DTE Energy 8K Other Events | DTE 4 Aug 05

Exhibit 99.4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of DTE Energy Company:

We have audited the consolidated statement of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows, and changes in shareholders’ 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 consolidated 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy 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 certain new accounting principles, in 2003 the Company changed its method of accounting for asset retirement obligations, energy trading contracts and gas inventories and in 2002 the Company changed its method of accounting for goodwill and energy trading contracts.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
March 15, 2005 (August 4, 2005 as to Note 16)

DTE Energy Company

Consolidated Statement of Operations


	Year Ended December 31
	2004			2003			2002
(in Millions, Except per Share Amounts)
Operating Revenues	$	7,114		$	7,041		$	6,729


Operating Expenses
Fuel, purchased power and gas		2,007			2,241			2,099
Operation and maintenance		3,420			3,109			2,589
Depreciation, depletion and amortization		744			687			737
Taxes other than income		312			334			352
Asset gains and losses, net		(215	)		(77	)		(42	)

		6,268			6,294			5,735


Operating Income		846			747			994


Other (Income) and Deductions
Interest expense		518			546			569
Interest income		(55	)		(37	)		(29	)
Other income		(80	)		(110	)		(45	)
Other expenses		67			82			34

		450			481			529


Income Before Income Taxes and Minority Interest		396			266			465

Income Tax Provision (Benefit) (Note 7)		165			(123	)		(84	)

Minority Interest		(212	)		(91	)		(37	)


Income from Continuing Operations		443			480			586

Income (Loss) from Discontinued Operations, net of tax (Note 3)		(12	)		68			46

Cumulative Effect of Accounting Changes, net of tax (Note 2)		—			(27	)		—


Net Income	$	431		$	521		$	632


Basic Earnings per Common Share (Note 8)
Income from continuing operations	$	2.56		$	2.87		$	3.57
Discontinued operations		(.06	)		.41			.28
Cumulative effect of accounting changes		—			(.17	)		—

Total	$	2.50		$	3.11		$	3.85


Diluted Earnings per Common Share (Note 8)
Income from continuing operations	$	2.55		$	2.85		$	3.55
Discontinued operations		(.06	)		.40			.28
Cumulative effect of accounting changes		—			(.16	)		—

Total	$	2.49		$	3.09		$	3.83


Average Common Shares
Basic		173			168			164
Diluted		173			168			165

Dividends Declared per Common Share	$	2.06		$	2.06		$	2.06

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Financial Position


	December 31
	2004			2003
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	56		$	54
Restricted cash (Note 1)		126			131
Accounts receivable
Customer (less allowance for doubtful accounts of $129 and $99, respectively)		880			877
Accrued unbilled revenues		378			316
Other		383			338
Inventories
Fuel and gas		509			467
Materials and supplies		159			162
Assets from risk management and trading activities		296			186
Other		209			181

		2,996			2,712


Investments
Nuclear decommissioning trust funds		590			518
Other		558			601

		1,148			1,119


Property
Property, plant and equipment		18,011			17,679
Less accumulated depreciation and depletion (Note 2)		(7,520	)		(7,355	)

		10,491			10,324


Other Assets
Goodwill (Note 3)		2,067			2,067
Regulatory assets (Note 4)		2,119			2,063
Securitized regulatory assets (Note 4)		1,438			1,527
Notes receivable		529			469
Assets from risk management and trading activities		125			88
Prepaid pension assets		184			181
Other		200			203

		6,662			6,598


Total Assets	$	21,297		$	20,753

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Financial Position


	December 31
	2004			2003
(in Millions, Except Shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	892		$	625
Accrued interest		111			110
Dividends payable		90			87
Accrued payroll		33			51
Income taxes		16			185
Short-term borrowings		403			370
Current portion long-term debt, including capital leases		514			477
Liabilities from risk management and trading activities		369			326
Other		581			593

		3,009			2,824


Other Liabilities
Deferred income taxes		1,124			988
Regulatory liabilities (Notes 2 and 4)		817			817
Asset retirement obligations (Note 2)		916			866
Unamortized investment tax credit		143			156
Liabilities from risk management and trading activities		224			173
Liabilities from transportation and storage contracts		387			495
Accrued pension liability		265			345
Deferred gains from asset sales		414			311
Minority interest		132			156
Nuclear decommissioning (Notes 2 and 5)		77			67
Other		635			599

		5,134			4,973


Long-Term Debt (net of current portion) (Note 9)
Mortgage bonds, notes and other		5,673			5,624
Securitization bonds		1,400			1,496
Equity-linked securities		178			185
Trust preferred-linked securities		289			289
Capital lease obligations		66			75

		7,606			7,669


Commitments and Contingencies (Notes 4, 5 and 13)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized,174,209,034 and 168,606,522 shares issued and outstanding, respectively		3,323			3,109
Retained earnings		2,383			2,308
Accumulated other comprehensive loss		(158	)		(130	)

		5,548			5,287


Total Liabilities and Shareholders’ Equity	$	21,297		$	20,753

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Cash Flows


	Year Ended December 31
	2004			2003			2002
(in Millions)
Operating Activities
Net income	$	431		$	521		$	632
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		744			691			759
Deferred income taxes		129			(220	)		(208	)
Gain on sale of interests in synfuel projects		(219	)		(83	)		(40	)
Gain on sale of ITC and other assets, net		(17	)		(145	)		—
Partners’ share of synfuel project losses		(223	)		(78	)		(40	)
Contributions from synfuel partners		141			65			22
Cumulative effect of accounting changes		—			27			—
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		9			172			(129	)

Net cash from operating activities		995			950			996


Investing Activities
Plant and equipment expenditures – utility		(815	)		(679	)		(794	)
Plant and equipment expenditures – non-utility		(89	)		(72	)		(190	)
Investment in joint ventures		(36	)		(34	)		(21	)
Proceeds from sale of interests in synfuel projects		221			89			32
Proceeds from sale of ITC and other assets		104			669			9
Restricted cash for debt redemptions		5			106			(79	)
Other investments		(71	)		(69	)		(72	)

Net cash from (used for) investing activities		(681	)		10			(1,115	)


Financing Activities
Issuance of long-term debt		736			527			1,138
Redemption of long-term debt		(759	)		(1,208	)		(793	)
Short-term borrowings, net		33			(44	)		(267	)
Issuance of common stock		41			44			265
Dividends on common stock		(354	)		(346	)		(338	)
Other		(9	)		(12	)		(21	)

Net cash used for financing activities		(312	)		(1,039	)		(16	)

Net Increase (Decrease) in Cash and Cash Equivalents		2			(79	)		(135	)
Cash and Cash Equivalents at Beginning of Period		54			133			268

Cash and Cash Equivalents at End of Period	$	56		$	54		$	133

See Notes to Consolidated Financial Statements

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity and
Comprehensive Income


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

Balance, December 31, 2001		161,134		$	2,811		$	1,846		$	(68	)	$	4,589

Net income		—			—			632			—			632
Issuance of new shares		6,426			270			—			—			270
Dividends declared on common stock		—			—			(341	)		—			(341	)
Repurchase and retirement of common stock		(98	)		(1	)		(2	)		—			(3	)
Pension obligations (Note 14)		—			—			—			(518	)		(518	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(33	)		(33	)
Unearned stock compensation and other		—			(28	)		(3	)		—			(31	)

Balance, December 31, 2002		167,462			3,052			2,132			(619	)		4,565

Net income		—			—			521			—			521
Issuance of new shares		1,225			57			—			—			57
Dividends declared on common stock		—			—			(348	)		—			(348	)
Repurchase and retirement of common stock		(80	)		(1	)		—			—			(1	)
Pension obligations (Note 14)		—			—			—			420			420
Net change in unrealized losses on derivatives, net of tax		—			—			—			17			17
Net change in unrealized gains on investments, net of tax		—			—			—			52			52
Unearned stock compensation and other		—			1			3			—			4

Balance, December 31, 2003		168,607			3,109			2,308			(130	)		5,287

Net income		—			—			431			—			431
Issuance of new shares		5,671			223			—			—			223
Dividends declared on common stock		—			—			(357	)		—			(357	)
Repurchase and retirement of common stock		(69	)		(3	)		—			—			(3	)
Pension obligations (Note 14)		—			—			—			7			7
Net change in unrealized losses on derivatives, net of tax		—			—			—			(15	)		(15	)
Net change in unrealized losses on investments, net of tax		—			—			—			(20	)		(20	)
Unearned stock compensation and other		—			(6	)		1			—			(5	)

Balance, December 31, 2004		174,209		$	3,323		$	2,383		$	(158	)	$	5,548

The following table displays comprehensive income (loss):


	2004			2003		2002
(in Millions)
Net income	$	431		$	521	$	632

Other comprehensive income (loss), net of tax:
Pension obligations, net of taxes of $(4), $(226) and $280 (Notes 4 and 14)		7			420		(518	)

Net unrealized losses on derivatives:
Gains (losses) arising during the period, net of taxes of $26, $(8) and $32		(49	)		16		(60	)
Amounts reclassified to earnings, net of taxes of $(18), $- and $(15)		34			1		27

		(15	)		17		(33	)

Net unrealized gains (losses) on investments:
Gains (losses) arising during the period, net of taxes of $3, $(28) and $-.		(5	)		52		—
Amounts reclassified to earnings, net of taxes of $8, $- and $-		(15	)		—		—

		(20	)		52		—

Comprehensive income	$	403		$	1,010	$	81

See Notes to Consolidated Financial Statements

DTE Energy Company

Notes to Consolidated Financial Statements

NOTE 1 — SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

DTE Energy is an exempt holding company under the Public Utility Holding Company Act of 1935 and owns the following businesses:

	•		The Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeast Michigan;

	•		Michigan Consolidated Gas Company (MichCon), a natural gas utility engaged in the purchase, storage, transmission and distribution and sale of natural gas to 1.2 million customers throughout Michigan; and

	•		Other non-utility subsidiaries engaged in energy marketing and trading, energy services and various other electricity, coal and gas related businesses.

Detroit Edison and MichCon are regulated by the Michigan Public Service Commission (MPSC). The Federal Energy Regulatory Commission (FERC) regulates certain activities of Detroit Edison’s business as well as various other aspects of businesses under DTE Energy. In addition, we are regulated by other federal and state regulatory agencies including the Nuclear Regulatory Commission (NRC) and the Environmental Protection Agency, among others.

References in this report to “we,” “us,” “our” or “Company” are to DTE Energy and its subsidiaries, collectively.

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. We eliminate all intercompany balances and transactions.

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 and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

Prior to December 2004, DTE Energy did not eliminate amounts, principally within Other Income and Other Deductions, resulting from certain intercompany transactions. The amounts of the transactions are immaterial and had no effect on net income. Previously reported prior period amounts have been adjusted to eliminate those intercompany transactions and are now consistent with the current year’s presentation.

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

Revenues

Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electric and gas 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. MichCon’s accrued revenues include a component for the cost of gas sold that is recoverable through the Gas Cost Recovery (GCR) mechanism. Annual PSCR and GCR proceedings before the MPSC permit Detroit Edison and MichCon 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.

Non-utility businesses recognize revenues as services are provided and products are delivered. Our Fuel Transportation and Marketing segment records in revenues net unrealized derivative gains and losses on energy trading contracts, including those to be physically settled.

Gains from Sale of Interests in Synthetic Fuel Facilities

Through December 2004, we have sold majority interests in eight of our nine synthetic fuel production plants, representing approximately 92% of our total production capacity. Proceeds from the sales are contingent upon production levels and the value of Section 29 tax credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13 for further discussion. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. We have recorded gains from the sale of interests in synthetic fuel facilities totaling $219 million, $83 million and $40 million during 2004, 2003 and 2002, respectively.

Until the gain recognition criteria are met, gains from selling interests in synfuel facilities will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year.

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 (OCI) 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;” unrealized gains and losses on available for sale securities under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities;” and, minimum pension liabilities as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions.”


	Minimum			Net			Net			Accumulated
	Pension			Unrealized			Unrealized			Other
	Liability			Losses on			Gains on			Comprehensive
	Adjustment			Derivatives			Investments			Loss
(in Millions)
Beginning balance	$	(98	)	$	(85	)	$	53		$	(130	)
Current-period change		7			(15	)		(20	)		(28	)

Ending balance	$	(91	)	$	(100	)	$	33		$	(158	)

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 and partnership operating 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.

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2004, the replacement cost of gas remaining in storage exceeded the $89 million LIFO cost by $330 million. At December 31, 2003, the replacement cost of gas remaining in storage exceeded the $117 million LIFO cost by $251 million. During 2004, MichCon liquidated 5.7 billion cubic feet of prior years’ LIFO layers. The liquidation benefited 2004 cost of gas by approximately $7 million, but had no impact on earnings as a result of the GCR mechanism.

Our Fuel Transportation and Marketing segment uses the average cost method for its gas in inventory.

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:


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

Total Electric Utility		12,931			12,671


Gas Utility
Distribution		2,020			1,961
Storage		221			224
Other		883			855

Total Gas Utility		3,124			3,040



Other Non-utility and Other		1,956			1,968

Total Property, Plant and Equipment		18,011			17,679


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

Total Electric Utility		(5,354	)		(5,339	)


Gas Utility
Distribution		(845	)		(798	)
Storage		(100	)		(102	)
Other		(448	)		(432	)

Total Gas Utility		(1,393	)		(1,332	)


Other Non-utility and Other		(773	)		(684	)

Total Accumulated Depreciation and Depletion		(7,520	)		(7,355	)

Net Property, Plant and Equipment	$	10,491		$	10,324

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, at Detroit Edison and MichCon 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 at Detroit Edison and MichCon on straight-line and units of production rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.4% in 2004, 2003 and 2002. The composite depreciation rate for MichCon was 3.6%, 3.5%, and 3.6% in 2004, 2003 and 2002, respectively.

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

Estimated Useful Lives in Years

Utility

Generation

Distribution

Transmission

Electric

—

Gas

N/A

Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods.

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

Gas Production

We follow the successful efforts method of accounting for investments in gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets

Our long-lived assets 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 $43 million in 2004, $40 million in 2003 and $46 million in 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $445 million and $151 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were $537 million and $303 million, respectively. Amortization expense of intangible assets is estimated to be $40 million annually for 2005 through 2009.

Excise and Sales Taxes

We record the billing of excise and sales taxes as receivable with an offsetting payable to the applicable taxing authority, with no impact on the consolidated 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 our electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.

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 directors’ 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.

Stock-Based Compensation

We have a stock-based employee compensation plan, which is described in Note 15. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation cost related to stock options is reflected in earnings, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. The recognition provisions under SFAS No. 123, “Accounting for Stock-Based Compensation,” require the recording of compensation expense for stock options equal to their fair value at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and earnings per share if we had recorded compensation expense for options granted under the fair value recognition provisions of SFAS No. 123.


	2004			2003			2002
(in Millions, except per share amounts)
Net Income as Reported	$	431		$	521		$	632
Less: Total Stock-based Expense (1)		(6	)		(7	)		(7	)

Pro Forma Net Income	$	425		$	514		$	625


Income Per Share
Basic – as reported	$	2.50		$	3.11		$	3.85

Basic – pro forma	$	2.46		$	3.06		$	3.81


Diluted – as reported	$	2.49		$	3.09		$	3.83

Diluted – pro forma	$	2.45		$	3.05		$	3.79


(1)		Expense determined using a Black-Scholes based option pricing model.

Investments in Debt and Equity Securities

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

Investment in Plug Power

In 1997, we invested in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. Since Plug Power is considered a development stage company, generally accepted accounting principles required us to record gains and losses from Plug Power stock issuances as an adjustment to equity. Prior to November 2003, we accounted for our investment in Plug Power under the equity method of accounting. We did not participate in Plug Power’s secondary stock offering in November 2003 and as of December 31, 2003 we owned 14.1 million shares or approximately 19% of Plug Power’s common stock. We have determined that we do not have the ability to exercise significant influence over the operating or financial policies of Plug Power. Accordingly, we began prospective application of the cost method of accounting for our investment in Plug Power, effective November 2003. We record our investment at market value and account for unrealized gains and losses in other comprehensive income or loss. In May 2004, we sold 3.5 million shares of Plug Power stock and recorded a gain of approximately $14 million, net of taxes. The sale reduced our ownership interest in Plug Power to 10.6 million shares, or approximately 14%.

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:


	2004			2003			2002
(in Millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	73		$	(50	)	$	(129	)
Accrued unbilled receivable		(62	)		(20	)		(54	)
Accrued GCR revenue		(35	)		29			(5	)
Inventories		(40	)		(61	)		(71	)
Accrued/Prepaid Pensions		88			(196	)		(10	)
Accounts payable		266			(21	)		66
Accrued PSCR refund		112			—			—
Exchange gas payable		(43	)		90			9
Income taxes payable		(170	)		135			(8	)
General taxes		(14	)		(12	)		(36	)
Risk management and trading activities		(64	)		127			69
Postretirement obligation		29			112			77
Other		(131	)		39			(37	)

	$	9		$	172		$	(129	)

Supplementary cash and non-cash information for the years ended December 31 were as follows:


	2004		2003		2002
(in Millions)
Cash Paid for
Interest (excluding interest capitalized)	$	517	$	552	$	551
Income taxes	$	203	$	31	$	167
Noncash Investing and Financing Activities
Notes received from sale of synfuel projects	$	214	$	238	$	217
Common stock contributed to pension plan	$	170	$	—	$	—
Exchange of debt	$	—	$	100	$	—
Issuance of equity-linked securities	$	—	$	—	$	21

See the following notes for other accounting policies impacting our financial statements:


Note		Title

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

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Energy Trading Activities

Under Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” companies were required to use mark-to-market accounting for contracts utilized in energy trading activities. EITF Issue No. 98-10 was rescinded in October 2002, and energy trading contracts must now be reviewed to determine if they meet the definition of a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities measured at their fair value. SFAS No. 133 also requires that changes in the fair value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts. Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, transparent prices can be obtained. Unrealized gains and losses are fully reserved for transactions that do not meet this criteria.

Additionally, inventory utilized in energy trading activities accounted for under the fair value method of accounting as prescribed by Accounting Research Bulletin (ARB) No. 43 is no longer permitted. Our Fuel Transportation and Marketin segment uses gas inventory in its trading operations and switched from the fair value method to the average cost method in January 2003.

Effective January 1, 2003, we no longer applied EITF Issue No. 98-10 to energy contracts and ARB No. 43 to gas inventory. As a result of discontinuing the application of these accounting principles, we recorded a cumulative effect of accounting change that reduced net income for the first quarter of 2003 by $16 million (net of taxes of $9 million).

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. To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to utility operations, 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 $306 million with offsetting accumulated depreciation of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 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 $11 million (net of tax of $7 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 pro forma effect on earnings had SFAS No. 143 been adopted for all periods presented would decrease reported net income and basic and diluted earnings per share as follows:


	(in Millions)
	Net		Basic and Diluted
Year	Income		Earnings per Share
2002	$	4.8	$	.03

A reconciliation of the asset retirement obligation for 2004 follows:


(in Millions)
Asset retirement obligations at January 1, 2004	$	866
Accretion		57
Liabilities settled		(5	)
Revisions in estimated cash flows		(2	)

Asset retirement obligations at December 31, 2004	$	916

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 $655 million of previously accrued asset removal costs related to our utility operations, 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 $95 million and was accounted for as an actuarial gain. The effects of the subsidy reduced net postretirement costs by $16 million in 2004.

Stock Based Payments

In December 2004, the FASB issued SFAS No. 123-R, “Stock Based Payments,” which establishes the accounting for transactions in which an entity exchanges equity instruments for goods or services. Application of SFAS No. 123-R is required for interim or annual periods beginning after June 15, 2005 with earlier adoption encouraged. We have completed a preliminary review and estimate that the new standard will reduce reported earnings by approximately $5 million to $10 million per year.

Goodwill and Other Intangible Assets

Effective January 1, 2002, we adopted SFAS No. 142,“Goodwill and Other Intangible Assets,” which addresses the financial accounting and reporting standards for the acquisition of intangible assets outside of a business combination and for goodwill and other intangible assets subsequent to their acquisition. This accounting standard requires that goodwill no longer be amortized, but reviewed at least annually for impairment. In accordance with SFAS No. 142, we discontinued the amortization of goodwill effective January 1, 2002.

NOTE 3 – DISPOSITIONS

International Transmission Company – Discontinued Operation

In February 2003, we sold International Transmission Company (ITC), our electric transmission business, for $610 million to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. The sale generated a preliminary net of tax gain of $63 million in 2003. The gain was net of transaction costs, the portion of the gain that was refundable to customers and the write off of approximately $44 million of allocated goodwill. The gain was lowered to $58 million in 2004 under the MPSC’s November 2004 final rate order that resulted in a revision of the applicable transaction costs and customer refund.

As prescribed by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reported the operations of ITC as a discontinued operation as shown in the following table:


	2003(3)		2002
(in Millions)
Revenues(1)	$	21	$	138
Expenses(2)		13		67

Operating income		8		71
Income taxes		3		25

Income from discontinued operations	$	5	$	46


(1)		Includes intercompany revenues of $18 million for 2003 and $118 million for 2002.

(2)		Excludes general corporate overhead costs that were previously allocated to ITC in 2003 and 2002.

(3)		Represents activity from January 1, 2003 through February 28, 2003, when ITC was sold.

Detroit Edison’s Steam Heating Business

In January 2003, we sold Detroit Edison’s steam heating business to Thermal Ventures II, LP. Due to the continuing involvement of Detroit Edison 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 Detroit Edison’s 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.

Southern Missouri Gas Company – Discontinued Operation

We own Southern Missouri Gas Company (SMGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the SFAS No. 144 criteria of an asset “held for sale,” and we have reported its operating results as a discontinued operation. We recognized a net of tax impairment loss of approximately $7 million in 2004, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Following receipt of regulatory approvals and resolution of other contingencies, it is anticipated that the transaction will close in 2005. SMGC had assets of $9 million and liabilities of $35 million at December 31, 2004.

NOTE 4 — REGULATORY MATTERS

Regulation

Detroit Edison and MichCon are 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 and MichCon apply the provisions of SFAS No. 71,“Accounting for the Effects of Certain Types of Regulation,”to their regulated 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 utility businesses 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 to Detroit Edison and MichCon.

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


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


Recoverable income taxes related to securitized regulatory assets	$	788		$	837
Recoverable minimum pension liability		605			585
Asset retirement obligation		183			192
Other recoverable income taxes		109			114
Recoverable costs under PA 141
Net stranded costs		122			68
Excess capital expenditures		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		63			60
Deferred environmental costs		31			29
Accrued GCR revenue		55			19
Other		5			3

		2,174			2,082
Less amount included in current assets		(55	)		(19	)

	$	2,119		$	2,063


Liabilities
Asset removal costs	$	679		$	655
Excess securitization savings		—			14
Customer refund – 1997 storm		2			2
Refundable income taxes		135			146
Accrued GCR potential disallowance		28			26
Accrued PSCR refund		112			—
Other		3			3

		959			846
Less amount included in current liabilities		(142	)		(29	)

	$	817		$	817

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 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 associated with utility operations is recoverable. See Notes 4 and 14.

•		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 expenditures –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.

•		Deferred environmental costs— The MPSC approved the deferral and recovery of investigation and remediation costs associated with former manufactured gas plant sites.

•		Accrued GCR revenue—Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

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.

•		Refundable income taxes— Income taxes refundable to MichCon’s customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC authorization.

•		Accrued GCR potential disallowance— Potential refund resulting from an MPSC order in MichCon’s 2002 GCR plan case that required MichCon to reduce revenues in the calculation of its 2002 GCR expense.

•		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
	Rate			Rate
	Increase (1)			Increase (1)
(in Millions)
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 Midwest Independent System Operator (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 $20 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.

Gas Rate Case

Rate Request —In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. MichCon requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004.

MPSC Interim Rate Order– In September 2004, the MPSC issued an order granting interim rate relief to MichCon in the amount of $35 million. The interim rate order was based on a 50% debt and 50% equity capital structure, and an 11.5% rate of return on common equity. Amounts collected are subject to a potential refund pending a final order in this rate case.

MPSC Staff Recommendation on Final Rate Relief –The Staff has recommended a $76 million increase in base rates compared to MichCon’s requested base rate relief of $194 million. The Staff also supports a provision, proposed by MichCon, that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. In addition, the Staff proposed a 50% debt and 50% equity capital structure utilizing a reduced rate of return on common equity of 11%. MichCon’s current allowed rate of return on common equity is 11.5%.

MPSC Proposal for Decision (PFD) –The Administrative Law Judge (ALJ) issued a PFD on MichCon’s rate request on December 10, 2004. The PFD recommends an increase in base rates of $60 million. The PFD supports the Staff’s recommendations for capital structure, rate of return on common equity and for the proposed reconciliation of uncollectible accounts receivable. MichCon expects a final order in the first quarter of 2005.

Gas Industry Restructuring

In December 2001, the MPSC approved MichCon’s application for a voluntary, expanded permanent gas Customer Choice program, which replaced the experimental program that expired in March 2002. The number of customers eligible to participate in the gas Customer Choice program increased over a three-year period. Effective April 2004, all of MichCon’s 1.2 million customers could elect to participate in the Customer Choice program, thereby purchasing their gas from suppliers other than MichCon. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of December 2004, approximately 111,000 customers are participating in the gas Customer Choice program.

Gas Cost Recovery Proceedings

2002 Plan Year- In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per thousand cubic feet (Mcf) for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset of approximately $14 million representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset is subject to the 2002 GCR reconciliation process. In March 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year.

Although we recorded a $26.5 million reserve in 2003 to reflect the impact of this order, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment, will be decided in MichCon’s 2002 GCR reconciliation case that was filed with the MPSC in February 2003. The Staff and various intervening parties in this proceeding are seeking to have the MPSC disallow an additional $26 million, representing unbilled revenues at December 2001. One party has also proposed the disallowance of half of an $8 million payment made to settle Enron bankruptcy issues. The other parties to the case have recommended that the Enron bankruptcy settlement be addressed in the 2003 GCR reconciliation case. An MPSC Administrative Law Judge has recommended disallowances of $26.5 million related to the use of storage gas in 2001 and $26 million related to the December 2001 unbilled issue, and recommended that the $8 million related to the Enron issue be addressed in the 2003 GCR reconciliation case. We have included this item in our testimony in the 2003 GCR reconciliation filed in February 2004. The Staff has recommended that MichCon be allowed to recover the entire $8 million related to the Enron issue. A final order in this proceeding is expected in 2005. In addition, we filed an appeal of the March 2003 MPSC order with the Michigan Court of Appeals. In November 2004, the Michigan Court of Appeals denied the appeal.

2003 Plan Year —In July 2003, the MPSC approved an increase in MichCon’s 2003 GCR rate to a maximum of $5.75 per Mcf for the billing months of August 2003 through December 2003. MichCon’s 2003 GCR reconciliation case was filed with the MPSC in February 2004. In November 2004, the ALJ issued a PFD in the 2003 reconciliation case. The ALJ recommended that MichCon recover the full $8 million related to the Enron issue since MichCon had reason to believe at that time that cancellation of the contract was in the best interests of customers and since customers ultimately realized a benefit from the cancellation. The ALJ agreed with the MPSC Staff that a $2 million accounting adjustment related to exchange gas be disallowed.

2004 Plan Year —In September 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf. MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR plan case. The operational GCR year would run from April to March of the following year. To accomplish the switch, the 2004 GCR plan case reflects a 15-month transitional period, January 2004 through March 2005. Under the transition proposal, MichCon would file two reconciliations pertaining to the transition period; one addressing the January 2004 to March 2004 period, the other addressing the remaining April 2004 to March 2005 period. The plan also proposes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery. Due to the sustained increase in market prices for natural gas, in June 2004 the MPSC approved a temporary increase in the maximum GCR factor and a contingent factor which resulted in a new temporary maximum factor of $6.62 per Mcf, effective from July 1, 2004 until the MPSC issues its final order in this case. As of December 31, 2004, MichCon has accrued a $55 million regulatory asset representing the under-recovery of actual gas costs incurred in 2004, and the 2003 and 2002 GCR under-recovery.

2005-2006 Plan Year —In December 2004, MichCon filed its 2005-2006 GCR plan case proposing a maximum GCR factor of $7.99 per Mcf. The plan includes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery.

Minimum Pension Liability

In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, 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 $605 million ($393 million net of tax) and $585 million ($380 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 file a consolidated federal income tax return.

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


(Dollars in Millions)	2004			2003			2002

Effective federal income tax rate		27.1	%		(34.4	)%		(16.7	)%


Income before income taxes and minority interest	$	396		$	266		$	465
Less minority interest		(212	)		(91	)		(37	)

Income from continuing operations before tax	$	608		$	357		$	502


Income tax expense at 35% statutory rate	$	213		$	125		$	175
Section 29 tax credits		(38	)		(241	)		(250	)
Investment tax credits		(8	)		(8	)		(9	)
Depreciation		(4	)		(4	)		2
Employee Stock Ownership Plan dividends		(5	)		(5	)		(4	)
Other, net		7			10			2

Income tax expense (benefit) from continuing operations	$	165		$	(123	)	$	(84	)

The minority interest allocation reflects the adjustment to earnings to allocate partnership losses to third party owners. The tax impact of partnership earnings and losses are attributable to the partners instead of the partnerships. The minority interest allocation is therefore removed in computing income taxes associated with continuing operations.

Components of income tax expense (benefit) were as follows:

(in Millions)


	2004			2003			2002
Continuing Operations
Current federal and other income tax expense	$	31		$	14		$	135
Deferred federal income tax expense (benefit)		134			(137	)		(219	)

		165			(123	)		(84	)
Discontinued operations		(4	)		61			25
Cumulative Effect of Accounting Changes		—			(15	)		—

Total	$	161		$	(77	)	$	(59	)

Internal Revenue Code Section 29 provides a tax credit for qualified fuels produced and sold by a taxpayer to an unrelated party during the taxable year. Our Section 29 tax credits earned but not utilized totaled $483 million and are carried forward indefinitely as alternative minimum tax credits. The majority of our tax credit properties, including all of our synfuel projects, have received private letter rulings from the Internal Revenue Service (IRS) that provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.

We have a net operating loss carryforward of $203 million that expires in years 2018 through 2020. We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforward prior to its expiration.

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

(in Millions)


	2004			2003
Property	$	(1,193	)	$	(1,124	)
Securitized regulatory assets		(778	)		(827	)
Alternative minimum tax credit carryforward		483			497
Merger basis differences		125			132
Pension and benefits		(56	)		(50	)
Net operating loss		71			84
Other		317			380

	$	(1,031	)	$	(908	)


Deferred income tax liabilities	$	(2,527	)	$	(2,525	)
Deferred income tax assets		1,496			1,617

	$	(1,031	)	$	(908	)

The IRS is currently conducting audits of our federal income tax returns for the years 1998 through 2001. In addition, one of our synfuel facilities is under audit by the IRS for 2001. Audits of four of our synfuel facilities for the years 2001 and 2002 were completed successfully during 2004. 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 $53 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

NOTE 8 – COMMON STOCK AND EARNINGS PER SHARE

Common Stock

In March 2004, we issued 4,344,492 shares of DTE Energy common stock, valued at $170 million. The common stock was contributed to a defined benefit retirement plan.

Under the DTE Energy Company Long-Term Incentive Plan, we grant non-vested stock awards to key employees, primarily management. At the time of grant, we record the fair value of the non-vested awards as unearned compensation, which is reflected as a reduction in common stock. The number of non-vested stock awards is included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested stock awards are excluded.

Shareholders’ Rights Agreement

We have a Shareholders’ Rights Agreement designed to maximize shareholder value should DTE Energy be acquired. Under certain triggering events, each right entitles the holder to purchase from DTE Energy one one-hundredth of a share of Series A Junior Participating Preferred Stock of DTE Energy at a price of $90.00, subject to adjustment as provided for in the Shareholders’ Rights Agreement. The rights expire in October 2007.

Earnings per Share

We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options, vesting of non-vested stock awards, and the issuance of performance share awards. A reconciliation of both calculations is presented in the following table:


(in Millions, except per share amounts)	2004		2003		2002
Basic Earnings per Share

Income from continuing operations	$	442.6	$	480.4	$	585.7

Average number of common shares outstanding		172.6		167.7		164.0

Income per share of common stock based on average number of shares outstanding	$	2.56	$	2.87	$	3.57


Diluted Earnings per Share
Income from continuing operations	$	442.6	$	480.4	$	585.7

Average number of common shares outstanding		172.6		167.7		164.0
Incremental shares from stock-based awards		.7		.6		.8

Average number of dilutive shares outstanding		173.3		168.3		164.8

Income per share of common stock assuming issuance of incremental shares	$	2.55	$	2.85	$	3.55

Options to purchase approximately one million shares of common stock in 2004, five million shares in 2003 and one million shares in 2002 were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive. Common stock to be issued in August 2005 associated with the equity-linked securities is not included in the computation of diluted earnings per share as these shares were not dilutive (Note 9).

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 was:


(in Millions)	2004			2003
DTE Energy Debt, Unsecured
6.1% due 2006 to 2033	$	1,945		$	2,005
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
MichCon Taxable Debt, Principally Secured
6.2% due 2006 to 2033		785			772
Quarterly Income Debt Securities (QUIDS)
7.5% due 2026 to 2038		385			385
Non-Recourse Debt		56			78
Other Long-Term Debt		95			106

		6,083			6,006
Less amount due within one year		(410	)		(382	)

	$	5,673		$	5,624


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

	$	1,400		$	1,496


Equity-Linked Securities	$	178		$	185


Trust Preferred — Linked Securities
8.625% due 2038	$	—		$	103
7.8% due 2032		186			186
7.5% due 2044		103			—

	$	289		$	289


*		Weighted average interest rates as of December 31, 2004

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

2005

•

Issued $400 million of Detroit Edison 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.

•

Detroit Edison redeemed $76 million of 7.5% senior notes and $100 million of 7.0% remarketed secured notes, which matured February 2005.

2004

•

MCN Financing II, an unconsolidated affiliate, redeemed $100 million of 8.625% Trust Originated Preferred Securities due 2038. Accordingly, the underlying trust preferred-linked securities were also simultaneously redeemed.

•

Redeemed $60 million of MCN Energy Enterprises 7.12% medium term notes.

•

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

•

Issued $32 million of Detroit Edison 4.65% tax-exempt bonds due in 2028, the proceeds of which were used to redeem the following Detroit Edison 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.

•

DTE Energy Trust II, an unconsolidated affiliate, issued an aggregate of $100 million of 7.50% Trust Originated Preferred Securities. The proceeds from the issuance were loaned to DTE Energy in exchange for debt securities with essentially the same terms as the related preferred securities.

•

Issued $250 million of DTE Energy floating rate notes due in 2007. The floating rate is based on 3 month LIBOR plus 0.95%. These notes may be called at par in June 2005. The proceeds were used to repay short-term borrowings incurred in connection with the June 2004 redemption of $250 million DTE Energy 6.0% senior notes.

•

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

•

Issued $120 million of MichCon 5.0% senior notes due in 2019. The proceeds were used to redeem the following two issues: $52 million of 6.85% senior notes due 2038 and $55 million of 6.85% senior notes due 2039.

2003

•

Issued $400 million of DTE Energy 6-3/8% senior notes maturing in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing DTE Enterprises, Inc. debt due April 2008. The exchange premium and other costs associated with the original debt were deferred and are being amortized to interest expense over the term of the new debt.

•

Redeemed $100 million of DTE Energy 6.17% Remarketed Notes maturing in 2038.

•

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

•

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

•

Issued $200 million of MichCon 5.7% senior notes maturing in March 2033.

•

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

•

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

In the years 2005 — 2009, our long-term debt maturities are $507 million, $680 million, $597 million, $455 million and $ 361 million, respectively.

Remarketable Securities

At December 31, 2004, $175 million of notes of Detroit Edison and MichCon were subject to periodic remarketings. The $100 million scheduled to remarket in February 2005 was optionally redeemed by Detroit Edison, and no remarketings will take place in 2005. We direct the remarketing agents to remarket these securities at the lowest interest rate necessary to produce a par bid. In the event that a remarketing fails, we would be required to purchase the securities.

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.

Equity-Linked Securities

In June 2002, DTE Energy issued 6.9 million equity security units with gross proceeds from the issuance of $172.5 million. An equity security unit consists of a stock purchase contract and a senior note of DTE Energy. Under the stock purchase contracts, we will sell, and equity security unit holders must buy, shares of DTE Energy common stock in August 2005 for $172.5 million. The issue price per share and the exact number of common shares to be sold is dependent on the market value of a share in August 2005. The issue price will be not less than $43.25 or more than $51.90 per common share, with the corresponding number of shares issued of not more than 4.0 million or less than 3.3 million shares. We are also obligated to pay the security unit holders a quarterly contract adjustment payment at an annual rate of 4.15% of the stated amount until the purchase contract settlement date. We recorded the present value of the contract adjustment payments of $26 million in long-term debt with an offsetting reduction in shareholders’ equity. The liability is reduced as the contract adjustment payments are made.

Each senior note has a stated value of $25, pays an annual interest rate of 4.60% and matures in August 2007. The senior notes are pledged as collateral to secure the security unit holders’ obligation to purchase DTE

Energy common stock under the stock purchase contracts. The security unit holders may satisfy their obligations under the stock purchase contracts by allowing the senior notes to be remarketed with proceeds being paid to DTE Energy as consideration for the purchase of stock under the stock purchase contracts. Alternatively, holders may choose to continue holding the senior notes and use cash as consideration for the purchase of stock under the stock purchase contracts.

Net proceeds from the equity security unit issuance totaled $167 million. Expenses incurred in connection with this issuance totaled $5.6 million and were allocated between the senior notes and the stock purchase contracts. The amount allocated to the senior notes was deferred and will be recognized as interest expense over the term of the notes. The amount allocated to the stock purchase contracts was charged to equity.

Trust Preferred-Linked Securities

DTE Energy has interests in various unconsolidated trusts that were formed for the sole purpose of issuing preferred securities and lending the gross proceeds to us. The sole assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments we make are used by the trusts to make cash distributions on the preferred securities it has issued.

We have the right to extend interest payment periods on the debt securities. Should we exercise this right, we cannot declare or pay dividends on, or redeem, purchase or acquire, any of our capital stock during the deferral period.

DTE Energy has issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debt securities and related indenture, provide full and unconditional guarantees of the trusts’ obligations under the preferred securities.

Financing costs for these issuances were paid for and deferred by DTE Energy. These costs are being amortized using the straight-line method over the estimated lives of the related securities.

Cross Default Provisions

Substantially all of the net utility properties of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit Edison or MichCon fail to timely pay their indebtedness under these mortgages, such failure will create cross defaults in the indebtedness of DTE Energy Corporate.

Preferred and Preference Securities – Authorized and Unissued

At December 31, 2004, DTE Energy had 5 million shares of preferred stock without par value authorized, with no shares issued. Of such amount, 1.5 million shares are reserved for issuance in accordance with the Shareholders’ Rights Agreement.

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.

At December 31, 2004, MichCon had 7 million shares of preferred stock with a par value of $1 per share and 4 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 May 2004, DTE Energy entered into a $375 million two-year unsecured revolving credit facility with a group of banks to be utilized for general corporate borrowings. DTE Energy had approximately $148 million of letters of credit outstanding against this facility at December 31, 2004. This agreement requires the company to maintain a debt to total capitalization ratio of no more than .65 to l and an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. DTE Energy is currently in compliance with these financial covenants.

In October 2004, DTE Energy entered into a $525 million, five-year unsecured revolving credit facility and lowered its existing three-year revolving credit facility from $350 million to $175 million. Detroit Edison and MichCon also entered into similar revolving credit facilities. Detroit Edison entered into a $206.25 million, five-year facility and lowered its three-year facility from $137.5 million to $68.75 million. MichCon entered into a $243.75 million, five-year facility and lowered its three-year facility from $162.5 million to $81.25 million. The five-year facilities replace the October 2003 364-day facilities, which expired. The three-year revolving credit facilities expire 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 each of the Companies’ commercial paper programs. Borrowings under the facilities will be available at prevailing short-term interest rates. The agreements require each of the Companies to maintain a debt to total capitalization ratio of no more than .65 to l and an EBITDA to interest ratio of no less than 2 to 1. The Companies are currently in compliance with these financial covenants. Should either Detroit Edison or MichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default under DTE Energy’s credit agreements.

As of December 31, 2004, we had outstanding commercial paper of $402 million and other short-term borrowings of $1 million.

Detroit Edison also 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 balances outstanding under this financing agreement at December 31, 2004.

The weighted average interest rates for short-term borrowings were 2.4% and 1.9% at December 31, 2004 and 2003, respectively.

NOTE 11 – CAPITAL AND OPERATING LEASES

Lessee– We lease various assets under capital and operating leases, including coal cars, a gas storage field, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2029. Portions of the office buildings are subleased to tenants.

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

(in Millions)


	Capital			Operating
	Leases			Leases
2005	$	11		$	64
2006		13			56
2007		10			47
2008		11			40
2009		11			38
Thereafter		38			378

Total minimum lease payments		94		$	623

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 $6 million under non-cancelable subleases expiring at various dates to 2020.

Rental expense for operating leases was $75 million in 2004, $73 million in 2003 and $40 million in 2002.

Lessor– MichCon leases a portion of its pipeline system to the Vector Pipeline Partnership through a capital lease contract that expires in 2020, with renewal options extending for five years. The components of the net investment in the capital lease at December 31, 2004, were as follows:

(in Millions)


2005	$	9
2006		9
2007		9
2008		9
2009		9
Thereafter		98

Total minimum future lease receipts		143
Residual value of leased pipeline		40
Less unearned income		(101	)

Net investment in capital lease		82
Less current portion		(1	)

	$	81

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, credit, interest rates and foreign currency. We have risk management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure. Except for the activities of the Fuel Transportation and Marketing segment, we do not hold or issue derivative instruments for trading purposes. The fair value of all derivatives is shown as “assets or liabilities from risk management and trading activities” in the consolidated statement of financial position.

Commodity Price Risk

Utility Operations

Detroit Edison– Detroit Edison generates, purchases, distributes and sells electricity. 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 for utility operations at December 31, 2004.

MichCon– MichCon purchases, stores, transmits and distributes and sells natural gas. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2005. These contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method.

Commodity price risk associated with our utilities is limited due to the PSCR and GCR mechanisms (Note 1).

Non-Utility Operations

Fuel Transportation and Marketing –Energy Marketing and Trading markets and trades wholesale electricity and natural gas physical products, trades financial instruments, and provides risk management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations on its operations. These derivatives are accounted for by recording changes in fair value to earnings, usually as adjustments to operating revenues or fuel, purchased power and gas expense. This fair value accounting better aligns financial reporting with the way the business is managed and its performance measured.

Fuel Transportation and Marketing experiences earnings volatility as a result of its gas inventory and other non-derivative assets that do not qualify for fair value accounting under U. S. generally accepted accounting principles. Although the risks associated with these asset positions are substantially offset, requirements to fair value the underlying derivatives result in unrealized gains and losses being recorded to earnings that eventually reverse upon settlement.

Energy Services and Biomass –Our Energy Services and Biomass businesses generate Section 29 tax credits. Additionally, through December 2004, Energy Services has sold majority interests in eight of its nine synthetic fuel production plants. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13 for further discussion.

To manage our exposure in 2005 to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The

derivatives, coupled with other contracts, economically hedge approximately 65% of our 2005 synfuel cash flow exposure. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full year 2005 average New York Mercantile Exchange (NYMEX) trading price of oil in relation to the strike price of each option. If the average NYMEX price of oil in 2005 is less than approximately $56 per barrel, the derivatives will yield no payment. If the average NYMEX price of oil exceeds approximately $56 per barrel, the derivatives will yield a payment equal to the excess of the average NYMEX price over $56 per barrel, multiplied by the number of barrels covered, up to a maximum price of approximately $68 per barrel. The agreements do not qualify for hedge accounting and, as a result, changes in the fair value of the options are recorded currently in earnings. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and therefore included in the “Asset gains and losses, net” line item in the consolidated statement of operations.

Gas Production– Our Gas Production business is engaged in natural gas exploration, development and production. We use derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in other comprehensive loss will be reclassified to earnings as the related forecasted production affects earnings through 2013. In 2005, we estimate reclassifying $35 million of losses to earnings.

Credit Risk

Our utility and non-utility businesses 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.

Interest Rate Risk

We use interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, we entered into a series of interest rate derivatives to limit our sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. We subsequently issued long-term debt and terminated these hedges at a cost that is included in other comprehensive loss. Amounts recorded in other comprehensive loss will be reclassified to interest expense as the related interest affects earnings through 2030. In 2005, we estimate reclassifying $6 million of losses to earnings.

Foreign Currency Risk

Energy Marketing and Trading has foreign currency forward contracts to hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. We entered into these contracts to mitigate any price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. Certain of these contracts are designated as cash flow hedges with changes in fair value recorded to other comprehensive income. Amounts recorded to other comprehensive income are classified to operating revenues or fuel, purchased power and gas expense when the related hedged item affects earnings.

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

$8.5 billion

$8.0 billion

$8.5 billion

$7.9 billion

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Synthetic Fuel Operations

We partially or wholly own nine synthetic fuel production facilities. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 tax credits.

In-Service Date- During July 2004, several unaffiliated companies announced that they have been notified that the IRS intends to challenge the placed in service dates for some of their synfuel facilities. If the IRS ultimately prevails, Section 29 credits claimed by these companies would be disallowed. The placed in service issue is fact-driven and specific to each facility. The in-service dates for eight of our nine synfuel plants have been favorably reviewed by the IRS in conjunction with issuing determination letters and/or recently completed audits. We believe all nine of our synthetic fuel plants meet the required in-service condition.

Through December 31, 2004, we have generated and recorded approximately $512 million in synfuel tax credits.

Oil Prices- To reduce U.S. dependence on imported oil, the Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides a natural market for these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which in recent years has been $3 — $4 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2004, we estimate that the threshold price at which the tax credit would have begun to be reduced was $51.34 and would have been completely phased out if the Reference Price reached $64.45. The Reference Price of oil is estimated to be $37.61 for 2004. We also estimate that the 2005 average wellhead price per barrel of oil would have to exceed approximately $52.37 per barrel to begin phase out and exceed approximately $65.74 per barrel to eliminate the credits. We cannot predict with any accuracy the future price of a barrel of oil.

Numerous recent events have increased domestic crude oil prices, including terrorism, storm-related supply disruptions and worldwide demand. If the credit is reduced or eliminated in future years, our financial statements would be negatively impacted. We continue to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy. To manage our exposure to oil prices in 2005, we entered into oil-related derivative contracts. See Note 12 for further discussion.

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- Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Enterprises (MichCon and Citizens) owns, or previously owned, 18 such former manufactured gas plant (MGP) sites. During the mid-1980’s, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. The existence of these sites and the results of the environmental investigations have been reported to the MDEQ.

Enterprises is remediating eight of the former MGP sites and conducting more extensive investigations at five other former MGP sites. Enterprises received MDEQ closure of one site, and a determination that it is not a responsible party for three other sites. Enterprises received closure from the EPA in 2002 for one site.

In 1984, Enterprises established a $12 million reserve for costs associated with environmental investigation and remediation activities. During 1993, MichCon received MPSC approval of a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites in excess of this reserve. Enterprises employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies. As a result of these studies, Enterprises accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. In early December 2004, Enterprises retained multiple environmental consultants to estimate the projected cost to remediate each MGP facility. The results of the evaluation indicated that the MGP reserve should be set at $24 million.

During 2004, Enterprises spent approximately $2 million investigating and remediating these former MGP sites. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and, therefore, have an effect on the Company’s financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Detroit Edison conducted remedial investigations at contaminated sites, including two former MGP 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.

Guarantees

In certain circumstances we enter into contractual guarantees. We may guarantee another entity’s obligation in the event it fails to perform. We may provide guarantees in certain indemnification agreements. Finally,

we may provide indirect guarantees of the indebtedness of others. Below are the details of specific material guarantees we currently provide. Our other guarantees are not individually material and total approximately $40 million at December 31, 2004.

Sale of Interests in Synfuel Facilities

We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities. The guarantees cover general commercial, environmental and tax-related exposure and will survive until 90 days after expiration of all applicable statute of limitations, or indefinitely, depending on the nature of the guarantee. We estimate that our maximum liability under these guarantees at December 31, 2004 totals $905 million.

Parent Company Guarantee of Subsidiary Obligations

We have issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $356 million at December 31, 2004. This estimated amount fluctuates based upon the provisions and maturities of the underlying agreements.

Personal Property Taxes

Prior to 1999, Detroit Edison, MichCon 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 and MichCon have filed motions and the MTT agreed to place their 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 and MichCon appeals. The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison and MichCon continue to record property tax expense based on the new tables. Detroit Edison and MichCon 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 and MichCon.

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, purchased power and gas 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

the steam heating business of Detroit Edison 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.

In 2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and terminated a related long-term gas exchange (storage) agreement. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season. The agreements were at rates that were not reflective of current market conditions and had been fair valued under accounting principles generally accepted in the U.S. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately $75 million as of December 31, 2003. As a result of the contract modification and termination, we recorded an adjustment to the net liability increasing 2004 earnings by $48 million, net of taxes.

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 and energy trading contracts. We estimate that these commitments will be approximately $7.3 billion through 2027. We also estimate that 2005 base level capital expenditures will be $1.1 billion. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

We purchase and sell electricity, gas, coal and coke 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 income from continuing operations,

net income and related per share 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

We have defined benefit retirement plans for eligible represented and nonrepresented employees. The plans are noncontributory, cover substantially all employees and provide 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. Our policy is to fund pension costs by contributing the minimum amount required by the Employee Retirement Income Security Act (ERISA) and additional amounts when we deem appropriate. We do not anticipate making a contribution to our qualified pension plans 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 DTE Energy’s other retirement plans.

Net pension cost (credit) includes the following components:


	Qualified Pension Plans									Nonqualified Pension Plans
(in Millions)	2004			2003			2002			2004		2003		2002
Service Cost	$	58		$	48		$	43		$	2	$	2	$	1
Interest Cost		168			164			162			3		4		3
Expected Return on Plan Assets		(216	)		(211	)		(223	)		—		—		—
Amortization of
Net loss		63			38			2			1		1		1
Prior service cost		8			8			9			—		—		1
Net transition asset		—			—			(2	)		—		—		—

Net Pension Cost (Credit)	$	81		$	47		$	(9	)	$	6	$	7	$	6

The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the consolidated statement of financial position at December 31:


	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	$	2,689		$	2,556		$	54		$	57


Projected Benefit Obligation—Beginning of Period	$	2,745		$	2,499		$	59		$	50
Service Cost		58			48			2			2
Interest Cost		168			164			3			4
Actuarial Loss (Gain)		76			201			(4	)		6
Benefits Paid		(149	)		(159	)		(4	)		(3	)
Plan Amendments		1			(8	)		—			—

Projected Benefit Obligation—End of Period	$	2,899		$	2,745		$	56		$	59


Plan Assets at Fair Value—Beginning of Period	$	2,348		$	1,845		$	—		$	—
Actual Return on Plan Assets		196			440			—			—
Company Contributions		170			222			4			3
Benefits Paid		(149	)		(159	)		(4	)		(3	)

Plan Assets at Fair Value—End of Period	$	2,565		$	2,348		$	—		$	—


Funded Status of the Plans	$	(334	)	$	(397	)	$	(56	)	$	(59	)
Unrecognized
Net loss		1,043			1,010			15			18
Prior service cost		34			41			1			3

Net Amount Recognized at Measurement Date		743			654			(40	)		(38	)
Company Contribution in December 2004		—			—			1			—

Net Amount Recognized—End of Period	$	743		$	654		$	(39	)	$	(38	)


Amount Recorded as
Prepaid pension assets	$	184		$	181		$	—		$	—
Accrued pension liability		(212	)		(287	)		(53	)		(58	)
Regulatory asset		594			572			11			13
Accumulated other comprehensive loss		139			147			2			4
Intangible asset		38			41			1			3

	$	743		$	654		$	(39	)	$	(38	)

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	$	173
2006		177
2007		182
2008		189
2009		194
2010 - 2014		1,091

Total	$	2,006

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 Detroit Edison’s 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, intangible asset and other comprehensive loss 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, the employee’s contribution rate and, in some cases, years of credited service. The cost of these plans was $28 million in 2004, $26 million in 2003 and $25 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:


	2004			2003			2002
(in Millions)
Service Cost	$	41		$	37		$	30
Interest Cost		92			87			78
Expected Return on Plan Assets		(56	)		(47	)		(59	)
Amortization of
Net loss		43			31			3
Prior service cost		(3	)		(3	)		(1	)
Net transition obligation		8			13			19

Net Postretirement Cost	$	125		$	118		$	70

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	$	1,582		$	1,494
Service Cost		41			37
Interest Cost		92			87
Actuarial Loss		146			162
Plan Amendments		7			(126	)
Benefits Paid		(75	)		(72	)

Accumulated Postretirement Benefit Obligation-End of Period	$	1,793		$	1,582


Plan Assets at Fair Value-Beginning of Period	$	586		$	537
Actual Return on Plan Assets		53			114
Company Contributions		40			—
Benefits Paid		—			(65	)

Plan Assets at Fair Value-End of Period	$	679		$	586


Funded Status of the Plans	$	(1,114	)	$	(996	)
Unrecognized
Net loss		811			705
Prior service cost		(8	)		(27	)
Net transition obligation		58			74

Accrued Postretirement Liability at Measurement Date		(253	)		(244	)
Company Contribution And Benefit Payments in December 2004		(20	)		—

Accrued Postretirement Liability-End of Period	$	(273	)	$	(244	)

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 $20 million and increased the accumulated benefit obligation by $177 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 $17 million and would have decreased the accumulated benefit obligation by $157 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	$	97
2006		106
2007		110
2008		113
2009		120
2010 - 2014		665

Total	$	1,211

The process used in determining the long-term rate of return for assets and the investment approach for our other postretirement benefits plans 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	%		66	%
Debt Securities		28			30
Other		4			4

		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 $95 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 $16 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		6
Amortization of actuarial gain		8

Decrease in postretirement benefit cost	$	16

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		11
2007		11
2008		12
2009		12
2010 - 2014		69

Total	$	115

Grantor Trust

MichCon maintains a Grantor Trust that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and MichCon can revoke the trust subject to providing the MPSC with prior notification. We account for our investment at fair value with unrealized gains and losses recorded to earnings.

NOTE 15 — STOCK-BASED COMPENSATION

The DTE Energy Stock Incentive Plan permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. A maximum of 18 million shares of common stock may be issued under the plan. Participants in the plan include our employees and members of our Board of Directors. As of December 31, 2004, no performance units have been granted under the plan.

Options

Options are exercisable according to the terms of the individual stock option award agreements and expire 10 years after the date of the grant. The option exercise price equals the fair value of the stock on the date that the option was granted. Stock option activity was as follows:


				Weighted
	Number of			Average
	Options			Exercise Price
Outstanding at December 31, 2001 (1,678,870 exercisable)		5,281,624		$	38.51
Granted		1,334,370		$	42.08
Exercised		(678,715	)	$	34.64
Canceled		(456,684	)	$	38.74

Outstanding at December 31, 2002 (2,285,323 exercisable)		5,480,595		$	39.87
Granted		1,654,879		$	40.56
Exercised		(329,528	)	$	35.88
Canceled		(152,824	)	$	42.67

Outstanding at December 31, 2003 (3,506,038 exercisable)		6,653,122		$	40.18
Granted		1,300,900		$	39.41
Exercised		(891,353	)	$	34.94
Canceled		(356,000	)	$	43.06

Outstanding at December 31, 2004 (3,939,939 exercisable at a weighted average exercise price of $40.52)		6,706,669		$	40.57

The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:


					Weighted
			Weighted		Average
Range of	Number of		Average		Remaining
Exercise Prices	Options		Exercise Price		Contractual Life
$27.62 - $38.04		649,604	$	31.70	5.02 years
$38.60 - $42.44		4,594,837	$	40.68	7.65 years
$42.60 - $44.54		690,950	$	42.70	6.38 years
$45.28 - $46.74		771,278	$	45.47	6.51 years

		6,706,669	$	40.57	7.13 years

We account for option awards under APB Opinion 25. Accordingly, no compensation expense has been recorded for options granted. As required by SFAS No. 123, we have determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:


	2004			2003			2002
Risk-free interest rate		3.55	%		2.93	%		5.33	%
Dividend yield		5.23	%		4.97	%		4.90	%
Expected volatility		20.00	%		20.89	%		19.79	%

Expected life	6 years			6 years			6 years

Fair value per option	$	4.46		$	4.78		$	6.25

Stock Awards

Stock awards granted under the plan are restricted for varying periods, which are generally for three years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares. Prior to vesting in stock awards, the participant: (i) may not sell, transfer, pledge, exchange or otherwise dispose of shares; (ii) shall not retain custody of the share certificates; and (iii) will deliver to us a stock power with respect to each stock award.

The stock awards are recorded at cost that approximates fair value on the date of grant. We account for stock awards as unearned compensation, which is recorded as a reduction to common stock. The cost is amortized to compensation expense over the vesting period. Stock award activity for the years ended December 31 was:


	2004		2003		2002
Restricted common shares awarded		209,650		102,060		113,410
Weighted average market price of shares awarded	$	39.95	$	41.39	$	42.92
Compensation cost charged against income (in thousands)	$	5,616	$	6,366	$	4,101

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitles the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achievement of certain performance objectives. The awards vest at the end of a specified period, usually three years. We account for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the

probable achievement of performance objectives; and (ii) the fair value of the shares. For 2004, 2003 and 2002, we recorded compensation expense totaling $6.1 million, $5.5 million and $3.6 million, respectively.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. Performance share awards are nontransferable and are subject to risk of forfeiture. As of December 31, 2004, there were 619,044 performance share awards outstanding.

NOTE 16 — SEGMENT AND RELATED INFORMATION

We operate our businesses through three strategic business units (Electric Utility, Gas Utility and Non-utility Operations). The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. This results in the following reportable segments:

Electric Utility

•

Consists of Detroit Edison, the company’s electric utility whose operations include the power generation and electric distribution facilities that service approximately 2.1 million residential, commercial and industrial customers throughout Southeastern Michigan.

Gas Utility

•

Consists primarily of the gas distribution services provided by MichCon, the company’s gas utility that purchases, stores and distributes natural gas throughout Michigan to 1.2 million residential, commercial and industrial customers.

Non-utility Operations

•

Power and Industrial Projects, primarily consisting of synfuel projects, on-site energy services, steel-related projects, power generation with services, and waste coal recovery operations;

	•		Unconventional Gas Production,primarily consisting of unconventional gas project development and production;

	•		Fuel Transportation and Marketing, primarily consisting of coal transportation and marketing, gas pipelines and storage, and energy marketing and trading operations; and

Corporate & Otherincludes administrative and general expenses, and interest costs of DTE Energy corporate that have not been allocated to the utility and non-utility businesses. Corporate & Other also includes various other non-utility operations, including investments in new emerging energy technologies and D-Tech, a provider of distributed generation products.

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of Section 29 tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated tax return. Inter-segment revenues primarily consist of power sales, gas sales and coal transportation services between Electric Utility and our other Non-utility Operations segments. DTE Energy’s interest income totaled $55 million in 2004, $37 million in 2003 and $29 million in 2002, and is primarily associated with the Power and Industrial Projects and Corporate & Other segments. Financial data of the business segments follows:

(in Millions)


				Depreciation,
	Operating			Depletion &		Interest			Income			Net			Total				Capital
2004	Revenue			Amortization		Expense			Taxes			Income			Assets		Goodwill		Expenditures

Electric Utility	$	3,568		$	523	$	280		$	64		$	150		$	12,708	$	1,202	$	702
Gas Utility		1,682			103		58			(9	)		20			2,816		772		113
Non-utility Operations
Power and Industrial Projects		1,100			89		35			42			179			1,841		41		24
Unconventional Gas Production		71			18		10			3			6			301		8		38
Fuel Transportation and Marketing		1,254			6		8			64			118			1,280		28		24

		2,425			113		53			109			303			3,422		77		86

Corporate & Other		60			5		176			1			(30	)		2,342		16		3
Reconciliation & Eliminations		(621	)		—		(49	)		—			—			—		—		—


Total from Continuing Operations	$	7,114		$	744	$	518		$	165			443			21,288		2,067		904


Discontinued Operations (Note 3)													(12	)		9		—		—

Total												$	431		$	21,297	$	2,067	$	904

(in Millions)


				Depreciation,
	Operating			Depletion &		Interest			Income			Net			Total				Capital
2003	Revenue			Amortization		Expense			Taxes			Income			Assets		Goodwill		Expenditures

Electric Utility	$	3,695		$	473	$	284		$	145		$	252		$	12,502	$	1,202	$	580
Gas Utility		1,498			101		58			—			29			2,719		776		99
Non-utility Operations
Power and Industrial Projects		938			90		21			(271	)		197			1,690		41		26
Unconventional Gas Production		70			17		7			5			12			282		8		28
Fuel Transportation and Marketing		1,061			4		6			41			69			1,089		28		13

		2,069			111		34			(225	)		278			3,061		77		67

Corporate & Other		52			2		202			(43	)		(79	)		2,457		12		5
Reconciliation & Eliminations		(273	)		—		(32	)		—			—			—		—		—


Total from Continuing Operations	$	7,041		$	687	$	546		$	(123	)		480			20,739		2,067		751


Discontinued Operations (Note 3)													68			14		—		—
Cumulative Effect of Accounting Changes													(27	)		—		—		—

Total												$	521		$	20,753	$	2,067	$	751


				Depreciation,
	Operating			Depletion &		Interest			Income			Net			Total				Capital
2002	Revenue			Amortization		Expense			Taxes			Income			Assets		Goodwill		Expenditures
									(in Millions)
Electric Utility	$	4,054		$	577	$	311		$	178		$	352		$	11,246	$	1,202	$	685
Gas Utility		1,369			104		57			36			66			2,601		776		93

Non-utility Operations
Power and Industrial Projects		651			31		19			(290	)		178			1,662		41		135
Unconventional Gas Production		72			17		6			8			19			268		8		32
Fuel Transportation and Marketing		981			5		16			18			32			1,054		29		3

		1,704			53		41			(264	)		229			2,984		78		170

Corporate & Other		56			3		195			(34	)		(61	)		2,522		12		26
Reconciliation & Eliminations		(454	)		—		(35	)		—			—			—		—		—


Total from Continuing Operations	$	6,729		$	737	$	569		$	(84	)		586			19,353		2,068		974


Discontinued Operations (Note 3)													46			632		44		10

Total												$	632		$	19,985	$	2,112	$	984

NOTE 17 — SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Quarterly earnings per share may not total for the years, since quarterly computations are based on weighted average common shares outstanding during each quarter. We account for the operations of ITC and SMGC as discontinued operations (Note 3).


	First			Second			Third			Fourth
(in Millions, except per share amounts)	Quarter (1)			Quarter			Quarter			Quarter			Year
2004
Operating Revenues	$	2,093		$	1,501		$	1,594		$	1,926		$	7,114
Operating Income	$	368		$	95		$	173		$	210		$	846
Net Income (Loss)
From continuing operations	$	197		$	35		$	93		$	118		$	443
Discontinued operations		(7	)		—			—			(5	)		(12	)

Total	$	190		$	35		$	93		$	113		$	431


Basic Earnings (Loss) per Share
From continuing operations	$	1.16		$	.20		$	.54		$	.68		$	2.56
Discontinued operations		(0.04	)		—			—			(.03	)		(.06	)

Total	$	1.12		$	.20		$	.54		$	.65		$	2.50


Diluted Earnings (Loss) per Share
From continuing operations	$	1.15		$	.20		$	.54		$	.68		$	2.55
Discontinued operations		(0.04	)		—			—			(.03	)		(.06	)

Total	$	1.11		$	.20		$	.54		$	.65		$	2.49


2003
Operating Revenues	$	2,095		$	1,600		$	1,654		$	1,692		$	7,041
Operating Income	$	217		$	71		$	232		$	227		$	747
Net Income (Loss)
From continuing operations	$	108		$	(37	)	$	180		$	229		$	480
Discontinued operations		74			(2	)		(4	)		—			68
Cumulative effect of accounting changes		(27	)		—			—			—			(27	)

Total	$	155		$	(39	)	$	176		$	229		$	521


Basic Earnings (Loss) per Share
From continuing operations	$	.65		$	(.22	)	$	1.07		$	1.36		$	2.87
Discontinued operations		.44			(.01	)		(.02	)		—			.41
Cumulative effect of accounting changes		(.17	)		—			—			—			(.17	)

Total	$	.92		$	(.23	)	$	1.05		$	1.36		$	3.11


Diluted Earnings (Loss) per Share
From continuing operations	$	.64		$	(.22	)	$	1.06		$	1.36		$	2.85
Discontinued operations		.44			(.01	)		(.02	)		—			.40
Cumulative effect of accounting changes		(.16	)		—			—			—			(.16	)

Total	$	.92		$	(.23	)	$	1.04		$	1.36		$	3.09


(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).

DTEEnergyCompany

Schedule II – Valuation and Qualifying Accounts


	Year Ending December 31,
	2004			2003			2002
(in Millions)
Allowance for Doubtful Accounts (shown as Deduction from accounts receivable in the consolidated statement of financial position)
Balance at Beginning of Period	$	99		$	82		$	57
Additions:
Charged to costs and expenses		108			80			45
Charged to other accounts (1)		9			4			15
Deductions (2)		(87	)		(67	)		(35	)

Balance At End of Period	$	129		$	99		$	82


(1)		Collection of accounts previously written off.

(2)		Uncollectible accounts written off.

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