exv99w4

Exhibit 99.4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
The Detroit Edison Company

We have audited the consolidated statement of financial position of The Detroit Edison Company and subsidiaries (the “Company”) as of December 31, 2004 and 2003 and the related consolidated statements of operations, cash flows, and changes in shareholder’s equity and comprehensive income for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Detroit Edison Company and subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, in connection with the required adoption of a new accounting principle, in 2003 the Company changed its method of accounting for asset retirement obligations.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 15, 2005 (August 4, 2005 as to Note 1 — Segment Realignment)

The Detroit Edison Company

Consolidated Statement of Operations


	Year Ended December 31
(in Millions)	2004			2003			2002
Operating Revenues	$	3,568		$	3,695		$	4,054


Operating Expenses
Fuel and purchased power		885			939			1,074
Operation and maintenance		1,394			1,352			1,271
Depreciation and amortization		523			473			577
Taxes other than income		249			257			273

		3,051			3,021			3,195


Operating Income		517			674			859


Other (Income) and Deductions
Interest expense		280			284			311
Interest income		—			(7	)		(1	)
Other income		(66	)		(93	)		(36	)
Other expenses		89			93			51

		303			277			325


Income Before Income Taxes		214			397			534


Income Tax Provision		64			145			178


Income Before Accounting Change		150			252			356

Cumulative Effect of Accounting Change (Note 2)		—			(6	)		—


Net Income	$	150		$	246		$	356

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Financial Position


	December 31
(in Millions)	2004			2003
Assets
Current Assets
Cash and cash equivalents	$	6		$	6
Restricted cash		75			82
Accounts receivable
Customer (less allowance for doubtful accounts of $55 and $51, respectively)		258			291
Accrued unbilled revenues		207			196
Other		120			169
Inventories
Fuel		100			108
Materials and supplies		118			124
Notes receivable from affiliate (Note 15)		85			7
Other		46			22

		1,015			1,005


Investments
Nuclear decommissioning trust funds		590			518
Other		55			54

		645			572


Property
Property, plant and equipment		12,931			12,671
Less accumulated depreciation (Note 2)		(5,354	)		(5,339	)

		7,577			7,332


Other Assets
Regulatory assets (Note 4)		2,053			2,000
Securitized regulatory assets (Note 4)		1,438			1,527
Other		114			113

		3,605			3,640


Total Assets	$	12,842		$	12,549

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Financial Position


	December 31
(in Millions, Except Shares)	2004			2003
Liabilities and Shareholder’s Equity
Current Liabilities
Accounts payable	$	346		$	211
Accrued interest		79			76
Dividends payable (Note 15)		76			74
Accrued payroll		12			27
Accrued vacations		76			76
Short-term borrowings		—			100
Accrued PSCR refund		112			—
Current portion long-term debt, including capital leases		499			144
Other		130			213

		1,330			921


Other Liabilities
Deferred income taxes		1,941			1,783
Regulatory liabilities (Notes 2 and 4)		253			254
Asset retirement obligations (Note 2)		869			819
Unamortized investment tax credit		125			135
Nuclear decommissioning (Notes 2 and 5)		77			67
Accrued pension liability		247			321
Other		676			639

		4,188			4,018

Long-Term Debt (net of current portion) (Note 9)
Mortgage bonds, notes and other		2,879			3,076
Securitization bonds		1,400			1,496
Capital lease obligations		66			75

		4,345			4,647


Commitments and Contingencies (Notes 4, 5 and 13)

Shareholder’s Equity
Common stock, $10 par value, 400,000,000 shares authorized, 138,632,324 and 134,287,832 shares issued and outstanding		1,386			1,343
Premium on common stock		1,104			977
Common stock expense		(44	)		(44	)
Retained earnings		531			686
Accumulated other comprehensive income		2			1

		2,979			2,963


Total Liabilities and Shareholder’s Equity	$	12,842		$	12,549

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Cash Flows


	Year Ended December 31
(in Millions)	2004			2003			2002
Operating Activities
Net Income	$	150		$	246		$	356
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		523			473			577
Deferred income taxes		142			32			(52	)
Loss (gain) on sale of assets		(1	)		21			—
Cumulative effect of accounting change		—			6			—
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		376			(13	)		(123	)

Net cash from operating activities		1,190			765			758

Investing Activities
Plant and equipment expenditures		(702	)		(580	)		(685	)
Proceeds from sale of assets		1			2			—
Restricted cash for debt redemptions		6			49			(63	)
Notes receivable from affiliate		(78	)		50			(57	)
Other investments		(66	)		(126	)		(86	)

Net cash used for investing activities		(839	)		(605	)		(891	)

Financing Activities
Issuance of long-term debt		266			49			570
Redemption of long-term debt		(206	)		(504	)		(318	)
Short-term borrowings, net		(100	)		100			—
Capital contribution by parent company		—			470			—
Repurchase of common stock		—			—			—
Dividends on common stock		(303	)		(295	)		(295	)
Other		(8	)		(10	)		(3	)

Net cash used for financing activities		(351	)		(190	)		(46	)

Net Increase (Decrease) in Cash and Cash Equivalents		—			(30	)		(179	)
Cash and Cash Equivalents at Beginning of the Period		6			36			215

Cash and Cash Equivalents at End of the Period	$	6		$	6		$	36

See Notes to Consolidated Financial Statements

The Detroit Edison Company

Consolidated Statement of Changes in Shareholder’s Equity and
Comprehensive Income


					Premium								Accumulated
					On		Common						Other
(Dollars in Millions,	Common Stock				Common		Stock			Retained			Comprehensive
Shares in Thousands)	Shares		Amount		Stock		Expense			Earnings			Income (Loss)			Total

Balance, December 31, 2001		134,288	$	1,343	$	507	$	(44	)	$	675		$	(23	)	$	2,458

Net income		—		—		—		—			356			—			356
Dividends declared on Common stock		—		—		—		—			(296	)		—			(296	)
Net change in unrealized losses on derivatives, net of tax		—		—		—		—			—			21			21
Pension obligation (Note 14)		—		—		—		—			—			(417	)		(417	)

Balance, December 31, 2002		134,288		1,343		507		(44	)		735			(419	)		2,122

Net income		—		—		—		—			246			—			246
Dividends declared on Common stock		—		—		—		—			(295	)		—			(295	)
Net change in unrealized losses on derivatives, net of tax		—		—		—		—			—			3			3
Pension obligation (Note 14)		—		—		—		—			—			417			417
Capital contribution by parent company		—		—		470		—			—			—			470

Balance, December 31, 2003		134,288		1,343		977		(44	)		686			1			2,963

Net income		—		—		—		—			150			—			150
Dividends declared on Common stock		—		—		—		—			(305	)		—			(305	)
Net change in unrealized gain on investments, net of tax		—		—		—		—			—			1			1
Common stock issued to parent company		4,344		43		127		—			—			—			170

Balance, December 31, 2004		138,632	$	1,386	$	1,104	$	(44	)	$	531		$	2		$	2,979

The following table displays comprehensive income (loss):


(in Millions)	2004		2003			2002
Net income	$	150	$	246		$	356

Other comprehensive income (loss), net of tax:
Net unrealized losses on derivatives:
Gains or (losses) arising during the period, net of taxes of $-, $4 and $-		—		8			(1	)
Amounts reclassified to earnings, net of taxes of $-, $(3) and $11		—		(5	)		22

		—		3			21
Net change in unrealized gain on investments, net of taxes of $-, $- and $-		1		—			—
Pension obligations, net of taxes of $-, $224 and $(224) (Notes 4 and 14)		—		417			(417	)

Comprehensive income (loss)	$	151	$	666		$	(40	)

See Notes to Consolidated Financial Statements

Corporate Structure

Detroit Edison is a Michigan public utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in a 7,600 square-mile area in southeastern Michigan. Detroit Edison is regulated by the Michigan Public Service Commission (MPSC) and the Federal Energy Regulatory Commission (FERC).

References in this report to “we,” “us” and “our” are to Detroit Edison and its subsidiaries, collectively.

Segment Realignment

Through the first quarter of 2005, we operated our business through two strategic business units (Energy Resources and Energy Distribution). In the second quarter of 2005, we have combined the previous two segments into a single segment that more closely reflects how we operate and manage our business. Based on this structure we set strategic goals, allocate resources and evaluate performance.

Principles of Consolidation

We consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When we do not influence the operating policies of an investee, the cost method is used.

For entities that are considered variable interest entities we apply the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46-R, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.” For a detailed discussion of FIN 46-R see Note 2 — New Accounting Pronouncements.

Basis of Presentation

The accompanying consolidated financial statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact reported amounts of assets, liabilities, revenues, expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

We reclassified certain prior year balances to match the current year’s financial statement presentation.

Revenues

Revenues from the sale and delivery of electricity are recognized as services are provided. We record revenues for electric services provided but unbilled at the end of each month.

Detroit Edison’s accrued revenues include a component for the cost of power sold that is recoverable through the Power Supply Cost Recovery (PSCR) mechanism. Annual PSCR proceedings before the MPSC permit Detroit Edison to recover prudent and reasonable supply costs. Any overcollection or

undercollection of costs, including interest, will be reflected in future rates. Prior to 2004, Detroit Edison’s retail rates were frozen under Public Act (PA) 141. See Note 4 for further discussion. Accordingly, Detroit Edison did not accrue revenues under the PSCR mechanism prior to 2004.

Comprehensive Income

We comply with Statement of Financial Accounting Standards (SFAS) No. 130, “Reporting Comprehensive Income,” that established standards for reporting comprehensive income. SFAS No. 130 defines comprehensive income as the change in common shareholders’ equity during a period from transactions and events from non-owner sources, including net income. As shown in the following table, amounts recorded to other comprehensive income at December 31, 2004 include: unrealized gains and losses from derivatives accounted for as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”


	Net		Net		Accumulated
	Unrealized		Unrealized		Other
	Gain on		Losses on		Comprehensive
(in Millions)	Investments		Derivatives		Income (Loss)
Beginning balance	$	—	$	1	$	1
Current-period change		1		—		1

Ending balance	$	1	$	1	$	2

Cash Equivalents and Restricted Cash

Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventories

We value fuel inventory and materials and supplies at average cost.

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:


(in Millions)	2004			2003
Property, Plant and Equipment
Electric Utility
Generation	$	7,100		$	6,938
Distribution		5,831			5,733

Total		12,931			12,671


Less Accumulated Depreciation and Depletion
Electric Utility
Generation		(3,277	)		(3,231	)
Distribution		(2,077	)		(2,108	)

Total		(5,354	)		(5,339	)


Net Property, Plant and Equipment	$	7,577		$	7,332

Property is stated at cost and includes construction-related labor, materials, overheads and an “allowance for funds used during construction” (AFUDC). The cost of properties retired, less salvage, are charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $3.8 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2006 were accrued at December 31, 2004. Amounts are being accrued on a pro-rata basis over an 18-month period that began in November 2004. We have utilized the accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method also matches the regulatory recovery of these costs in rates set by the MPSC.

We base depreciation provisions for utility property on straight-line rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.4% in 2004, 2003 and 2002.

The average estimated useful life for each class of property, plant and equipment as of December 31, 2004 follows:

Estimated Useful Lives in Years


Generation	Distribution
39		37

We credit depreciation and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures.

Long-Lived Assets

Long-lived assets that we own are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less cost to sell.

Intangible Assets, including Software Costs

Our intangible assets consist primarily of software. We capitalize the costs associated with computer software we develop or obtain for use in our business. We amortize intangible assets on a straight-line basis over expected periods of benefit. Intangible assets amortization expense was $32 million in 2004, $30 million in 2003 and $36 million in 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $253 million and $88 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were $352 million and $250 million, respectively. Amortization expense of intangible assets is estimated to be $27 million annually for 2005 through 2009.

Excise and Sales Taxes

We record the billing of excise and sales taxes as receivables with an offsetting payable to the applicable taxing authority, with no impact on the statement of operations.

Deferred Debt Costs

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to Detroit Edison, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

Insured and Uninsured Risks

We have a comprehensive insurance program in place to provide coverage for various types of risks. Our insurance policies cover risk of loss from various events, including property damage, general liability, workers’ compensation, auto liability and officers’ liability.

Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. We periodically review our insurance coverage. During 2003, we reviewed our process for estimating and recognizing reserves for self-insured risks. As a result of this review, we revised the process for estimating liabilities under our self-insured layers to include an actuarially determined estimate of “incurred but not reported” (IBNR) claims. We have an actuarially determined estimate of our IBNR liability prepared annually and adjust the related reserve as appropriate.

Investments in Debt and Equity Securities

We generally classify investments in debt and equity securities as trading and have recorded such investments at market value with unrealized gains or losses included in earnings. Changes in the fair value of nuclear decommissioning-related investments are recorded as adjustments to regulatory assets or liabilities (Note 5).

Consolidated Statement of Cash Flows

A detailed analysis of the changes in assets and liabilities that are reported in the consolidated statement of cash flows follows:


(in Millions)	2004			2003			2002
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	91		$	13		$	40
Accrued unbilled receivables		(11	)		(19	)		(47	)
Inventories		14			18			34
Accrued pensions		123			(179	)		(44	)
Accounts payable		135			(27	)		(78	)
Accrued PSCR refund		112			—			—
Accrued payroll		(15	)		3			(65	)
Income taxes payable		(14	)		(24	)		(75	)
General taxes		(13	)		(7	)		(2	)
Risk management and trading activities		(1	)		(7	)		(32	)
Postretirement obligation		11			93			60
Other		(56	)		123			86

	$	376		$	(13	)	$	(123	)

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and 2 nuclear plants. We believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and are deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $278 million with offsetting accumulated depreciation of $103 million, a retirement obligation liability of $771 million and reversed previously recognized obligations of $366 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to utility operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $6 million (net of tax of $4 million) for 2003.

If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as assets with an indeterminate life, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, distribution assets have an indeterminate life, retirement cash flows cannot be determined and there is a low probability of retirement, therefore no liability has been recorded for these assets.

The impact on the twelve-month period of 2003 of SFAS No. 143 and the pro-forma effect for the comparable 2002 periods as if SFAS No. 143 had been adopted at January 1, 2002 are immaterial.

A reconciliation of the asset retirement obligation for 2004 follows:


(in Millions)
Asset retirement obligations at January 1, 2004	$	819
Accretion		55
Liabilities settled		(5	)

Asset retirement obligations at December 31, 2004	$	869

A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities, which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At December 31, 2003, we reclassified approximately $238 million of previously accrued asset removal costs, which had been previously netted against accumulated depreciation to regulatory liabilities. There is a generic case before the MPSC to determine the accounting and regulatory treatment of removal costs for Michigan utilities.

Consolidation of Variable Interest Entities

In January 2003, FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51,” was issued and requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses.

In October 2003 and December 2003, the FASB issued Staff Position No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, which clarified and replaced FIN 46 and also provided for the deferral of the effective date of FIN 46 for certain variable interest entities. We have evaluated all of our equity and non-equity interests and have adopted all current provisions of FIN 46-R. The adoption of FIN 46-R did not have a material effect on our financial statements.

Medicare Act Accounting

In December 2003, the “Medicare Prescription Drug, Improvement and Modernization Act of 2003" (Medicare Act) was signed into law. The Medicare Act provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. We elected at that time to defer the provisions of the Medicare Act, and its impact on our accumulated postretirement benefit obligation and net periodic postretirement benefit cost pending, the issuance of specific authoritative accounting guidance by the FASB.

In May 2004, FASB Staff Position (FSP) No. 106-2 was issued on accounting for the effects of the Medicare Act. The guidance in this FSP is applicable to sponsors of single-employer defined benefit postretirement health care plans for which (a) the employer has concluded the prescription drug benefits available under the plan to some or all participants are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy under the Medicare Act and (b) the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. We believe we qualify for the subsidy under the Medicare Act and the expected subsidy will partially offset our share of the cost of postretirement prescription drug coverage.

In June 2004, we adopted FSP No. 106-2, retroactive to January 1, 2004. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $70 million and was accounted for as an actuarial gain. The effects of the subsidy reduced net postretirement costs by $12 million in 2004.

NOTE 3 — DISPOSITIONS

Steam Heating Business

In January 2003, we sold our steam heating business to Thermal Ventures II, LP. Due to our continuing involvement in the steam heating business, including the commitment to purchase steam and/or electricity through 2024, fund certain capital improvements and guarantee the buyer’s credit facility, we recorded a net of tax loss of approximately $14 million in 2003. As a result of our continuing involvement, this transaction is not considered a sale for accounting purposes. The steam heating business had assets of $6 million at December 31, 2002, and had net losses of $12 million in 2002. See Note 13 — Commitments and Contingencies.

NOTE 4 — REGULATORY MATTERS

Regulation

Detroit Edison is subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to retail rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.

As subsequently discussed in the “Electric Industry Restructuring” section, Detroit Edison’s rates were frozen through 2003 and capped for small business customers through 2004 and for residential customers through 2005 as a result of Public Act (PA) 141. However, Detroit Edison was allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

Regulatory Assets and Liabilities

Detroit Edison applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to its operations. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its business and may require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates. Management believes that currently available facts support the continued application of SFAS No. 71.

The following are balances and a brief description of the regulatory assets and liabilities at December 31:


(in Millions)	2004			2003
Assets
Securitized regulatory assets	$	1,438		$	1,527


Recoverable income taxes related to securitized regulatory assets	$	788		$	837
Recoverable minimum pension liability		604			583
Asset retirement obligation		183			192
Other recoverable income taxes		109			114
Recoverable costs under PA 141
Net stranded costs		122			68
Excess capital investment		7			—
Deferred Clean Air Act expenditures		76			54
Midwest Independent System Operator charges		27			21
Transmission integration costs		—			10
Electric Customer Choice implementation costs		95			84
Enhanced security costs		8			6
Unamortized loss on reacquired debt		29			28
Other		5			3

	$	2,053		$	2,000


Liabilities
Asset removal costs	$	250		$	238
Excess securitization savings		—			14
Customer refund - 1997 storm		2			2
Accrued PSCR refund		112			—
Other		1			—

		365			254
Less amount included in current liabilities		(112	)		—

	$	253		$	254

ASSETS

•

Securitized regulatory assets — The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015.

•

Recoverable income taxes related to securitized regulatory assets — Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax.

•

Recoverable minimum pension liability — An additional minimum pension liability was recorded under generally accepted accounting principles (Note 14) due to the current under funded status of certain pension plans. The traditional rate setting process allows for the recovery of pension costs as measured by generally accepted accounting principles. Accordingly, the minimum pension liability is recoverable.

•

Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

•

Other recoverable income taxes — Income taxes receivable from Detroit Edison’s customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison’s rates.

•

Net stranded costs — PA 141 permits, after MPSC authorization, the recovery of and a return on fixed cost deficiency associated with the electric Customer Choice program. Net stranded costs occur when fixed cost related revenues do not cover the fixed cost revenue requirements.

•

Excess capital investment — Starting in 2004, PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.

•

Deferred Clean Air Act expenditures — PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.

•

Midwest Independent System Operator charges — PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator.

•

Transmission integration costs —The MPSC’s November 2004 final rate order denied recovery and determined these costs to be transaction expenses in DTE Energy’s sale of ITC.

•

Electric Customer Choice implementation costs — PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program.

•

Enhanced security costs — PA 141 permits, after MPSC authorization, the recovery of enhanced homeland security costs for an electric generating facility.

•

Unamortized loss on reacquired debt — The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.

LIABILITIES

•

Asset removal costs - The amount collected from customers for the funding of future asset removal activities.

•

Excess securitization savings — Savings associated with the 2001 securitization of Fermi 2 and other costs are refundable to Detroit Edison’s customers.

•

Customer refund — 1997 storm — The over collection of 1997 storm costs, which will be refunded in accordance with the MPSC’s November 2004 rate order.

•

Accrued PSCR refund - Payable for the temporary over-recovery of and a return on power supply costs, and beginning with the MPSC’s November 2004 rate order, transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

Electric Rate Case

Rate Request- In June 2003, Detroit Edison filed an application with the MPSC requesting a change in retail electric rates, resumption of the PSCR mechanism, and recovery of net stranded costs. The application and subsequent revisions resulted in a request to increase base rates by $583 million annually.

In addition, Detroit Edison requested recovery of certain regulatory assets. As subsequently discussed, Detroit Edison received interim and final rate orders relating to its June 2003 rate application.

A summary of the rate orders follows:


	Interim			Final
(in Millions)	Rate Increase (1)			Rate Increase (1)
Base Rate Revenue Deficiency	$	248		$	336
Recovery of SMC Discounts		—			38

Overall Base Rate Increase		248			374
PSCR Savings		(126	)		(126	)

Total	$	122		$	248


	Actual			Estimate
	2004			2005 (2)		Total
Cumulative Recoverable Regulatory Assets
Clean Air Act	$	76		$	68	$	144
MISO Transmission Costs		27			49		76
Excess Capital Expenditures		7			15		22
Customer Refund - 1997 Storm		(2	)		—		(2	)

		108			132		240
Electric Choice Implementation Costs		95			6		101
Net Stranded Costs		44			—		44

Total	$	247		$	138	$	385


(1)		The impact of rate caps not included.

(2)		Represents estimated amounts to be incurred in 2005, as well as carrying costs on unrecovered balances, that were authorized for recovery by the MPSC. Actual amounts incurred are subject to review in future MPSC proceedings, and any overcollections or undercollections will be reflected in future rates.

MPSC Interim Rate Order - On February 20, 2004, the MPSC issued an order for interim rate relief. The order authorized an interim increase in base rates, a transition charge for customers participating in the electric Customer Choice program and a new PSCR factor.

The interim base rate increase totaled $248 million annually, effective February 21, 2004, and was applicable to all customers not subject to a rate cap. The increase was allocated to both full-service customers ($240 million) and electric Customer Choice customers ($8 million). However, because of the rate caps under PA 141, not all of the increase was realized in 2004. The interim order also terminated certain transition credits and authorized transition charges to electric Customer Choice customers designed to result in $30 million in additional revenues. Additionally, the MPSC authorized a reduced PSCR factor for all customers, designed to lower revenues by $126 million annually. However, the MPSC order allowed Detroit Edison to increase base rates for customers still subject to the cap in an equal and offsetting amount with the required reduction in the PSCR factor to maintain the total capped rate levels currently in effect for these customers.

The MPSC deferred addressing other items in the rate request, including a surcharge to recover regulatory assets, until a final rate order was issued.

MPSC Final Rate Order - On November 23, 2004, the MPSC issued an order for final rate relief. The MPSC determined that the base rate increase granted to Detroit Edison should be $336 million annually effective November 24, 2004 and is applicable to all customers not subject to the rate cap. The final order provides for the future recovery of losses resulting from electric Customer Choice. Additionally, beginning in 2005, the final order allows Detroit Edison to recover the discounts previously provided to special manufacturing contract (SMC) customers of $38 million, resulting in an overall base rate increase of $374 million annually. As subsequently discussed, Detroit Edison has been deferring certain costs as regulatory assets that it believes are recoverable under PA 141 once rate caps expire. The final order

addressed numerous issues relating to regulatory assets, including the amounts recoverable and the recovery mechanism. The final order authorized the recovery of a lower level of stranded costs than had been recorded through February 20, 2004, the date of the interim order. Accordingly, Detroit Edison adjusted its net stranded costs related regulatory asset, which decreased 2004 net income by $21 million.

The MPSC’s final order authorizes the recovery of approximately $385 million of regulatory assets through three mechanisms:

•

The first mechanism recovers certain accrued regulatory assets over a five-year period using a regulatory asset recovery surcharge (RARS) and is collectible from all full service customers as their rate caps expire. The total amount to be collected is estimated to be $240 million, plus carrying costs of 9.74% on unrecovered balances. The recoverable regulatory assets include costs associated with Clean Air Act compliance, deferred MISO transmission fees, and deferred excess capital expenditures. The MPSC also authorized the refunding of over collected 1997 storm costs.

•

The second mechanism includes a surcharge to recover electric Customer Choice implementation costs of $101 million and is collectible from both full service and electric Customer Choice customers. This charge will not be implemented until all current rate caps expire in 2006 and will include carrying costs of 7% on unrecovered balances.

•

The third mechanism includes a surcharge to recover $44 million in historical stranded costs incurred in 2002, 2003 and January and February 2004 and is collectible from electric Customer Choice customers, including carrying costs of 7% on unrecovered balances.

Other significant items authorized by the MPSC in its final order:

•

Rate increase was based on a 54% debt and 46% equity capital structure, and an 11% rate of return on common equity.

•

Customer rate caps do not expire until January 2006. As a result, the MPSC determined that there is a need to true-up stranded costs for at least 2004. This true-up case must be filed by March 31, 2005. The MPSC also permits Detroit Edison to file additional annual stranded cost true-up proceedings if it deems appropriate to do so pursuant to PA 141.

•

Transmission and MISO costs and costs associated with nitrogen oxide (NOx) allowances will be recoverable through the PSCR mechanism and charged to full service customers; however, costs associated with sulfur dioxide (SOx) allowances will not be included in the PSCR, but recoverable through base rates.

•

Full cost recovery of $550 million of Clean Air Act environmental expenditures was authorized. We believe that future mandated environmental expenditures will also be recovered through base rates.

•

A pension tracking mechanism was established to manage changes in pension costs. Under the tracking mechanism, Detroit Edison would recover or refund pension costs above or below the amount reflected in base rates. Detroit Edison was also required to propose a similar tracking mechanism for retiree health care costs. In February 2005, Detroit Edison filed a request with the MPSC seeking authority to implement a tracking mechanism for retiree health care costs (Other Postemployment Benefits Costs Tracker).

•

Detroit Edison was ordered to file a rate unbundling and restructuring case by March 23, 2005. As subsequently discussed, this rate restructuring proposal was filed on February 4, 2005.

•

Changes to the existing electric Customer Choice program regarding customers returning to full utility service. Customers electing to participate in the electric Customer Choice program will not be permitted to return to Detroit Edison’s full service rates for two years. Electric Customer Choice customers returning to full service must remain on bundled rates for at least one year following their return. Customers who fail to give the appropriate notice or do not stay on the electric Customer Choice program for two years are required to pay the higher of the applicable tariff energy price plus 10%, or the market price of power plus 10%, for any power taken from Detroit Edison.

In December 2004, Detroit Edison and other parties filed petitions for rehearing relating to the MPSC’s November 2004 final rate order. Among other items, Detroit Edison’s petition requests a correction of the capital structure used in determination of the final order and recovery of certain disallowed costs. Detroit Edison awaits an MPSC decision on the petitions for rehearing.

Electric Rate Restructuring Proposal

On February 4, 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies that are part of its current pricing structure. The proposal would adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, commercial and industrial rates would be lowered, but residential rates would increase over a five-year period beginning in 2007. The MPSC anticipates that this proceeding will be completed in time to have new rates in effect no later than January 1, 2006.

Other Postemployment Benefits Costs Tracker

On February 10, 2005, Detroit Edison filed an application requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. The application was filed as required pursuant to the MPSC’s November 2004 order.

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs - In 2000, the Michigan Legislature enacted PA 141 that reduced electric retail rates by 5%, as a result of savings derived from the issuance of securitization bonds. The legislation also contained provisions freezing rates through 2003 and preventing rate increases (i.e., rate caps) for small business customers through 2004 and for residential customers through 2005. The price freeze period expired on February 20, 2004 pursuant to an MPSC order. In addition, PA 141 codified the MPSC’s existing electric Customer Choice program and provided Detroit Edison with the right to recover net stranded costs associated with Customer Choice. Detroit Edison was also allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual proceeding or true-up before the MPSC reconciling the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital. Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding.

In July 2003, the MPSC issued an order finding that Detroit Edison had no net stranded costs in 2000 and 2001. Detroit Edison filed a petition for rehearing of the July 2003 order, which the MPSC denied in

December 2003. Detroit Edison has appealed. As previously discussed, the MPSC’s November 2004 final order authorized recovery of $44 million of historical stranded costs incurred in 2002, 2003 and January and February 2004 collectible from electric Customer Choice customers through transition charges. Since March 1, 2004, Detroit Edison has recorded $108 million of additional stranded costs as a regulatory asset as the result of rate caps and higher electric Customer Choice sales losses than included in the 2004 MPSC interim order.

Securitization - Detroit Edison formed The Detroit Edison Securitization Funding LLC (Securitization LLC), a wholly owned subsidiary, for the purpose of securitizing its qualified costs, primarily related to the unamortized investment in the Fermi 2 nuclear power plant. In March 2001, the Securitization LLC issued $1.75 billion of securitization bonds, and Detroit Edison sold $1.75 billion of qualified costs to the Securitization LLC. The Securitization LLC is independent of Detroit Edison, as is its ownership of the qualified costs. Due to principles of consolidation, the qualified costs and securitization bonds appear on the company’s consolidated statement of financial position. The Company makes no claim to these assets. Ownership of such assets has vested in the Securitization LLC and been assigned to the trustee for the securitization bonds. Neither the qualified costs nor funds from an MPSC approved non-bypassable surcharge collected from Detroit Edison’s customers for the payment of costs related to the Securitization LLC and securitization bonds are available to Detroit Edison’s creditors.

Excess Securitization Savings — In January 2004, the MPSC issued an order directing Detroit Edison to file a report by March 15, 2004, of the accounting of the savings due to securitization and the application of those savings through December 2003. In addition, Detroit Edison was requested to include in the report an estimate of the foregone carrying cost associated with the excess securitization savings. A report was filed on February 16, 2004 in compliance with the MPSC order.

DTE2 Accounting Application

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. The new information systems are replacing systems that are approaching the end of their useful lives. We expect the benefits of DTE2 to include lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize DTE2 costs, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. Through December 2004, we have expensed approximately $12 million of training, maintenance and overhead costs pending MPSC action on our application. Detroit Edison is proposing a 15-year amortization period for the costs, exclusive of the computer equipment costs.

Power Supply Cost Recovery Proceedings

2004 Plan Year - An MPSC December 2003 order resumed the PSCR mechanism that had been suspended while rates were frozen. The order authorized a new PSCR factor for all customers effective January 1, 2004. The MPSC’s February 2004 interim order provided for a credit of 1.05 mills per kWh compared to a 2.04 mills per kWh charge previously in effect. Detroit Edison will file a 2004 PSCR reconciliation case by March 31, 2005.

2005 Plan Year - In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004

MPSC rate order. The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor are power supply costs, transmission expenses and NOx emission allowance costs. Detroit Edison self-implemented a factor of a negative 2.00 mills per kWh on January 1, 2005. The Michigan Attorney General has filed a motion for summary disposition of this proceeding based on arguments that the PSCR statute requires a fixed 48-month PSCR factor. We cannot predict the nature or timing of actions the MPSC will take on this motion.

Transmission Proceedings

On November 18, 2004, a FERC order approved a transmission pricing structure to facilitate seamless trading of electricity between MISO and the PJM Interconnection. The pricing structure eliminates layers of transmission charges between the two regional transmission organizations. The FERC noted that the new pricing structure may result in transmission owners facing abrupt revenue shifts. To facilitate the transition to the new pricing structure, the FERC authorized a Seams Elimination Cost Adjustment (SECA), effective from December 2004 through March 2006. Under MISO’s filing with the FERC, Detroit Edison’s SECA obligation would be $2.2 million per month from December 2004 through March 2005. Detroit Edison has estimated that the SECA charge for the April 2005 through March 2006 period will be approximately $1 million per month. On December 20, 2004, Detroit Edison filed a request for rehearing with the FERC which states, among other things, that SECA is retroactive ratemaking and is unlawful under the Federal Power Act. Under the MPSC’s November 2004 final rate order, transmission expenses are recoverable through the PSCR mechanism. Therefore, SECA charges, if ultimately imposed, should not have a financial impact to Detroit Edison.

Minimum Pension Liability

In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, “Employers’ Accounting for Pensions,” with offsetting amounts to an intangible asset and other comprehensive income. During 2003, the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff opinion, management believes that it will be allowed to recover in rates the minimum pension liability associated with its utility operations. In 2004 and 2003, we reclassified approximately $604 million ($393 million net of tax) and $583 million ($379 million net of tax), respectively, of other comprehensive loss associated with the minimum pension liability to a regulatory asset (Note 14).

Other

We are unable to predict the outcome of the regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders, which may materially impact the financial position, results of operations and cash flows of the Company.

NOTE 5 — NUCLEAR OPERATIONS

General

Fermi 2, our nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 megawatts. This plant represents approximately 10% of Detroit Edison’s summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. See Note 4 — Regulatory Matters. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned. The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.

Property Insurance

Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of these insurance polices.

Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. These policies have a 12-week waiting period and provide an aggregate $490 million of coverage over a three-year period.

Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.

For multiple terrorism losses caused by acts of terrorism not covered under the Terrorism Risk Insurance Act (TRIA) of 2002 occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.

Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $28 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance

As required by federal law, Detroit Edison maintains $300 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 1988 (Act), deferred premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $10 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear incident at any of these facilities. The Act expired on August 1, 2002. During 2003, the U.S. Congress extended the Act for commercial nuclear facilities through December 31, 2003. However, provisions of the Act remain in effect for existing commercial reactors. Legislation to extend the Act in conjunction with comprehensive energy legislation is currently under debate in Congress. We cannot predict whether Congress will pass the legislation.

Decommissioning

The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. We believe the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula.

Detroit Edison has established a restricted external trust to hold funds collected from customers for decommissioning and the disposal of low-level radioactive waste. Detroit Edison collected $38 million in 2004, $36 million in 2003 and $42 million in 2002 from customers for decommissioning and low-level radioactive waste disposal. Net unrealized investment gains of $17 million and $62 million in 2004 and 2003, respectively, and $39 million in losses in 2002, were recorded as adjustments to the nuclear decommissioning trust funds and regulatory assets. At December 31, 2004, investments in the external

trust consisted of approximately 55% in publicly traded equity securities, 43% in fixed debt instruments and 2% in cash equivalents.

At December 31, 2004 and 2003, Detroit Edison had external decommissioning trust funds of $546 million and $474 million, respectively, for the future decommissioning of Fermi 2. At December 31, 2004 and 2003, Detroit Edison had an additional $18 million and $22 million in trust funds for the decommissioning of Fermi 1. At December 31, 2004 and 2003, Detroit Edison also had an external decommissioning trust fund for low-level radioactive waste disposal costs of $26 million and $22 million, respectively. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.0 billion in 2004 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, the company began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be complete by 2009.

As a result of adopting SFAS No. 143, Detroit Edison recorded a retirement obligation liability for the decommissioning of Fermi 1 and 2 and reversed previously recognized decommissioning liabilities. At December 31, 2004, we have recorded a liability for the removal of the non-nuclear portion of the plants of $77 million.

Nuclear Fuel Disposal Costs

In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kWh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays have occurred in the DOE’s program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Until the DOE is able to fulfill its obligation under the contract, Detroit Edison is responsible for the spent nuclear fuel storage. Detroit Edison estimates that existing storage capacity will be sufficient until 2007. Detroit Edison is a party in the litigation against the DOE for both past and future costs associated with the DOE’s failure to accept spent nuclear fuel under the timetable set forth in the Act.

NOTE 6 — JOINTLY OWNED UTILITY PLANT

Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Ownership information of the two utility plants as of December 31, 2004 was as follows:


			Ludington
			Hydroelectric
	Belle River		Pumped Storage
In-service date		1984-1985		1973
Total plant capacity	1,026 MW		1,872 MW
Ownership interest		*		49	%
Investment (in Millions)	$	1,581	$	166
Accumulated depreciation (in Millions)	$	740	$	88


*		Detroit Edison’s ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St. Clair Power Plants and 75% in common facilities used at Unit No. 2.

Belle River

The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities. The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

Ludington Hydroelectric Pumped Storage

Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant’s operation, maintenance and capital improvement costs.

NOTE 7 — INCOME TAXES

We are part of the consolidated federal income tax return of DTE Energy. The federal income tax expense for Detroit Edison is determined on an individual company basis with no allocation of tax benefits or expenses from other affiliates of DTE Energy.

Total income tax expense varied from the statutory federal income tax rate for the following reasons:


(Dollars in Millions)	2004			2003			2002
Effective federal income tax rate		29.9	%		36.5	%		33.3	%


Income tax expense at 35% statutory rate	$	75		$	139		$	187

Investment tax credits		(7	)		(7	)		(7	)
Depreciation		3			3			3
Employee Stock Ownership Plan dividends		(4	)		(4	)		(3	)
Other, net		(3	)		14			(2	)

Total	$	64		$	145		$	178

Components of income tax expense were as follows:


(in Millions)	2004			2003		2002
Current federal and other income tax expense	$	(78	)	$	109	$	236
Deferred federal and other tax expense (benefit)		142			36		(58	)


Total	$	64		$	145	$	178

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

Deferred income tax assets (liabilities) were comprised of the following at December 31:


(in Millions)	2004			2003
Property	$	(1,147	)	$	(989	)
Securitized regulatory assets		(778	)		(827	)
Pension and benefits		26			43
Other, net		(17	)		(2	)

	$	(1,916	)	$	(1,775	)


Deferred income tax liabilities	$	(2,326	)	$	(2,117	)
Deferred income tax assets		410			342

	$	(1,916	)	$	(1,775	)

The Internal Revenue Service is currently conducting audits of Detroit Edison as a component of the DTE Energy federal income tax returns for the years 1998 through 2001 . The Company accrues tax and interest related to tax uncertainties that arise due to actual or potential disagreements with governmental agencies about the tax treatment of specific items. At December 31, 2004, the Company had accrued approximately $10 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

NOTE 8 — COMMON STOCK

In March 2004, we issued 4,344,492 shares of common stock to DTE Energy.

NOTE 9 — LONG-TERM DEBT AND PREFERRED SECURITIES

Long-Term Debt

Our long-term debt outstanding and weighted average interest rates of debt outstanding at December 31, 2004 was:


(in Millions)	2004			2003
Detroit Edison Taxable Debt, Principally Secured
6.1% due 2005 to 2032	$	1,672		$	1,485

Detroit Edison Tax Exempt Revenue Bonds
5.6% due 2008 to 2032		1,145			1,175
Quarterly Income Debt Securities (QUIDS)
7.5% due 2026 to 2028		385			385
Other Long-Term Debt		74			81

		3,276			3,126
Less amount due within one year		(397	)		(50	)

	$	2,879		$	3,076


Securitization Bonds	$	1,496		$	1,585
Less amount due within one year		(96	)		(89	)

	$	1,400		$	1,496

We issued and optionally redeemed long-term debt consisting of the following:

2005

•		Issued $400 million of senior notes in two series, $200 million of 4.8% series due 2015 and $200 million of 5.45% series due 2035. The proceeds were used to redeem the $385 million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

•		Redeemed $76 million of 7.5% senior notes and $100 million of 7.0% remarketed secured notes, which matured February 2005.

2004

•		Issued $36 million of 4-7/8% tax-exempt bonds due 2029, the proceeds of which were used to redeem $36 million of 6.55% tax-exempt bonds due 2024.

•		Issued $32 million of 4.65% tax-exempt bonds due in 2028, the proceeds of which were used to redeem the following tax-exempt issues: $11.5 million of 6.05% bonds due 2023, $7.5 million of 5.875% bonds due 2024, and $13 million of 6.45% bonds due 2024.

•		Issued $200 million of 5.40% senior notes due in 2014. The proceeds were used to repay short-term borrowings and for general corporate purposes.

2003

•		Issued $49 million of 5.5% tax exempt bonds maturing in 2030.

•		Redeemed $49 million of 6.55% tax-exempt bonds maturing in 2024.

•		Redeemed $314 million of taxable debt with an average interest rate of 7.4% and maturities from 2003-2023.

•		Redeemed $34 million of 6.875% tax-exempt bonds maturing in 2022.

In the years 2005- 2009, our long-term debt maturities are $493 million, $126 million, $135 million, $178 million and $158 million, respectively.

Quarterly Income Debt Securities (QUIDS)

Detroit Edison had three series of QUIDS outstanding at December 31, 2004. Detroit Edison redeemed all of its outstanding QUIDS on March 4, 2005.

Cross Default Provisions

Substantially all of the net utility properties of Detroit Edison are subject to the lien of its mortgage. Should Detroit Edison fail to timely pay its indebtedness under this mortgage, such failure will create cross defaults in the indebtedness of DTE Energy.

Preferred and Preference Securities – Authorized and Unissued

At December 31, 2004, Detroit Edison had approximately 6.75 million shares of preferred stock with a par value of $100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

NOTE 10 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2004, Detroit Edison entered into a $206.25 million, five-year unsecured revolving credit facility and lowered its existing three-year facility from $137.5 million to $68.75 million. The five-year facility replaces the October 2003 364-day facility, which expired. The three-year revolving credit facility expires in October 2006. The five- and three-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity

support for Detroit Edison’s commercial paper program. Borrowings under the facilities will be available at prevailing short-term interest rates. The agreements require Detroit Edison to maintain a debt to total capitalization ratio of no more than .65 to l and “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. Detroit Edison is currently in compliance with these financial covenants.

As of December 31, 2004, we had no outstanding commercial paper.

Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants. We had no balance outstanding under this financing agreement at December 31, 2004.

NOTE 11 — CAPITAL AND OPERATING LEASES

Lessee — We lease various assets under capital and operating leases, including coal cars, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2022.

Future minimum lease payments under non-cancelable leases at December 31, 2004 were:


	Capital			Operating
(in Millions)	Leases			Leases
2005	$	11		$	32
2006		13			31
2007		10			26
2008		11			25
2009		11			23
Thereafter		38			155

Total minimum lease payments		94		$	292

Less imputed interest		(21	)

Present value of net minimum lease payments		73
Less current portion		(7	)

Non-current portion	$	66

Total minimum lease payments for operating leases have not been reduced by future minimum sublease rentals totaling $3 million under non-cancelable subleases expiring at various dates to 2020.

Rental expense for operating leases was $37 million in 2004, $30 million in 2003 and $26 million in 2002.

NOTE 12 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

We comply with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149. Listed below are important SFAS No. 133 requirements:

•		All derivative instruments must be recognized as assets or liabilities and measured at fair value, unless they meet the normal purchases and sales exemption.

•		The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated as a hedge and qualifies for hedge accounting.

•		Special accounting is allowed for a derivative instrument qualifying as a hedge and designated as a hedge for the variability of cash flow associated with a forecasted transaction. Gain or loss associated with the effective portion of the hedge is recorded in other comprehensive income. The ineffective portion is recorded to earnings. Amounts recorded in other comprehensive income will be reclassified to net income when the forecasted transaction affects earnings. If a cash flow hedge is discontinued because it is likely the forecasted transaction will not occur, net gains or losses are immediately recorded to earnings.

•		Special accounting is also allowed for a derivative instrument qualifying as a hedge and designated as a hedge of the changes in fair value of an existing asset, liability or firm commitment. Gain or loss on the hedging instrument is recorded into earnings. An offsetting loss or gain on the underlying asset, liability or firm commitment is also recorded to earnings.

Our primary market risk exposure is associated with commodity prices and credit. We have risk management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure. We do not hold or issue derivative instruments for trading purposes.

Commodity Price Risk

Detroit Edison uses forward energy, capacity, and futures contracts to manage changes in the price of electricity and fuel. These derivatives are designated as cash flow hedges or meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. There were no commodity price risk cash flow hedges at December 31, 2004. Our commodity price risk is limited due to the PSCR mechanism (Note 1).

Credit Risk

We are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. We use standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty.

Fair Value of Other Financial Instruments

The fair value of financial instruments is determined by using various market data and other valuation techniques. The table below shows the fair value relative to the carrying value for long-term debt securities. The carrying value of certain other financial instruments, such as notes payable, customer deposits and notes receivable approximate fair value and are not shown.

2004

2003

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$5.1 billion

$4.8 billion

$5.1 billion

$4.7 billion

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Environmental

Air - The EPA issued ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution. The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, carbon dioxide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $580 million through December 2004, and estimates that it will spend up to $100 million in 2005 and incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy both the existing and proposed new control requirements. Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure, in excess of current depreciation levels, could be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end on December 31, 2005 upon MPSC authorization. Under PA 141 and the MPSC’s November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

Water - Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the intakes. It is estimated that we will incur up to $50 million over the next five to seven years in additional capital expenditures for Detroit Edison.

Contaminated Sites - Detroit Edison conducted remedial investigations at contaminated sites, including two former manufactured gas plant sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

Personal Property Taxes

Prior to 1999, Detroit Edison and other Michigan utilities asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002, issued its decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. Detroit Edison has filed motions and the MTT agreed to place the cases in abeyance pending the conclusion of settlement negotiations being conducted by State of Michigan Treasury officials. On February 14, 2005, MTT issued a scheduling order that lifts the prior abeyances in a significant number of Detroit Edison appeals. The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison continues to record property tax expense based on the new tables. Detroit Edison will continue through settlement or litigation to seek to apply the new tables retroactively and to ultimately

resolve the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. To the extent that settlements cannot be achieved with the jurisdictions, litigation regarding the valuation of utility property will delay any recoveries by Detroit Edison.

Other Commitments

Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a special charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments is being amortized to fuel and purchased power expense with non-cash accretion expense being recorded through 2008. We purchased $42 million of steam and electricity in 2004, $39 million in 2003 and $37 million in 2002. We estimate steam and electric purchase commitments through 2024 will not exceed $472 million. As discussed in Note 3 – Dispositions, in January 2003, we sold our steam heating business to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

At December 31, 2004, we have entered into numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments. We estimate that these commitments will be approximately $1.4 billion through 2018. We also estimate that 2005 base level capital expenditures will be $800 million. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

We purchase and sell electricity from and to numerous companies operating in the steel, automotive, energy and retail industries. Several customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of loss. We believe our previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

Other

We are involved in certain legal, regulatory, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

See Note 4 and Note 5 for a discussion of contingencies related to Regulatory Matters and Nuclear Operations.

NOTE 14 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Measurement Date

In the fourth quarter of 2004, we changed the date for actuarial measurement of our obligations for benefit programs from December 31 to November 30. We believe the one-month change of the measurement date is a preferable change as it allows time for management to plan and execute its review of the completeness and accuracy of its benefit programs results and to fully reflect the impact on its financial results. The change did not have a material effect on retained earnings as of January 1, 2004, and net income amounts for any interim period in 2004. Accordingly, all amounts reported in the following tables for balances as of December 31, 2004 are based on a measurement date of November 30, 2004. Amounts reported in tables for the year ended December 31, 2004 and for balances as of December 31, 2003 are based on a measurement date of December 31, 2003. Amounts reported in tables for the year ended December 31, 2003 are based on a measurement date of December 31, 2002.

Qualified and Nonqualified Pension Plan Benefits

Detroit Edison has a defined benefit retirement plan. The plan is noncontributory, covers substantially all employees and provides retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. Certain represented and nonrepresented employees are covered under cash balance benefits based on annual employer contributions and interest credits. Detroit Edison operates as the sponsor of the plan, which is treated as a plan covering employees of various affiliates of DTE Energy Company. The annual expense disclosed below is Detroit Edison’s portion of the total plan expense. Each affiliate is charged their portion of the expense. Our policy is to fund pension costs by contributing the minimum amount required by the Employee Retirement Income Security Act (ERISA) and additional amounts we deem appropriate. We do not anticipate making a contribution to our qualified pension plan in 2005.

We also maintain supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. These plans provide for benefits that supplement those provided by Detroit Edison’s other retirement plans.

Net pension cost includes the following components:


	Qualified Pension Plans									Nonqualified Pension Plans
(in Millions)	2004			2003			2002			2004		2003		2002
Service Cost	$	47		$	40		$	35		$	1	$	1	$	1
Interest Cost		130			127			124			2		2		2
Expected Return on Plan Assets		(135	)		(129	)		(133	)		—		—		—
Amortization of
Net loss		49			32			2			1		1		1
Prior service cost		9			9			9			—		—		—
Net transition asset		—			—			(1	)		—		—		—

Net Pension Cost	$	100		$	79		$	36		$	4	$	4	$	4

The following table reconciles the obligations, assets and funded status of the plan as well as the amount recognized as pension liability in the consolidated statement of financial position at December 31. The results include liabilities and assets for Detroit Edison and all affiliates participating in the combined plan. The prepaid asset contributed to the combined plan by such affiliates is reflected as an amount due to affiliates, $247 million and $219 million at December 31, 2004 and 2003, respectively.


	Qualified Pension Plans						Nonqualified Pension Plans
(in Millions)	2004			2003			2004			2003
Measurement Date	November 30			December 31			November 30			December 31
Accumulated Benefit Obligation-End of Period	$	2,447		$	2,316		$	34		$	34


Projected Benefit Obligation-Beginning of Period	$	2,498		$	2,287		$	36		$	31
Service Cost		53			44			1			1
Interest Cost		153			150			2			2
Actuarial Loss (Gain)		69			166			(1	)		4
Benefits Paid		(136	)		(145	)		(2	)		(2	)
Plan Amendments		6			(4	)		—			—

Projected Benefit Obligation-End of Period	$	2,643		$	2,498		$	36		$	36


Plan Assets at Fair Value-Beginning of Period	$	2,029		$	1,572		$	—		$	-
Actual Return on Plan Assets		172			380			—			-
Company Contributions		170			222			2			2
Benefits Paid		(136	)		(145	)		(2	)		(2	)

Plan Assets at Fair Value-End of Period	$	2,235		$	2,029		$	—		$	-


Funded Status of the Plans	$	(408	)	$	(469	)	$	(36	)	$	(36	)
Unrecognized
Net loss		790			753			11			13
Prior service cost		41			41			2			3
Net transition assets		(1	)		—			—			—

Net Amount Recognized-End of Period	$	422		$	325		$	(23	)	$	(20	)


Amount Recorded as
Accrued pension liability	$	(212	)	$	(288	)	$	(35	)	$	(33	)
Regulatory asset		594			572			10			11
Intangible asset		40			41			2			2

	$	422		$	325		$	(23	)	$	(20	)

Assumptions used in determining the projected benefit obligation and net pension costs are listed below:


	2004			2003			2002
Projected Benefit Obligation
Discount rate		6.00	%		6.25	%		6.75	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%

Net Pension Costs
Discount rate		6.25	%		6.75	%		7.25	%
Annual increase in future compensation levels		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on Plan assets		9.0	%		9.0	%		9.5	%

At December 31, 2004, the benefits related to our qualified and nonqualified plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:


(in Millions)
2005	$	156
2006		160
2007		165
2008		170
2009		175
2010 - 2014		981

Total	$	1,807

We employ a consistent formal process in determining the long-term rate of return for various asset classes. We evaluate input from our consultants, including their review of historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness .

We employ a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return of plan assets consistent with prudent levels of risk. The intent of this strategy is to minimize plan expenses over the long-term. Risk tolerance is established through consideration of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, growth and value investment styles, and large and small market capitalizations. Other assets such as private equity and absolute return funds are used judiciously to enhance long term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.

Our plans’ weighted-average asset allocations by asset category at December 31 were as follows:


	2004			2003
Equity Securities		69	%		67	%
Debt Securities		26			27
Other		5			6

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2004 were as follows:


Equity Securities	65	%
Debt Securities	28
Other	7

	100	%

In December 2002, we recognized an additional minimum pension liability as required under SFAS No. 87, “Employers’ Accounting for Pensions.” An additional pension liability may be required when the accumulated benefit obligation of the plan exceeds the fair value of plan assets. Under SFAS No. 87, we recorded an additional minimum pension liability, an intangible asset and other comprehensive loss. In 2003, we reclassified $572 million of other comprehensive loss related to the minimum pension liability to a regulatory asset after the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. The additional minimum pension liability, regulatory asset and intangible asset are adjusted in December of each year based on the plans’ funded status.

We also sponsor defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and nonrepresented employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of these plans was $22 million in 2004, $21 million in 2003 and $20 million in 2002.

Other Postretirement Benefits

We provide certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. Our policy is to fund certain trusts to meet our postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and nonrepresented employees.

Net postretirement cost includes the following components:


(in Millions)	2004			2003			2002
Service Cost	$	33		$	31		$	25
Interest Cost		69			66			59
Expected Return on Plan Assets		(45	)		(36	)		(44	)
Amortization of
Net loss		33			23			2
Net transition obligation		8			13			19

Net Postretirement Cost	$	98		$	97		$	61

The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the consolidated statement of financial position at December 31:


(in Millions)	2004			2003
Measurement Date	November 30			December 31
Accumulated Postretirement Benefit Obligation-Beginning of Period	$	1,192		$	1,131
Service Cost		33			31
Interest Cost		69			66
Actuarial Loss		106			122
Plan Amendments		21			(106	)
Benefits Paid		(60	)		(52	)

Accumulated Postretirement Benefit Obligation-End of Period	$	1,361		$	1,192


Plan Assets at Fair Value-Beginning of Period	$	468		$	425
Actual Return on Plan Assets		43			91
Company Contributions		40			—
Benefits Paid		—			(48	)

Plan Assets at Fair Value-End of Period	$	551		$	468


Funded Status of the Plans	$	(810	)	$	(724	)
Unrecognized
Net loss		594			518
Prior service cost		30			1
Net transition obligation		58			74

Accrued Postretirement Liability at Measurement Date		(128	)		(131	)
Company Contribution And Benefit Payments in December 2004		(14	)		—

Accrued Postretirement Liability-End of Period	$	(142	)	$	(131	)

Assumptions used in determining the projected benefit obligation and net benefit costs are listed below:


	2004			2003			2002
Projected Benefit Obligation
Discount rate		6.00	%		6.25	%		6.75	%

Net Benefit Costs
Discount rate		6.25	%		6.75	%		7.25	%
Expected long-term rate of return on Plan assets.		9.0	%		9.0	%		9.5	%

Benefit costs were calculated assuming health care cost trend rates beginning at 9.0% for 2005 and decreasing to 5.0% in 2010 and thereafter for persons under age 65 and decreasing from 8.0% to 5.0% for persons age 65 and over. A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $15 million and increased the accumulated benefit obligation by $128 million at December 31, 2004. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by $13 million and would have decreased the accumulated benefit obligation by $114 million at December 31, 2004.

Effective 2005, we amended our postretirement health care plan to provide for some enhancements. The changes increased our expected 2005 postretirement cost by $6 million.

At December 31, 2004, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:


(in Millions)
2005	$	74
2006		81
2007		84
2008		87
2009		92
2010 - 2014		504

Total	$	922

The process used in determining the long-term rate of return for assets and the investment approach for our other postretirement benefits plan is similar to those previously described for our qualified pension plans.

Our plans’ weighted-average asset allocations by asset category at December 31 were as follows:


	2004			2003
Equity Securities		68	%		65	%
Debt Securities		28			30
Other		4			5

		100	%		100	%

Our plans’ weighted-average asset target allocations by asset category at December 31, 2004 were as follows:


Equity Securities	65	%
Debt Securities	28
Other	7

	100	%

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the benefit established by law. As discussed in Note 2, we adopted FSP No. 106-2 in 2004, which provides guidance on the accounting for the Medicare Act. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $70 million at January 1, 2004 and was accounted for as an actuarial gain. The effects of the subsidy reduced net periodic postretirement benefit costs by $12 million in 2004. The impact of the Medicare Act on the components of other postretirement benefit costs for the year ended December 31 was as follows:


(in Millions)	2004
Reduction in service cost	$	2
Reduction in interest cost		4
Amortization of actuarial gain		6

Decrease in postretirement benefit cost	$	12

At December 31, 2004, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:


(in Millions)
2005	$	-
2006		9
2007		9
2008		10
2009		10
2010 - 2014		53

Total	$	91

NOTE 15 — RELATED PARTY TRANSACTIONS

We have transactions with affiliated companies to sell energy for resale, provide fuel supply services and power plant operation and maintenance services for the delivery of electric energy. Under a service agreement with DTE Energy, various DTE Energy affiliates, including Detroit Edison provide corporate support functions consisting of financial, auditing, tax, legal, treasury, cash management, human resources, information technology, regulatory and other services, which are billed to DTE Energy corporate. As these functions essentially support the entire DTE Energy Company, their costs are fully allocated to the various DTE Energy affiliates based on services utilized. The net of these billings included in the consolidated statement of operations was income of $19 million in 2004 and $18 million in 2003, and expenses of $7 million in 2002.

In addition, we had intercompany revenue, primarily from the sale of energy to affiliates, of $255 million, $71 million and $108 million in 2004, 2003 and 2002, respectively. We had intercompany expenses, primarily for purchased power, of $66 million, $45 million and $100 million in 2004, 2003 and 2002, respectively.

Our accounts receivable from affiliated companies totaled $29 million and $34 million at December 31, 2004 and 2003, respectively. Our accounts payable to affiliated companies totaled $56 million and $67 million at December 31, 2004 and 2003, respectively.

We had a short-term note receivable from DTE Energy of $85 million and $7 million at December 31, 2004 and 2003, respectively. This note is subject to a credit agreement with DTE Energy whereby short-term excess cash or cash shortfalls are remitted to or funded by DTE Energy. This credit arrangement involves the charge and payment of interest at market-based rates.

We declared dividends to DTE Energy of $305 million in 2004, $295 million in 2003 and $296 million in 2002. We paid dividends to DTE Energy of $303 million in 2004 and $295 million in 2003 and 2002. We received a $470 million capital contribution from DTE Energy in 2003. We issued 4,344,492 shares

of our common stock to DTE Energy and in return DTE Energy contributed 4,344,492 shares of its common stock, valued at $170 million, to our defined benefit retirement plan.

NOTE 16 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	First		Second		Third		Fourth
(in Millions)	Quarter (1)		Quarter		Quarter		Quarter		Year
2004
Operating Revenues	$	886	$	835	$	958	$	889	$	3,568
Operating Income	$	145	$	92	$	169	$	111	$	517
Net Income	$	44	$	8	$	62	$	36	$	150

2003
Operating Revenues	$	937	$	870	$	1,017	$	871	$	3,695
Operating Income	$	116	$	112	$	219	$	227	$	674
Net Income	$	15	$	30	$	96	$	105	$	246


(1)		Previously reported first quarter 2004 amounts have been adjusted to reflect the retroactive adoption of FSP No. 106-2, relating to the impact of the Medicare Act on postretirement benefit costs (Note 2).


Note		Title

2		New Accounting Pronouncements
4		Regulatory Matters
7		Income Taxes
12		Financial and Other Derivative Instruments
14		Retirement Benefits and Trusteed Assets


	Year Ending December 31,
(in Millions)	2004			2003			2002
Allowance for Doubtful Accounts (shown as Deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period	$	51		$	48		$	27
Additions:
Charged to costs and expenses		45			39			24
Charged to other accounts (1)		5			3			9
Deductions (2)		(46	)		(39	)		(12	)

Balance At End of Period	$	55		$	51		$	48


(1)		Collection of accounts previously written off.

(2)		Non-collectible accounts written off.