EX-99.3

Exhibit 99.3

Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated statements of financial position of DTE Energy Company and subsidiaries (the “Company”) as of December 31, 2008 and 2007, 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, 2008. Our audits also included the financial statement schedules included in Exhibit 99.3. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements of the Company taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 8 to the consolidated financial statements, in connection with the required adoption of a new accounting standard, the Company changed its method of accounting for uncertainty in income taxes on January 1, 2007. As discussed in Notes 18 and 19 to the consolidated financial statements, in connection with the required adoption of new accounting standards, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans and share based payments, respectively.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009 (not presented herein) expressed an unqualified opinion on the Company’s internal control over financial reporting.

As discussed in Note 2 to the consolidated financial statements, the accompanying financial statements as of December 31, 2008 and 2007 and for each of the three years in the period ended December 31, 2008 have been retrospectively adjusted for the adoption of Statement of Financial Accounting Standards No. 160 (SFAS No. 160), Noncontrolling Interests in Consolidated Financial Statements, an amendment to ARB No. 51, and FSP EITF 03-6-1, Determining Whether Instruments Granted in Shared-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1).

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan

February 27, 2009
(August 20, 2009, as to the effects of the retrospective adoption of SFAS No. 160 and FSP EITF 03-6-1 as described in Note 2 to the consolidated financial statements)

DTE Energy Company
Consolidated Statements of Operations


	Year Ended December 31
	2008			2007			2006
	(In millions, Except per share amounts)
Operating Revenues	$	9,329		$	8,475		$	8,157

Operating Expenses
Fuel, purchased power and gas		4,306			3,552			3,047
Operation and maintenance		2,694			2,892			2,677
Depreciation, depletion and amortization		901			932			990
Taxes other than income		304			357			309
Gain on sale of non-utility business		(128	)		(900	)		—
Other asset (gains) and losses, reserves and impairments, net		(11	)		37			67

		8,066			6,870			7,090

Operating Income		1,263			1,605			1,067

Other (Income) and Deductions
Interest expense		503			533			525
Interest income		(19	)		(25	)		(26	)
Other income		(104	)		(93	)		(61	)
Other expenses		64			35			93

		444			450			531

Income Before Income Taxes		819			1,155			536

Income Tax Provision		288			364			146


Income from Continuing Operations		531			791			390

Discontinued Operations Income (Loss), net of tax		22			(4	)		(208	)


Cumulative Effect of Accounting Changes, net of tax		—			—			1


Net Income		553			787			183

Less: Net Income (Loss) Attributable to Noncontrolling Interests From
Continuing operations		5			4			1
Discontinued operations		2			(188	)		(251	)

		7			(184	)		(250	)


Net Income Attributable to DTE Energy Company	$	546		$	971		$	433


Basic Earnings per Common Share
Income from continuing operations	$	3.22		$	4.62		$	2.18
Discontinued operations		.12			1.08			.24
Cumulative effect of accounting changes		—			—			.01

Total	$	3.34		$	5.70		$	2.43

Diluted Earnings per Common Share
Income from continuing operations	$	3.22		$	4.61		$	2.18
Discontinued operations		.12			1.08			.24
Cumulative effect of accounting changes		—			—			.01

Total	$	3.34		$	5.69		$	2.43

Weighted Average Common Shares Outstanding
Basic		163			170			178
Diluted		163			171			178
Dividends Declared per Common Share	$	2.12		$	2.12		$	2.075

See Notes to Consolidated Financial Statements

DTE Energy Company
Consolidated Statements of Financial Position


	December 31
	2008			2007
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	86		$	123
Restricted cash		86			140
Accounts receivable (less allowance for doubtful accounts of $265 and $182, respectively)
Customer		1,666			1,658
Other		166			514
Accrued power and gas supply cost recovery revenue		22			76
Inventories
Fuel and gas		333			429
Materials and supplies		206			204
Deferred income taxes		227			387
Derivative assets		316			181
Other		220			196
Current assets held for sale		—			83

		3,328			3,991


Investments
Nuclear decommissioning trust funds		685			824
Other		595			446

		1,280			1,270


Property
Property, plant and equipment		20,065			18,809
Less accumulated depreciation and depletion		(7,834	)		(7,401	)

		12,231			11,408


Other Assets
Goodwill		2,037			2,037
Regulatory assets		4,231			2,786
Securitized regulatory assets		1,001			1,124
Intangible assets		70			25
Notes receivable		115			87
Derivative assets		140			199
Prepaid pension assets		—			152
Other		157			116
Noncurrent assets held for sale		—			547

		7,751			7,073

Total Assets	$	24,590		$	23,742

See Notes to Consolidated Financial Statements

DTE Energy Company
Consolidated Statements of Financial Position


	December 31
	2008			2007
	(In millions, except shares)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	899		$	1,189
Accrued interest		119			112
Dividends payable		86			87
Short-term borrowings		744			1,084
Current portion long-term debt, including capital leases		362			454
Derivative liabilities		285			281
Deferred gains and reserves		3			400
Other		515			566
Current liabilities associated with assets held for sale		—			48

		3,013			4,221


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		6,458			5,576
Securitization bonds		932			1,065
Trust preferred-linked securities		289			289
Capital lease obligations		62			41

		7,741			6,971


Other Liabilities
Deferred income taxes		1,958			1,824
Regulatory liabilities		1,202			1,168
Asset retirement obligations		1,340			1,277
Unamortized investment tax credit		96			108
Derivative liabilities		344			450
Liabilities from transportation and storage contracts		111			126
Accrued pension liability		871			68
Accrued postretirement liability		1,434			1,094
Nuclear decommissioning		114			134
Other		328			318
Noncurrent liabilities associated with assets held for sale		—			82

		7,798			6,649

Commitments and Contingencies (Notes 5, 6, and 17)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 163,019,596 and 163,232,095 shares issued and outstanding, respectively		3,175			3,176
Retained earnings		2,985			2,790
Accumulated other comprehensive loss		(165	)		(113	)

Total DTE Energy Company Shareholders’ Equity		5,995			5,853

Noncontrolling Interests		43			48

Total Equity		6,038			5,901

Total Liabilities and Equity	$	24,590		$	23,742

See Notes to Consolidated Financial Statements

DTE Energy Company
Consolidated Statements of Cash Flows


	Year Ended December 31
	2008			2007			2006
	(In millions)
Operating Activities
Net income	$	553		$	787		$	183
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		899			926			1,014
Deferred income taxes		348			144			28
Gain on sale of non-utility business		(128	)		(900	)		—
Other asset (gains), losses and reserves, net		(4	)		(9	)		(11	)
Gain on sale of interests in synfuel projects		(31	)		(248	)		(38	)
Impairment of synfuel projects		—			4			77
Contributions from synfuel partners		14			229			197
Cumulative effect of accounting changes		—			—			(1	)
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(92	)		192			7

Net cash from operating activities		1,559			1,125			1,456

Investing Activities
Plant and equipment expenditures — utility		(1,183	)		(1,035	)		(1,126	)
Plant and equipment expenditures — non-utility		(190	)		(264	)		(277	)
Acquisitions, net of cash acquired		—			—			(42	)
Proceeds from sale of interests in synfuel projects		84			447			246
Refunds to synfuel partners		(387	)		(115	)		—
Proceeds from sale of non-utility business		253			1,262			—
Proceeds from sale of other assets, net		25			85			67
Restricted cash		54			6			(21	)
Proceeds from sale of nuclear decommissioning trust fund assets		232			286			253
Investment in nuclear decommissioning trust funds		(255	)		(323	)		(284	)
Other investments		(156	)		(19	)		(10	)

Net cash from (used) for investing activities		(1,523	)		330			(1,194	)

Financing Activities
Issuance of long-term debt		1,310			50			612
Redemption of long-term debt		(446	)		(393	)		(687	)
Repurchase of long-term debt		(238	)		—			—
Short-term borrowings, net		(340	)		(47	)		291
Issuance of common stock		—			—			17
Repurchase of common stock		(16	)		(708	)		(61	)
Dividends on common stock		(344	)		(364	)		(365	)
Other		(10	)		(6	)		(10	)

Net cash used for financing activities		(84	)		(1,468	)		(203	)

Net Increase (Decrease) in Cash and Cash Equivalents		(48	)		(13	)		59
Cash and Cash Equivalents Reclassified (to) from Assets Held for Sale		11			(11	)		—
Cash and Cash Equivalents at Beginning of Period		123			147			88

Cash and Cash Equivalents at End of Period	$	86		$	123		$	147

See Notes to Consolidated Financial Statements

DTE Energy Company
Consolidated Statements of Changes in Shareholders’ Equity


										Accumulated			Non-
	Common Stock						Retained			Other Comprehensive			Controlling
	Shares			Amount			Earnings			Loss			Interest			Total
(Dollars in Millions, Shares in Thousands)
Balance, December 31, 2005		177,814		$	3,483		$	2,557		$	(271	)	$	92		$	5,861

Net income (loss)		—			—			433			—			(250	)		183
Issuance of new shares		411			17			—			—			—			17
Dividends declared on common stock		—			—			(368	)		—			—			(368	)
Repurchase and retirement of common stock		(1,283	)		(32	)		(29	)		—			—			(61	)
Adjustment to initially apply SFAS No. 158, net of tax		—			—			—			(38	)		—			(38	)
Benefit obligations, net of tax		—			—			—			3			—			3
Net change in unrealized losses on derivatives, net of tax		—			—			—			102			—			102
Net change in unrealized losses on investments, net of tax		—			—			—			(7	)		—			(7	)
Contributions from noncontrolling interests Net change in unrealized losses on derivatives, net of tax		—			—			—			—			197			197
Stock-based compensation, distributions to noncontrolling interests and other		196			(1	)		—			—			3			2

Balance, December 31, 2006		177,138			3,467			2,593			(211	)		42			5,891

Net income (loss)		—			—			971			—			(184	)		787
Implementation of FIN 48		—			—			(5	)		—			—			(5	)
Dividends declared on common stock		—			—			(358	)		—			—			(358	)
Repurchase and retirement of common stock		(14,440	)		(297	)		(411	)		—			—			(708	)
Benefit obligations, net of tax		—			—			—			6			—			6
Net change in unrealized losses on derivatives, net of tax		—			—			—			91			—			91
Net change in unrealized losses on investments, net of tax		—			—			—			1			—			1
Contributions from noncontrolling interests Net change in unrealized losses on derivatives, net of tax		—			—			—			—			229			229
Stock-based compensation, distributions to noncontrolling interests and other		534			6			—			—			(39	)		(33	)

Balance, December 31, 2007		163,232			3,176			2,790			(113	)		48			5,901

Net income		—			—			546			—			7			553
Implementation of SFAS No. 157, net of tax		—			—			4			—			—			4
Implementation of SFAS No. 158 measurement date provision, net of tax		—			—			(9	)		—			—			(9	)
Dividends declared on common stock		—			—			(346	)		—			—			(346	)
Repurchase and retirement of common stock		(479	)		(16	)		—			—			—			(16	)
Benefit obligations, net of tax		—			—			—			(22	)		—			(22	)
Foreign exchange translation, net of tax		—			—			—			(2	)		—			(2	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			6			—			6
Net change in unrealized losses on investments, net of tax		—			—			—			(34	)		—			(34	)
Contributions from noncontrolling interests Net change in unrealized losses on derivatives, net of tax		—			—			—			—			14			14
Stock-based compensation, distributions to noncontrolling interests and other		267			15			—			—			(26	)		(11	)

Balance, December 31, 2008		163,020		$	3,175		$	2,985		$	(165	)	$	43		$	6,038

See Notes to Consolidated Financial Statements

DTE Energy Company
Notes to Consolidated Financial Statements

Note 1 — SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

DTE Energy owns the following businesses:

	•		Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electric energy to approximately 2.2 million customers in southeast Michigan;

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

	•		Our four non-utility segments are involved in 1) gas pipelines and storage; 2) unconventional gas exploration, development and production; 3) power and industrial projects and coal transportation and marketing; and 4) energy marketing and trading operations.

Detroit Edison and MichCon are regulated by the MPSC. The FERC regulates certain activities of Detroit Edison’s business as well as various other aspects of businesses under DTE Energy. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and MDEQ.

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

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 management 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 the Company’s estimates.

Certain prior year balances were reclassified to match the current year’s financial statement presentation.

Principles of Consolidation

The Company consolidates all majority owned subsidiaries and investments in entities in which it has 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 the Company does not influence the operating policies of an investee, the cost method is used. These consolidated financial statements also reflect the Company’s proportionate interests in certain jointly owned utility plant. The Company eliminates all intercompany balances and transactions.

For entities that are considered variable interest entities, the Company applies the provisions of FIN 46(R), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. We consolidate variable interest entities (VIEs) for which we are the primary beneficiary in accordance with FIN 46(R). In general, we determine whether we are the primary beneficiary of a VIE through a qualitative analysis of risk which indentifies which variable interest holder absorbs the majority of the financial risk or rewards and variability of the VIE. In performing this analysis, we consider all relevant facts and circumstances, including: the design and activities of the VIE, the terms of the contracts the VIE has entered into, the identification of variable interest holders including equity owners, customers, suppliers and debt holders and which parties participated significantly in the design of the entity. If the qualitative analysis is inconclusive, a specific quantitative analysis is performed in accordance with FIN 46(R).

Legal entities within the Company’s Power and Industrial Projects segments enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk and generally are VIEs. These

arrangements are assessed on a qualitative and, if necessary, quantitative basis, in accordance with the requirements of FIN 46(R) to determine who is the primary beneficiary. If the Company is the primary beneficiary, the VIE is consolidated. If the Company is not the primary beneficiary, the VIE is accounted for under the equity method of accounting. The VIEs are reviewed for reconsideration events each quarter, and the assessment of the primary beneficiary updated, if necessary.

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 the Company. The sole assets of the trusts are debt securities of DTE Energy with terms similar to those of the related preferred securities. Payments the Company makes are used by the trusts to make cash distributions on the preferred securities it has issued. We have reviewed these interests in accordance with FIN 46(R) and have determined they are VIEs, but the Company is not the primary beneficiary.

The maximum risk exposure for consolidated VIEs is reflected on our Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally the extent of our investment.

The following table summarizes the amounts for the Company’s variable interest entities as of December 31, 2008 and 2007:


	2008			2007
	(In millions)
Variable Interest Entities — Consolidated
Total Assets	$	47		$	113
Total Liabilities		39			81
Shareholders’ Equity		(4	)		51
Variable Interest Entities — Non-consolidated
Other Investments	$	191		$	54
Trust preferred — linked securities		289			289

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 PSCR mechanism. MichCon’s accrued revenues include a component for the cost of gas sold that is recoverable through the 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. See Note 5.

Non-utility businesses recognize revenues as services are provided and products are delivered. Trading activities are accounted for under the provisions of EITF Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”, which requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the Consolidated Statement of Operations. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses in operating revenues.

Comprehensive Income

Comprehensive income is 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 for the year ended December 31, 2008 include unrealized gains and losses from derivatives accounted for as cash flow hedges, unrealized gains and losses on available for sale securities, and changes in benefit obligations, consisting of deferred actuarial losses, prior service costs and transition amounts related to pension and other postretirement benefit plans, pursuant to SFAS No. 158, and foreign currency translation adjustments.


	Net			Net									Accumulated
	Unrealized			Unrealized									Other
	Gains on			Losses on			Benefit			Foreign Currency			Comprehensive
	Derivatives			Investments			Obligations			Translation			Loss
	(In millions)
Beginning balances	$	(13	)	$	16		$	(116	)	$	—		$	(113	)
Current period change		6			(34	)		(22	)		(2	)		(52	)


Ending balance	$	(7	)	$	(18	)	$	(138	)	$	(2	)	$	(165	)

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 designated for interest and principal payments within one year is classified as a current asset.

Receivables

Accounts receivable are primarily composed of trade receivables and unbilled revenue. Our accounts receivable are stated at net realizable value. Customer accounts are written off based upon approved regulatory and legislative requirements.

The allowance for doubtful accounts for our two utilities is calculated using the aging approach that utilizes rates developed in reserve studies. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly, however, factors such as assistance programs may delay aggressive action. We assess late payment fees on trade receivables based on contractual past-due terms established with customers.

For our Energy Trading, non-regulated segment, the customer allowance for doubtful accounts is calculated based on specific review of probable future collectibles based on receivable balances in excess of 90 days.

Unbilled revenues of $812 million and $843 million are included in customer accounts receivable at December 31, 2008 and 2007, respectively.

Inventories

The Company values fuel inventory, including gas inventory in the Energy Trading segment, and materials and supplies at average cost.

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2008, the replacement cost of gas remaining in storage exceeded the $14 million LIFO cost by $232 million. During 2008, MichCon liquidated 4.2 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2008 cost of gas by approximately $21 million, but had no impact on earnings as a result of the GCR mechanism. At December 31, 2007, the replacement cost of gas remaining in storage exceeded the $32 million LIFO cost by $288 million. During 2007, MichCon liquidated 9.5 billion cubic feet of prior years’ LIFO layers. The liquidation reduced 2007 cost of gas by approximately $30 million, but had no impact on earnings as a result of the GCR mechanism.

Property, Retirement and Maintenance, and Depreciation and Depletion

Summary of property by classification as of December 31:


	2008			2007
	(In millions)
Property, Plant and Equipment
Electric Utility
Generation	$	8,544		$	8,100
Distribution		6,433			6,272

Total Electric Utility		14,977			14,372

Gas Utility
Distribution		2,327			2,392
Storage		378			273
Other		1,090			953

Total Gas Utility		3,795			3,618

Non-utility and other		1,293			1,423
Assets held for sale		—			(604	)

Total Property, Plant and Equipment		20,065			18,809


Less Accumulated Depreciation and Depletion
Electric Utility
Generation		(3,690	)		(3,539	)
Distribution		(2,138	)		(2,101	)

Total Electric Utility		(5,828	)		(5,640	)

Gas Utility
Distribution		(955	)		(970	)
Storage		(107	)		(100	)
Other		(603	)		(538	)

Total Gas Utility		(1,665	)		(1,608	)

Non-utility and other		(341	)		(350	)
Assets held for sale		—			197

Total Accumulated Depreciation and Depletion		(7,834	)		(7,401	)

Net Property, Plant and Equipment	$	12,231		$	11,408

Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during construction (AFUDC). AFUDC capitalized during 2008 and 2007 was approximately $50 million and $32 million, respectively. The cost of properties retired, less salvage value, at Detroit Edison and MichCon is charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $25 million and $4 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2009 were accrued at December 31, 2008 and December 31, 2007, respectively. Amounts are being accrued on a pro-rata basis over an 18-month period that began in November 2007. This accrual of outage costs matches the regulatory recovery of these costs in rates set by the MPSC.

The Company bases 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 3.3% in 2008, 2007 and 2006. The composite depreciation rate for MichCon was 3.2% in 2008, 3.1% in 2007 and 2.8% in 2006.

The average estimated useful life for each major class of utility property, plant and equipment as of December 31, 2008 follows:

Estimated Useful Lives in Years

Utility

Generation

Distribution

Transmission

Electric

N/A

Gas

N/A

Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods. The estimated useful lives for major classes of non-utility assets and facilities ranges from 5 to 50 years.

The Company credits depreciation, depletion and amortization expense when it establishes regulatory assets for plant-related costs such as depreciation or plant-related financing costs. The Company charges depreciation, depletion and amortization expense when it amortizes these regulatory assets. The Company credits interest expense to reflect the accretion income on certain regulatory assets.

Intangible assets relating to capitalized software are classified as Property, plant and equipment and the related amortization is included in Accumulated depreciation and depletion on the Consolidated Statements of Financial Position. The Company capitalizes the costs associated with computer software it develops or obtains for use in its business. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 3 to 15 years. Intangible assets amortization expense was $54 million in 2008, $42 million in 2007 and $37 million in 2006. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2008 were $576 million and $192 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $493 million and $141 million, respectively. Amortization expense of intangible assets is estimated to be $54 million annually for 2009 through 2013.

Asset Retirement Obligations

The Company records asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations for gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate.

For the Company’s regulated operations, timing differences arise in the expense recognition of legal asset retirement costs that the Company is currently recovering in rates. The Company defers such differences under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

No liability has been recorded with respect to lead-based paint, as the quantities of lead-based paint in the Company’s facilities are unknown. In addition, there is no incremental cost to demolitions of lead-based paint facilities vs. non-lead-based paint facilities and no regulations currently exist requiring any type of special disposal of items containing lead-based paint.

The Ludington Hydroelectric Power Plant (a jointly owned plant) has an indeterminate life and no legal obligation currently exists to decommission the plant at some future date. Substations, manholes and certain other distribution assets within Detroit Edison have an indeterminate life. Therefore, no liability has been recorded for these assets.

A reconciliation of the asset retirement obligations for 2008 follows:


	(In millions)
Asset retirement obligations at January 1, 2008	$	1,293
Accretion		84
Liabilities incurred		2
Liabilities settled		(18	)
Transfers from Assets held for sale		14
Revision in estimated cash flows		(14	)

Asset retirement obligations at December 31, 2008		1,361
Less amount included in current liabilities		(21	)

	$	1,340

Approximately $1.2 billion of the asset retirement obligations represent nuclear decommissioning liabilities that are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

Unconventional Gas Production

The Company follows 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 if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. 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. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets

The Company reviews its long-lived assets 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 costs to sell.

Our Power and Industrial Projects segment has long-term contracts with General Motors Corporation (GM) and Ford Motor Company (Ford) to provide onsite energy services at certain of their facilities. At December 31, 2008, the book value of long-lived assets used in the servicing of these facilities was approximately $85 million. In addition, we have an equity investment of approximately $40 million in an entity which provides similar services to Chrysler LLC (Chrysler). These companies are in financial distress, with GM and Chrysler recently receiving loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. We consider the recent announcements by these companies as an indication of possible impairment due to a significant adverse change in the business climate that could affect the value of our long-lived assets as described in SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” and have performed an impairment test on these assets. Based on our current undiscounted cash flow projections we have determined that we do not have an impairment as of December 31, 2008. We have also determined that we do not have an other than temporary decline in our Chrysler-related equity investment as described in APB 18, “The Equity Method of Accounting for Investments in Common Stock.” We will continue to assess these matters in future periods for possible asset impairments.

Goodwill

The Company has goodwill resulting from purchase business combinations.

The change in the carrying amount of goodwill for the fiscal years ended December 31, 2008 and December 31, 2007 is as follows:


	Total
	(In millions)
Balance at December 31, 2006	$	2,057
Synthetic fuels impairment		(4	)
Sale of non-utility businesses and other		(16	)

Balance at December 31, 2007	$	2,037

Balance at December 31, 2008	$	2,037

We performed our annual impairment test on October 1, 2008 and determined that the estimated fair value of our reporting units exceeded their carrying value and no impairment existed. During the fourth quarter of 2008, the closing price of DTE Energy’s stock declined by approximately 11% and at December 31, 2008 was approximately 3 percent below its book value per share. In assessing whether the recent modest decline in the trading price of DTE Energy’s common stock below its book value was an indication of impairment, we considered the following factors: (1) the relatively short duration and modest decline in the trading price of DTE Energy’s common stock; (2) the anticipated impact of the national and regional recession on DTE Energy’s future operating results and cash flows; (3) the favorable results of the recently performed annual impairment test and (4) a comparison of book value to the traded market price, including the impact of a control premium. As a result of this assessment, we determined that the decline in market price did not represent a triggering event at December 31, 2008 requiring an update to the October 1, 2008 impairment test. We will continue to assess these matters in future periods for possible impairments.

Intangible Assets

The Company has certain intangible assets relating to non-utility contracts and emission allowances. The Company amortizes intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. Intangible assets amortization expense was $7 million in 2008, $2 million in 2007 and $5 million in 2006. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2008 were $85 million and $15 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2007 were $31 million and $6 million, respectively. Our intangible assets related to emission allowances increased to $19 million at December 31, 2008 from $9 million at December 31, 2007. Net intangible assets reclassified to Assets held for sale totaled $38 million at December 31, 2007. Amortization expense of intangible assets is estimated to be $7 million annually for 2009 through 2013.

Excise and Sales Taxes

The Company records the billing of excise and sales taxes as a receivable with an offsetting payable to the applicable taxing authority, with no impact on the Consolidated Statements 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 the Company’s 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.

Investments in Debt and Equity Securities

The Company generally classifies investments in debt and equity securities as either trading or available-for-sale and has 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 Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s investments are reviewed for impairment each reporting period. If the assessment indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value. See Note 15.

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:


	2008			2007			2006
	(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	328		$	(163	)	$	385
Accrued GCR revenue		(71	)		(10	)		120
Inventories		96			80			(49	)
Recoverable pension and postretirement costs		(1,324	)		738			(1,184	)
Accrued/prepaid pensions		944			(401	)		218
Accounts payable		(286	)		5			(10	)
Accrued PSCR refund		82			41			(101	)
Income taxes payable		(22	)		(19	)		46
Derivative assets and liabilities		(178	)		222			(520	)
Postretirement obligation		340			(320	)		1,008
Other assets		(51	)		(430	)		(134	)
Other liabilities		50			449			228

	$	(92	)	$	192		$	7

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


	2008			2007		2006
	(In millions)
Cash paid (received) for:
Interest (net of interest capitalized)	$	496		$	537	$	526
Income taxes	$	(59	)	$	326	$	89

In connection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent. As a result, the Company entered into a demand financing agreement for up to $50 million with its clearing agent in lieu of posting additional cash collateral (a non-cash transaction). The amounts outstanding under this facility were $26 million and $13 million at December 31, 2008 and 2007, respectively.

See the following notes for other accounting policies impacting the Company’s consolidated financial statements:


Note		Title
	2	New Accounting Pronouncements
	5	Regulatory Matters
	8	Income Taxes
	15	Fair Value
	16	Financial and Other Derivative Instruments
	18	Retirement Benefits and Trusteed Assets
	19	Stock-based Compensation

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Accounting

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. Effective January 1, 2008, the Company adopted SFAS No. 157. As permitted by FASB Staff Position FAS No. 157-2, the Company has elected to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009. The cumulative effect adjustment upon adoption of SFAS No. 157 represented a $4 million increase to the January 1, 2008 balance of retained earnings. See also Note 15.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115. This Statement permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. An entity will report in earnings unrealized gains and losses on items, for which the fair value option has been elected, at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. At January 1, 2008, the Company elected not to use the fair value option for financial assets and liabilities held at that date.

In October 2008, the FASB issued FASB Staff Position (FSP) 157-3, Determining the Fair Value of a Financial Asset in a Market That is Not Active. The FSP clarifies the application of SFAS No. 157, Fair Value Measurements, in an inactive market, and provides an illustrative example to demonstrate how the fair value of a financial asset is determined when the market for that financial asset is inactive. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption of the FSP did not have a material impact on the Company’s consolidated financial statements.

Business Combinations

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish this, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is applied prospectively to business combinations entered into by the Company after January 1, 2009, with earlier adoption prohibited. The Company will apply the requirements of SFAS No. 141(R) to business combinations consummated after January 1, 2009.

GAAP Hierarchy

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements under GAAP. SFAS No. 162 is effective 60 days following the approval of the Public Company Accounting Oversight Board amendments to AU section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The Company will adopt SFAS No. 162 once effective. The adoption is not expected to have a material impact on its consolidated financial statements.

Useful Life of Intangible Assets

In May 2008, the FASB issued FSP 142-3, Determination of the Useful Life of Intangible Assets. This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. For a recognized intangible asset, an entity shall disclose information that enables users to assess the extent to which the expected future cash flows associated with the asset are affected by the entity’s intent and/or ability to renew or extend the arrangement. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. The FSP will not have a material impact on the Company’s consolidated financial statements.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities

In June 2008, the FASB issued FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities. This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, Earnings Per Share. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. Stock awards granted by the Company under its stock-based compensation plan qualify as a participating security. As required by FSP EITF 03-6-1, the Company adopted this new accounting standard as of January 1, 2009 and applied the new accounting retrospectively for all periods presented. The impact of adopting FSP EITF 03-6-1 is as follows:


			SFAS EITF
	As Previously		03-6-1
	Reported		Adjustments			As Adjusted
2008
Basic Earnings per Common Share
Income from continuing operations	$	3.24	$	(.02	)	$	3.22
Discontinued operations		.13		(.01	)		.12
Cumulative effect of accounting changes		—		—			—

Total	$	3.37	$	(.03	)	$	3.34

Diluted Earnings per Common Share
Income from continuing operations	$	3.23	$	(.01	)	$	3.22
Discontinued operations		.13		(.01	)		.12
Cumulative effect of accounting changes		—		—			—

Total	$	3.36	$	(.02	)	$	3.34

2007
Basic Earnings per Common Share
Income from continuing operations	$	4.64	$	(.02	)	$	4.62
Discontinued operations		1.09		(.01	)		1.08
Cumulative effect of accounting changes		—		—			—

Total	$	5.73	$	(.03	)	$	5.70

Diluted Earnings per Common Share
Income from continuing operations	$	4.62	$	(.01	)	$	4.61
Discontinued operations		1.08		—			1.08
Cumulative effect of accounting changes		—		—			—

Total	$	5.70	$	(.01	)	$	5.69


			SFAS EITF
	As Previously		03-6-1
	Reported		Adjustments			As Adjusted
2006
Basic Earnings per Common Share
Income from continuing operations	$	2.19	$	(.01	)	$	2.18
Discontinued operations		.24		—			.24
Cumulative effect of accounting changes		.01		—			.01

Total	$	2.44	$	(.01	)	$	2.43

Diluted Earnings per Common Share
Income from continuing operations	$	2.18	$	—		$	2.18
Discontinued operations		.24		.01			.24
Cumulative effect of accounting changes		.01		(.01	)		.01

Total	$	2.43	$	—		$	2.43

Disclosures about Derivative Instruments and Guarantees

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This Statement requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company will adopt SFAS No. 161 on January 1, 2009.

In September 2008, the FASB issued FSP No. 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161. This FSP is intended to improve disclosures about credit derivatives by requiring more information about the potential adverse effects of changes in credit risk on the financial position, financial performance, and cash flows of the sellers of credit derivatives. This FSP also requires additional disclosures about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN 45 are effective for reporting periods ending after November 15, 2008. The FSP also clarifies that the disclosures required by SFAS No. 161 should be provided for any reporting period (annual or interim) beginning after November 15, 2008. The Company has adopted these pronouncements as of December 31, 2008. See Note 16 for further disclosures.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. This Statement establishes accounting and reporting standards for the Noncontrolling Interests in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that Noncontrolling Interests in a subsidiary are ownership interests in the consolidated entity that should be reported as equity in the consolidated financial statements. As required by SFAS No. 160, the Company adopted this new standard as of January 1, 2009 and applied the new presentation and disclosure requirements retrospectively for all periods presented. As a result, the formats and captions of certain financial statement amounts presented herein have been revised from amounts previously reported to present Noncontrolling Interests in accordance with SFAS No. 160. The impact of the retrospective application of this standard includes the following:

	•		Minority interest expense — $5 million, $4 million, and $1 million for the years ended 2008, 2007, and 2006, respectively, reclassified as Net Income Attributable to Noncontrolling Interests, Income from Continuing Operations, below Net Income.

	•		Minority interest expense in discontinued operations — $2 million, $(188) million, and $(251) million for the years ended 2008, 2007, and 2006, respectively, reclassified as Net Income Attributable to Noncontrolling Interests, Income (loss) from discontinued operations, below Net income.

	•		Minority interest — $43 million and $48 million, as of December 31, 2008 and 2007, respectively, previously included in liabilities moved to Noncontrolling Interests in Total Shareholders’ Equity on our Consolidated Statements of Financial Position.

	•		Separately reflect Noncontrolling Interests activity in the Consolidated Statement of Changes in Shareholders’ Equity and Consolidated Statements of Comprehensive Income.

Offsetting Amounts Related to Certain Contracts

In April 2007, the FASB issued FSP FIN 39-1, Amendment of FASB Interpretation No. 39. This FSP permits the Company to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, the Company is permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007. It is applied retrospectively by adjusting the financial statements for all periods presented. The Company adopted FSP FIN 39-1 as of January 1, 2008. At adoption, the Company chose to offset the collateral amounts against the fair value of derivative assets and liabilities, reducing both the Company’s total assets and total liabilities. The Company retrospectively reclassified certain assets and liabilities on the Consolidated Statement of Financial Position at December 31, 2007 as follows:


	As Previously		FSP FIN 39-1
	Reported		Adjustments			As Adjusted
	(In millions)
Current Assets
Accounts receivable-other	$	504	$	10		$	514
Derivative assets		195		(14	)		181
Other Assets
Derivative assets		207		(8	)		199
Current Liabilities
Accounts payable		1,198		(9	)		1,189
Derivative liabilities		282		(1	)		281
Other Liabilities
Derivative liabilities		452		(2	)		450

The total cash collateral received, net of cash collateral posted was $30 million at December 31, 2008. In accordance with FSP FIN 39-1, derivative assets and derivative liabilities are shown net of collateral of $31 million and $17 million, respectively. At December 31, 2008, amounts not related to unrealized derivative positions totaling $7 million and $23 million were included in accounts receivable and accounts payable, respectively.

Disclosures about Transfers of Financial Assets and Interests in Variable Interest Entities

In December 2008, the FASB issued FASB Staff Position (FSP) FAS 140-4 and FIN 46(R)-8, Disclosures about Transfers of Financial Assets and Interest in Variable Interest Entities. The purpose of the FSP is to promptly improve disclosures by public entities and enterprises until the pending amendments to FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, are finalized and approved by the Board. Effective for reporting periods ending after December 15, 2008, the FSP amends Statement 140 to require public entities to provide additional disclosures about transfers of financial assets and variable interests in qualifying special-purpose entities. It also amends FIN 46(R) to require public enterprises to provide additional disclosures about their involvement with variable interest entities. The adoption of this FSP did not have a material impact on the Company’s consolidated financial statements. See Note 1.

Employers’ Disclosures about Postretirement Benefit Plan Assets

On December 30, 2008, the FASB issued FASB Staff Position (FSP) FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. This FSP amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The disclosure requirements required by this FSP are effective for fiscal years ending after December 15, 2009. The Company will adopt this FSP on December 31, 2009.

NOTE 3 — DISPOSALS AND DISCONTINUED OPERATIONS

Sale of Antrim Shale Gas Exploration and Production Business

In 2007, the Company sold its Antrim shale gas exploration and production business (Antrim) for gross proceeds of $1.3 billion. The pre-tax gain recognized on this sale amounted to $900 million ($580 million after-tax) and is reported on the Consolidated Statements of Operations under the line item, “Gain on sale of non-utility business,” and included in the Corporate & Other segment. Prior to the sale, the operating results of Antrim were reflected in the Unconventional Gas Production segment.

The Antrim business is not presented as a discontinued operation due to continuation of cash flows related to the sale of a portion of Antrim’s natural gas production to Energy Trading under the terms of natural gas sales contracts that expire in 2010 and 2012. These continuing cash flows, while not significant to DTE Energy, are significant to Antrim and therefore meet the definition of continuing cash flows as described in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations.

Prior to the sale, a substantial portion of the Company’s price risk related to expected gas production from its Antrim shale business had been hedged through 2013. These financial contracts were accounted for as cash flow hedges, with changes in estimated fair value of the contracts reflected in other comprehensive income. Upon the sale of Antrim, the financial contracts no longer qualified as cash flow hedges. In conjunction with the Antrim sale, the Company reclassified amounts held in accumulated other comprehensive income and recorded the effective settlements, reducing operating revenues in 2007 by $323 million.

Plan to Sell Interest in Certain Power and Industrial Projects

During the third quarter of 2007, the Company announced its plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During 2008, the United States asset sale market weakened and challenges in the debt market persisted. As a result of these developments, the Company’s work on this planned monetization was discontinued. As of June 30, 2008, the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used. During the second quarter of 2008, the Company recorded a loss of $19 million related to the valuation adjustment for the cumulative depreciation and amortization not recorded during the held for sale period. The Consolidated Statements of Financial Position included $28 million of Noncontrolling Interests in the Projects classified as held for sale as of December 31, 2007.

The following table presents the major classes of assets and liabilities of the Projects classified as held for sale at December 31, 2007:


	(In millions)
Cash and cash equivalents	$	11
Accounts receivable (less allowance for doubtful accounts of $4)		65
Inventories		4
Other current assets		3

Total current assets held for sale		83

Investments		55
Property, plant and equipment, net of accumulated depreciation of $183		285
Intangible assets		38
Long-term notes receivable		46
Other noncurrent assets		1

Total noncurrent assets held for sale		425

Total assets held for sale	$	508

Accounts payable	$	38
Other current liabilities		10

Total current liabilities associated with assets held for sale		48

Long-term debt (including capital lease obligations of $31)		53
Asset retirement obligations		16
Other liabilities		13

Total noncurrent liabilities associated with assets held for sale		82

Total liabilities related to assets held for sale	$	130

Sale of Interest in Barnett Shale Properties

In 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $260 million. As of December 31, 2007, property, plant and equipment of approximately $122 million, net of approximately $14 million of accumulated depreciation and depletion, was classified as held for sale. The Company recognized a gain of $128 million ($81 million after-tax) on the sale during 2008.

Synthetic Fuel Business

The Company discontinued the operations of its synthetic fuel production facilities throughout the United States as of December 31, 2007. Synfuel plants chemically changed coal and waste coal into a synthetic fuel as determined under the Internal Revenue Code. Production tax credits were provided for the production and sale of solid synthetic fuel produced from coal and were available through December 31, 2007. The synthetic fuel business generated operating losses that were substantially offset by production tax credits.

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential commercial, environmental, oil price and tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at December 31, 2008 is $2.9 billion.

As shown in the following table, the Company has reported the business activity of the synthetic fuel business as a discontinued operation. The amounts exclude general corporate overhead costs:


	2008			2007			2006
	(In millions)
Operating Revenues	$	7		$	1,069		$	863
Operation and Maintenance		9			1,265			1,019
Depreciation and Amortization		(2	)		(6	)		24
Taxes other than Income		(1	)		5			12
Asset (Gains) and Losses, Reserves and Impairments, Net(1)		(31	)		(280	)		40

Operating Income (Loss)		32			85			(232	)
Other (Income) and Deductions		(2	)		(9	)		(20	)
Income Taxes
Provision		13			98			14
Production Tax Credits		(1	)		(21	)		(23	)

		12			77			(9	)

Net Income (Loss)		22			17			(203	)
Noncontrolling Interests		2			(188	)		(251	)

Net Income Attributable to DTE Energy Company(1)	$	20		$	205		$	48


(1)		Includes intercompany pre-tax gain of $32 million ($21 million after-tax) for 2007.

NOTE 4 — OTHER IMPAIRMENTS AND RESTRUCTURING

Other Impairments

Barnett shale

Our Unconventional Gas Production segment recorded pre-tax impairment losses of $8 million and $27 million in 2008 and 2007, respectively. The 2008 impairment related primarily to the write-off of leases that expired or will expire within the next twelve months and are not expected to be developed under current economic conditions. The 2007 impairment consisted of expired leases in Bosque County, which is located in the southern expansion area of the Barnett shale in North Texas. The properties were impaired due to the lack of economic and operating viability of the properties. Impairment losses were recorded within the Other asset (gains) and losses, reserves, and impairments, net line in the Consolidated Statements of Operations.

Landfill Gas Recovery

In 2006, the Company’s Power and Industrial Projects segment recorded a pre-tax impairment loss of $14 million at its landfill gas recovery unit relating to the write down of assets at several landfill sites. The fixed assets were impaired due to continued operating losses and the oil price-related phase-out of production tax credits. The impairment was recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations. The Company calculated the expected

undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of certain assets was not recoverable. The Company determined the fair value of the assets utilizing a discounted cash flow technique.

Non-Utility Power Generation

In 2006, the Power and Industrial Projects segment recorded a pre-tax impairment loss totaling $74 million for its investments in two natural gas-fired electric generating plants.

A loss of $42 million related to a 100% owned plant is recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations. The generating plant was impaired due to continued operating losses and the September 2006 delisting by MISO, resulting in the plant no longer providing capacity for the power grid. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the plant, which indicated that the carrying amount of the plant was not recoverable. The Company determined the fair value of the plant utilizing a discounted cash flow technique.

A loss of $32 million related to a 50% equity interest in a gas-fired peaking electric generating plant is recorded within the Other (income) and deductions, Other expenses line in the Consolidated Statements of Operations. The investment was impaired due to continued operating losses and the expected sale of the investment. The Company determined the fair value of the plant utilizing a discounted cash flow technique, which indicated that the carrying amount of the investment exceeded its fair value.

Waste Coal Recovery

In 2006, our Power and Industrial Projects segment recorded a pre-tax impairment loss of $19 million related to its investment in proprietary technology used to refine waste coal. The fixed assets at our development operation were impaired due to continued operating losses and negative cash flow. In addition, the Company impaired all of its patents related to waste coal technology. The Company calculated the expected undiscounted cash flows from the use and eventual disposition of the assets, which indicated that the carrying amount of the assets was not recoverable. The Company determined the fair value of the assets utilizing a discounted cash flow technique. The impairment loss was recorded within the Other asset (gains) and losses, reserves and impairments, net line in the Consolidated Statements of Operations.

Restructuring Costs

In 2005, the Company initiated a company-wide review of its operations called the Performance Excellence Process. Specifically, the Company began a series of focused improvement initiatives within Detroit Edison and MichCon, and associated corporate support functions. The Company incurred costs to achieve (CTA) restructuring expense for employee severance and other costs. Other costs include project management and consultant support. In September 2006, the MPSC issued an order approving a settlement agreement that allows Detroit Edison and MichCon, commencing in 2006, to defer the incremental CTA. Further, the order provides for Detroit Edison and MichCon to amortize the CTA deferrals over a ten-year period beginning with the year subsequent to the year the CTA was deferred. Detroit Edison deferred approximately $24 million, $54 million and $102 million of CTA in 2008, 2007 and 2006 as a regulatory asset. The recovery of these costs was provided for by the MPSC in the order approving the settlement in the show cause proceeding and in the December 23, 2008 MPSC rate order. Amortization of prior year deferred CTA costs amounted to $16 million in 2008 and $10 million in 2007. MichCon cannot defer CTA costs at this time because a regulatory recovery mechanism has not been established by the MPSC. MichCon expects to seek a recovery mechanism in its next rate case expected to be filed in 2009.

Amounts expensed are recorded in the Operation and maintenance line on the Consolidated Statements of Operations. Deferred amounts are recorded in the Regulatory asset line on the Consolidated Statements of Financial Position. Costs incurred in 2008, 2007 and 2006 are as follows:


	Employee
	Severance Costs						Other Costs						Total Cost
	2008		2007		2006		2008		2007		2006		2008		2007		2006
	(In millions)
Costs incurred:
Electric Utility	$	—	$	15	$	51	$	26	$	50	$	56	$	26	$	65	$	107
Gas Utility		—		3		17		7		6		7		7		9		24
Other		—		1		2		3		1		1		3		2		3

Total costs		—		19		70		36		57		64		36		76		134
Less amounts deferred or capitalized:
Electric Utility		—		15		51		26		50		56		26		65		107

Amount expensed	$	—	$	4	$	19	$	10		7	$	8	$	10	$	11	$	27

NOTE 5 — REGULATORY MATTERS

Regulation

Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to 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.

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:


	2008			2007
	(In millions)
Assets
Securitized regulatory assets	$	1,001		$	1,124

Recoverable income taxes related to securitized regulatory assets	$	549		$	616
Recoverable pension and postretirement costs
Pension		1,505			495
Postretirement costs		787			496
Asset retirement obligation		452			266
Other recoverable income taxes		89			94
Recoverable costs under PA 141
Excess capital expenditures		4			11
Deferred Clean Air Act expenditures		10			28
Midwest Independent System Operator charges		8			23
Electric Customer Choice implementation costs		37			58
Enhanced security costs		6			10
Unamortized loss on reacquired debt		73			67
Deferred environmental costs		43			41
Accrued PSCR/GCR revenue		22			76
Recoverable uncollectibles expense		122			42
Cost to achieve Performance Excellence Process		154			146
Enterprise Business Systems costs		26			26
Deferred income taxes — Michigan Business Tax		394			364
Other		2			3

		4,283			2,862
Less amount included in current assets		(52	)		(76	)

	$	4,231		$	2,786


Liabilities
Asset removal costs	$	534		$	581
Accrued pension
Pension equalization mechanism		72			44
Negative pension offset		110			71
Accrued PSCR/GCR refund		11			70
Refundable costs under PA 141		16			—
Refundable income taxes		93			104
Fermi 2 refueling outage		25			4
Deferred income taxes — Michigan Business Tax		388			364
Other		5			5

		1,254			1,243
Less amount included in current liabilities		(52	)		(75	)

	$	1,202		$	1,168

As noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in Detroit Edison or MichCon’s rate base, thereby providing a return on invested costs. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base.

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 over a fourteen-year period ending 2015.

	•		Recoverable pension and postretirement costs — In 2007, the Company adopted SFAS No. 158 which required, among other things, the recognition in other comprehensive income of the actuarial gains or losses and the prior service costs that arise during the period but that are not immediately recognized as components of net periodic benefit costs. The Company received approval from the MPSC to record the charge related to the additional liability as a regulatory asset since the traditional rate setting process allows for the recovery of pension and postretirement costs. The asset will reverse as the deferred items are recognized as benefit expenses in net income. (1)

	•		Asset retirement obligation — Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 and FIN 47. These obligations are primarily for Fermi 2 decommissioning costs. The asset captures the timing differences between expense recognition and current recovery in rates and will reverse over the remaining life of the related plant. (1)

	•		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. This asset will reverse over the remaining life of the related plant. (1)

	•		Excess capital expenditures — 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.

	•		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 609 of 2002 permits, after MPSC authorization, the recovery of enhanced 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 Gas Utility’s former MGP sites. This asset is offset in working capital by an environmental liability reserve. The amortization of the regulatory asset is not included in MichCon’s current rates because it is offset by the recognition of insurance proceeds. MichCon will request recovery of the remaining asset balance in future rate filings after the recognition of insurance proceeds is complete. (1)

	•		Accrued PSCR revenue — Receivable for the temporary under-recovery of and a return on fuel and purchased power costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

	•		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.

	•		Recoverable uncollectibles expense — MichCon receivable for the MPSC approved uncollectible expense true-up mechanism that tracks the difference in the fluctuation in uncollectible accounts and amounts recognized pursuant to the MPSC authorization.

	•		Cost to achieve Performance Excellence Process (PEP) — The MPSC authorized the deferral of costs to implement the PEP. These costs consist of employee severance, project management and consultant support. These costs will be amortized over a ten-year period beginning with the year subsequent to the year the costs were deferred.

	•		Enterprise Business Systems (EBS) costs — The MPSC approved the deferral and amortization over 10 years beginning in January 2009 of EBS costs that would otherwise be expensed. (1)

•

Deferred income taxes — Michigan Business Tax (MBT) - In July 2007, the MBT was enacted by the State of Michigan. State deferred tax liabilities were established for the Company’s utilities, and offsetting regulatory assets were recorded as the impacts of the deferred tax liabilities will be reflected in rates as the related taxable temporary differences reverse and flow through current income tax expense. (1)


(1)		Regulatory assets not earning a return.

LIABILITIES

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

	•		Pension equalization mechanism — Pension expense refundable to customers representing the difference created from volatility in the pension obligation and amounts recognized pursuant to MPSC authorization.

	•		Negative pension offset — MichCon’s negative pension costs are not included as a reduction to its authorized rates; therefore, the Company is accruing a regulatory liability to eliminate the impact on earnings of the negative pension expense accrued. This regulatory liability will reverse to the extent MichCon’s pension expense is positive in future years.

	•		Accrued PSCR refund — Payable for the temporary over-recovery of and a return on power supply costs and transmission costs incurred by Detroit Edison which are recoverable through the PSCR mechanism.

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

	•		Refundable costs under PA 141 — Detroit Edison’s 2007 Choice Incentive Mechanism (CIM) reconciliation and allocation resulted in the elimination of Regulatory Asset Recovery Surcharge (RARS) balances for commercial and industrial customers. RARS revenues received in 2008 that exceed the regulatory asset balances are required to be refunded to the affected classes.

	•		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.

	•		Fermi 2 refueling outage — Accrued liability for refueling outage at Fermi 2 pursuant to MPSC authorization.

	•		Deferred income taxes — Michigan Business Tax — In July 2007, the MBT was enacted by the State of Michigan. State deferred tax assets were established for the Company’s utilities, and offsetting regulatory liabilities were recorded as the impacts of the deferred tax assets will be reflected in rates.

MPSC Show Cause Order

In March 2006, the MPSC issued an order directing Detroit Edison to show cause by June 1, 2006 why its rates should not be reduced in 2007. Subsequently, Detroit Edison filed its response to this order and the MPSC issued an order approving a settlement agreement in this proceeding on August 31, 2006. The order provided for an annualized rate reduction of $53 million for 2006, effective September 5, 2006. Beginning January 1, 2007, and continuing until April 13, 2008, one year from the filing of the general rate case on April 13, 2007, rates were reduced by an additional $26 million, for a total reduction of $79 million annually. The revenue reduction is net of the recovery of the amortization of the costs associated with the implementation of the Performance Excellence Process. The settlement agreement provided for some level of realignment of the existing rate structure by allocating a larger percentage share of the rate reduction to the commercial and industrial customer classes than to the residential customer classes.

As part of the settlement agreement, a CIM was established with a base level of electric choice sales set at 3,400 GWh. The CIM prescribes regulatory treatment of changes in non-fuel revenue attributed to increases or decreases in electric Customer Choice sales. If electric Customer Choice sales exceed 3,600 GWh, Detroit Edison will be able to recover 90% of its reduction in non-fuel revenue from full service customers, up to $71 million. If electric Customer Choice sales fall below 3,200 GWh, Detroit Edison will credit 100% of the increase in non-fuel revenue to the unrecovered regulatory asset balance. In March 2008, Detroit Edison filed a reconciliation of its CIM for the year 2007. Detroit Edison’s annual Electric Choice sales for 2007 were 2,239 GWh which was below the base level of sales of 3,200 GWh. Accordingly, the Company used the resulting additional non-fuel revenue to reduce unrecovered regulatory asset balances related to the RARS mechanism. This reconciliation did not result in any rate increase.

In November 2008, a settlement was filed in the 2007 CIM reconciliation. In the settlement, the parties agreed that the Detroit Edison 2007 CIM reconciliation and allocation filing was correct. All RARS revenues received in 2008 that exceed the regulatory asset balances will be refunded to the affected customer classes, and the only remaining classes to be reconciled in the RARS reconciliation case are the Residential and Special Manufacturing Contract classes. On January 13, 2009, the MPSC issued an order approving the settlement agreement.

2007 Electric Rate Case Filing

Pursuant to the February 2006 MPSC order in Detroit Edison’s rate restructuring case and the August 2006 MPSC order in the settlement of the show cause case, Detroit Edison filed a general rate case on April 13, 2007 based on a 2006 historical test year. Supplements and updates were filed on August 31, 2007 and February 20, 2008.

On December 23, 2008, the MPSC issued an order in Detroit Edison’s February 20, 2008 updated rate case filing. The MPSC approved an annual revenue increase of $84 million effective January 14, 2009 or 2.0% average increase in Detroit Edison’s annual revenue requirement for 2009. Included in the approved $84 million increase in revenues is a return on equity of 11% on an expected 49% equity and 51% debt capital structure.

Other key aspects of the MPSC order include the following:

	•		In order to more accurately reflect the actual cost of providing service to business customers, the MPSC adopted an immediate 39% phase out of the residential rate subsidy, with the remaining amount to be eliminated in equal installments over the next five years, every October 1.

	•		Accepted Detroit Edison’s proposal to reinstate and modify the tracking mechanism on Electric Choice sales (CIM) with a base level of 1,561 GWh. The modified mechanism will not have a cap on the amount recoverable.

	•		Accepted Detroit Edison’s proposal to terminate the Pension Equalization Mechanism.

	•		Approved an annual reconciliation mechanism to track expenses associated with restoration costs (storm and non-storm related expenses) and line clearance expenses. Annual reconciliations will be required using a base expense level of $110 million and $51 million, respectively.

	•		Approved Detroit Edison’s proposal to recover a return on $15 million of costs in working capital associated with expenses associated with preparation of an application for a new nuclear generation facility at its current Fermi 2 site.

2009 Electric Rate Case Filing

Detroit Edison filed a general rate case on January 26, 2009 based on a twelve months ended June 2008 historical test year. The filing with the MPSC requested a $378 million, or 8.1% average increase in Detroit Edison’s annual revenue requirement for the twelve months ended June 30, 2010 projected test year.

The requested $378 million increase in revenues is required to recover the increased costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, customer uncollectible accounts, inflation, the capital costs of plant additions and the reduction in territory sales.

In addition, Detroit Edison’s filing made, among other requests, the following proposals:

	•		Continued progress toward correcting the existing rate structure to more accurately reflect the actual cost of providing service to business customers;

	•		Continued application of an adjustment mechanism to enable the Company to address the costs associated with retail electric customers migrating to and from Detroit Edison’s full service retail electric tariff service;

	•		Application of an uncollectible expense true-up mechanism based on the $87 million expense level of uncollectible expenses that occurred during the 12 month period ended June 2008;

	•		Continued application of the storm restoration expense recovery mechanism and modification to the line clearance expense recovery mechanism; and

	•		Implementation of a revenue decoupling mechanism.

Cost-Based Tariffs for Schools

In January 2009, Detroit Edison filed a required application that included two new cost-based tariffs for schools, universities and community colleges. The filing is in compliance with Public Act 286 which required utilities to file tariffs that ensure that eligible educational institutions are charged retail electric rates that reflect the actual cost of providing service to those customers. In February 2009, an MPSC order consolidated this proceeding with the January 26, 2009 electric rate case filing.

Accounting for Costs Related to Enterprise Business Systems

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize costs related to EBS, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. In April 2005, the MPSC approved a settlement agreement providing for the deferral of certain EBS costs, which would otherwise be expensed, as a regulatory asset for future rate recovery starting January 1, 2006. At December 31, 2008, approximately $26 million of EBS costs have been deferred as a regulatory asset. In the MPSC’s December 2008 order in the 2007 Detroit Edison rate case, the Commission approved the recovery of deferred EBS costs over a 10-year period beginning in January 2009.

Fermi 2 Enhanced Security Costs Settlement

The Customer Choice and Electricity Reliability Act, as amended in 2003, allows for the recovery of reasonable and prudent costs of new and enhanced security measures required by state or federal law, including providing for reasonable security from an act of terrorism. In April 2007, the MPSC approved a settlement agreement that authorizes Detroit Edison to recover Fermi 2 Enhanced Security Costs (ESC) incurred during the period of September 11, 2001 through December 31, 2005. The settlement defined Detroit Edison’s ESC, discounted back to September 11, 2001, as $9.1 million plus carrying charges. A total of $13 million, including carrying charges, has been deferred as a regulatory asset. Detroit Edison is authorized to incorporate into its rates an enhanced security factor over a period not to exceed five years. Amortization expense related to this regulatory asset was approximately $4 million and $3 million for the years ended December 31, 2008, and 2007, respectively.

Reconciliation of Regulatory Asset Recovery Surcharge

In December 2006, Detroit Edison filed a reconciliation of costs underlying its existing RARS. This true-up filing was made to maximize the remaining time for recovery of significant cost increases prior to expiration of the RARS 5-year recovery limit under PA 141. Detroit Edison requested a reconciliation of the regulatory asset surcharge to ensure proper recovery by the end of the 5-year period of: (1) Clean Air Act Expenditures, (2) Capital in Excess of Base Depreciation, (3) MISO Costs and (4) the regulatory liability for the 1997 Storm Charge. In July 2007, the MPSC approved a negotiated RARS deficiency settlement that resulted in a $10 million write-down of RARS-related costs in 2007. As discussed above, the CIM in the MPSC Show-Cause Order will reduce the regulatory asset. Approximately $11 million and $28 million was credited to the unrecovered regulatory asset balance during the years ended December 31, 2008 and 2007, respectively. The CIM expired in April 2008.

Power Supply Cost Recovery Proceedings

2005 Plan Year — In March 2006, Detroit Edison filed its 2005 PSCR reconciliation that sought approval for recovery of an under-collection of approximately $144 million at December 31, 2005 from its commercial and industrial customers. In addition to the 2005 PSCR plan year reconciliation, the filing included reconciliation for the Pension Equalization Mechanism (PEM) for the periods from November 24, 2004 through December 31, 2004 and from January 1, 2005 through December 31, 2005. The PEM reconciliation seeks to allocate and refund approximately $12 million to customers based on their contributions to pension expense during the subject periods. An order was issued on May 22, 2007 approving a 2005 PSCR under-collection amount of $94 million and the recovery of this amount through a surcharge for 12 months beginning in June 2007. In addition, the order approved Detroit Edison’s proposed

PEM reconciliation that was refunded to customers on a bills-rendered basis during June 2007. The surcharge will be reconciled in the Company’s 2008 PSCR reconciliation.

2006 Plan Year — In March 2007, Detroit Edison filed its 2006 PSCR reconciliation that sought approval for recovery of an under-collection of approximately $51 million. Included in the 2006 PSCR reconciliation filing was the Company’s PEM reconciliation that reflects a $21 million over-collection which is subject to refund to customers. An MPSC order was issued on April 22, 2008 approving the 2006 PSCR under-collection amount of $51 million and the recovery of this amount as part of the 2007 PSCR factor. In addition, the order approved Detroit Edison’s PEM reconciliation and authorized the Company to refund the $22 million over-recovery, including interest, to customers in May 2008. The refund will be reconciled in the Company’s 2008 PEM reconciliation.

2007 Plan Year — In September 2006, Detroit Edison filed its 2007 PSCR plan case seeking approval of a levelized PSCR factor of 6.98 mills per kWh above the amount included in base rates for all PSCR customers. The Company’s PSCR plan filing included $130 million for the recovery of its projected 2006 PSCR under-collection, bringing the total requested PSCR factor to 9.73 mills/kWh. The Company filed supplemental testimony and briefs in December 2006 supporting its updated request to include approximately $81 million for the recovery of its projected 2006 PSCR under-collection. The MPSC issued a temporary order in December 2006 approving the Company’s request. In addition, Detroit Edison was granted the authority to include all PSCR over/(under) collections in future PSCR plans, thereby reducing the time between refund or recovery of PSCR reconciliation amounts. The Company began to collect its 2007 power supply costs, including the 2006 rollover amount, through a PSCR factor of 8.69 mills/kWh on January 1, 2007. In August 2007, the MPSC approved Detroit Edison’s 2007 PSCR plan case and authorized the Company to charge a maximum power supply cost recovery factor of 8.69 mills/kWh in 2007. The Company filed its 2007 PSCR reconciliation case in March 2008 and updated the filing in December 2008. The updated filing requests recovery of a $41 million PSCR under-collection through its 2008 PSCR plan. Included in the 2007 PSCR reconciliation filing was the Company’s 2007 PEM reconciliation that reflects a $21 million over-collection, including interest and prior year refunds. The Company expects an order in this proceeding in the second quarter of 2009.

2008 Plan Year — In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. Also included in the filing was a request for approval of the Company’s emission compliance strategy which included pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind) energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On July 29, 2008, the MPSC issued a temporary order approving Detroit Edison’s request to increase the PSCR factor to 11.22 mills/kWh. In January 2009, the MPSC approved the Company’s 2008 PSCR plan and authorized the Company to charge a maximum PSCR factor of 11.22 mills/kWh for 2008.

2009 Plan Year — In September 2008, Detroit Edison filed its 2009 PSCR plan case seeking approval of a levelized PSCR factor of 17.67 mills/kWh above the amount included in base rates for residential customers and a levelized PSCR factor of 17.29 mills/kWh above the amount included in base rates for commercial and industrial customers. The Company is supporting a total power supply expense forecast of $1.73 billion. The plan also includes approximately $69 million for the recovery of its projected 2008 PSCR under-collection from all customers and approximately $12 million for the refund of its 2005 PSCR reconciliation surcharge over-collection to commercial and industrial customers only. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a renewable (wind) energy project. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including, fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowance costs, transmission costs and MISO costs. The Company self-implemented a PSCR factor of 11.64 mills/kWh above the amount included in base rates for residential customers and a PSCR factor of 11.22 mills/kWh above the amount included in base rates for commercial and industrial customers on bills rendered in January 2009. Subsequently, as a result of the December 23, 2008 MPSC order in the 2007 Detroit Edison Rate case, the Company implemented a PSCR factor of 3.18 mills/kWh below the amount included in base rates for residential customers and a PSCR factor of 3.60 mills/kWh below the amount included in base rates for commercial and industrial customers for bills rendered effective January 14, 2009.

2009 MichCon Depreciation Filing

Depreciation Filing — On June 26, 2007, the MPSC issued its final order in the generic hearings on depreciation for Michigan electric and gas utilities. The MPSC ordered Michigan utilities to file depreciation studies using the current method, a FAS 143

approach that considers the time value of money and an inflation adjusted method proposed by the Company that removes excess escalation. In compliance with the MPSC order MichCon filed its ordered depreciation studies on November 3, 2008. The various required depreciation studies indicate composite depreciation rates from 2.07% to 2.55%. The Company has proposed no change to its current composite depreciation rate of 2.97%. The Company expects an order in this proceeding in the fourth quarter of 2009.

Uncollectible Expense True-Up Mechanism (UETM) and Report of Safety and Training-Related Expenditures

2005 UETM — In March 2006, MichCon filed an application with the MPSC for approval of its UETM for 2005. MichCon’s 2005 base rates included $37 million for anticipated uncollectible expenses. Actual 2005 uncollectible expenses totaled $60 million. The true-up mechanism allowed MichCon to recover 90% of uncollectibles that exceeded the $37 million base. Under the formula prescribed by the MPSC, MichCon recorded an under-recovery of approximately $11 million for uncollectible expenses from May 2005 (when the mechanism took effect) through the end of 2005. In December 2006, the MPSC issued an order authorizing MichCon to implement the UETM monthly surcharge for service rendered on and after January 1, 2007.

As part of the March 2006 application with the MPSC, MichCon filed a review of its 2005 annual safety and training-related expenditures. MichCon reported that actual safety and training-related expenditures for the initial period exceeded the pro-rata amounts included in base rates and, based on the under-recovered position, recommended no refund at that time. In the December 2006 order, the MPSC also approved MichCon’s 2005 safety and training report. On October 14, 2008, the State of Michigan Court of Appeals rejected the appeal of the Attorney General of the State of Michigan upholding the right of the MPSC to authorize MichCon to charge the 2005 UETM.

2006 UETM — In March 2007, MichCon filed an application with the MPSC for approval of its UETM for 2006 requesting $33 million of under-recovery plus applicable carrying costs of $3 million. The March 2007 application included a report of MichCon’s 2006 annual safety and training-related expenditures, which showed a $2 million over-recovery. In August 2007, MichCon filed revised exhibits reflecting an agreement with the MPSC Staff to net the $2 million over-recovery and associated interest related to the 2006 safety and training-related expenditures against the 2006 UETM under-recovery. An MPSC order was issued in December 2007 approving the collection of $33 million requested in the August 2007 revised filing. MichCon was authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2008.

2007 UETM — In March 2008, MichCon filed an application with the MPSC for approval of its UETM for 2007 requesting approximately $34 million consisting of $33 million of costs related to 2007 uncollectible expense and associated carrying charges and $1 million of under-collections for the 2005 UETM. The March 2008 application included a report of MichCon’s 2007 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. An MPSC order was issued in December 2008 approving the collection of $34 million requested in the March 2008 filing. MichCon was authorized to implement the new UETM monthly surcharge for service rendered on and after January 1, 2009.

Gas Cost Recovery Proceedings

2005-2006 Plan Year — In June 2006, MichCon filed its GCR reconciliation for the 2005-2006 GCR year. The filing supported a total over-recovery, including interest through March 2006, of $13 million. MPSC Staff and other intervenors filed testimony regarding the reconciliation in which they recommended disallowances related to MichCon’s implementation of its dollar cost averaging fixed price program. In January 2007, MichCon filed testimony rebutting these recommendations. In December 2007, the MPSC issued an order adopting the adjustments proposed by the MPSC Staff, resulting in an $8 million disallowance. Expense related to the disallowance was recorded in 2007. The MPSC authorized MichCon to roll a net over-recovery, inclusive of interest, of $20 million into its 2006-2007 GCR reconciliation. In December 2007, MichCon filed an appeal of the case with the Michigan Court of Appeals. MichCon is currently unable to predict the outcome of the appeal.

2006-2007 Plan Year — In June 2007, MichCon filed its GCR reconciliation for the 2006-2007 GCR year. The filing supported a total under-recovery, including interest through March 2007, of $18 million. In March 2008, the parties reached a settlement agreement that allowed for full recovery of MichCon’s GCR costs during the 2006-2007 GCR year. The under-recovery, including interest through March 2007, agreed to under the settlement is $9 million and was included in the 2007-2008 GCR reconciliation. An MPSC order was issued on April 22, 2008 approving the settlement.

2007-2008 Plan Year / Base Gas Sale Consolidated — In August 2006, MichCon filed an application with the MPSC requesting permission to sell base gas that would become accessible with storage facilities upgrades. In December 2006, MichCon filed its 2007-2008 GCR plan case proposing a maximum GCR factor of $8.49 per Mcf. In August 2007, a settlement agreement in this proceeding was reached by all intervening parties that provided for a sharing with customers of the proceeds from the sale of base gas. In addition, the agreement provided for a rate case filing moratorium until January 1, 2009, unless certain unanticipated changes occur that impact income by more than $5 million. The settlement agreement was approved by the MPSC in August 2007. Under the settlement terms, MichCon delivered 13.4 Bcf of this gas to its customers through 2007 at a savings to market-priced supplies of approximately $41 million. This settlement also provided for MichCon to retain the proceeds from the sale of 3.6 Bcf of base gas, of which MichCon sold 0.75 Bcf of base gas in 2007 at a pre-tax gain of $5 million and 2.84 Bcf in December 2008 at a pre-tax gain of $22 million. In June 2008, MichCon filed its GCR reconciliation for the 2007-2008 GCR year. The filing supported a total under-recovery, including interest through March 2008, of $10 million.

2008-2009 Plan Year — In December 2007, MichCon filed its GCR plan case for the 2008-2009 GCR Plan year. MichCon filed for a maximum GCR factor of $8.36 per Mcf, adjustable by a contingent mechanism. In June 2008, MichCon made an informational filing documenting the increase in market prices for gas since its December 2007 filing and calculating its new maximum factor of $10.76 per Mcf based on its contingent mechanism. On August 26, 2008, the MPSC approved a partial settlement agreement which includes the establishment of a new maximum base GCR factor of $11.36 per Mcf that will not be subject to adjustment by contingent GCR factors for the remainder of the 2008-2009 GCR plan year. An MPSC order addressing the remaining issues in this case is expected in 2009.

2009-2010 Plan Year — In December 2008, MichCon filed its GCR plan case for the 2009-2010 GCR Plan year. MichCon filed for a maximum GCR factor of $8.46 per Mcf, adjustable by a contingent mechanism. An MPSC order in this case is expected in 2009.

2009 Proposed Base Gas Sale — In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. MichCon proposed to sell 1.3 Bcf of the base gas to GCR customers during the 2009-2010 GCR period at cost and to sell the remaining 2.7 Bcf to non-system supply customers in 2009 at market prices. MichCon requested that the MPSC treat the proceeds from the sale of the 2.7 Bcf of base gas to non-system supply customers as a one-time increase in MichCon’s net income and not include the proceeds in the calculation of MichCon’s revenue requirements in future rate cases.

Other

In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for further proceedings to establish the precise amount and timing of this recovery. Detroit Edison has filed a supplement to its April 2007 rate case to address the recovery of the merger control premium costs. In September 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger control premium as well as the recovery of transmission costs through the PSCR. The Company is unable to predict the financial or other outcome of any legal or regulatory proceeding at this time.

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

NOTE 6 — NUCLEAR OPERATIONS

General

Fermi 2, the Company’s nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 MW. 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. 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 the insurance policies.

Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2’s unavailability due to an insured event. This policy has a 12-week waiting period and provides 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.

In 2007, the Terrorism Risk Insurance Extension Act of 2005 (TRIA) was extended through December 31, 2014. A major change in the extension is the inclusion of “domestic” acts of terrorism in the definition of covered or “certified” acts. For multiple terrorism losses caused by acts of terrorism not covered under the TRIA 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 $30 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 2005, deferred premium charges up to $117.5 million could be levied against each licensed nuclear facility, but not more than $17.5 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.

Decommissioning

Detroit Edison has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. This obligation is reflected as an asset retirement obligation on the Consolidated Statements of Financial Position. Based on the actual or anticipated extended life of the nuclear plant, decommissioning expenditures for Fermi 2 are expected to be incurred primarily during the period of 2025 through 2050. It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.3 billion in 2008 dollars and $3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, Detroit Edison 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 completed by 2012.

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 and the disposal of low-level radioactive waste. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. The Company believes the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula. The decommissioning assets, anticipated earnings thereon and future revenues from decommissioning collections will be used to decommission Fermi 2. The Company expects the liabilities to be reduced to zero at the conclusion of the decommissioning activities. If amounts remain in the trust funds for Fermi 2 following the completion of the decommissioning activities, those amounts will be disbursed based on rulings by the MPSC and FERC.

A portion of the funds recovered through the Fermi 2 decommissioning surcharge and deposited in external trust accounts is designated for the removal of non-radioactive assets and the clean-up of the Fermi site. This removal and clean-up is not considered a legal liability. Therefore, it is not included in the asset retirement obligation, but is reflected as the nuclear decommissioning regulatory liability.

The decommissioning of Fermi 1 is funded by Detroit Edison. Contributions to the Fermi 1 trust are discretionary.

The following table summarizes the fair value of the nuclear decommissioning trust fund assets.


	As of December 31
	2008		2007
	(In millions)
Fermi 2	$	649	$	778
Fermi 1		3		13
Low level radioactive waste		33		33

Total	$	685	$	824

At December 31, 2008, investments in the external nuclear decommissioning trust funds consisted of approximately 42% in publicly traded equity securities, 57% in fixed debt instruments and 1% in cash equivalents. The debt securities had an average maturity of approximately 5 years. At December 31, 2007, investments in the external nuclear decommissioning trust funds consisted of approximately 54% in publicly traded equity securities, 45% in fixed income and 1% in cash equivalents. The debt securities had an average maturity of approximately 5.3 years.

The costs of securities sold are determined on the basis of specific identification. The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:


	Year Ended December 31
	2008			2007			2006
	(In millions)
Realized gains	$	34		$	25		$	21
Realized losses	$	(49	)	$	(17	)	$	(9	)
Proceeds from sales of securities	$	232		$	286		$	253

Realized gains and losses and proceeds from sales of securities for the Fermi 2 and the low level Radioactive Waste funds are recorded to the asset retirement obligation regulatory asset and nuclear decommissioning regulatory liability, respectively. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:


	Fair		Unrealized
	Value		Gains
	(In millions)
As of December 31, 2008
Equity Securities	$	288	$	65
Debt Securities		388		17
Cash and Cash Equivalents		9		—

	$	685	$	82

As of December 31, 2007
Equity Securities	$	443	$	170
Debt Securities		373		9
Cash and Cash Equivalents		8		—

	$	824	$	179

Securities held in the nuclear decommissioning trust funds are classified as available-for-sale. As Detroit Edison does not have the ability to hold impaired investments for a period of time sufficient to allow for the anticipated recovery of market value, all unrealized losses are considered to be other than temporary impairments.

Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $92 million and $22 million of unrealized losses as regulatory assets for the years ended December 31, 2008 and 2007, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, impairment charges for unrealized losses incurred by the Fermi 1 trust

are recognized in earnings immediately. For the year ended December 31, 2008 no impairment charges were recognized by Detroit Edison for unrealized losses incurred by the Fermi 1 trust. For the year ended December 31, 2007, Detroit Edison recognized impairment charges of $0.2 million, for unrealized losses incurred by the Fermi 1 trust.

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. 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 Federal Nuclear Waste Policy Act of 1982. Detroit Edison currently employs a used nuclear fuel storage strategy utilizing a spent fuel pool. We have begun work on an on-site dry cask storage facility which is expected to provide sufficient storage capability for the life of the plant as defined by the original operating license.

NOTE 7 — 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, 2008 was as follows:


			Ludington
			Hydroelectric
	Belle River		Pumped Storage
In-service date		1984-1985		1973
Total plant capacity	1,260MW		1,872		MW
Ownership interest		*		49	%
Investment (in Millions)	$	1,588	$	165
Accumulated depreciation (in Millions)	$	853	$	106


*		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 8 — INCOME TAXES

Income Tax Summary

The Company files a consolidated federal income tax return. Total income tax expense varied from the statutory federal income tax rate for the following reasons:


	2008			2007			2006
	(In millions)
Income before income taxes	$	819		$	1,155		$	536

Income tax expense at 35% statutory rate	$	287		$	404		$	188
Production tax credits		(7	)		(11	)		(12	)
Investment tax credits		(7	)		(8	)		(8	)
Depreciation		(4	)		(4	)		(4	)
Employee Stock Ownership Plan dividends		(4	)		(5	)		(5	)
Medicare part D subsidy		(5	)		(6	)		(6	)
State and local income taxes, net of federal benefit		23			2			5
Other, net		5			(8	)		(12	)

Income tax expense from continuing operations	$	288		$	364		$	146

Effective income tax rate		35.2	%		31.5	%		27.2	%

Components of income tax expense were as follows:


	2008		2007		2006
	(In millions)
Continuing operations
Current income taxes
Federal	$	130	$	276	$	90
State and other income tax expense		17		1		(2	)

Total current income taxes		147		277		88
Deferred income taxes
Federal		121		85		48
State and other income tax expense		20		2		10

Total deferred income taxes		141		87		58

Total income taxes from continuing operations		288		364		146
Discontinued operations		12		66		(11	)
Cumulative effect of accounting changes		—		—		1

Total	$	300	$	430	$	136

Production tax credits earned in prior years but not utilized totaled $224 million and are carried forward indefinitely as alternative minimum tax credits. The majority of the production tax credits earned, including all of those from our synfuel projects, were generated from projects that had received a private letter ruling (PLR) from the Internal Revenue Service (IRS). These PLRs 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.

Investment tax credits are deferred and amortized to income over the average life of the related property.

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. Consistent with rate making treatment, deferred taxes are offset in the table below for temporary differences which have related regulatory assets and liabilities.

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


	2008			2007
	(In millions)
Property, plant and equipment	$	(1,734	)	$	(1,384	)
Securitized regulatory assets		(545	)		(621	)
Alternative minimum tax credit carry-forwards		224			186
Merger basis differences		51			57
Pension and benefits		33			28
Other comprehensive income		81			62
Derivative assets and liabilities		109			142
State net operating loss and credit carry-forwards		42			28
Other		50			93

		(1,689	)		(1,409	)
Less valuation allowance		(42	)		(28	)

	$	(1,731	)	$	(1,437	)

Current deferred income tax assets	$	227		$	387
Long-term deferred income tax liabilities		(1,958	)		(1,824	)

	$	(1,731	)	$	(1,437	)

Deferred income tax assets	$	1,406		$	1,771
Deferred income tax liabilities		(3,137	)		(3,208	)

	$	(1,731	)	$	(1,437	)

The above table excludes deferred tax liabilities associated with unamortized investment tax credits that are shown separately on the Consolidated Statements of Financial Position.

The Company has state deferred tax assets related to net operating loss and credit carry-forwards of $42 million and $28 million at December 31, 2008 and 2007, respectively. The state net operating loss and credit carry-forwards expire from 2009 through 2029. The Company has recorded valuation allowances at December 31, 2008 and 2007 of approximately $42 million and $28 million, respectively, a change of $14 million, with respect to these deferred tax assets. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income and projections for future taxable income over the periods which the deferred tax assets are deductible, the Company believes it is more likely than not that it will realize the benefits of those deductible differences, net of the existing valuation allowance as of December 31, 2008.

Uncertain Tax Positions

The Company adopted the provisions of FIN 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (FIN 48) on January 1, 2007. This interpretation prescribes a more-likely-than-not recognition threshold and a measurement attribute for the financial statement reporting of tax positions taken or expected to be taken on a tax return. As a result of the implementation of FIN 48, the Company recognized a $5 million increase in liabilities that was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2008			2007
	(In millions)
Balance at January 1	$	22		$	45
Additions for tax positions of prior years		12			4
Reductions for tax positions of prior years		(5	)		(8	)
Additions for tax positions related to the current year		47			—
Settlements		(1	)		(15	)
Lapse of statute of limitations		(3	)		(4	)

Balance at December 31	$	72		$	22

The Company has $18 million of unrecognized tax benefits at December 31, 2008, that, if recognized, would favorably impact our effective tax rate. During the next 12 months it is reasonably possible that the Company will settle certain federal and state tax examinations and audits. Furthermore, during the next 12 months, statutes of limitations will expire for the Company’s tax returns in various states. Therefore, as of December 31, 2008, the Company believes that it is reasonably possible that there will be a decrease in unrecognized tax benefits of $5 million to $9 million within the next twelve months.

The Company recognizes interest and penalties pertaining to income taxes in Interest expense and Other expenses, respectively, on its Consolidated Statements of Operations. Accrued interest pertaining to income taxes totaled $8 million and $7 million at December 31, 2008 and December 31, 2007, respectively. The Company had no accrued penalties pertaining to income taxes. The Company recognized interest expense related to income taxes of $2 million during 2008 and $1 million during 2007.

The Company’s U.S. federal income tax returns for years 2004 and subsequent years remain subject to examination by the IRS. The Company’s Michigan Business Tax for the year 2008 is subject to examination by the State of Michigan. The Company also files tax returns in numerous state and local jurisdictions with varying statutes of limitation.

Michigan Business Tax

In July 2007, the Michigan Business Tax (MBT) was enacted by the State of Michigan to replace the Michigan Single Business Tax (MSBT) effective January 1, 2008. The MBT is comprised of an apportioned modified gross receipts tax of 0.8 percent; and an apportioned business income tax of 4.95 percent. The MBT provides credits for Michigan business investment, compensation, and research and development. The MBT is accounted for as an income tax.

In 2007, a state deferred tax liability of $224 million was recognized by the Company for cumulative differences between book and tax assets and liabilities for the consolidated group. Effective September 30, 2007, legislation was adopted by the State of Michigan creating a deduction for businesses that realize an increase in their deferred tax liability due to the enactment of the MBT. Therefore, a deferred tax asset of $224 million was established related to the future deduction. The deduction will be claimed during the period of 2015 through 2029. The recognition of the enactment of the MBT did not have an impact on our income tax provision for 2007.

The 2007 state consolidated deferred tax liability was increased in 2008 by $19 million to $243 million to reflect changes in federal income tax temporary differences primarily due to an approved IRS change in accounting method for our utilities for tax year 2007. The related one-time deferred tax asset for the tax deduction created for businesses that realize an increase in their deferred tax liability due to enactment of the MBT was also increased by $19 million to $243 million. The deferred tax liabilities of our regulatory utilities were increased by $24 million to $388 million and the corresponding regulatory assets and liabilities were also increased by $24 million to $388 million in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, as the impacts of the deferred tax liabilities and assets recognized upon enactment and amendment of the MBT will be reflected in our rates.

In 2008, the state consolidated deferred tax liability increased by $25 million to $268 million as of December 31, 2008 with $20 million of the increase charged to state deferred tax expense and $5 million charged to the related regulatory assets at the utilities. The regulatory asset at the utilities increased to $394 million as of December 31, 2008.

NOTE 9 — COMMON STOCK

Common Stock

The DTE Energy Board of Directors has authorized the repurchase of up to $1.55 billion of common stock through 2009. Through December 31, 2008, repurchases of approximately $725 million of common stock were made.

Under the DTE Energy Company Long-Term Incentive Plan, the Company grants non-vested stock awards to key employees, primarily management. As a result of a stock award, a settlement of an award of performance shares, or by exercise of a participant’s stock option, the Company may deliver common stock from the Company’s authorized but unissued common stock and/or from outstanding common stock acquired by or on behalf of the Company in the name of the participant. The number of non-vested restricted stock awards is included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded.

Dividends

Certain of the Company’s credit facilities contain a provision requiring the Company to maintain a ratio of consolidated debt to capitalization equal to or less than 0.65:1, which has the effect of limiting the amount of dividends the Company can pay in order to maintain compliance with this provision. The effect of this provision as of December 31, 2008 was to restrict approximately $555 million as payments for dividends of total retained earnings of approximately $3 billion. There are no other effective limitations with respect to the Company’s ability to pay dividends.

NOTE 10 — EARNINGS PER SHARE

The Company reports 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, including stock awards granted under the Company’s stock-based compensation plan that qualify as participating securities. The calculation of 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. Non-vested restricted stock awards are included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested restricted stock awards are excluded, unless considered participating securities. A reconciliation of both calculations is presented in the following table:


	2008		2007		2006
	(In millions, except per share amounts)
Basic Earnings per Share
Income from continuing operations	$	526	$	787	$	389

Average number of common shares outstanding		163		170		178

Income per share of common stock based on weighted average number of shares outstanding	$	3.22	$	4.62	$	2.18

Diluted Earnings per Share
Income from continuing operations	$	526	$	787	$	389

Average number of dilutive shares outstanding		163		171		178

Income per share of common stock assuming issuance of incremental shares	$	3.22	$	4.61	$	2.18

Options to purchase approximately 5 million shares, 2,100 shares, and 100,000 shares of common stock in 2008, 2007 and 2006, respectively, 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.

NOTE 11 — LONG-TERM DEBT

Long-Term Debt

The Company’s long-term debt outstanding and weighted average interest rates(1) of debt outstanding at December 31 were:


	2008			2007
	(In millions)
*Mortgage bonds, notes, and other*
DTE Energy Debt, Unsecured
6.7% due 2009 to 2033	$	1,497		$	1,496
Detroit Edison Taxable Debt, Principally Secured
5.9% due 2010 to 2038		2,841			2,305
Detroit Edison Tax-Exempt Revenue Bonds(2)
5.2% due 2011 to 2036		1,263			1,213
MichCon Taxable Debt, Principally Secured
6.1% due 2012 to 2033		889			715
Other Long-Term Debt, Including Non-Recourse Debt		188			196

		6,678			5,925
Less debt associated with assets held for sale		—			(22	)
Less amount due within one year		(220	)		(327	)

	$	6,458		$	5,576

*Securitization bonds*
6.4% due 2009 to 2015	$	1,064		$	1,185
Less amount due within one year		(132	)		(120	)

	$	932		$	1,065

*Trust preferred — linked securities*
7.8% due 2032	$	186		$	186
7.5% due 2044		103			103

	$	289		$	289


(1)		Weighted average interest rates as of December 31, 2008 are shown below the description of each category of debt.

(2)		Detroit Edison Tax Exempt Revenue Bonds are issued by a public body that loans the proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds.

Debt Issuances

In 2008, the Company has issued or remarketed the following long-term debt:


Company	Month Issued	Type	Interest Rate			Maturity		Amount
		(In millions)
MichCon	April	Senior Notes(1)		5.26	%		2013	$	60
MichCon	April	Senior Notes(1)		6.04	%		2018		100
MichCon	April	Senior Notes(1)		6.44	%		2023		25
Detroit Edison	April	Tax-Exempt Revenue Bonds(2)	Variable				2036		69
Detroit Edison	May	Tax-Exempt Revenue Bonds(2)	Variable				2029		118
Detroit Edison	May	Tax-Exempt Revenue Bonds(3)		5.30	%		2030		51
MichCon	June	Senior Notes(4)		6.78	%		2028		75
Detroit Edison	June	Senior Notes(1)		5.60	%		2018		300
Detroit Edison	July	Tax-Exempt Revenue Bonds(5)	Variable				2020		32
MichCon	August	Senior Notes(6)		5.94	%		2015		140
MichCon	August	Senior Notes(6)		6.36	%		2020		50
Detroit Edison	October	Senior Notes(1)		6.40	%		2013		250
Detroit Edison	December	Tax-Exempt Revenue Bonds(7)		6.75	%		2038		50

								$	1,320


(1)		Proceeds were used to pay down short-term debt and for general corporate purposes.

(2)		Proceeds were used to refinance auction rate Tax-Exempt Revenue Bonds.

(3)		These Tax-Exempt Revenue Bonds were converted from an auction rate mode and remarketed in a fixed rate mode to maturity.

(4)		Proceeds were used to repay the 6.45% Remarketable Securities due 2038 subject to mandatory or optional tender on June 30, 2008.

(5)		Proceeds were used to refinance Tax-Exempt Revenue Bonds that matured July 2008.

(6)		Proceeds were used to repay a portion of the $200 million MichCon 6.125% Senior Notes due September 2008.

(7)		Proceeds to be used to finance the construction, acquisition, improvement and installation of certain solid waste disposal facilities at Detroit Edison’s Monroe Power Plant.

Debt Retirements and Redemptions

In 2008, the following debt has been retired, through optional redemption or payment at maturity:


Company	Month Retired	Type	Interest Rate			Maturity		Amount
		(In millions)
Detroit Edison	April	Tax-Exempt Revenue Bonds(1)	Variable				2036	$	69
Detroit Edison	May	Tax-Exempt Revenue Bonds(1)	Variable				2029		118
MichCon	June	Remarketable Securities(2)		6.45	%		2038		75
Detroit Edison	July	Tax-Exempt Revenue Bonds(3)		7.00	%		2008		32
MichCon	September	Senior Notes(4)		6.125	%		2008		200

								$	494


(1)		These Tax-Exempt Revenue Bonds were converted from auction rate mode and subsequently redeemed with proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.


(2)		These Remarketable Securities were optionally redeemed by MichCon with proceeds from the issuance of new MichCon Senior Notes.

(3)		These Tax-Exempt Revenue Bonds were redeemed with the proceeds from the issuance of new Detroit Edison Tax-Exempt Revenue Bonds.

(4)		These Senior Notes were redeemed with the proceeds from the issuance of new MichCon Senior Notes and short-term debt.

The following table shows the scheduled debt maturities, excluding any unamortized discount or premium on debt:


											2014 and
	2009		2010		2011		2012		2013		Thereafter		Total
	(In millions)
Amount to mature	$	352	$	670	$	914	$	452	$	560	$	5,092	$	8,040

Trust Preferred-Linked Securities

The Company has the right to extend interest payment periods on the debt securities. Should the Company exercise this right, it cannot declare or pay dividends on, or redeem, purchase or acquire, any of its 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 the Company’s 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 may create cross defaults in the indebtedness of DTE Energy.

NOTE 12 — PREFERRED SECURITIES

Preferred and Preference Securities — Authorized and Unissued

As of December 31, 2008, the amount of authorized and unissued stock is as follows:


Company	Type of Stock	Par Value		Shares Authorized
DTE Energy	Preferred	None			5,000,000
Detroit Edison	Preferred	$	100		6,747,484
Detroit Edison	Preference	$	1		30,000,000
MichCon	Preferred	$	1		7,000,000
MichCon	Preference	$	1		4,000,000

NOTE 13 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year credit facilities are with a syndicate of banks and may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, at December 31, 2008, Detroit Edison and MichCon had short-term unsecured bank loans of $75 million and $50 million, respectively. Also in 2008, DTE Energy entered into two supplemental

$30 million facilities to support the issuance of letters of credit. The above agreements require the Company to maintain a debt to total capitalization ratio of no more than 0.65 to 1. DTE Energy, Detroit Edison and MichCon are in compliance with this financial covenant. In December 2008, MichCon issued a $20 million secured short-term note, due in September 2009. The availability under these combined facilities is shown in the following table:


	DTE Energy			Detroit Edison			MichCon			Total
	(In millions)
Five-year unsecured revolving facility, expiring October 2010	$	675		$	69		$	181		$	925
Five-year unsecured revolving facility, expiring October 2009		525			206			244			975
Unsecured bank loan facility, expiring July 2009		—			75			—			75
Unsecured bank loan facility, expiring June 2009		—			—			50			50
Secured floating rate note, maturing September 2009		—			—			20			20
One-year unsecured letter of credit facility, expiring November 2009		30			—			—			30
One-year unsecured letter of credit facility, expiring December 2009		30			—			—			30

Total credit facilities at December 31, 2008		1,260			350			495			2,105

Amounts outstanding at December 31, 2008:
Commercial paper issuances		(77	)		—			(272	)		(349	)
Borrowings		(100	)		(75	)		(220	)		(395	)
Letters of credit		(275	)		—			—			(275	)

		(452	)		(75	)		(492	)		(1,019	)

Net availability at December 31, 2008	$	808		$	275		$	3		$	1,086

We have other outstanding letters of credit which are not included in the above described facilities totaling approximately $16 million which are used for various corporate purposes.

The weighted average interest rate for short-term borrowings was 3.9% and 5.4% at December 31, 2008 and 2007, respectively.

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. The Company has a demand financing agreement for up to $50 million with its clearing agent. The amount outstanding under this agreement was $26 million and $13 million at December 31, 2008 and 2007, respectively.

Detroit Edison terminated a $200 million short-term financing agreement secured by customer accounts receivable in 2008.

NOTE 14 — CAPITAL AND OPERATING LEASES

Lessee — The Company leases various assets under capital and operating leases, including coal cars, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2031. Future minimum lease payments under non-cancelable leases at December 31, 2008 were:


	Capital		Operating
	Leases		Leases
	(In millions)
2009	$	15	$	36
2010		14		30
2011		12		27
2012		9		25
2013		9		21
Thereafter		32		99

Total minimum lease payments		91	$	238

Less imputed interest		19

Present value of net minimum lease payments		72
Less current portion		10

Non-current portion	$	62

Rental expense for operating leases was $49 million in 2008, $60 million in 2007, and $72 million in 2006.

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, 2008, were as follows:


	(In millions)
2009	$	9
2010		9
2011		9
2012		9
2013		9
Thereafter		62

Total minimum future lease receipts		107
Residual value of leased pipeline		40
Less unearned income		(70	)

Net investment in capital lease		77
Less current portion		2

	$	75

NOTE 15 — FAIR VALUE

Effective January 1, 2008, the Company adopted SFAS No. 157. This Statement defines fair value, establishes a framework for measuring fair value and expands the disclosures about fair value measurements. The Company has elected the option to defer the effective date of SFAS No. 157 as it pertains to non-financial assets and liabilities to January 1, 2009.

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated or generally unobservable inputs. The Company makes certain assumptions it believes that market participants would use in pricing assets or liabilities, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. Credit risk of the Company and its counterparties is incorporated in the valuation of assets and liabilities through the use of credit reserves, the impact of which is immaterial for the year ended December 31, 2008. The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

SFAS No. 157 establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. SFAS No. 157 requires that assets and liabilities be classified in their entirety based on the lowest level of input that is significant to the fair value measurement in its entirety. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The Company classifies fair value balances based on the fair value hierarchy defined by SFAS No. 157 as follows:

	•		Level 1 — Consists of unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access as of the reporting date.

	•		Level 2 — Consists of inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

	•		Level 3 — Consists of unobservable inputs for assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2008:


													Net Balance at
										Netting			December 31,
	Level 1			Level 2			Level 3			Adjustments(2)			2008
	(In millions)
Assets:
Cash equivalents	$	36		$	—		$	—		$	—		$	36
Nuclear decommissioning trusts and Other investments(1)		492		$	310		$	1		$	—		$	803
Derivative assets		2,051			1,118			677			(3,390	)		456

Total	$	2,579		$	1,428		$	678		$	(3,390	)	$	1,295


Liabilities:
Derivative liabilities		(2,026	)		(1,118	)		(861	)		3,376			(629	)

Total	$	(2,026	)	$	(1,118	)	$	(861	)	$	3,376		$	(629	)

Net assets (liabilities) at December 31, 2008	$	553		$	310		$	(183	)	$	(14	)	$	666


(1)		Excludes cash surrender value of life insurance investments.

(2)		Amounts represent the impact of master netting agreements that allow the Company to net gain and loss positions and cash collateral held or placed with the same counterparties.

The following table presents the fair value reconciliation of Level 3 derivative assets and liabilities and purchase of Other investments of $1 million measured at fair value on a recurring basis for the year ended December 31, 2008:


	(In millions)
Liability balance as of January 1, 2008(1)	$	(366	)
Changes in fair value recorded in income		(10	)
Changes in fair value recorded in regulatory liabilities		2
Changes in fair value recorded in other comprehensive income		6
Purchases, issuances and settlements		195
Transfers in/out of Level 3		(10	)

Liability balance as of December 31, 2008	$	(183	)

The amount of total gains included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at December 31, 2008	$	129


(1)		Balance as of January 1, 2008 includes a cumulative effect adjustment which represents an increase to beginning retained earnings related to Level 3 derivatives upon adoption of SFAS No. 157.

Net losses of $10 million related to Level 3 derivative assets and liabilities are reported in Operating Revenues for the year ended December 31, 2008 consistent with the Company’s accounting policy. Net gains of $154 million related to Level 1 and Level 2 derivative assets and liabilities, and the impact of netting, are also reported in Operating Revenues for the year ended December 31, 2008. Transfers in/out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Transfers in/out of Level 3 are reflected as if they had occurred at the beginning of the period.

SFAS No. 157 provides for limited retrospective application, the net of which is recorded as an adjustment to beginning retained earnings in the period of adoption. As a result, the Company recorded a cumulative effect adjustment of $4 million, net of taxes, as an increase to beginning retained earnings as of January 1, 2008.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized as Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trust fund investments have been established to satisfy Detroit Edison’s nuclear decommissioning obligations. The nuclear decommissioning trusts and other fund investments hold debt and equity securities directly and indirectly through commingled funds and institutional mutual funds. Exchange-traded debt and equity securities held directly are valued using quoted market prices on actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or pricing services. For non-exchange traded fixed income securities, the trustees receive prices from pricing services. A primary price source is identified by asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustees challenge an assigned price and determine that another price source is considered to be preferable. DTE Energy has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, DTE Energy selectively corroborates the fair values of securities by comparison of market-based price sources.

Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. Mathematical valuation models are used for derivatives for which external market data is not readily observable, such as contracts which extend beyond the actively traded reporting period. Derivative instruments are principally used in the Company’s Energy Trading segment.

Fair Value of 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 as carrying value approximates fair value. As of December 31, 2008, the Company had approximately $747 million of tax exempt securities and $120 million of taxable securities insured by insurers. Overall credit market conditions have resulted in credit rating downgrades and may result in future credit rating downgrades for these insurers. The Company does not expect the impact on interest rates or fair value to be material.

2008

2007

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$7.7 billion

$8.0 billion

$7.6 billion

$7.4 billion

NOTE 16 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company complies with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted. Under SFAS No. 133, all derivatives are recognized on the Consolidated Statement of Financial Position at their fair value unless they qualify for certain scope exceptions, including normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

The Company’s primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. The Company has risk management policies to monitor and decrease market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy Trading segment and the coal marketing activities of its Power and Industrial Projects segment. The fair value of all derivatives is included in Derivative assets or liabilities on the Consolidated Statements of Financial Position.

Commodity Price Risk and Foreign Currency Risk

Utility Operations

Detroit Edison — Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. Contracts that are derivatives and meet the normal purchases and sales exemption are accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when realized. This results in the deferral of unrealized gains and losses or regulatory assets or liabilities, until realized.

MichCon — MichCon purchases, stores, transmits and distributes natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2012. These gas-supply contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward storage and transportation capacity contracts. Forward firm transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Non-Utility Operations

Power and Industrial Projects — These business segments manage and operate on-site energy and steel related projects, coke batteries, landfill gas recovery and power generation assets. These businesses utilize fixed-priced contracts in the marketing and management of their assets. These contracts are generally not derivatives and are therefore accounted for under the accrual method. The business unit also engages in coal marketing which includes the marketing and trading of physical coal and coal financial instruments, and forward contracts for the purchase and sale of emissions allowances. Certain of the physical coal contracts meet the normal purchase and sales exemption and are accounted for using the accrual method. Financial and other physical coal contracts are derivatives and are accounted for by recording changes in fair value to earnings.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional gas project development and production. The Company uses derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in other comprehensive income/ (loss) will be reclassified to earnings, as the related production affects earnings through 2010. In 2008 and 2007, $0.5 million of after-tax gains and $222 million of after-tax losses, respectively, were reclassified to earnings. The 2007 amounts principally related to the sale of the Antrim business. See Note 3 for further discussion of the discontinuance of a portion of cash flow hedge accounting upon sale of the Antrim business. In 2009, management estimates reclassifying an after-tax gain of approximately $3 million to earnings.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades wholesale electricity and natural gas physical products and energy 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 in its operations. These derivatives are accounted for by recording changes in fair value to earnings, unless certain hedge accounting criteria are met.

Energy Trading — Foreign Currency Risk — Energy Trading has foreign currency forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company entered into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. Certain of these contracts were previously designated as cash flow hedges. Amounts were recorded to Other comprehensive income and reclassified to Operating revenues or Fuel, purchased power and gas expense when the related hedged item impacted earnings.

In 2008 and 2007, $1 million and $7 million, respectively, of after-tax losses were reclassified to earnings. The foreign currency hedge has been fully realized as of December 31, 2008 and therefore, no further earnings impact is expected.

Gas Midstream — These business units are primarily engaged in services related to the transportation, processing and storage of natural gas. These businesses utilize fixed-priced contracts in their marketing and management of their businesses. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Credit Risk

The utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. The Company maintains 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. The Company generally uses standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty.

The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends, and other information. Based on the Company’s credit policies and its December 31, 2008 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to result in material effects on the Company’s financial statements.

Interest Rate Risk

The Company uses interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility. In 2004 and 2000, the Company entered into a series of interest rate derivatives to limit its sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. The Company 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 2033. In 2009, the Company estimates reclassifying $4 million of losses to earnings.

NOTE 17 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.4 billion through 2008. The Company estimates Detroit Edison future undiscounted capital expenditures at up to $100 million in 2009 and up to $2.8 billion of additional capital expenditures through 2018 based on current regulations.

Water — In response to an EPA regulation, 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 water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 2008 in additional capital expenditures to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule. A decision is expected in the first quarter of 2009. Concurrently, the EPA continues to develop a revised rule, which is expected to be published in early 2009.

Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At December 31, 2008 and 2007, the Company had $12 million and $15 million, respectively, accrued for remediation.

Gas Utility

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. Gas Utility owns, or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. During 2008, the Company spent approximately $2 million investigating and remediating these former MGP sites. As of December 31, 2008 and 2007, the Company had $38 million and $40 million, respectively, accrued for remediation.

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 affect the Company’s financial position and cash flows. However, the Company anticipates 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.

Non-Utility

The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. The Company is in the process of installing new environmental equipment at our coke battery facility in Michigan. The Company expects the projects to be completed by the first half of 2009. The Michigan coke battery facility received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the impact of this issue. Furthermore, the Company is in the process of settling historical air violations at its coke battery facility located in Pennsylvania. At this time, we cannot predict the impact of this settlement. The Company is investigating wastewater treatment technologies for the coke battery facility located in Pennsylvania. This investigation may result in capital expenditures to meet regulatory requirements. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Guarantees

In certain limited circumstances, the Company enters into contractual guarantees. The Company may guarantee another entity’s obligation in the event it fails to perform. The Company may provide guarantees in certain indemnification agreements. Finally, the Company may provide indirect guarantees for the indebtedness of others. Below are the details of specific material guarantees the Company currently provides.

Millennium Pipeline Project Guarantee

The Company owns a 26% equity interest in the Millennium Pipeline Project (Millennium). Millennium is accounted for under the equity method. Millennium began commercial operations in December 2008.

On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010 and was fully drawn as of December 31, 2008. Proceeds of the facility are being used to fund project costs and expenses relating to the development, construction and commercial start up and testing of the pipeline project and for general corporate purposes. In addition, the facility has been utilized to reimburse the project partners for costs and expenses incurred in connection with the project for the period subsequent to June 1, 2004 through immediately prior to the closing of the facility. The Company received approximately $23.5 million in September 2007 as reimbursement for costs and expenses incurred by it during the above-mentioned period. The Company accounted for this reimbursement as a return of capital.

The Company has agreed to guarantee 26% of the borrowing facility and in the event of default by Millennium the maximum potential amount of future payments under this guarantee is approximately $210 million. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. Related to this facility, the Company has also agreed to guarantee 26% of Millennium’s forward-starting interest rate swaps with a notional amount of $420 million. The Company’s exposure on the forward-starting interest rate swaps varies with changes in Treasury rates and credit swap spreads and was approximately $27 million at December 31, 2008. Because we are unable to forecast changes in Treasury rates and credit swap spreads, we are unable to estimate our maximum exposure under our share of Millennium’s forward-starting interest rate swaps. An incremental .25% decrease in the forward interest rate swap rates will increase our exposure by approximately $4 million. There are no recourse provisions or collateral that would enable us to recover any amounts paid under the guarantees, other than our share of project assets.

Parent Company Guarantee of Subsidiary Obligations

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post.

The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of December 31, 2008, the value of the transactions for which the Company would have been exposed to collateral requests had the Company’s credit rating been below investment grade on such date was approximately $430 million. In circumstances where an entity is downgraded below investment grade and collateral requrests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

Other Guarantees

The Company’s other guarantees are not individually material with maximum potential payments totaling $10 million at December 31, 2008.

The Company is often required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of December 31, 2008, the Company had approximately $11 million of performance bonds outstanding. In the event that such bonds are called for nonperformance, the Company would be obligated to reimburse the issuer of the performance bond. The Company is released from the performance bonds as the contractual performance is completed and does not believe that a material amount of any currently outstanding performance bonds will be called.

Labor Contracts

There are several bargaining units for our union employees. The majority of our union employees are under contracts that expire in June and October 2010 and August 2012.

Purchase Commitments

Detroit Edison has an Energy Purchase Agreement to purchase electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison purchased steam through 2008. The term of the Energy Purchase Agreement for the purchase of electricity runs through June 2024. We purchased approximately $42 million of steam and electricity in each of 2008, 2007 and 2006. We estimate electric purchase commitments from 2009 through 2024 will not exceed $300 million in the aggregate.

In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of sale, Detroit Edison guaranteed bank loans of $13 million that Thermal Ventures II, LP used for capital improvements to the steam heating system. At December 31, 2008 and 2007, the Company had reserves of $13 million related to the bank loan guarantee.

As of December 31, 2008, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.9 billion from 2009 through 2051. The Company also estimates that 2009 capital expenditures will be approximately $1.1 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Certain of the Company’s customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The Company regularly reviews contingent matters relating to these customers and its purchase and sale contracts and it records provisions for amounts considered at risk of probable loss. Management believes the

Company’s previously accrued amounts are adequate for probable losses. The final resolution of these matters may have a material effect on the Company’s consolidated financial statements.

Our utilities and certain non-utility businesses provide services to the domestic automotive industry, including GM, Ford and Chrysler and many of their vendors and suppliers. GM and Chrysler have recently received loans from the U.S. Government to provide them with the working capital necessary to continue to operate in the short term. In February 2009, GM and Chrysler submitted viability plans to the U.S. Government indicating that additional loans were necessary to continue operations in the short term. Further plant closures, bankruptcies or a federal government mandated restructuring program could have a significant impact on our results, particularly in our Electric Utility and Power and Industrial Projects segments. As the circumstances surrounding the viability of these entities are dynamic and uncertain, we continue to monitor developments as they occur.

Other Contingencies

The Company is 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, additional environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. The Company cannot predict the final disposition of such proceedings. The Company regularly reviews legal matters and records provisions for claims it can estimate and are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on the Company’s operations or financial statements in the periods they are resolved.

See Note 5 for a discussion of contingencies related to Regulatory Matters.

NOTE 18 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R). SFAS No. 158 requires companies to (1) recognize the over funded or under funded status of defined benefit pension and other postretirement plans in its financial statements, (2) recognize as a component of other comprehensive income, net of tax, the actuarial gains or losses and the prior service costs or credits that arise during the period but are not immediately recognized as components of net periodic benefit cost, (3) recognize adjustments to other comprehensive income when the actuarial gains or losses, prior service costs or credits, and transition assets or obligations are recognized as components of net periodic benefit cost, (4) measure postretirement benefit plan assets and plan obligations as of the date of the employer’s statement of financial position, and (5) disclose additional information in the notes to financial statements about certain effects on net periodic benefit cost in the upcoming fiscal year that arise from delayed recognition of the actuarial gains and losses and the prior service cost and credits.

The requirement to recognize the funded status of a postretirement benefit plan and the related disclosure requirements is effective for fiscal years ending after December 15, 2006. The Company adopted this requirement as of December 31, 2006. In 2008, as required by SFAS 158, we changed the measurement date of our pension and postretirement benefit plans from November 30 to December 31. As a result, we recognized adjustments of $17 million ($9 million after-tax) and $4 million to retained earnings and regulatory liabilities, respectively, which represents approximately one month of pension and other postretirement benefit costs for the period from December 1, 2007 to December 31, 2008. Retrospective application of the changes required by SFAS No. 158 is prohibited; therefore certain disclosures below are not comparable.

Detroit Edison and MichCon received approval from the MPSC to record the impact of the adoption of the SFAS 158 provisions related to funded status as a regulatory asset or liability since the traditional rate setting process allows for the recovery of pension and other postretirement plan costs.

Measurement Date

All amounts and balances reported in the following tables as of December 31, 2008 and December 31, 2007 are based on measurement dates of December 31, 2008 and November 30, 2007, respectively.

Pension Plan Benefits

The Company has qualified defined benefit retirement plans for eligible represented and non-represented employees. The plans are noncontributory and cover substantially all employees. The plans provide traditional retirement benefits based on the employees’ years of benefit service, average final compensation and age at retirement. In addition, certain represented and non-represented employees are covered under cash balance provisions that determine benefits on annual employer contributions and interest credits. The Company also maintains 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.

The Company’s policy is to fund pension costs by contributing amounts consistent with the Pension Protection Act of 2006 provisions and additional amounts when it deems appropriate. In December 2008, the Company contributed $100 million to the pension plans. Also, the Company contributed $50 million to the pension plans in January 2009. The Company anticipates making up to a $250 million contribution to its pension plans in 2009.

Net pension cost includes the following components:


	Pension Plans
	2008			2007			2006
	(In millions)
Service cost	$	55		$	62		$	64
Interest cost		190			178			176
Expected return on plan assets		(259	)		(237	)		(222	)
Amortization of:
Net actuarial loss		32			59			59
Prior service cost		6			6			8
Special termination benefits		—			8			49

Net pension cost	$	24		$	76		$	134

Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.


	Pension Plans
	2008			2007
	(In millions)
Other changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets
Net actuarial loss (gain)	$	1,061		$	(255	)
Amortization of net actuarial gain		(32	)		(59	)
Prior service cost		13			1
Amortization of prior service cost		(6	)		(6	)

Total recognized in other comprehensive income and regulatory assets	$	1,036		$	(319	)

Total recognized in net periodic pension cost, Other comprehensive income and regulatory assets	$	1,060		$	(243	)
Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	52		$	34
Prior service cost		5			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:


	Pension Plans
	2008			2007
	(In millions)
Accumulated benefit obligation, end of year	$	2,828		$	2,836

Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	3,050		$	3,246
December 2007 benefit payments		(19	)		—
Service cost		55			62
Interest cost		191			178
Actuarial (gain) loss		(79	)		(212	)
Benefits paid		(201	)		(233	)
Measurement date change		22			—
Special termination benefits		—			8
Plan amendments		13			1

Projected benefit obligation, end of year	$	3,032		$	3,050


Change in plan assets
Plan assets at fair value, beginning of year	$	2,980		$	2,744
December 2007 contributions		150			—
December 2007 payments		(18	)		—
Actual return on plan assets		(884	)		280
Company contributions		106			189
Measurement date change		22			—
Benefits paid		(201	)		(233	)

Plan assets at fair value, end of year	$	2,155		$	2,980

Funded status of the plans	$	(877	)	$	(70	)
December contribution		—			151

Funded status, end of year	$	(877	)	$	81


Amount recorded as:
Noncurrent assets	$	—		$	152
Current liabilities		(6	)		(4	)
Noncurrent liabilities		(871	)		(67	)

	$	(877	)	$	81

Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	204		$	180
Prior service (credit)		(6	)		(8	)

	$	198		$	172

Amounts recognized in regulatory assets
Net actuarial loss	$	1,482		$	477
Prior service cost		23			18

	$	1,505		$	495

The aggregate accumulated benefit obligation, projected benefit obligation and fair value of plan assets as of December 31, 2008 for plans with benefit obligations in excess of plan assets was $2.8 billion, $3 billion and $2.2 billion, respectively.

The aggregate accumulated benefit obligation and projected benefit obligation of plan assets as of December 31, 2007 for plans with benefit obligations in excess of plan assets was $69 million and $72 million, respectively. There was no fair value related to plans with benefit obligations in excess of plan assets as of December 31, 2007.

The aggregate accumulated benefit obligation, projected benefit obligation and fair value of plan assets as of December 31, 2007 for plans with plan assets in excess of benefit obligations was $2.8 billion, $3 billion and $3 billion, respectively.

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


	2008			2007			2006
Projected benefit obligation
Discount rate		6.9	%		6.5	%		5.7	%
Rate of compensation increase		4.0	%		4.0	%		4.0	%
Net pension costs
Discount rate		6.5	%		5.7	%		5.9	%
Rate of compensation increase		4.0	%		4.0	%		4.0	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%

At December 31, 2008, the benefits related to the Company’s qualified and nonqualified pension 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)
2009	$	199
2010		202
2011		206
2012		213
2013		217
2014 – 2018		1,186

Total	$	2,223

The Company employs a formal process in determining the long-term rate of return for various asset classes. Management reviews 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.

The Company employs a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return on 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 hedge funds are used to enhance long-term returns while improving portfolio diversification. Derivatives may be utilized in a risk controlled manner, to potentially increase the portfolio beyond the market value of invested assets and reduce portfolio investment risk. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.

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


	2008			2007
U.S. Equity securities		31	%		48	%
Non U.S. Equity securities		16			18
Debt securities		24			19
Hedge Funds and Similar Investments		22			12
Private Equity and Other		7			3

		100	%		100	%

The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2008 were as follows:


U.S. Equity securities	35	%
Non U.S. Equity securities	20
Debt securities	20
Hedge Funds and Similar Investments	20
Private Equity and Other	5

	100	%

The Company also sponsors defined contribution retirement savings plans. Participation in one of these plans is available to substantially all represented and non-represented employees. The Company matches 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 $33 million in 2008 and $29 million in each of the years 2007 and 2006.

Other Postretirement Benefits

The Company provides certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. The Company’s policy is to fund certain trusts to meet its postretirement benefit obligations. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and non-represented employees. In December 2008, the Company made cash contributions of $116 million to its postretirement benefit plans. In January 2009, the Company made cash contributions of $40 million to its postretirement benefit plans. At the discretion of management, the Company may make up to an additional $130 million contribution to its VEBA trusts in 2009.

Net postretirement cost includes the following components:


	2008			2007			2006
	(In millions)
Service cost	$	62		$	62		$	59
Interest cost		121			118			115
Expected return on plan assets		(75	)		(67	)		(61	)
Amortization of
Net loss		38			69			72
Prior service (credit)		(6	)		(3	)		(3	)
Net transition obligation		2			7			7
Special termination benefits		—			2			8

Net postretirement cost	$	142		$	188		$	197

Special termination benefits in the above tables represent costs associated with our Performance Excellence Process.


	2008			2007
	(In millions)
Other changes in plan assets and APBO recognized in other comprehensive income and regulatory assets
Net actuarial loss (gain)	$	334		$	(299	)
Amortization of net actuarial (gain)		(39	)		(69	)
Prior service (credit)		(1	)		(55	)
Amortization of prior service credit		6			2
Amortization of transition (asset)		(2	)		(6	)

Total recognized in other comprehensive income and regulatory assets	$	298		$	(427	)


Total recognized in net periodic pension cost, other comprehensive income and regulatory assets	$	440		$	(239	)


	(In millions)
Estimated amounts to be amortized from accumulated other comprehensive income and regulatory assets into net periodic benefit cost during next fiscal year
Net actuarial loss	$	69		$	38
Prior service (credit)	$	(6	)	$	(6	)
Net transition obligation	$	2		$	2

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:


	2008			2007
	(In millions)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation, beginning of year	$	1,922		$	2,184
December 2007 cash flow		(6	)		—
Service cost		62			62
Interest cost		121			118
Actuarial (gain) loss		10			(297	)
Plan amendments		(1	)		(55	)
Medicare Part D subsidy		7			7
Special termination benefits		—			2
Measurement date change		15			—
Benefits paid		(98	)		(99	)

Accumulated postretirement benefit obligation, end of year	$	2,032		$	1,922


Change in plan assets
Plan assets at fair value, beginning of year	$	835		$	794
December 2007 VEBA cash flow		(13	)		—
Actual return on plan assets		(251	)		69
Measurement date change		6			—
Company contributions		116			56
Benefits paid		(95	)		(84	)

Plan assets at fair value, end of year	$	598		$	835

Funded status of the plans, as of November 30	$	—		$	(1,087	)
December adjustment		—			(7	)

Funded status, as of December 31	$	(1,434	)	$	(1,094	)

Noncurrent liabilities	$	(1,434	)	$	(1,094	)
Amounts recognized in Accumulated other comprehensive loss, pre-tax
Net actuarial loss	$	68		$	75
Prior service (credit)		(36	)		(48	)
Net transition (asset)		(15	)		(18	)

	$	17		$	9


Amounts recognized in regulatory assets
Net actuarial loss	$	760		$	458
Prior service cost		3			9
Net transition obligation		24			29

	$	787		$	496

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


	2008			2007			2006

Projected benefit obligation
Discount rate		6.90	%		6.50	%		5.70	%
Net benefit costs
Discount rate		6.50	%		5.70	%		5.90	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%
Health care trend rate pre-65		7.00	%		8.00	%		9.00	%
Health care trend rate post-65		6.00	%		7.00	%		8.00	%
Ultimate health care trend rate		5.00	%		5.00	%		5.00	%
Year in which ultimate reached		2011			2011			2011

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 $29 million and increased the accumulated benefit obligation by $241 million at December 31, 2008. 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 $26 million and would have decreased the accumulated benefit obligation by $238 million at December 31, 2008.

At December 31, 2008, 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)
2009	$	127
2010		133
2011		138
2012		140
2013		144
2014 — 2018		769

Total	$	1,451

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. The effects of the subsidy reduced net periodic postretirement benefit costs by $14 million in 2008, $16 million in 2007, and $17 million in 2006.

At December 31, 2008, 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)
2009	$	5
2010		4
2011		6
2012		7
2013		7
2014 — 2018		35

Total	$	64

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

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


	2008			2007
U.S. Equity securities		39	%		50	%
Non U.S. Equity securities		17			18
Debt securities		26			20
Hedge Funds and Similar Investments		13			11
Private Equity and Other		5			1

		100	%		100	%

The Company’s plans’ weighted-average asset target allocations by asset category at December 31, 2008 were as follows:


U.S. Equity securities	27	%
Non U.S. Equity securities	24
Debt securities	16
Hedge Funds and Similar Investments	28
Private Equity and Other	5

	100	%

Grantor Trust

MichCon maintains a Grantor Trust to fund other postretirement benefit obligations 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. The Company accounts for its investment at fair value with unrealized gains and losses recorded to earnings.

NOTE 19 — STOCK-BASED COMPENSATION

The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units to employees and members of its Board of Directors. Key provisions of the stock incentive program are:

	•		Authorized limit is 9,000,000 shares of common stock;

	•		Prohibits the grant of a stock option with an exercise price that is less than the fair market value of the Company’s stock on the date of the grant; and

	•		Imposes the following award limits to a single participant in a single calendar year, (1) options for more than 500,000 shares of common stock; (2) stock awards for more than 150,000 shares of common stock; (3) performance share awards for more than 300,000 shares of common stock (based on the maximum payout under the award); or (4) more than 1,000,000 performance units, which have a face amount of $1.00 each.

Effective January 1, 2006, the Company adopted SFAS No. 123(R), Share-Based Payment, using the modified prospective transition method. Under this method, the Company records compensation expense at fair value over the vesting period for all awards it grants after the date it adopted the standard. In addition, the Company is required to record compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption grants of stock awards and performance shares will continue to be expensed. DTE Energy did not make the one-time election to adopt the alternative transition method described in FSP SFAS No. 123(R)-3, Transition Election Related to Accounting for the Tax Effect of Share-Based Payment Awards, but has chosen instead to follow the original guidance provided by SFAS No. 123(R) in accounting for the tax effects of stock based compensation awards.

Stock-based compensation for the reporting periods is as follows:


	2008		2007		2006
	(In millions)
Stock-based compensation expense	$	38	$	28	$	24
Tax benefit of compensation expense	$	13	$	10	$	8

The cumulative effect of the adoption of SFAS No. 123(R) in 2006 was an increase in net income of $1 million as a result of estimating forfeitures for previously granted stock awards and performance shares. The Company generally purchases shares on the open market for options that are exercised or it may settle in cash other stock-based compensation.

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 options vest ratably over a three-year period.

Stock option activity was as follows:


				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
	(In millions)
Options outstanding at January 1, 2008		4,394,809		$	42.37
Granted		811,300		$	41.77
Exercised		(104,261	)	$	32.13
Forfeited or expired		(88,149	)	$	44.02

Options outstanding at December 31, 2008		5,013,699		$	42.45	$	—

Options exercisable at December 31, 2008		3,766,477		$	42.17	$	—

As of December 31, 2008, the weighted average remaining contractual life for the exercisable shares is 4.46 years. As of December 31, 2008, 1,247,222 options were non-vested. During 2008, 610,440 options vested.

The weighted average grant date fair value of options granted during 2008, 2007, and 2006 was $4.76, $6.46, and $6.12, respectively. The intrinsic value of options exercised for the years ended December 31, 2008, 2007 and 2006 was $1 million, $16 million, and $6 million, respectively. Total option expense recognized during 2008, 2007 and 2006 was $3 million, $4 million and $6 million, respectively.

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 (Years)
$27.00-$38.00		108,117	$	31.75		1.07
$38.01-$42.00		2,759,759	$	40.97		5.35
$42.01-$45.00		1,398,488	$	43.91		5.98
$45.01-$50.00		747,335	$	46.76		5.69

		5,013,699	$	42.45		5.49

The Company determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:


	December 31			December 31			December 31
	2008			2007			2006
Risk-free interest rate		3.05	%		4.71	%		4.58	%
Dividend yield		5.20	%		4.38	%		4.75	%
Expected volatility		20.45	%		17.99	%		19.79	%
Expected life	6 years			6 years			6 years

In connection with the adoption of SFAS No. 123(R), the Company reviewed and updated its forfeiture, expected term and volatility assumptions. The Company modified option volatility to include both historical and implied share-price volatility. Implied volatility is derived from exchange traded options on DTE Energy common stock. The Company’s expected life estimate is based on industry standards.

Stock Awards

Stock awards granted under the plan are restricted for varying periods, 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 the Company 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. The cost is amortized to compensation expense over the vesting period.

Stock award activity for the periods ended December 31 was:


	2008		2007		2006
Fair value of awards vested (in Millions)	$	18	$	10	$	5
Restricted common shares awarded		389,055		620,125		282,555
Weighted average market price of shares awarded	$	41.96	$	49.48	$	43.64
Compensation cost charged against income (in Millions)	$	20	$	16	$	10

The following table summarizes the Company’s stock awards activity for the period ended December 31, 2008:


				Weighted Average
	Restricted			Grant Date
	Stock			Fair Value
Balance at January 1, 2008		984,310		$	47.36
Grants		389,055		$	41.96
Forfeitures		(67,165	)	$	45.45
Vested		(374,478	)	$	46.90

Balance at December 31, 2008		931,722		$	45.31

Performance Share Awards

Performance shares awarded under the plan are for a specified number of shares of common stock that entitle 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 and market conditions. The awards vest at the end of a specified period, usually three years. The Company accounts 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 closing stock price market value. The settlement of the award is at based on the closing price at the settlement date.

The Company recorded compensation expense as follows:


	2008		2007		2006
	(In millions)
Compensation expense	$	15	$	7	$	8
Cash settlements(1)	$	3	$	5	$	4


(1)		Approximates the intrinsic value of the liability.

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.

The following table summarizes the Company’s performance share activity for the period ended December 31, 2008:


	Performance Shares
Balance at January 1, 2008		1,174,153
Grants		534,965
Forfeitures		(74,970	)
Payouts		(312,647	)

Balance at December 31, 2008		1,321,501

Unrecognized Compensation Costs

As of December 31, 2008, there was $33 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. That cost is expected to be recognized over a weighted-average period of 1.33 years.


	Unrecognized
	Compensation		Weighted Average
	Cost		to be Recognized
	(In millions)		(In Years)
Stock awards	$	16		1.10
Performance shares		15		1.53
Options		2		1.62

	$	33		1.33

The tax benefit realized for tax deductions related to the Company’s stock incentive plan totaled $13 million for the period ended December 31, 2008. Approximately $1.6 million, $1.4 million, and $1.6 million of compensation cost was capitalized as part of fixed assets during 2008, 2007, and 2006, respectively.

NOTE 20 — SEGMENT AND RELATED INFORMATION

Beginning in the second quarter of 2008, the Company realigned its Coal Transportation and Marketing business from the Coal and Gas Midstream segment (now the Gas Midstream segment) to the Power and Industrial Projects segment, due to changes in how financial information is evaluated and resources are allocated to segments by senior management. The Company’s segment information reflects this change for all periods presented. The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility

•

The Company’s Electric Utility segment consists of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.2 million residential, commercial and industrial customers in southeastern Michigan.

Gas Utility

•

The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Non-Utility Operations

	•		Gas Midstream consists of gas pipelines and storage businesses;

	•		Unconventional Gas Production is engaged in unconventional gas project development and production;

	•		Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers, biomass energy projects and coal transportation and marketing; and

	•		Energy Trading primarily consists of energy marketing and trading operations.

Corporate & Other, includes various holding company activities, holds certain non-utility debt and energy-related investments.

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production 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 federal tax return.

Inter-segment billing for goods and services exchanged between segments is based upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal transportation services in the following segments:


	2008			2007			2006
	(In millions)
Electric Utility	$	16		$	36		$	59
Gas Utility		7			5			16
Gas Midstream		10			17			17
Unconventional Gas Production		—			64			134
Power and Industrial Projects		80			197			169
Energy Trading		145			7			75
Corporate & Other		(80	)		(35	)		7

	$	178		$	291		$	477

Financial data of the business segments follows:


															Net Inc
															Attrib.
															To
				Depreciation,											DTE
	Operating			Depletion &		Interest			Interest			Income			Energy			Total				Capital
	Revenue			Amortization		Income			Expense			Taxes			Comp.			Assets		Goodwill		Expenditures
	(In millions)
2008
Electric Utility	$	4,874		$	743	$	(6	)	$	293		$	186		$	331		$	15,798	$	1,206	$	944
Gas Utility		2,152			102		(8	)		66			41			85			3,884		772		239
Non-utility Operations:
Gas Midstream		71			5		(1	)		7			24			38			316		9		19
Unconventional Gas Production(1)		48			12		—			2			47			84			314		2		101
Power and Industrial Projects		987			34		(7	)		20			11			40			1,126		31		65
Energy Trading		1,388			5		(5	)		10			31			42			787		17		5

		2,494			56		(13	)		39			113			204			2,543		59		190
Corporate & Other		(13	)		—		(41	)		154			(52	)		(94	)		2,365		—		—
Reconciliation and Eliminations		(178	)		—		49			(49	)		—			—			—		—		—

Total from Continuing Operations	$	9,329		$	901	$	(19	)	$	503		$	288			526			24,590		2,037		1,373

Discontinued Operations (Note 3)																20			—		—		—

Total															$	546		$	24,590	$	2,037	$	1,373


															Net Inc
															Attrib.
															To
				Depreciation,											DTE
	Operating			Depletion &		Interest			Interest			Income			Energy			Total				Capital
	Revenue			Amortization		Income			Expense			Taxes			Comp.			Assets		Goodwill		Expenditures
	(In millions)
2007
Electric Utility	$	4,900		$	764	$	(7	)	$	294		$	149		$	317		$	14,854	$	1,206	$	809
Gas Utility		1,875			93		(10	)		61			23			70			3,266		772		226
Non-utility Operations:
Gas Midstream		66			6		(2	)		11			18			34			258		9		35
Unconventional Gas Production(1)		(228	)		22		—			13			(117	)		(217	)		355		2		161
Power and Industrial Projects		1,244			41		(9	)		28			7			49			753		31		66
Energy Trading		924			5		(5	)		11			17			32			1,113		17		2

		2,006			74		(16	)		63			(75	)		(102	)		2,479		59		264
Corporate & Other(1)		(15	)		1		(51	)		174			267			502			2,369		—		—
Reconciliation and Eliminations		(291	)		—		59			(59	)		—			—			—		—		—

Total from Continuing Operations	$	8,475		$	932	$	(25	)	$	533		$	364			787			22,968		2,037		1,299

Discontinued Operations (Note 3)																205			774		—		—
Reconciliation and Eliminations																(21	)		—		—		—

Total from Discontinued Operations																184			774		—		—

Total															$	971		$	23,742	$	2,037	$	1,299


(1)		Net income attributable to DTE Energy Company of the Unconventional Gas production segment in 2008 reflects the gain recognized on the sale of Barnett shale properties. Operating revenues and net loss attributable to DTE Energy Company of the Unconventional Gas Production segment in 2007 reflect the recognition of losses on hedge contracts associated with the Antrim sale transaction. Net income attributable to DTE Energy Company of the Corporate & Other segment in 2007 results principally from the gain recognized on the Antrim sale transaction. See Note 3.

NOTE 21 — 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.


	First		Second		Third		Fourth
	Quarter		Quarter(1)		Quarter		Quarter(2)		Year
	(In millions, except per share amounts)
2008
Operating Revenues	$	2,570	$	2,251	$	2,338	$	2,170	$	9,329
Operating Income	$	429	$	157	$	375	$	302	$	1,263
Net Income Attributable to DTE Energy Company
From continuing operations	$	200	$	28	$	169	$	129	$	526
Discontinued operations		12		—		8		—		20

Total	$	212	$	28	$	177	$	129	$	546

Basic Earnings per Share
From continuing operations	$	1.22	$	.18	$	1.03	$	.79	$	3.22
Discontinued operations		.08		—		.05		—		.12

Total	$	1.30	$	.18	$	1.08	$	.79	$	3.34

Diluted Earnings per Share
From continuing operations	$	1.22	$	.18	$	1.03	$	.79	$	3.22
Discontinued operations		.07		—		.05		—		.12

Total	$	1.29	$	.18	$	1.08	$	.79	$	3.34

2007
Operating Revenues	$	2,462	$	1,676	$	2,127	$	2,210	$	8,475
Operating Income	$	269	$	721	$	286	$	329	$	1,605
Net Income Attributable to DTE Energy Company
From continuing operations	$	96	$	348	$	152	$	191	$	787
Discontinued operations		38		37		45		64		184

Total	$	134	$	385	$	197	$	255	$	971

Basic Earnings per Share
From continuing operations	$	.54	$	2.00	$	.92	$	1.16	$	4.62
Discontinued operations		.21		.21		.27		.39		1.08

Total	$	.75	$	2.21	$	1.19	$	1.55	$	5.70

Diluted Earnings per Share
From continuing operations	$	.54	$	1.99	$	.92	$	1.16	$	4.61
Discontinued operations		.21		.21		.27		.39		1.08

Total	$	.75	$	2.20	$	1.19	$	1.55	$	5.69


(1)		In the second quarter of 2007, the Company recorded a $900 million ($580 million after-tax) gain on the Antrim sale transaction and $323 million ($210 million after-tax) of losses on hedge contracts associated with the Antrim sale. See Note 3.

(2)		In the fourth quarter of 2007, the Company recorded adjustments that increased operating income by $20 million ($13 million after-tax) to correct prior amounts. These adjustments were primarily to record property, plant and equipment and deferred CTA costs at Detroit Edison for expenditures that had been expensed in earlier quarters of 2007.

100


	Year Ending December 31,
	2008			2007			2006
	(In millions)
Allowance for Doubtful Accounts (shown as deduction from Accounts Receivable in the Consolidated Statement of Financial Position)
Balance at Beginning of Period	$	182		$	170		$	136
Additions:
Charged to costs and expenses		198			133			120
Charged to other accounts(1)		18			12			7
Deductions(2)		(133	)		(133	)		(93	)

Balance at End of Period	$	265		$	182		$	170


(1)		Collection of accounts previously written off and balances previously held for sale of $4 million.

(2)		Uncollectible accounts written off.