) in cash and equivalents		—		(1	)	(70	)	240		—			169
Cash and equivalents, beginning of year		9		4		87		58		—			158
Cash and equivalents, end of year	$	9		3		17		298		—		$	327

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Explanation of reclassifications and eliminations on consolidating schedules

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

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

[3] Reclassification of 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.

17. Consolidated quarterly financial information (unaudited)

Selected quarterly consolidated financial information of the Company for 2006 and 2005 follows:

	Quarters ended								Year ended
2006	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues (1),(2)	$	473,971	$	503,350	$	568,236	$	504,855	$	2,050,412
Operating income (1),(2)		31,562		28,502		32,736		24,355		117,155
Net income for common stock (1),(2)		20,988		17,286		23,666		13,007		74,947
	Quarters ended								Year ended
2005	March 31		June 30		Sept. 30		Dec. 31		Dec. 31
(in thousands)
Operating revenues	$	373,690	$	428,807	$	489,877	$	509,336	$	1,801,710
Operating income (3)		23,065		29,624		32,614		28,239		113,542
Net income for common stock (3)		12,385		19,644		22,587		18,186		72,802

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

(1) For 2006, amounts include interim rate relief for HECO.

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

(3) For 2005, the amounts for the fourth quarter include $10 million of interim rate relief for HECO.

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