10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended September 30, 2011

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Michigan	38-3217752
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
One Energy Plaza, Detroit, Michigan	48226-1279
(Address of principal executive offices)	(Zip Code)

313-235-4000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YesþNoo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YesþNoo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YesoNoþ

At September 30, 2011, 169,250,934 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.

DTEENERGY COMPANY

QUARTERLY REPORT ON FORM 10-Q

QUARTER ENDED September 30, 2011

TABLE OF CONTENTS

	PAGE
DEFINITIONS	1
FORWARD-LOOKING STATEMENTS	3
PART I — FINANCIAL INFORMATION
Consolidated Statements of Operations (Unaudited)	5
Consolidated Statements of Financial Position (Unaudited)	6
Consolidated Statements of Cash Flows (Unaudited)	8
Consolidated Statements of Changes in Equity and Comprehensive Income (Unaudited)	9
Notes to Consolidated Financial Statements (Unaudited)	10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3. Quantitative and Qualitative Disclosures About Market Risk	55
Item 4. Controls and Procedures	58
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	59
Item 1A. Risk Factors	59
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers	60
Item 6. Exhibits	61
SIGNATURE	63
EX-3-11
EX-12.48
EX-31.69
EX-31.70
EX-32.69
EX-32.70
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

DEFINITIONS

ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CIM	A Choice Incentive Mechanism authorized by the MPSC that allows Detroit Edison to recover or refund non-fuel revenues lost or gained as a result of fluctuations in electric Customer Choice sales.
Citizens	Citizens Fuel Gas Company distributes natural gas in Adrian, Michigan
Company	DTE Energy Company and any subsidiary companies
CTA	Costs to achieve, consisting of project management, consultant support and employee severance, related to the Performance Excellence Process
Customer Choice	Michigan legislation giving customers the option to choose alternative suppliers for electricity and gas.
Detroit Edison	The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies
DTE Energy	DTE Energy Company, directly or indirectly the parent of Detroit Edison, MichCon and numerous non-utility subsidiaries
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FTRs	Financial transmission rights are financial instruments that entitle the holder to receive payments related to costs incurred for congestion on the transmission grid.
GCR	A Gas Cost Recovery mechanism authorized by the MPSC that allows MichCon to recover through rates its natural gas costs.
MCIT	Michigan Corporate Income Tax
MDEQ	Michigan Department of Environmental Quality
MichCon	Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies
MISO	Midwest Independent System Operator is an Independent System Operator and the Regional Transmission Organization serving the Midwest United States and Manitoba, Canada.
MPSC	Michigan Public Service Commission
Non-utility	An entity that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not directly regulated by the MPSC.
NRC	United States Nuclear Regulatory Commission
Production tax credits	Tax credits as authorized under Sections 45K and 45 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a production tax credit can vary each year as determined by the Internal Revenue Service.

1

Proved reserves	Estimated quantities of natural gas, natural gas liquids and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions.
PSCR	A Power Supply Cost Recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power costs.
RDM	A Revenue Decoupling Mechanism authorized by the MPSC that is designed to minimize the impact on revenues of changes in average customer usage of electricity and natural gas.
Securitization	Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly owned special purpose entity, The Detroit Edison Securitization Funding LLC.
Subsidiaries	The direct and indirect subsidiaries of DTE Energy Company
Unconventional Gas	Includes those gas and oil deposits that originated and are stored in coal bed, tight sandstone and shale formations
VIE	Variable Interest Entity
Units of Measurement
Bcf	Billion cubic feet of gas
Bcfe	Conversion metric of natural gas, the ratio of 6 Mcf of gas to 1 barrel of oil
BTU	Heat value (energy content) of fuel
dth/d	Decatherms per day
kWh	Kilowatthour of electricity
Mcf	Thousand cubic feet of gas
MMcf	Million cubic feet of gas
MW	Megawatt of electricity
MWh	Megawatthour of electricity

2

FORWARD-LOOKINGSTATEMENTS

Certain information presented herein includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the financial condition, results of operations and business of DTE Energy. Words such as “anticipate,” “believe,” “expect,” “projected” and “goals” signify forward-looking statements. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated or budgeted. Many factors may impact forward-looking statements including, but not limited to, the following:

• economic conditions and population changes in our geographic area resulting in changes in demand, customer conservation, increased thefts of electricity and gas and high levels of uncollectible accounts receivable;

• changes in the economic and financial viability of suppliers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company;

• access to capital markets and the results of other financing efforts which can be affected by credit agency ratings;

• instability in capital markets which could impact availability of short and long-term financing;

• the timing and extent of changes in interest rates;

• the level of borrowings;

• the potential for losses on investments, including nuclear decommissioning and benefit plan assets and the related increases in future expense and contributions;

• impact of regulation by the FERC, MPSC, NRC and other applicable governmental proceedings and regulations, including any associated impact on rate structures;

• the amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals or new legislation;

• the potential for increased costs or delays in completion of significant construction projects;

• the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;

• environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements;

• health, safety, financial, environmental and regulatory risks associated with ownership and operation of nuclear facilities;

• impact of electric and gas utility restructuring in Michigan, including legislative amendments and Customer Choice programs;

• employee relations and the impact of collective bargaining agreements;

• unplanned outages;

• changes in the cost and availability of coal and other raw materials, purchased power and natural gas;

• volatility in the short-term natural gas storage markets impacting third-party storage revenues;

• cost reduction efforts and the maximization of plant and distribution system performance;

• the effects of competition;

• the uncertainties of successful exploration of unconventional gas resources and challenges in estimating gas and oil reserves with certainty;

• changes in and application of federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;

• the cost of protecting assets against, or damage due to, terrorism or cyber attacks;

• the availability, cost, coverage and terms of insurance and stability of insurance providers;

• changes in and application of accounting standards and financial reporting regulations;

• changes in federal or state laws and their interpretation with respect to regulation, energy policy and other

3

business issues;

• binding arbitration, litigation and related appeals; and

• the risks discussed in our public filings with the Securities and Exchange Commission.

New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statements refer only as of the date on which such statements are made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

4

Part I — Item 1.

DTEENERGYCOMPANY

CONSOLIDATEDSTATEMENTSOFOPERATIONS (UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions, Except per Share Amounts)	2011			2010			2011			2010
Operating Revenues	$	2,265		$	2,139		$	6,724		$	6,384
Operating Expenses
Fuel, purchased power and gas	866			763			2,708			2,366
Operation and maintenance	670			649			1,948			1,898
Depreciation, depletion and amortization	259			271			752			775
Taxes other than income	79			69			239			231
Asset (gains) and losses, reserves and impairments, net	(8		)	1			—			—
	1,866			1,753			5,647			5,270
Operating Income	399			386			1,077			1,114
Other (Income) and Deductions
Interest expense	120			142			370			418
Interest income	(3		)	(3		)	(8		)	(9		)
Other income	(20		)	(20		)	(59		)	(62		)
Other expenses	16			9			31			32
	113			128			334			379
Income Before Income Taxes	286			258			743			735
Income Tax Expense	101			92			180			252
Net Income	185			166			563			483
Less: Net Income Attributable to Noncontrolling Interests	2			3			2			5
Net Income Attributable to DTE Energy Company	$	183		$	163		$	561		$	478
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	1.08		$	0.97		$	3.31		$	2.85
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	1.07		$	0.96		$	3.30		$	2.84
Weighted Average Common Shares Outstanding
Basic	169			169			169			168
Diluted	170			170			170			168
Dividends Declared per Common Share	$	0.59		$	0.56		$	1.74		$	1.62

See Notes to Consolidated Financial Statements (Unaudited)

5

DTEENERGYCOMPANY

CONSOLIDATEDSTATEMENTSOFFINANCIALPOSITION (UNAUDITED)

	September 30,			December 31,
(in Millions)	2011			2010
ASSETS
Current Assets
Cash and cash equivalents	$	46		$	65
Restricted cash, principally Securitization	73			120
Accounts receivable (less allowance for doubtful accounts of $168 and $196, respectively)
Customer	1,206			1,393
Other	121			402
Inventories
Fuel and gas	567			460
Materials and supplies	209			202
Deferred income taxes	130			139
Derivative assets	109			131
Regulatory assets	201			58
Other	249			197
	2,911			3,167
Investments
Nuclear decommissioning trust funds	893			939
Other	527			518
	1,420			1,457
Property
Property, plant and equipment	22,312			21,574
Less accumulated depreciation, depletion and amortization	(8,890		)	(8,582		)
	13,422			12,992
Other Assets
Goodwill	2,020			2,020
Regulatory assets	3,940			4,058
Securitized regulatory assets	618			729
Intangible assets	74			67
Notes receivable	124			123
Derivative assets	59			77
Other	192			206
	7,027			7,280
Total Assets	$	24,780		$	24,896

See Notes to Consolidated Financial Statements (Unaudited)

6

DTEENERGYCOMPANY

CONSOLIDATEDSTATEMENTSOFFINANCIALPOSITION (UNAUDITED)

	September 30,			December 31,
(in Millions, Except Shares)	2011			2010
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	708		$	729
Accrued interest	121			111
Dividends payable	99			95
Short-term borrowings	275			150
Current portion long-term debt, including capital leases	247			925
Derivative liabilities	114			142
Other	536			597
	2,100			2,749
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,702			6,114
Securitization bonds	479			643
Trust preferred-linked securities	289			289
Capital lease obligations	27			43
	7,497			7,089
Other Liabilities
Deferred income taxes	3,076			2,632
Regulatory liabilities	1,040			1,328
Asset retirement obligations	1,560			1,498
Unamortized investment tax credit	68			75
Derivative liabilities	62			110
Liabilities from transportation and storage contracts	73			83
Accrued pension liability	680			866
Accrued postretirement liability	1,216			1,275
Nuclear decommissioning	141			149
Other	258			275
	8,174			8,291
Commitments and Contingencies (Notes 6 and 10)
Equity
Common stock, without par value, 400,000,000 shares authorized, 169,250,934 and 169,428,406 shares issued and outstanding, respectively	3,418			3,440
Retained earnings	3,698			3,431
Accumulated other comprehensive loss	(146		)	(149		)
Total DTE Energy Company Equity	6,970			6,722
Noncontrolling interests	39			45
Total Equity	7,009			6,767
Total Liabilities and Equity	$	24,780		$	24,896

See Notes to Consolidated Financial Statements (Unaudited)

7

DTEENERGYCOMPANY

CONSOLIDATEDSTATEMENTSOFCASHFLOWS (UNAUDITED)

	Nine Months Ended
	September 30
(in Millions)	2011			2010
Operating Activities
Net income	$	563		$	483
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	752			775
Deferred income taxes	123			173
Asset losses, reserves and impairments, net	—			5
Changes in assets and liabilities, exclusive of changes shown separately (Note 13)	48			73
Net cash from operating activities	1,486			1,509
Investing Activities
Plant and equipment expenditures — utility	(968		)	(743		)
Plant and equipment expenditures — non-utility	(61		)	(75		)
Proceeds from sale of assets	13			28
Restricted cash for debt redemption, principally Securitization	47			33
Proceeds from sale of nuclear decommissioning trust fund assets	69			179
Investment in nuclear decommissioning trust funds	(97		)	(204		)
Consolidation of VIEs	—			19
Investment in Millennium Pipeline Project	—			(49		)
Other	(55		)	(22		)
Net cash used for investing activities	(1,052		)	(834		)
Financing Activities
Issuance of long-term debt, net	908			595
Redemption of long-term debt	(1,161		)	(660		)
Short-term borrowings	126			(307		)
Issuance of common stock	—			26
Repurchase of common stock	(18		)	—
Dividends on common stock	(289		)	(265		)
Other	(19		)	(32		)
Net cash used for financing activities	(453		)	(643		)
Net Increase (Decrease) in Cash and Cash Equivalents	(19		)	32
Cash and Cash Equivalents at Beginning of Period	65			52
Cash and Cash Equivalents at End of Period	$	46		$	84

See Notes to Consolidated Financial Statements (Unaudited)

8

DTEENERGYCOMPANY

CONSOLIDATEDSTATEMENTSOFCHANGES INEQUITYAND

COMPREHENSIVEINCOME (UNAUDITED)

									Accumulated Other
	Common Stock					Retained			Comprehensive			Noncontrolling
(Dollars in Millions, Shares in Thousands)	Shares		Amount			Earnings			Loss			Interest			Total
Balance, December 31, 2010	169,428		$	3,440		$	3,431		$	(149	)	$	45		$	6,767
Net income						561						2			563
Dividends declared on common stock						(294		)							(294		)
Repurchase of common stock	(928	)	(45		)										(45		)
Benefit obligations, net of tax									5						5
Foreign currency translation, net of tax									(1		)				(1		)
Net change in unrealized losses on investments, net of taxes									(1		)				(1		)
Stock-based compensation, distributions to noncontrolling interests and other	751		23									(8		)	15
Balance, September 30, 2011	169,251		$	3,418		$	3,698		$	(146	)	$	39		$	7,009

The following table displays comprehensive income for the nine-month periods ended September 30:

(in Millions)	2011			2010
Net income	$	563		$	483
Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligation, net of taxes of $2 and $3	5			6
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $— and $5	—			10
	5			16
Net unrealized gains (losses) on derivatives:
Gains (losses) during the period, net of taxes of $— and $1	—			1
Amounts reclassified to income, net of taxes of $— and $1	—			1
	—			2
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $— and $(6)	(1		)	(11		)
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $— and $(5)	—			(10		)
	(1		)	(21		)
Foreign currency translation, net of taxes of $— and $—	(1		)	—
Comprehensive income	566			480
Less: Comprehensive income attributable to noncontrolling interests	2			5
Comprehensive income attributable to DTE Energy Company	$	564		$	475

See Notes to Consolidated Financial Statements (Unaudited)

9

DTEENERGYCOMPANY

NOTES TOCONSOLIDATEDFINANCIALSTATEMENTS (UNAUDITIED)

NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

• Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan;

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

• Other businesses involved in (1) natural gas pipelines, gathering and storage; (2) unconventional gas and oil project 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. Certain activities of Detroit Edison and MichCon, as well as various other aspects of businesses under DTE Energy are regulated by the FERC. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.

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

Basis of Presentation

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2010 Annual Report on Form 10-K.

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.

The Consolidated Financial Statements are unaudited, but in the Company’s opinion include all adjustments necessary to a fair statement of the results for the interim periods. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2011.

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.

The Company evaluates whether an entity is a VIE whenever reconsideration events occur. The Company consolidates VIEs for which it is the primary beneficiary. If the Company is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of accounting. When assessing the determination of the primary beneficiary, the Company considers all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the VIE. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

Legal entities within the Company’s Power and Industrial Projects segment enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are generally designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk. These entities generally are VIEs. In addition, the Company has interests in certain VIEs that we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.

10

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of September 30, 2011, the carrying amount of assets and liabilities in the Consolidated Statement of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

In 2001, Detroit Edison financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly owned special purpose entity, Securitization. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated as the Company is the primary beneficiary.

DTE Energy has interests in two unconsolidated trusts that were formed for the purpose of issuing preferred securities and lending the gross proceeds to the Company. The 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. DTE Energy has reviewed these trusts and has determined they are VIEs, but the Company is not the primary beneficiary as it does not have variable interests in the trusts and therefore, the trusts are not consolidated by the Company.

The maximum risk exposure for consolidated VIEs is reflected on the Company’s Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally limited to its investment and amounts which it has guaranteed.

The following table summarizes the major balance sheet items for consolidated VIEs as of September 30, 2011 and December 31, 2010. Amounts at September 30, 2011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below.

	September 30, 2011
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	8	$	8	$	—
Restricted cash	58		7		65		64
Accounts receivable	38		14		52		40
Inventories	—		145		145		—
Other current assets	—		1		1		—
Property, plant and equipment	—		58		58		25
Securitized regulatory assets	618		—		618		618
Other assets	10		6		16		18
	$	724	$	239	$	963	$	765
LIABILITIES
Accounts payable and accrued current liabilities	$	4	$	38	$	42	$	4
Current portion long-term debt, including capital leases	164		7		171		171
Other current liabilities	62		1		63		64
Mortgage bonds, notes and other	—		31		31		31
Securitization bonds	479		—		479		479
Capital lease obligations	—		20		20		20
Other long term liabilities	6		2		8		7
	$	715	$	99	$	814	$	776

11

	December 31, 2010
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash	104		8		112		112
Accounts receivable	42		8		50		44
Inventories	—		99		99		—
Other current assets	—		1		1		—
Property, plant and equipment	—		54		54		38
Securitized regulatory assets	729		—		729		729
Other assets	13		9		22		21
	$	888	$	183	$	1,071	$	944
LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases	150		7		157		157
Other current liabilities	62		6		68		66
Mortgage bonds, notes and other	—		35		35		35
Securitization bonds	643		—		643		643
Capital lease obligations	—		23		23		23
Other long term liabilities	6		7		13		12
	$	878	$	105	$	983	$	954

Amounts for non-consolidated VIEs as September 30, 2011 and December 31, 2010 were as follows:

	September 30,		December 31,
(in Millions)	2011		2010
Other investments	$	121	$	98
Note receivable	5		6
Trust preferred — linked securities	289		289

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Emission allowances and renewable energy credits are charged to expense as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $9 million at September 30, 2011 and December 31, 2010. The Company’s intangible assets related to renewable energy credits were $26 million and $17 million at September 30, 2011 and December 31, 2010, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at September 30, 2011were $65 million and $26 million, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2010 were $63 million and $22 million, respectively. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years.

Income Taxes

The Company’s effective tax rate for the three months ended September 30, 2011was 35 percent as compared to 36 percent for the three months ended September 30, 2010. The Company’s effective tax rate for the nine months ended September 30, 2011 was 24 percent as compared to 34 percent for the nine months ended September 30, 2010. The decrease in the effective tax rate in 2011 is due primarily to the recognition of an $88 million income tax benefit due to the enactment of the Michigan Corporate Income Tax which is discussed below.

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The Company had $4 million of unrecognized tax benefits at September 30, 2011 and $5 million at December 31, 2010, that, if recognized, would favorably impact its effective tax rate. The Company has increased its unrecognized tax benefit by $40 million in the nine months ended September 30, 2011, as a result of a change in a tax position taken during a prior period. During the next twelve months, it is reasonably possible that the Company will settle certain federal tax audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $49 million.

Michigan Corporate Income Tax (MCIT)

On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and will become effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

Effective with the enactment of the MCIT in the second quarter of 2011, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $41 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT.

Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of net deferred tax assets of $307 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $88 million decrease in deferred tax liabilities attributable to our non-utility entities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $88 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy’s unitary Michigan tax return. The $88 million was recognized as a reduction to income tax expense in the second quarter of 2011.

Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statements of Cash Flows.

Offsetting Amounts Related to Certain Contracts

The Company offsets 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 agreement, which reduces both the Company’s total assets and total liabilities. As of September 30, 2011, the total cash collateral posted, net of cash collateral received, was $66 million. Derivative liabilities are shown net of collateral of $3 million. At September 30, 2011, the Company recorded cash collateral received of $1 million and cash collateral paid of $64 million not related to derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

NOTE 3 — FAIR VALUE

Fair value is defined 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 was immaterial at September 30, 2011 and December 31, 2010.

The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

A fair value hierarchy has been established, that 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. All assets and liabilities are required to 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 as follows:

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• 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 September 30, 2011:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			September 30, 2011
Assets:
Nuclear decommissioning trusts	$	532		$	361		$	—		$	—		$	893
Other investments(1)	48			56			—			—			104
Derivative assets:
Foreign currency exchange contracts	—			6			—			(6		)	—
Commodity Contracts:
Natural Gas	1,650			79			17			(1,698		)	48
Electricity	—			326			67			(282		)	111
Other	22			—			7			(20		)	9
Total derivative assets	1,672			411			91			(2,006		)	168
Total	$	2,252		$	828		$	91		$	(2,006	)	$	1,165
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(9	)	$	—		$	6		$	(3	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,616		)	(167		)	(12		)	1,698			(97		)
Electricity	—			(295		)	(70		)	285			(80		)
Other	(14		)	(1		)	—			20			5
Total derivative liabilities	(1,630		)	(473		)	(82		)	2,009			(176		)
Total	$	(1,630	)	$	(473	)	$	(82	)	$	2,009		$	(176	)
Net Assets as of September 30, 2011	$	622		$	355		$	9		$	3		$	989
Assets:
Current	$	1,251		$	322		$	62		$	(1,526	)	$	109
Noncurrent(3)	1,001			506			29			(480		)	1,056
Total Assets	$	2,252		$	828		$	91		$	(2,006	)	$	1,165
Liabilities:
Current	$	(1,235	)	$	(348	)	$	(60	)	$	1,529		$	(114	)
Noncurrent	(395		)	(125		)	(22		)	480			(62		)
Total Liabilities	$	(1,630	)	$	(473	)	$	(82	)	$	2,009		$	(176	)
Net Assets as of September 30, 2011	$	622		$	355		$	9		$	3		$	989

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The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			December 31, 2010
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments(1)	56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			20			—			(20		)	—
Commodity Contracts:
Natural Gas	1,846			128			12			(1,960		)	26
Electricity	—			649			117			(589		)	177
Other	68			4			4			(71		)	5
Total derivative assets	1,914			801			133			(2,640		)	208
Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,844		)	(263		)	(11		)	1,955			(163		)
Electricity	—			(653		)	(63		)	643			(73		)
Other	(63		)	(8		)	—			66			(5		)
Total derivative liabilities	(1,907		)	(955		)	(74		)	2,684			(252		)
Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006
Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent(3)	1,270			533			84			(760		)	1,127
Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent	(617		)	(225		)	(53		)	785			(110		)
Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

_____________________________

(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.

(3) Includes $104 million and $111 million at September 30, 2011 and December 31, 2010, respectively, of other investments that are included in the Consolidated Statements of Financial Position in Other Investments.

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The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30, 2011
(in Millions)	Natural Gas			Electricity			Other		Total
Net Assets as of July 1, 2011	$	1		$	57		$	7	$	65
Transfers into Level 3	(1		)	(6		)	—		(7		)
Transfers out of Level 3	—			(42		)	—		(42		)
Total gains or (losses):
Included in earnings	6			23			—		29
Purchases, issuances, sales and settlements:
Settlements	(1		)	(35		)	—		(36		)
Net Assets (Liabilities) as of September 30, 2011	$	5		$	(3	)	$	7	$	9
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2011	$	6		$	5		$	—	$	11

	Three Months Ended September 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of July 1, 2010	$	2		$	155		$	4		$	161
Changes in fair value recorded in income	3			21			1			25
Purchases, issuances and settlements	(1		)	(29		)	(1		)	(31		)
Transfers in/out of Level 3	—			(22		)	—			(22		)
Net Assets as of September 30, 2010	$	4		$	125		$	4		$	133
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2010	$	2		$	(4	)	$	1		$	(1	)

	Nine Months Ended September 30, 2011
(in Millions)	Natural Gas		Electricity			Other			Total
Net Assets as of January 1, 2011	$	1	$	54		$	4		$	59
Transfers into Level 3	—		(4		)	—			(4		)
Transfers out of Level 3	1		(25		)	—			(24		)
Total gains or (losses):
Included in earnings	3		34			2			39
Recorded in regulatory assets/liabilities	—		—			3			3
Purchases, issuances, sales and settlements:
Purchases	—		1			—			1
Settlements	—		(63		)	(2		)	(65		)
Net Assets (Liabilities) as of September 30, 2011	$	5	$	(3	)	$	7		$	9
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2011	$	5	$	17		$	2		$	24

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	Nine Months Ended September 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value recorded in income	4			117			1			122
Changes in fair value recorded in regulatory assets/liabilities	—			—			4			4
Purchases, issuances and settlements	(6		)	(59		)	(4		)	(69		)
Transfers in/out of Level 3	4			48			—			52
Net Assets as of September 30, 2010	$	4		$	125		$	4		$	133
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2010	$	(2	)	$	58		$	1		$	57

Transfers in and transfers out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and 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 and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. For the three and nine months ended September 30, 2011, $42 million and $25 million, respectively, of net assets reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2. For the three and nine months ended September 30, 2011, $6 million and $4 million, respectively, of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3.

Transfers from Level 3 to Level 2 of $22 million reflect inputs related to certain power transactions identified as observable due to available broker quotes for the three months ended September 30, 2010. Transfers from Level 2 to Level 3 of $48 million reflect inputs related to certain power transactions identified as unobservable due to lack of available broker quotes for the nine months ended September 30, 2010. No significant transfers between Levels 1 and 2 occurred in the three and nine months ended September 30, 2011 and 2010.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other 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 in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or 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 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. DTE Energy considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. DTE Energy monitors the prices that are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. DTE Energy has obtained an understanding of how these prices are derived. Additionally, DTE Energy selectively corroborates the fair value of its transactions by comparison of market-based price sources. 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.

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Fair Value of Financial Instruments

The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 4 for further fair value information on financial and derivative instruments.

	September 30, 2011				December 31, 2010
(in Billions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-Term Debt	$	8.8	$	7.7	$	8.5	$	8.0

Nuclear Decommissioning Trust Funds

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. See Note 5.

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.

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:

	September 30,		December 31,
(in Millions)	2011		2010
Fermi 2	$	858	$	910
Fermi 1	3		3
Low level radioactive waste	32		26
Total	$	893	$	939

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:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Realized gains	$	8		$	8		$	34		$	29
Realized losses	(9		)	(6		)	(26		)	(25		)
Proceeds from sales of securities	10			51			69			179

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the Regulatory asset and Nuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

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	Fair		Unrealized
(in Millions)	Value		Gains
As of September 30, 2011
Equity securities	$	485	$	52
Debt securities	395		22
Cash and cash equivalents	13		—
	$	893	$	74
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities	361		11
Cash and cash equivalents	6		—
	$	939	$	88

The debt securities at September 30, 2011 and December 31, 2010 had an average maturity of approximately 7 and 6 years, respectively. 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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. Detroit Edison recognized $87 million and $26 million of unrealized losses as Regulatory assets at September 30, 2011 and December 31, 2010, 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, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized for the three and nine months ended September 30, 2011 and September 30, 2010 for Fermi 1 trust assets.

Other Available-For-Sale Securities

The following table summarizes the fair value of the Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:

	September 30, 2011				December 31, 2010
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	85	$	85	$	133	$	133
Equity securities	5		5		6		6

As of September 30, 2011, these securities were comprised primarily of money-market funds and equity securities. During the nine months ended September 30, 2011 and 2010, no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the period. Gains (losses) related to trading securities held at September 30, 2011 and September 30, 2010 were $(3) million and $3 million, respectively.

NOTE 4 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the 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 the derivative 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 exchange. The Company has risk management policies to monitor and manage market risks. The Company uses derivative instruments to manage some of the exposure. The Company uses derivative instruments for trading purposes in its Energy

19

Trading segment and the coal marketing activities of its Power and Industrial Projects segment. Contracts classified as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, unconventional gas reserves, power transmission, pipeline transportation and certain storage assets.

Electric Utility — 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. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.

Gas Utility — MichCon purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through March 2014. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Gas Storage and Pipelines — This segment is primarily engaged in services related to the transportation, gathering and storage of natural gas. Primarily fixed-priced contracts are used in the marketing and management of transportation, gathering and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional natural gas and oil project development and production. The Company may use derivative contracts to manage changes in the price of natural gas and crude oil.

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal 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 segment 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 emission allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity and natural gas physical products and energy financial instruments, and provides energy and asset 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 hedge accounting criteria are met.

Energy Trading — Foreign Currency Exchange Risk — Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Corporate and Other — 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 through 2033. In 2011, the Company estimates reclassifying less than $1 million of losses to earnings.

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 September 30, 2011 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

20

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year). The following describe the four categories of activities represented by their operating characteristics and key risks:

• Asset Optimization - Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with power transmission, gas transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.

• Marketing and Origination - Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

• Fundamentals Based Trading - Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

• Other - Includes derivative activity at Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

The following tables present the fair value of derivative instruments as of September 30, 2011:

(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	6	$	(9	)
Commodity Contracts:
Natural Gas	1,746		(1,795		)
Electricity	393		(365		)
Other	29		(15		)
Total derivatives not designated as hedging instruments	$	2,174	$	(2,184	)
Total derivatives:
Current	$	1,635	$	(1,643	)
Noncurrent	539		(542		)
Total derivatives	$	2,174	$	(2,185	)

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	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,635		$	539		$	(1,643	)	$	(542	)
Counterparty netting	(1,526		)	(480		)	1,526			480
Collateral adjustment	—			—			3			—
Total derivatives as reported	$	109		$	59		$	(114	)	$	(62	)

The following tables present the fair value of derivative instruments as of December 31, 2010:

(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas	1,986		(2,118		)
Electricity	766		(716		)
Other	76		(71		)
Total derivatives not designated as hedging instruments	$	2,848	$	(2,935	)
Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent	837		(895		)
Total derivatives	$	2,848	$	(2,936	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting	(1,871		)	(760		)	1,871			760
Collateral adjustment	(9		)	—			28			25
Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

The income effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and September 30, 2010 is as follows:

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	Location of Gain (Loss) Recognized	Gain (Loss) Recognized in Income on Derivatives for Three Months Ended					Gain (Loss) Recognized in Income on Derivatives for Nine Months Ended
(in Millions)	in Income	September 30					September 30
Derivatives Not Designated As Hedging Instruments	On Derivatives	2011		2010			2011			2010
Foreign currency exchange contracts	Operating Revenue	$	4	$	(8	)	$	(1	)	$	(5	)
Commodity Contracts:
Natural Gas	Operating Revenue	9		24			24			51
Natural Gas	Fuel, purchased power and gas	10		(1		)	—			(7		)
Electricity	Operating Revenue	35		(6		)	64			43
Other	Operating Revenue	1		5			9			6
Other	Operation and maintenance	—		(2		)	—			(3		)
Total		$	59	$	12		$	96		$	85

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position are $3 million in gains related to FTRs recognized in Regulatory liabilities for the nine months ended September 30, 2011. There was no material effect for the three months ended September 30, 2011.

The following table presents the cumulative gross volume of derivative contracts outstanding as of September 30, 2011:

Commodity	Number of Units
Natural Gas (MMBtu)	631,382,267
Electricity (MWh)	46,441,874
Foreign Currency Exchange ($ CAD)	60,992,581

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 September 30, 2011, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date under both hard trigger and soft trigger provisions was approximately $209 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

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NOTE 5 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the nine months ended September 30, 2011 follows:

(in Millions)
Asset retirement obligations at December 31, 2010	$	1,514
Accretion	69
Liabilities incurred	3
Revision in estimated cash flows	(1		)
Liabilities settled	(15		)
Asset retirement obligations at September 30, 2011	1,570
Less amount included in current liabilities	(10		)
	$	1,560

In 2001, Detroit Edison began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In the first quarter of 2011, based on management decisions revising the timing and estimate of cash flows, Detroit Edison accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management intends to suspend decommissioning activities and place the facility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations. In the second quarter of 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the Detroit Edison asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations.

NOTE 6 — REGULATORY MATTERS

2010 Electric Rate Case Filing

On October 20, 2011, the MPSC issued an order in Detroit Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $175 million. Included in the approved increase in revenues was a return on equity of 10.5% on an expected permanent capital structure of 49.2% equity and 50.8% debt.

Detroit Edison self-implemented a rate increase of $107 million on April 28, 2011. The MPSC stated the net revenue collected due to self-implementation be credited to the 2011 Choice Incentive Mechanism (CIM) regulatory asset. Self-implementation revenue of approximately $31 million was credited to the CIM Regulatory Asset as of September 30, 2011. The MPSC required that within ninety days, Detroit Edison file a report regarding the amount of revenue collected through application of its self-implemented rate increase and a proposed reconciliation with the final rates and rate design approved in the order. In addition, a 2011 CIM reconciliation is expected to be filed in early 2012.

Other key aspects of the MPSC order include the following:

• adopt a new Revenue Decoupling Mechanism (RDM) effective April 1, 2012, that will compare actual revenue (excluding the impacts of weather) by rate class with the base established in this rate case. The RDM has an annual collar of 1.5% in the first year and 3% in the second and subsequent years. The RDM established in the previous rate case, which considered the impact of weather, will be terminated effective October 31, 2011. Therefore, there will be no RDM in place from October 31, 2011 through April 1, 2012;

• recognition of the expiration of a wholesale contract. Since the expiration of the wholesale contract is not until December 31, 2011, the MPSC is requiring Detroit Edison to calculate a customer credit for each kWh sold under the wholesale contract from October 29, 2011 through December 31, 2011, with the credit to be applied in its next PSCR reconciliation;

• the Restoration Reconciliation Mechanism, Line Clearance Recovery Mechanism, Uncollectible Expense Tracking Mechanism and CIM are terminated as of the date of the order;

• due to uncertainty resulting from the Michigan Court of Appeals overturning collection of the Low Income Energy Efficiency Fund (LIEEF), the MPSC required the continued collection of LIEEF amounts in base rates and placement into escrow pending further orders by the MPSC;

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• approval of Detroit Edison's proposal to reduce the Nuclear Decommissioning Surcharge by approximately $20 million annually; and

• implementation of lower depreciation rates previously approved in a June 2011 MPSC order.

Detroit Edison Uncollectible Expense True-Up Mechanism (UETM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its UETM for 2010 requesting authority to refund approximately $7 million consisting of costs related to 2010 uncollectible expense. In August 2011, the MPSC approved a settlement agreement for the 2010 UETM authorizing a refund of approximately $7 million to be applied as credits to customer bills beginning September 1, 2011.

Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line ClearanceTracker (LCT) Reconciliation

In March 2011, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2010 RETM and LCT. The Company's 2010 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested recovery of $19.5 million. In October 2011, the MPSC approved a settlement agreement reconciling the RETM and approving the LCT report. The MPSC authorized surcharges to recover $19.5 million over a three-month period beginning November 1, 2011.

Detroit Edison Revenue Decoupling Mechanism (RDM)

In May 2011, Detroit Edison filed an application with the MPSC for approval of its RDM reconciliation for the period February 2010 through January 2011 requesting authority to refund approximately $56 million, plus interest. This is the initial reconciliation filing under the pilot RDM. In addition to the refund liability for the initial reconciliation filing, Detroit Edison has accrued an RDM refund for the February 2011 through September 2011 period of approximately $71 million, plus interest. There are various interpretations and alternative calculation methodologies relating to the RDM refund calculation that could ultimately be adopted by the MPSC that could result in significant adjustments in excess of the amounts accrued as of September 30, 2011. An MPSC order on the initial filing is expected in the first half of 2012.

Power Supply Cost Recovery (PSCR) Proceedings

The PSCR process is designed to allow Detroit Edison to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. Detroit Edison’s power supply costs include fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, urea costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

The following table summarizes Detroit Edison’s PSCR reconciliation filing currently pending with the MPSC:

		Net Under-Recovery,		PSCR Cost of
		Including Interest		Power Sold
PSCR Year	Date Filed	(in Millions)		(in Billions)
2010	March 2011	$	52.6	$	1.2

2010 PSCR Year — The net under-recovery of $52.6 million includes an over-recovery of $15.6 million for the 2009 PSCR year. In addition, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism, and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing.

2011 Plan Year — In September 2010, Detroit Edison filed its 2011 PSCR plan case seeking approval of a levelized PSCR factor of 2.98 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.2 billion. The plan also includes approximately $36 million for the recovery of its projected 2010 PSCR under-recovery.

2012 Plan Year — In September 2011, Detroit Edison filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected

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2011 PSCR under-recovery.

Energy Optimization (EO) Plans

In September 2011, Detroit Edison and MichCon filed biennial EO Plans with the MPSC as required. Detroit Edison's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $294 million and further requested approval of surcharges to recover these costs. MichCon's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $103 million and further requested approval of surcharges to recover these costs.

Low Income Energy Efficiency Fund

The Customer Choice and Electricity Reliability Act of 2000 authorized the creation of the LIEEF administered by the MPSC. The purpose of the fund is to provide shut-off and other protection for low income customers and to promote energy efficiency by all customer classes. Detroit Edison and MichCon collect funding for the LIEEF as part of their base rates and remit the funds to the State of Michigan monthly. In July 2011, the Michigan Court of Appeals issued a decision reversing the portion of MichCon's June 2010 MPSC rate order that permitted MichCon to recover funding for the LIEEF in base rates. In response to the Court of Appeals decision, Detroit Edison and MichCon have ceased remitting payments for LIEEF funding to the State of Michigan. In October 2011, the MPSC issued orders directing Detroit Edison and MichCon to continue collecting funds for LIEEF in rates and to escrow the collected funds pending further order by the MPSC. As a result of these actions, Detroit Edison and MichCon no longer record Operation and Maintenance expense for the payments to the LIEEF fund, but record an offset to Revenues for the amounts that are being escrowed.

MichCon UETM

In March 2011, MichCon filed an application with the MPSC for approval of its UETM for 2010 requesting recovery of $31 million. The $31 million consists of $7 million related to 2010 uncollectible expense and $24 million related to the 2008 UETM under-collection. In September 2011, the MPSC approved a settlement agreement approving the 2010 UETM and the implementation of a surcharge beginning October 1, 2011.

MichCon Revenue Decoupling Mechanism (RDM)

In September 2011, MichCon filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. MichCon's RDM application proposed the recovery of approximately $20 million.

Gas Cost Recovery (GCR) Proceedings

The GCR process is designed to allow MichCon to recover all of its gas supply costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

The following table summarizes MichCon’s GCR reconciliation filing currently pending with the MPSC:

		Net Over-Recovery,		GCR Cost of
		Including Interest		Gas Sold
GCR Year	Date Filed	(in Millions)		(in Billions)
2009-2010	June 2010	$	5.9	$	1.0
2010-2011	June 2011	$	1.0	$	0.7

2011-2012 Plan Year — In December 2010, MichCon filed its GCR plan case for the 2011-2012 GCR plan year. MichCon filed for a maximum base GCR factor of $5.89 per Mcf adjustable monthly by a contingency factor.

Gas Main Renewal and Gas Meter Move Out Programs

The June 3, 2010 MPSC gas rate case order required MichCon to make filings related to gas main renewal and meter move-out programs. In a July 30, 2010 filing, MichCon proposed to implement a 10-year gas main renewal program beginning in 2012 which would require capital expenditures of approximately $17 million per year for renewing gas distribution mains, retiring gas mains, and where appropriate and when related to the gas main renewal or retirement activity, relocating inside meters to outside locations and renewing service lines. In a September 30, 2010 filing, MichCon proposed to implement a 10-year gas meter move out program beginning in 2012 which would require capital expenditures of approximately $22 million per year primarily for

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relocation of inside meters to the outside of residents' houses. In September 2011, the MPSC issued orders approving both programs and requested MichCon to include the recovery of costs associated with these two programs in future MichCon rate cases.

Other

The Company is unable to predict the outcome of the unresolved 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 7 — EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options.

	Three Months				Nine Months
	Ended September 30				Ended September 30
(in Millions, except per share amounts)	2011		2010		2011		2010
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	183	$	163	$	561	$	478
Average number of common shares outstanding	169		169		169		168
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	99	$	94	$	293	$	271
Dividends declared — net restricted shares	—		1		1		1
Total distributed earnings	$	99	$	95	$	294	$	272
Net income less distributed earnings	$	84	$	68	$	267	$	206
Distributed (dividends per common share)	0.59		0.56		$	1.74	$	1.62
Undistributed	0.49		0.41		1.57		1.23
Total Basic Earnings per Common Share	$	1.08	0.97		$	3.31	$	2.85
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	183	$	163	$	561	$	478
Average number of common shares outstanding	169		169		169		168
Average incremental shares from assumed exercise of options	1		1		1		—
Common shares for dilutive calculation	170		170		170		168
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	99	$	94	$	293	$	271
Dividends declared — net restricted shares	—		1		1		1
Total distributed earnings	$	99	$	95	$	294	$	272
Net income less distributed earnings	$	84	$	68	$	267	$	206
Distributed (dividends per common share)	$	0.59	$	0.56	$	1.74	$	1.62
Undistributed	0.48		0.40		1.56		1.22
Total Diluted Earnings per Common Share	$	1.07	$	0.96	$	3.30	$	2.84

Options to purchase approximately 0.4 million shares of common stock as of September 30, 2010, 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 8 — LONG-TERM DEBT

Debt Issuances

In 2011, the Company remarketed or issued the following long-term debt:

(in Millions)

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Company	Month Issued	Type	Interest Rate		Maturity	Amount
Detroit Edison	April	Tax-Exempt Revenue Bonds(1)(2)	2.35	%	2024	$	31
Detroit Edison	May	Mortgage Bonds(3)	3.90	%	2021	250
DTE Energy	May	Senior Notes(4)	Variable(5)		2013	300
Detroit Edison	September	Mortgage Bonds(6)	4.31	%	2023	102
Detroit Edison	September	Mortgage Bonds(6)	4.46	%	2026	77
Detroit Edison	September	Mortgage Bonds(6)	5.67	%	2041	46
Detroit Edison	September	Tax-Exempt Revenue Bonds(2)(7)	2.13	%	2030	82
Detroit Edison	September	Mortgage Bonds (8)	4.50	%	2041	140
						$	1,028

_____________________________

(1) These bonds were remarketed for a three-year term ending April 1, 2014. The final maturity of the issue is October 1, 2024.

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

(3) Proceeds were used for general corporate purposes.

(4) Proceeds were used to repay a portion of DTE Energy’s $600 million7.05% Senior Notes due June 1, 2011 and for general corporate purposes.

(5) The interest rate is reset quarterly at the three-month LIBOR plus 70 basis points.

(6) Proceeds were used to retire callable tax-exempt revenue bonds and for general corporate purposes.

(7) These bonds were remarketed for a five-year term ending September 1, 2016. The final maturity of the issue is September 1, 2030.

(8) Proceeds were used to retire approximately $140 million of callable tax-exempt revenue bonds and for general corporate purposes.

Debt Retirements and Redemptions

In 2011, the following debt was retired:

(in Millions)

Company	Month Retired	Type	Interest Rate		Maturity	Amount
Detroit Edison	May	Tax-Exempt Revenue Bonds	6.95	%	2011	$	26
DTE Energy	June	Senior Notes	7.05	%	2011	600
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.55	%	2029	118
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65	%	2029	67
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65	%	2029	40
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.45	%	2029	140
						$	991

NOTE 9 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon have entered into unsecured revolving credit facilities with similar terms with a syndicate of 23 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.25% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.

The above agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and

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junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain MichCon short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At September 30, 2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon were 0.49 to 1, 0.52 to 1 and 0.47 to 1, respectively, and were in compliance with this financial covenant. The availability under these combined facilities at September 30, 2011 is shown in the following table:

(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Unsecured revolving credit facility, expiring August 2012	$	538	$	212	$	250	$	1,000
Unsecured revolving credit facility, expiring August 2013	562		63		175		800
Unsecured letter of credit facility, expiring in May 2013	50		—		—		50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Total credit facilities at September 30, 2011	$	1,275	$	275	$	425	$	1,975
Amounts outstanding at September 30, 2011:
Commercial paper issuances	126		49		100		275
Letters of credit outstanding at September 30, 2011	144		—		—		144
	270		49		100		419
Net availability at September 30, 2011	$	1,005	$	226	$	325	$	1,556

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $38 million which are used for various corporate purposes.

In October 2011, the Company completed an early renewal of its $1.0 billion and $800 million syndicated unsecured revolving credit facilities before their scheduled expiration in August 2012 and August 2013, respectively. The new $1.8 billionfive-year facility will expire in October 2016 and has covenants similar to the prior facilities.

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 $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At September 30, 2011, a $15 million letter of credit was in place, raising the capacity under this facility to $115 million. The $15 million letter of credit is included in the table above. The amount outstanding under this agreement was $4 million and $39 million at September 30, 2011 and December 31, 2010, respectively.

NOTE 10 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The rules have led 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 $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of approximately $200 million in 2011 and up to $2 billion of additional capital expenditures through 2020 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The EPA’s proposed National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric Utility Steam Generating Units rule (covering mercury and other air pollutants) was issued on March 16, 2011 for review and comment. The EPA accepted comments on the proposal and may modify it prior to finalization, scheduled for November 2011. Also, on July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which replaces the Clean Air Interstate Rule (CAIR), requiring further reductions of sulfur dioxides and nitrogen oxides. DTE Energy is reviewing potential impacts of the proposed and recently finalized rules, but is not able to quantify the financial impact of these and other expected rulemakings at this time.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant

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Deterioration requirements, and operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison’s fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA’s motion for preliminary injunction was denied. On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit.

DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV, Detroit Edison could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of these matters, or the timing of its resolution.

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 completed studies and expected future studies, 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 $80 million in additional capital expenditures over the 4 to 6 years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted 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 and in April 2009 upheld the EPA’s use of this provision in determining best technology available for reducing environmental impacts. On April 20, 2011, the EPA published a proposed rule. A final rule is scheduled to be issued in mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the financial impacts of these developing requirements.

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. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The 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, including the area surrounding an ash landfill, electrical distribution substations, and 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 September 30, 2011 and December 31, 2010, the Company had $8 million and $9 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.

Landfill — Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction. Those repairs are ongoing and are expected to be completed by 2013.

The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the financial impact of those expected rulemakings at this time.

Gas Utility

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Contaminated Sites — Gas Utility owns, or previously owned, 15 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. As of September 30, 2011 and December 31, 2010, the Company had $41 million and $36 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. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a 10-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s 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 Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a Notice of Violation in June of 2007 alleging 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 financial impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDEQ concerning visible emissions readings that resulted from the Company self reporting to MDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the financial impact of this investigation.

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company expects to enter into the Consent Order during the fourth quarter of 2011.

The Company received two Notices of Violation from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $1.5 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company may spend an additional $13 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.

The Company believes that its non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). Both IBMACT and CISWI regulations were stayed and a re-proposal is expected by the end of 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Based on the final approved regulations, anticipated in the first half of 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit

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filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. On October 15, 2009, the U.S. District Court granted defendants’ motions dismissing all of plaintiffs’ federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs’ state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.

Nuclear Operations

Property Insurance

Detroit Edison maintains 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 $29 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 of January 1, 2011, as required by federal law, Detroit Edison maintains $375 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.

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 accounted for as 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 and the proposed fiscal year 2011 federal budget recommends termination of funding for completion of the government’s long-term storage facility. 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 spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

Guarantees

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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. The Company’s guarantees are not individually material with maximum potential payments totaling $10 million at September 30, 2011.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of September 30, 2011, the Company had approximately $14 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 the Company’s approximately 5,000 represented employees. In the 2011 second quarter, a new three-year agreement was ratified covering approximately 400 represented employees. The majority of the remaining represented employees are under contracts that expire August 2012 and June and October 2013.

Purchase Commitments

As of September 30, 2011, 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 billion from 2011 through 2051.

The Company also estimates that 2011 capital expenditures will be approximately $1.7 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, financial and other industries. Certain of its 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 records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

Other Contingencies

The Company is involved in certain other 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 that 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 Notes 4 and 6 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 11 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

The following table details the components of net periodic benefit costs for pension benefits and other postretirement benefits:

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							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Three Months Ended September 30
Service cost	$	15		$	16		$	14		$	15
Interest cost	51			51			28			31
Expected return on plan assets	(62		)	(65		)	(24		)	(18		)
Amortization of:
Net actuarial loss	41			25			12			13
Prior service cost (credit)	—			1			(7		)	(1		)
Net transition liability	—			—			1			1
Special termination benefits	—			—			—			—
Net periodic benefit cost	$	45		$	28		$	24		$	41

							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Nine Months Ended September 30
Service cost	$	52		$	48		$	48		$	46
Interest cost	152			152			90			94
Expected return on plan assets	(185		)	(194		)	(71		)	(56		)
Amortization of:
Net actuarial loss	107			75			42			40
Prior service cost (credit)	2			3			(20		)	(3		)
Net transition liability	—			—			2			2
Special termination benefits	2						—			—
Net periodic benefit cost	$	130		$	84		$	91		$	123

Pension and Other Postretirement Contributions

In January 2011, the Company contributed $200 million to its pension plans.

In January 2011, the Company contributed $81 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $125 million contribution to its other postretirement benefit plans by the end of 2011.

NOTE 12 — STOCK-BASED COMPENSATION

The following table summarizes the components of stock-based compensation expense:

	Three Months Ended
	September 30
(in Millions)	2011		2010
Stock-based compensation expense	$	13	$	9
Tax benefit	5		4
Stock-based compensation cost capitalized in property, plant and equipment	1		1

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	Nine Months Ended
	September 30
(in Millions)	2011		2010
Stock-based compensation expense	$	42	$	38
Tax benefit	16		15
Stock-based compensation cost capitalized in property, plant and equipment	3		2

Stock Options

The following table summarizes our stock option activity for the nine months ended September 30, 2011:

	Number of Options		Weighted Average Exercise Price Per Share		(in Millions) Aggregate Intrinsic Value
Options outstanding at January 1, 2011	4,827,457		$	41.09
Granted	—		$	—
Exercised	(1,541,690	)	$	40.52
Forfeited or expired	(21,963	)	$	43.41
Options outstanding at September 30, 2011	3,263,804		$	41.34	$	26
Options exercisable at September 30, 2011	2,597,318		$	42.30	$	18

As of September 30, 2011, the weighted average remaining contractual life for the exercisable shares was 4.42 years. As of September 30, 2011, 666,486 options were non-vested. During the nine months ended September 30, 2011, 687,061 options vested.

The intrinsic value of options exercised for the nine months ended September 30, 2011 was $14 million. Total option expense recognized was $1 million and $3 million for the nine months ended September 30, 2011 and 2010, respectively.

Restricted Stock Awards

The following summarizes stock awards activity for the nine months ended September 30, 2011:

	Restricted Stock		Weighted Average Grant Date Fair Value Per Share
Balance at January 1, 2011	757,414		$	37.32
Grants	381,840		$	47.98
Forfeitures	(65,592	)	$	40.84
Vested and issued	(339,138	)	$	38.25
Balance at September 30, 2011	734,524		$	42.22

Performance Share Awards

The following summarizes performance share activity for the nine months ended September 30, 2011:

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	Performance Shares
Balance at January 1, 2011	1,527,253
Grants	611,844
Forfeitures	(66,357	)
Payouts	(467,688	)
Balance at September 30, 2011	1,605,052

Unrecognized Compensation Cost

As of September 30, 2011, the Company had $56 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. These costs are expected to be recognized over a weighted-average period of 1.27 years.

NOTE 13 — SUPPLEMENTAL CASH FLOW INFORMATION

The following table details the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows, and supplementary non-cash information:

	Nine Months Ended
	September 30
(in Millions)	2011			2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	181		$	357
Inventories	(115		)	(200		)
Accrued/prepaid pensions	(186		)	(99		)
Accounts payable	(34		)	(14		)
Income taxes receivable/payable	267			19
Derivative assets and liabilities	(36		)	(58		)
Postretirement obligation	(59		)	20
Other assets	67			(11		)
Other liabilities	(37		)	59
	$	48		$	73
Noncash financing activities:
Common stock issued for employee benefit plans	$	1		$	147

NOTE 14 — SEGMENT INFORMATION

The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan.

Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Gas Storage and Pipelines consists of natural gas pipeline, gathering and storage businesses.

Unconventional Gas Production is engaged in unconventional gas and oil project development and production.

Power and Industrial Projects is comprised of coke batteries and pulverized coal projects, reduced emission fuel and steel industry fuel-related projects, on-site energy services, renewable power generation, landfill gas recovery and coal transportation, marketing and trading.

Energy Trading consists of energy marketing and trading operations.

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

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The federal 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 if applicable. The MBT provision of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various tax credits and net operating losses if applicable. See Note 2 for a discussion of the MCIT, which replaces the MBT effective January 1, 2012. The subsidiaries record federal and state income taxes payable to or receivable from DTE Energy based on the federal and state tax provisions of each company.

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:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Electric Utility	$	7		$	8		$	25		$	23
Gas Utility	1			1			2			1
Gas Storage and Pipelines	1			1			7			3
Power and Industrial Projects	30			50			119			122
Energy Trading	17			21			54			65
Corporate & Other	(12		)	(18		)	(40		)	(51		)
	$	44		$	63		$	167		$	163

Financial data of the business segments follows:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues
Electric Utility	$	1,517		$	1,444		$	3,950		$	3,798
Gas Utility	159			170			1,090			1,157
Gas Storage and Pipelines	21			20			69			62
Unconventional Gas Production	11			7			29			23
Power and Industrial Projects	259			303			781			846
Energy Trading	342			258			970			661
Corporate & Other	—			—			2			—
Reconciliation & Eliminations	(44		)	(63		)	(167		)	(163		)
Total	$	2,265		$	2,139		$	6,724		$	6,384
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	157		$	165		$	345		$	343
Gas Utility	(11		)	(6		)	69			92
Gas Storage and Pipelines	13			12			42			36
Unconventional Gas Production	(2		)	(4		)	(5		)	(9		)
Power and Industrial Projects	12			26			27			66
Energy Trading	22			(12		)	36			—
Corporate & Other (1)	(8		)	(18		)	47			(50		)
Net Income Attributable to DTE Energy	$	183		$	163		$	561		$	478

_____________________________

(1) The 2011 net income for Corporate & Other includes an income tax benefit of $88 million related to the enactment of the MCIT in the second quarter of 2011. See Note 2.

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Part I — Item 2.

DTE ENERGY COMPANY

Management’s Discussion and Analysis

of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company and is the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

Net income attributable to DTE Energy in the third quarter of 2011 was $183 million, or $1.07 per diluted share, compared to net income attributable to DTE Energy of $163 million, or $0.96 per diluted share, in the third quarter of 2010. Net income attributable to DTE Energy in the nine months ended September 30, 2011 was $561 million, or $3.30 per diluted share, compared to net income attributable to DTE Energy of $478 million, or $2.84 per diluted share, in the comparable period of 2010. The increases in net income were impacted by higher earnings in the Electric Utility and Energy Trading segments, partially offset by lower earnings in the Power and Industrial Projects. The increase for the nine month period is primarily due to an income tax benefit of $88 million in the Corporate & Other segment related to the enactment of the MCIT in the second quarter of 2011. See Note 2 of the Notes to Consolidated Financial Statements.

Please see detailed explanations of segment performance in the following Results of Operations section.

The items discussed below influenced our current financial performance and/or may affect future results.

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

UTILITY OPERATIONS

Our Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan.

On October 20, 2011, the MPSC issued an order in Detroit Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $175 million. Detroit Edison self-implemented a rate increase of $107 million on April 28, 2011. The MPSC stated the net revenue collected due to self-implementation be credited to the 2011 Choice Incentive Mechanism (CIM) regulatory asset. Self-implementation revenue of approximately $31 million was credited to the CIM Regulatory Asset as of September 30, 2011. The MPSC required that within ninety days, Detroit Edison file a report regarding the amount of revenue collected through application of its self-implemented rate increase and a proposed reconciliation with the final rates and rate design approved in the order. In addition, a 2011 CIM reconciliation is expected to be filed in early 2012. See Note 6 of the Notes to Consolidated Financial Statements.

Our Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Detroit Edison has experienced decreased electric sales in the nine months ended September 30, 2011 driven by lower interconnection and industrial sales, partially offset by higher residential and commercial sales. Interconnection sales are lower due primarily to lower power plant generation, while industrial sales are lower due to decreased demand from customers in the automotive and steel industries and their related suppliers and other ancillary businesses. The residential sales increase is primarily a result of weather related usage. MichCon’s sales were higher due to colder winter weather, partially offset by a decrease in the number of customers, reduced natural gas usage by customers due to economic conditions and an increased emphasis on conservation of energy usage.

Both utilities have exposure to the collectability of receivables in our market area. The Company continues to work with our customers through a variety of proactive programs to assist them. We also partner with federal, state and local officials to attempt to increase the share of low-income funding allocated to our customers. Changes in the level of funding provided to our low-income customers will affect the level of uncollectible expense. Reductions in the federal and state low income assistance programs could substantially reduce the approximately $125 million of assistance provided to DTE Energy's low income customers in 2010. To mitigate volatility of changes in the uncollectible expense, MichCon has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in its last rate case. Detroit Edison had an uncollectible expense tracking mechanism through October 2011 which was eliminated in Detroit Edison's October 20, 2011 MPSC order. The uncollectible expense

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tracking mechanisms require annual reconciliation proceedings before the MPSC.

	Nine Months Ended
	September 30
(in Millions)	2011		2010
Uncollectible Expense
Detroit Edison	$	34	$	42
MichCon	36		49
	$	70	$	91

We are continuing our efforts to identify opportunities to improve cash flow at our utilities through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects. We are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength. See the Capital Resources and Liquidity section in this Management’s Discussion and Analysis for further discussion of our liquidity outlook.

NON-UTILITY OPERATIONS

We have significant investments in non-utility businesses. We employ disciplined investment criteria when assessing opportunities that leverage our assets, skills and expertise. Specifically, we invest in targeted energy markets with attractive competitive dynamics where meaningful scale is in alignment with our risk profile. We expect growth opportunities in the Gas Storage and Pipelines and Power and Industrial Projects segments in the future. We believe that expansion of these businesses will also result in our ability to further diversify geographically.

Gas Storage and Pipelines owns partnership interests in two natural gas storage fields and two interstate pipelines serving the Midwest, Ontario and Northeast markets. Much of the growth in demand for natural gas is expected to occur in the Eastern Canada and the Northeast U.S. regions. We believe that the Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. We believe that Millennium Pipeline is well positioned for growth related to production from the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York. Our planned Bluestone lateral and gathering system will be one such project.

Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production primarily within the Barnett shale in north Texas. Our acreage covers an area that produces high BTU gas which provides a significant contribution to revenues from the value of natural gas liquids extracted from the gas stream. During this period of low natural gas prices, these natural gas liquids, with prices correlated to crude oil prices, have provided a significant increase to our realized wellhead price. Our drilling efforts have and will continue to target liquids rich gas and oil producing locations. We continue to develop our holdings and to seek opportunities for additional monetization of select properties when conditions are appropriate.

Power and Industrial Projects is comprised primarily of projects that deliver energy, products and services to industrial, commercial and institutional customers; provide coal transportation and marketing; and sell electricity generated from biomass-fired energy projects. This business segment provides services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries. Renewable energy, environmental and economic trends are creating growth opportunities. We believe that the increasing number of states with renewable portfolio standards provides the opportunity to market the expertise of the Power and Industrial Projects segment in on-site energy management, waste-wood power generation, reduced emission fuel, landfill gas and other related services.

Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers’ behalf under FERC Asset Management Arrangements.

CAPITAL INVESTMENTS

Our utility businesses require significant capital investments each year in order to maintain and improve the reliability of their asset bases, including power generation plants, distribution systems, storage fields and other facilities and fleets. In addition, significant capital investments are required to comply with increasingly stringent environmental requirements. For both Detroit Edison and MichCon, we plan to seek regulatory approval in general rate case filings to include these capital expenditures within our regulatory rate base consistent with prior general rate case filing treatment.

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Detroit Edison is required to implement a 20-year renewable energy plan to address the provisions of Michigan Public Act 295 of 2008, with the goals of delivering cleaner renewable electric generation to its customers, further diversifying Detroit Edison’s and the State of Michigan’s sources of electric supply and addressing the state and national goals of increasing energy independence. Detroit Edison will seek separate regulatory approval and recovery of these renewable capital expenditures within our regulatory rate base through our renewable energy plan filings.

MichCon was required in its 2010 rate order to file two infrastructure improvement cases. MichCon filed a 10-year gas main renewal case for approximately $17 million per year and also filed a 10-year meter move out case for approximately $22 million per year. In September 2011, the MPSC issued orders approving both programs and requested MichCon to include the recovery of costs associated with these two programs in future rate cases.

In April 2010, the Company signed an agreement with the U.S. Department of Energy for a grant of approximately $84 million in matching funds on total anticipated spending of approximately $168 million related to the accelerated deployment of smart grid technology in Michigan through 2012. The smart grid technology includes the establishment of an advanced metering infrastructure and other technologies that address improved electric distribution service.

Non-utility investments are expected primarily in Gas Storage and Pipeline assets and renewable opportunities in the Power and Industrial Projects businesses.

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various substances on the environment are studied and governmental regulations are developed and implemented. Actual costs to comply could vary substantially. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers.

Air - Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The rules have led 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 $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of approximately $200 million in 2011 and up to $2 billion of additional capital expenditures through 2020 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The EPA's proposed National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric Utility Steam Generating Units rule (covering mercury and other air pollutants) was issued on March 16, 2011 for review and comment. The EPA accepted comments on the proposal and may modify it prior to finalization, scheduled for November 2011. Also, on July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which replaces the Clean Air Interstate Rule (CAIR), requiring further reductions of sulfur dioxides and nitrogen oxides. DTE Energy is reviewing potential impacts of the proposed and recently finalized rules, but is not able to quantify the financial impact of these and other expected rulemakings at this time.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA's motion for preliminary injunction was denied. On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit.

DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV's Detroit Edison could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. The Company cannot predict the financial impact or outcome of this

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matter, or the timing of its resolution.

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 completed studies and expected future studies, 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 $80 million in additional capital expenditures over the four to six years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted 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 and in April 2009 upheld the EPA's use of this provision in determining best technology available for reducing environmental impacts. On April 20, 2011, the EPA published a proposed rule. A final rule is scheduled to be issued in mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the financial impacts of these developing requirements.

Manufactured Gas Plant (MGP) and Other 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. The facilities, which produced gas, have been designated as MGP sites. Gas Utility owns, or previously owned, 15 such former MGP sites. Detroit Edison owns, or previously owned, three former MGP sites. In addition to the MGP sites, we are also in the process of cleaning up other sites where contamination is present as a result of historical and ongoing utility operations. These other sites include an engineered ash storage facility, electrical distribution substations, gas pipelines, and underground and aboveground storage tank locations. Cleanup activities associated with these sites will be conducted over the next several years.

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. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a 10-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company's results of operations.

Landfill - Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction. Those repairs are ongoing and are expected to be completed by 2013.

The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either, to designate coal ash as a “Hazardous Waste” as defined by RCRA or to regulate coal ash as non-hazardous waste under RCRA. However, agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA were to designate coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the financial impact of those expected rulemakings at this time.

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 Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a Notice of Violation in June of 2007 alleging 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 financial impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDEQ concerning visible emissions readings that resulted from the Company self reporting to MDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the financial impact of this investigation. The Company is also in the process of negotiating a Consent Order with the EPA to settle historical air and water violations at its coke battery facility located in Pennsylvania. The Company expects to enter into the Consent Order during the fourth quarter of 2011. The Company is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment and upgrade its coal pile storm water runoff management program for the coke battery facility located in Pennsylvania. This upgrade is

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expected to be completed over the next two years to meet future regulatory requirements.

The Company believes that its non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Other

In 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). Both IBMACT and CISWI regulations were stayed and a re-proposal is expected by the end of 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of 3 years for compliance with the applicable standards. Based on the final approved regulations, anticipated in the first half of 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

Global Climate Change

The EPA has promulgated the Greenhouse Gas Tailoring rule that regulates greenhouse gases as pollutants under the EPA’s new source permitting and major source operating permit programs, and that requires a Best Available Control Technology (BACT) determination for new and modified major sources of greenhouse gas (GHG). In addition, the EPA will be issuing proposed GHG performance standards for new and modified electric generating units in late 2011. In the U.S. Congress, efforts are focused on delaying the EPA’s regulation of GHGs with no expectation of enacting a comprehensive national climate program. Pending or future regulatory or legislative actions could have a material impact on our operations and financial position and the rates we charge our customers. Impacts include expenditures for environmental equipment beyond what is currently planned, financing costs related to additional capital expenditures, the purchase of emission offsets from market sources and the retirement of facilities where control equipment is not economical. We would seek to recover these incremental costs through increased rates charged to our utility customers. Increased costs for energy produced from traditional sources could also increase the economic viability of energy produced from renewable and/or nuclear sources and energy efficiency initiatives and the development of market-based trading of carbon offsets providing business opportunities for our utility and non-utility segments. It is not possible to quantify the financial impacts on DTE Energy or its customers at this time.

OUTLOOK

The next few years will be a period of rapid change for DTE Energy and for the energy industry. We believe that our strong utility base, combined with our integrated non-utility operations, position us well for long-term growth.

Looking forward, we will focus on several areas that we expect will improve future performance:

• improving Electric and Gas Utility customer satisfaction;

• continuing to maintain regulatory stability and investment recovery for our utilities;

• managing the growth of our utility asset base with consideration of customer affordability;

• optimizing our cost structure across all business segments;

• investing in non-utility businesses, particularly our Gas Storage and Pipelines and Power and Industrial Projects segments, that integrate our assets and leverage our skills and expertise; and

• managing cash, capital and liquidity to maintain or improve our financial strength.

We will continue to pursue opportunities to grow our businesses in a disciplined manner by securing opportunities that meet our strategic, financial and risk criteria.

RESULTS OF OPERATIONS

The following sections provide a detailed discussion of the operating performance and future outlook of our segments.

Net income attributable to DTE Energy by segment for the three and nine months ended September 30, 2011 and 2010 is as follows:

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	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	157		$	165		$	345		$	343
Gas Utility	(11		)	(6		)	69			92
Gas Storage and Pipelines	13			12			42			36
Unconventional Gas Production	(2		)	(4		)	(5		)	(9		)
Power and Industrial Projects	12			26			27			66
Energy Trading	22			(12		)	36			—
Corporate & Other	(8		)	(18		)	47			(50		)
Net Income Attributable to DTE Energy	$	183		$	163		$	561		$	478

ELECTRIC UTILITY

Our Electric Utility segment consists principally of Detroit Edison.

Electric Utility results are discussed below:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	1,517		$	1,444		$	3,950		$	3,798
Fuel and Purchased Power	553			484			1,348			1,217
Gross Margin	964			960			2,602			2,581
Operation and Maintenance	354			325			1,014			960
Depreciation and Amortization	215			230			622			644
Taxes Other Than Income	63			54			182			180
Asset (Gains) and Losses, Net	(1		)	—			13			(1		)
Operating Income	333			351			771			798
Other (Income) and Deductions	79			78			214			236
Income Tax Expense	97			108			212			219
Net Income Attributable to DTE Energy Company	$	157		$	165		$	345		$	343
Operating Income as a Percentage of Operating Revenues	22		%	24		%	20		%	21		%

Gross margin increased $4 million in the third quarter of 2011 and $21 million in the nine-month period ended September 30, 2011. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

(in Millions)	Three Months			Nine Months
Base sales, net of RDM and CIM	$	17		$	49
Securitization bond and tax surcharge	(13		)	(27		)
Electric Choice implementation surcharge elimination	(7		)	(18		)
Energy optimization incentive	—			9
Restoration tracker	22			27
Low Income Energy Efficiency Fund revenue deferral	(13		)	(13		)
Other	(2		)	(6		)
Increase in gross margin	$	4		$	21

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	Three Months Ended		Nine Months Ended
	September 30		September 30
(in Thousands of MWh)	2011	2010	2011	2010
Electric Sales
Residential	4,863	5,034	12,358	12,301
Commercial	4,759	4,730	12,750	12,660
Industrial	2,606	2,357	7,353	7,438
Other	782	798	2,343	2,398
	13,010	12,919	34,804	34,797
Interconnection sales (1)	884	1,270	2,346	4,031
Total Electric Sales	13,894	14,189	37,150	38,828
Electric Deliveries
Retail and Wholesale	13,010	12,919	34,804	34,797
Electric Customer Choice	1,393	1,289	4,104	3,675
Total Electric Sales and Deliveries	14,403	14,208	38,908	38,472

_____________________________

(1) Represents power that is not distributed by Detroit Edison.

Power Generated and Purchased

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Thousands of MWh)	2011			2010			2011			2010
Power Plant Generation
Fossil	10,143			11,224			27,007			30,339
Nuclear	2,386			2,368			6,500			6,656
	12,529			13,592			33,507			36,995
Purchased Power	2,353			1,669			6,403			4,465
System Output	14,882			15,261			39,910			41,460
Less Line Loss and Internal Use	(988		)	(1,072		)	(2,760		)	(2,632		)
Net System Output	13,894			14,189			37,150			38,828
Average Unit Cost ($/MWh) Generation (1)	$	25.45		$	19.81		$	22.90		$	19.22
Purchased Power	$	49.15		$	51.07		$	44.81		$	43.71
Overall Average Unit Cost	$	29.20		$	23.23		$	26.41		$	21.85

_____________________________

(1) Represents fuel costs associated with power plants.

Operation and maintenance expense increased $29 million and $54 million in the three and nine months ended September 30, 2011, respectively. The increase for the 2011 third quarter is primarily due to higher restoration and line clearance expenses of $26 million, increased power plant generation maintenance and outage expenses of $15 million and higher energy optimization and renewable energy expenses of $4 million, partially offset by $13 million in reduced contributions to a low income and energy efficiency fund due to a recent court order. The increase for the 2011 nine-month period is attributable to higher restoration and line clearance expenses of $27 million, increased power plant generation maintenance and outage expenses of $24 million, higher energy optimization and renewable energy expenses of $14 million, partially offset by $13 million in reduced contributions to a low income and energy efficiency fund due to a recent court order. See Note 6 of the Notes to Consolidated Financial Statements.

Asset (gains) and losses, net increased $1 million and decreased $14 million in the three and nine months ended September 30, 2011, respectively. The change in the nine month period is primarily attributable to an accrual of $19 million in the first quarter of 2011 resulting from management’s revisions of the timing and estimate of cash flows for the decommissioning of Fermi 1, partially offset by a second quarter 2011 revision of $6 million in the timing and estimate of cash flows for the Fermi 1 asbestos

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removal obligation. See Note 5 of the Notes to the Consolidated Financial Statements.

Outlook — We continue to move forward in our efforts to improve the operating performance and cash flow of Detroit Edison. We expect that our planned significant environmental and renewable energy investments will result in earnings growth. Looking forward, additional factors may impact earnings such as the outcome of regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs, and uncertainty of legislative or regulatory actions regarding climate change. We expect to continue our efforts to improve productivity and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

In July 2011, Detroit Edison notified the NRC that it intends to apply for renewal of the operating license for the Fermi 2 nuclear power plant. The current license expires in 2025 and NRC approval of the application would permit the plant to operate an additional 20 years. The application is expected to be filed with the NRC in 2014.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results are discussed below:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	159		$	170		$	1,090		$	1,157
Cost of Gas	36			39			537			586
Gross Margin	123			131			553			571
Operation and Maintenance	94			96			298			274
Depreciation and Amortization	22			20			66			68
Taxes Other Than Income	11			12			42			43
Operating Income (Loss)	(4		)	3			147			186
Other (Income) and Deductions	15			14			41			44
Income Tax Expense (Benefit)	(8		)	(5		)	37			50
Net Income (Loss) Attributable to DTE Energy Company	$	(11	)	$	(6	)	$	69		$	92
Operating Income as a Percentage of Operating Revenues	(3		)%	2		%	13		%	16		%

Gross margin decreased $8 million in the third quarter of 2011 and $18 million in the nine-month period ended September 30, 2011. Revenues associated with certain tracking mechanisms and surcharges are offset by related expenses elsewhere in the Statement of Operations. The following table details changes in various gross margin components relative to the comparable prior period:

(in Millions)	Three Months			Nine Months
Weather	$	—		$	43
Uncollectible tracking mechanism	—			(35		)
2010 self-implementation and rate order	(2		)	(19		)
Revenue decoupling mechanism	—			8
Energy optimization revenue and incentive	—			10
Midstream storage and transportation revenues	(3		)	(12		)
Revenue of subsidiaries transferred to Gas Storage and Pipelines segment	(4		)	(13		)
Other	1			—
Decrease in gross margin	$	(8	)	$	(18	)

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	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2011		2010		2011		2010
Gas Markets
Gas sales	$	99	$	96	$	832	$	887
End user transportation	29		30		145		136
	128		126		977		1,023
Intermediate transportation	12		17		42		48
Storage and other	19		27		71		86
	$	159	$	170	$	1,090	$	1,157
Gas Markets (in Bcf)
Gas sales	9		8		89		79
End user transportation	26		29		104		101
	35		37		193		180
Intermediate transportation	50		86		195		293
	85		123		388		473

Operation and maintenance expense decreased $2 million and increased $24 million in the three and nine months ended September 30, 2011, respectively. The increase for the nine month period is due primarily to the 2010 deferral of $32 million of previously expensed CTA restructuring expenses. The 2011 nine month period also included higher energy optimization expenses of $7 million, partially offset by lower uncollectible expenses of $14 million.

Outlook — We continue to move forward in our efforts to improve the operating performance and cash flow of Gas Utility. Unfavorable economic trends have resulted in a decrease in the number of customers in our service territory, increased customer conservation and continued high levels of theft and uncollectible accounts receivable. The MPSC has provided for an uncollectible expense tracking mechanism which assists in mitigating the impacts of economic conditions in our service territory and a revenue decoupling mechanism that addresses changes in average customer usage due to general economic conditions and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings volatility in the future. Looking forward, additional factors may impact earnings such as infrastructure improvement capital programs, the outcome of future regulatory proceedings, investment returns and changes in discount rate assumptions in benefit plans and health care costs. We expect to continue our efforts to improve productivity, minimize lost and stolen gas, and decrease our costs while improving customer satisfaction with consideration of customer rate affordability.

GAS STORAGE AND PIPELINES

Our Gas Storage and Pipelines segment consists of our non-utility gas pipelines and storage businesses.

Gas Storage and Pipelines results are discussed below:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	21		$	20		$	69		$	62
Operation and Maintenance	3			3			10			11
Depreciation and Amortization	2			1			5			4
Taxes Other Than Income	—			—			2			1
Operating Income	16			16			52			46
Other (Income) and Deductions	(6		)	(4		)	(19		)	(14		)
Income Tax Expense	8			8			26			23
Net Income	14			12			45			37
Noncontrolling Interest	1			—			3			1
Net Income Attributable to DTE Energy Company	$	13		$	12		$	42		$	36

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Net income attributable to DTE Energy Company increased $1 million and $6 million in the three and nine months ended September 30, 2011, respectively. The 2011 nine month increase was primarily driven by earnings from two operating subsidiaries that were transferred from an affiliate effective January 1, 2011 and a settlement for customer gas treating services performed in prior years.

Outlook — Our Gas Storage and Pipelines business expects to continue its steady growth plan and is evaluating new pipeline and storage investment opportunities. Millennium Pipeline has secured customers for its Phase 1 & 2 expansions which are scheduled to be in-service in the fourth quarter of 2012 and the fourth quarter of 2013, respectively. Millennium’s total capacity with the Phase 1 & 2 expansion will increase from 525,000 dth/d to over 800,000 dth/d. In addition, DTE has executed an agreement with Southwestern Energy Services Company to support its Bluestone lateral and gathering system. Bluestone is a 40 mile pipeline in Susquehanna County, Pennsylvania and Broome County, New York designed to initially flow 250,000 dth/d to both Millennium Pipeline and Tennessee Pipeline and is scheduled to be in-service in the second quarter of 2012. DTE plans to spend up to $280 million over the next five years on the Bluestone lateral and gathering system.

UNCONVENTIONAL GAS PRODUCTION

Our Unconventional Gas Production business is engaged in natural gas and oil exploration, development and production primarily within the Barnett shale in northern Texas.

Unconventional Gas Production results are discussed below:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	11		$	7		$	29		$	23
Operation and Maintenance	6			4			16			12
Depreciation, Depletion and Amortization	4			3			13			11
Taxes Other Than Income	1			—			2			1
Asset (Gains) and Losses, Net	—			3			—			7
Operating Loss	—			(3		)	(2		)	(8		)
Other (Income) and Deductions	2			2			5			5
Income Tax Benefit	—			(1		)	(2		)	(4		)
Net Loss Attributable to DTE Energy Company	$	(2	)	$	(4	)	$	(5	)	$	(9	)

Unconventional Gas Production results, for the nine month period, were slightly favorable primarily due to a $7 million impairment of expired or expiring leasehold positions in 2010. Both revenues and expenses increased as a result of new wells on line, increased liquids prices and higher crude oil production.

Outlook — In the longer-term, we plan to continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for monetization of select properties when conditions are appropriate. Our strategy for 2011 is to maintain our focus on optimizing the productivity of our wells. Given the continued outlook of low natural gas prices, drilling efforts will continue to target liquids rich gas and oil production. The majority of our acreage position has rights to shallow reserves lying above the Barnett shale, specifically the Marble Falls formation. Recent drilling efforts have been largely successful in finding oil and high BTU gas. We anticipate the continued development of this liquids play which is expected to add value to our asset base. During 2011, we expect total capital investment of $30 million to drill approximately 25 new wells and continue to acquire select acreage and achieve production of approximately 5.5 Bcfe of natural gas, compared with 5 Bcfe in 2010.

POWER AND INDUSTRIAL PROJECTS

Power and Industrial Projects is comprised primarily of projects that deliver energy and utility-type products and services to industrial, commercial and institutional customers; provide coal transportation services and marketing; and sell electricity generated from biomass-fired energy projects.

Power and Industrial Projects results are discussed below:

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	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues	$	259		$	303		$	781		$	846
Operation and Maintenance	232			256			699			720
Depreciation and Amortization	14			15			43			44
Taxes Other Than Income	3			3			8			10
Asset (Gains) Losses and Reserves and Impairments, Net	(7		)	(3		)	(13		)	(7		)
Operating Income	17			32			44			79
Other (Income) and Deductions	2			1			10			6
Income Taxes
Expense	3			11			11			28
Production Tax Credits	(1		)	(8		)	(4		)	(24		)
	2			3			7			4
Net Income	13			28			27			69
Noncontrolling Interests	1			2			—			3
Net Income Attributable to DTE Energy Company	$	12		$	26		$	27		$	66

Operating revenues decreased $44 million and $65 million in the three and nine months ended September 30, 2011, respectively. The decrease in the third quarter of 2011 is primarily due to $60 million of lower coal transportation and marketing services primarily due to the expiration of our long-term rail transportation contract in 2010 and an $11 million decrease associated with reduced emission fuels projects reflecting lower pass-through costs, offset by a $20 million increase in coke demand and pricing and a $7 million increase in new on-site projects. The decrease in the nine-month period is primarily due to $160 million of lower coal transportation and marketing services related to the expired rail transportation contract, offset by a $60 million increase in coke demand and pricing, a $12 million increase related to reduced emission fuels projects, and a $23 million increase in new on-site projects.

Operation and maintenance expense decreased $24 million and $21 million in the three and nine months ended September 30, 2011, respectively. The decrease in the third quarter of 2011 is primarily due to $41 million of lower coal transportation and marketing services primarily due to the expiration of our long-term rail transportation contract in 2010 and an $11 million decrease associated with reduced emission fuels projects, partially offset by a $27 million increase in coal costs and a $7 million increase in new on-site projects. The decrease in the nine-month period is primarily due to $127 million lower coal transportation and marketing services related to the expired rail transportation contract, partially offset by an $83 million increase in coal costs, an $11 million increase related to reduced emission fuels projects, and a $22 million increase in new on-site projects. Additionally, lower coke battery operating costs for the three and nine month periods favorably impacted results by $6 million and $10 million, respectively.

Asset (Gains) Losses and Reserves and Impairments, Net were higher by $4 million and $6 million in the three and nine months ended September 30, 2011, respectively. The increases in the third quarter and nine month period are primarily due to higher production of refined coal from our reduced emissions fuels projects that qualify for tax credits.

Production tax credits were lower by $7 million and $20 million in the three and nine months ended September 30, 2011, respectively, due primarily to expiration of steel industry fuels credits as of December 31, 2010.

Outlook — We expect sustained production levels of metallurgical coke and pulverized coal supplied to steel industry customers for 2011. During 2010 we experienced higher margins from coke sales due to premium pricing and lower coal costs. In 2011, we have returned to normal margin levels. The tax credits associated with our steel industry fuels facilities expired at December 31, 2010 which generated approximately $29 million in 2010. We supply on-site energy services to the domestic automotive manufacturers who have also experienced stabilized demand for automobiles. In March 2011, the Company acquired a cogeneration facility and will provide electricity and steam to customers in the chemical industry.

In late 2009, we began operating five reduced emission fuel facilities located at Detroit Edison owned coal-fired power plants. We are currently constructing two facilities at another Detroit Edison owned power plant and we have negotiated to construct two facilities at third party owned power plants. The facilities reduce Nitrogen Oxides (NOX) and Mercury (Hg) emissions and qualify for production tax credits when the fuel is sold to an unrelated party. Qualifying facilities are eligible to generate tax credits for ten years. We continue to optimize these facilities by seeking investors for facilities operating at Detroit Edison sites and intend to relocate or construct other facilities at alternative sites which may provide increased production and emission

48

reduction opportunities in 2011 and future years. In January 2011, the Company sold a membership interest in one of these reduced emission fuel facilities that is located at a Detroit Edison site.

Environmental and economic trends are creating growth opportunities for renewable power. The increasing number of states with renewable portfolio standards provides investment opportunities in waste-wood power generation. In addition to the three facilities in operation, we expect to convert and place into service additional facilities in 2011 and 2013. We will continue to look for additional investment opportunities for waste-wood renewable power generation and other energy projects at favorable prices.

Power and Industrial Projects will continue to leverage its extensive energy-related operating experience and project management capability to develop additional energy projects to serve energy intensive industrial customers.

ENERGY TRADING

Energy Trading focuses on physical and financial power and gas marketing and trading, structured transactions, enhancement of returns from DTE Energy’s asset portfolio, and optimization of contracted natural gas pipeline transportation and storage, and power transmission and generating capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers’ behalf under FERC Asset Management Arrangements.

Energy Trading results are discussed below:

	Three Months Ended					Nine Months Ended
	September 30					September 30
(in Millions)	2011		2010			2011		2010
Operating Revenues	$	342	$	258		$	970	$	661
Fuel, Purchased Power and Gas	284		258			851		597
Gross Margin	58		—			119		64
Operation and Maintenance	18		13			49		47
Depreciation, Depletion and Amortization	1		1			2		3
Taxes Other Than Income	—		—			2		2
Operating Income (Loss)	39		(14		)	66		12
Other (Income) and Deductions	3		3			7		10
Income Tax Expense (Benefit)	14		(5		)	23		2
Net Income (Loss) Attributable to DTE Energy Company	$	22	$	(12	)	$	36	$	—

Gross margin increased $58 million in the third quarter of 2011 and increased $55 million for the nine months ended September 30, 2011. The overall increase in gross margin for the third quarter and nine months ended 2011 is the result of improved economic performance relative to the same periods in 2010, coupled with the absence of prior year timing losses. We experienced timing-related earnings volatility based on market movement related to derivative contracts.

The third quarter increase of $58 million represents a $29 million increase in both our realized and unrealized margins. The $29 million increase in realized margins is due to $42 million of favorable results, primarily in our power and gas trading and power full requirements strategies, offset by $13 million of unfavorable results, primarily in our gas structured and gas full requirements strategies. The $29 million increase in unrealized margins is due to $34 million of favorable results, primarily in our power transmission, power full requirements, and power and gas trading strategies. This was offset by $5 million of unfavorable results, primarily in our gas full requirements strategy.

The $55 million increase for the nine month period represents a $35 million increase in realized margins and a $20 million increase in unrealized margins. The $35 million increase in realized margins is due to $57 million of favorable results, primarily in our power trading and power full requirements strategies, offset by $22 million of unfavorable results, primarily in our gas structured and power origination strategies. The $20 million increase in unrealized margins is due to $39 million of favorable results, primarily in our power full requirements, gas trading and gas structured strategies, offset by $19 million of unfavorable results, primarily in our power trading and gas storage strategies.

Outlook — In the near term, we expect market conditions to remain challenging and the profitability of this segment may be impacted by the volatility or lack thereof in commodity prices in the markets we participate in and the uncertainty of impacts associated with financial reform, regulatory changes and changes in operating rules of regional transmission organizations.

The Energy Trading portfolio includes financial instruments, physical commodity contracts and gas inventory, as well as

49

contracted natural gas pipeline transportation and storage, and power transmission and generation capacity positions. Energy Trading also provides natural gas, power and ancillary services to various utilities and producers which may include the management of associated storage and transportation contracts on the customers' behalf under FERC Asset Management Arrangements. Significant portions of the Energy Trading portfolio are economically hedged. Most financial instruments and physical power and gas contracts are deemed derivatives, whereas natural gas inventory, power transmission, pipeline transportation and certain storage assets are not derivatives. As a result, we will experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. Our strategy is to economically manage the price risk of these underlying non-derivative contracts and assets with futures, forwards, swaps and options. This results in gains and losses that are recognized in different interim and annual accounting periods.

See also the “Fair Value” section.

CORPORATE & OTHER

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

The net loss of $8 million for the third quarter of 2011 was an improvement of $10 million from the net loss of $18 million in the third quarter of 2010. Net income of $47 million in the nine-month period ended September 30, 2011 was an improvement of $97 million from the net loss of $50 million in the comparable 2010 period. The improvement in both periods resulted from lower interest on long-term debt, while the improvement in the 2011 nine-month period is also due to an income tax benefit of $88 million related to the enactment of the MCIT in the second quarter of 2011. See Note 2 of the Notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND LIQUIDITY

Cash Requirements

We use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, retire and pay interest on long-term debt and pay dividends. We believe that we will have sufficient internal and external capital resources to fund anticipated capital and operating requirements. In 2011, we expect that cash from operations will be comparable to 2010 levels. We anticipate base level utility capital investments, environmental, renewable and energy optimization expenditures and expenditures for non-utility businesses in 2011 of approximately $1.7 billion. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Capital spending for growth of existing or new non-utility businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

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	Nine Months Ended
	September 30
(in Millions)	2011			2010
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	563		$	483
Depreciation, depletion and amortization	752			775
Deferred income taxes	123			173
Asset (gains), losses and reserves, net	—			5
Working capital and other	48			73
	1,486			1,509
Investing activities:
Plant and equipment expenditures — utility	(968		)	(743		)
Plant and equipment expenditures — non-utility	(61		)	(75		)
Proceeds from sale of other assets, net	13			28
Restricted cash and other investments	(36		)	(44		)
	(1,052		)	(834		)
Financing activities:
Issuance of long-term debt	908			595
Redemption of long-term debt	(1,161		)	(660		)
Short-term borrowings, net	126			(307		)
Issuance of common stock	—			26
Repurchase of common stock	(18		)	—
Dividends on common stock and other	(308		)	(297		)
	(453		)	(643		)
Net Increase(Decrease) in Cash and Cash Equivalents	$	(19	)	$	32

Cash from Operating Activities

A majority of our operating cash flow is provided by our electric and gas utilities, which are significantly influenced by factors such as weather, electric Customer Choice, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.

Cash from operations in the nine months ended September 30, 2011 was lower by $23 million in 2011 due primarily to lower cash provided by working capital items. See Note 13 of the Notes to Consolidated Financial Statements.

Cash from Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets, while cash outflows are primarily generated from plant and equipment expenditures. In any given year, we will look to realize cash from under-performing or non-strategic assets or matured fully valued assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure, for gas pipeline replacements and to comply with environmental regulations and renewable energy requirements. Capital spending within our non-utility businesses is for ongoing maintenance and expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis. We have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we initially invest based on research and analysis. We start with a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.

Net cash used for investing activities increased in the nine months ended September 30, 2011 by $218 million primarily due to increased utility capital expenditures and increased non-utility investments, partially offset by the prior year impact of the consolidation of VIEs. See Note 1 of the Notes to Consolidated Financial Statements.

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Cash from Financing Activities

We rely on both short-term borrowing and long-term financing as a source of funding for our capital requirements not satisfied by our operations.

Our strategy is to have a targeted debt portfolio blend of fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50 percent to 52 percent, to ensure it is consistent with our objective to have a strong investment grade debt rating.

Net cash used for financing activities decreased $190 million during the nine months ended September 30, 2011 as increased issuances and redemptions of long-term debt were offset by decreased payments for short-term borrowings.

Outlook

We expect cash flow from operations to increase over the long-term primarily as a result of growth from our utilities and the non-utility businesses. We expect growth in our utilities to be driven primarily by new and existing state and federal regulations that will result in additional environmental and renewable energy investments which will increase the base from which rates are determined. Our non-utility growth is expected from additional investments in energy projects as economic conditions improve.

We may be impacted by the delayed collection of under-recoveries of our various recovery and tracking mechanisms as a result of timing of MPSC orders. Energy prices are likely to be a source of volatility with regard to working capital requirements for the foreseeable future. We are continuing our efforts to identify opportunities to improve cash flow through working capital initiatives and maintaining flexibility in the timing and extent of our long-term capital projects.

On October 20, 2011, the MPSC issued an order in Detroit Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $175 million. Detroit Edison self-implemented a rate increase of $107 million on April 28, 2011. The MPSC stated the net revenue collected due to self-implementation be credited to the 2011 Choice Incentive Mechanism (CIM) regulatory asset. The MPSC required that within ninety days, Detroit Edison file a report regarding the amount of revenue collected through application of its self-implemented rate increase and a proposed reconciliation with the final rates and rate design approved in the order. In addition, a 2011 CIM reconciliation is expected to be filed in early 2012. See Note 6 of the Notes to Consolidated Financial Statements.

We have approximately $250 million in long-term debt maturing in the next 12 months. Substantially all of the debt maturities relate to Securitization, Detroit Edison, and MichCon. The repayment of the principal amount of the Securitization debt is funded through a surcharge payable by Detroit Edison’s electric customers. The repayment of the other Detroit Edison and MichCon debt is expected to be refinanced with long-term debt.

DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon have unsecured revolving credit facilities with similar terms with a syndicate of 23 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.25% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance. DTE Energy had approximately $1.6 billion of available liquidity at September 30, 2011.

In October 2011, the Company completed an early renewal of its $1.0 billion and $800 million syndicated unsecured revolving credit facilities before their scheduled expiration in August 2012 and August 2013, respectively. The new $1.8 billion five-year facility will expire in October 2016 and has covenants similar to the prior facilities.

The Company contributed $200 million to its pension plans in January 2011. The Company contributed $81 million to its other postretirement benefit plans in January 2011. At the discretion of management, the Company may make up to an additional $125 million contribution to its other postretirement benefit plans by the end of 2011.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 provided for a special allowance for bonus depreciation in 2011 and 2012. Bonus depreciation is accelerated depreciation on certain types of business equipment that allows a tax deduction of either 50% or 100% of the cost of qualifying property in the year the asset is placed in service. DTE Energy expects to generate approximately $150 million to $250 million of cash in 2011-2012 from bonus depreciation deductions, a significant portion of which is expected to result from Detroit Edison property, plant and equipment expenditures during the qualifying period. The cash benefit is an acceleration of tax deductions that the Company would otherwise have received over 20 years.

We believe we have sufficient operating flexibility, cash resources and funding sources to maintain adequate amounts of liquidity and to meet our future operating cash and capital expenditure needs. However, virtually all of our businesses are capital intensive, or require access to capital, and the inability to access adequate capital could adversely impact earnings and

52

cash flows.

See Notes 6, 8, 9, and 11 of the Notes to the Consolidated Financial Statements.

CRITICAL ACCOUNTING ESTIMATES

Regulation

A significant portion of our business is subject to regulation. This results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. Detroit Edison and MichCon are required to record regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in the discontinuance of this accounting treatment for regulatory assets and liabilities for some or all of our businesses. Management believes that currently available facts support the continued use of regulatory assets and liabilities and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment.

Detroit Edison Revenue Decoupling Mechanism (RDM)

In May 2011, Detroit Edison filed an application with the MPSC for approval of its RDM reconciliation for the period February 2010 through January 2011 requesting authority to refund approximately $56 million, plus interest. This is the initial reconciliation filing under the pilot RDM. In addition to the refund liability for the initial reconciliation filing, Detroit Edison has accrued an RDM refund for the February 2011 through September 2011 period of $71 million, plus interest. There are various interpretations and alternative calculation methodologies relating to the RDM refund calculation that could ultimately be adopted by the MPSC that could result in significant adjustments in excess of the amounts accrued as of September 30, 2011. An MPSC order on the initial filing is expected in the first half of 2012.

FAIR VALUE

Derivatives are generally recorded at fair value and shown as Derivative Assets or Liabilities. Contracts we typically classify as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items we do not generally account for as derivatives include natural gas inventory, power transmission, pipeline transportation and certain storage assets. See Notes 3 and 4 of the Notes to Consolidated Financial Statements.

As a result of adherence to generally accepted accounting principles, the tables below do not include the expected earnings impact of non-derivative gas storage, transportation and power contracts. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods, resulting in volatility in DTE Energy's reported period-by-period earnings; however, the financial impact of the timing differences will reverse at the time of physical delivery and/or settlement.

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year).

The Company has established 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). For further discussion of the fair value hierarchy, see Note 3 of the Notes to Consolidated Financial Statements.

The following tables provide details on changes in our MTM net asset (or liability) position for the nine months ended September 30, 2011:

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(in Millions)	Total
MTM at December 31, 2010	$	(44	)
Reclassify to realized upon settlement	25
Changes in fair value recorded to income	96
Amounts recorded to unrealized income	121
Change in fair value recorded in regulatory liabilities	3
Change in collateral held by (for) others	(42		)
Option premiums received and other	(46		)
MTM at September 30, 2011	$	(8	)

The table below shows the maturity of our MTM positions:

										2014
(in Millions)										And		Total Fair
Source of Fair Value	2011			2012			2013			Beyond		Value
Level 1	$	42		$	(23	)	$	14		$	9	$	42
Level 2	(9		)	(17		)	(37		)	1		(62		)
Level 3	(7		)	6			7			3		9
Total MTM before collateral adjustments	$	26		$	(34	)	$	(16	)	$	13	$	(11	)
Collateral adjustments												$	3
Total MTM at September 30, 2011												$	(8	)

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Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Price Risk

We have commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

Our Electric and Gas utility businesses have risks in conjunction with the anticipated purchases of coal, natural gas, uranium, electricity, and base metals to meet their service obligations. However, the Company does not bear significant exposure to earnings risk as such changes are included in the PSCR and GCR regulatory rate-recovery mechanisms. In addition, changes in the price of natural gas can impact the valuation of lost and stolen gas, storage sales revenue and uncollectible expenses at the Gas Utility. Gas Utility manages its market price risk related to storage sales revenue primarily through the sale of long-term storage contracts. The Company is exposed to short-term cash flow or liquidity risk as a result of the time differential between actual cash settlements and regulatory rate recovery.

Our Gas Storage and Pipelines business segment has limited exposure to natural gas price fluctuations and manages its exposure through the sale of long-term storage and transportation contracts.

Our Unconventional Gas Production business segment has exposure to natural gas and crude oil price fluctuations. These commodity price fluctuations can impact both current year earnings and reserve valuations. To manage this exposure we may use forward energy and futures contracts.

Our Power and Industrial Projects business segment is subject to electricity, natural gas, coal and coal-based product price risk. To the extent that commodity price risk has not been mitigated through the use of long-term contracts, we manage this exposure using forward energy, capacity and futures contracts.

Our Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign currency exchange price fluctuations. These risks are managed by our energy marketing and trading operations through the use of forward energy, capacity, storage, options and futures contracts, within pre-determined risk parameters.

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail, financial and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and record provisions for amounts considered at risk of probable loss. We believe our accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on our consolidated financial statements.

Other

MichCon has an uncollectible expense tracking mechanism that enables it to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in its last rate case. Detroit Edison had an uncollectible expense tracking mechanism through October 2011 which was eliminated with Detroit Edison's October 20, 2011 MPSC order. The uncollectible expense tracking mechanisms require annual reconciliation proceedings before the MPSC. See Note 6 of the Notes to Consolidated Financial Statements.

We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internal credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of September 30, 2011:

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	Credit Exposure Before Cash		Cash		Net Credit
(in Millions)	Collateral		Collateral		Exposure
Investment Grade(1)
A- and Greater	$	162	$	—	$	162
BBB+ and BBB	261		—		261
BBB-	100		—		100
Total Investment Grade	523		—		523
Non-investment grade(2)	3		—		3
Internally Rated — investment grade(3)	101		—		101
Internally Rated — non-investment grade(4)	32		—		32
Total	$	659	$	—	$	659

_____________________________

(1) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s Investor Service (Moody’s) and BBB- assigned by Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures combined for this category represented approximately 31 percent of the total gross credit exposure.

(2) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented less than 1 percent of the total gross credit exposure.

(3) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, but are considered investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 10 percent of the total gross credit exposure.

(4) This category includes counterparties that have not been rated by Moody’s or Standard & Poor’s, and are considered non-investment grade based on DTE Energy’s evaluation of the counterparty’s creditworthiness. The five largest counterparty exposures combined for this category represented approximately 5 percent of the total gross credit exposure.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of September 30, 2011, we had a floating rate debt-to-total debt ratio of approximately eight percent (excluding securitized debt).

Foreign Currency Exchange Risk

We have foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency exchange fluctuations, we have entered into a series of foreign currency exchange forward contracts through July 2015. Additionally, we may enter into fair value foreign currency exchange hedges to mitigate changes in the value of contracts or loans.

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt obligations and foreign currency exchange forward contracts. The commodity contracts and foreign currency exchange risk listed below principally relate to our energy marketing and trading activities. The sensitivity analysis involved increasing and decreasing forward rates at September 30, 2011 and September 30, 2010 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of September 30, 2011 and September 30, 2010:

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	Assuming a 10% Increase in Rates						Assuming a 10% Decrease in Rates
(in Millions)	As of September 30,						As of September 30
Activity	2011			2010			2011		2010		Change in the Fair Value of
Coal Contracts	$	(3	)	$	—		$	3	$	—	Commodity contracts
Gas Contracts	(9		)	(6		)	9		6		Commodity contracts
Power Contracts	(2		)	(5		)	1		7		Commodity contracts
Interest Rate Risk	(267		)	(294		)	283		315		Long-term debt
Foreign Currency Exchange Risk	(1		)	6			1		7		Forward contracts
Discount Rates	—			—			—		—		Commodity contracts

For further discussion of market risk, see Note 4 of the Notes to Consolidated Financial Statements.

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Part I — Item 4.

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of DTE Energy’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2011, which is the end of the period covered by this report. Based on this evaluation, the CEO and CFO have concluded that such disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to the Company’s management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II — Other Information

Item 1. - Legal Proceedings

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company expects to enter into the Consent Order during the fourth quarter of 2011.

In July 2009, DTE Energy received a NOV/FOV from the EPA alleging, among other things, that five of Detroit Edison's power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and Title V operating permit requirements under the Clean Air Act. In June 2010, EPA issued a NOV/FOV making similar allegations related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States Department of Justice, at the request of EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison's fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA's motion for preliminary injunction was denied. On August 23, 2011, the U.S. District Court judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit.

DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the two NOVs/FOVs, Detroit Edison could also be required to install additional pollution control equipment at some or all of the power plants in question, consider early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of these matters, or the timing of its resolution.

Item 1A. — Risk Factors

There are various risks associated with the operations of DTE Energy’s utility and non-utility businesses. To provide a framework to understand the operating environment of DTE Energy, we have provided a brief explanation of the more significant risks associated with our businesses in Part 1, Item 1A. Risk Factors in the Company’s 2010 Form 10-K. Although we have tried to identify and discuss key risk factors, others could emerge in the future. In addition to the risk factors set forth in our 10-K, the following updated risks could affect our performance.

Operation of a nuclear facility subjects us to risk. Ownership of an operating nuclear generating plant subjects us to significant additional risks. These risks include, among others, plant security, environmental regulation and remediation, changes in federal nuclear regulation and operational factors that can significantly impact the performance and cost of operating a nuclear facility. While we maintain insurance for various nuclear-related risks, there can be no assurances that such insurance will be sufficient to cover our costs in the event of an accident or business interruption at our nuclear generating plant, which may affect our financial performance.

Construction and capital improvements to our power facilities and distribution systems subject us to risk. We are managing ongoing and planning future significant construction and capital improvement projects at multiple power generation and distribution facilities and our gas distribution system. Many factors that could cause delays or increased prices for these complex projects are beyond our control, including the cost of materials and labor, subcontractor performance, timing and issuance of necessary permits, construction disputes and weather conditions. Failure to complete these projects on schedule and on budget for any reason could adversely affect our financial performance and operations at the affected facilities and businesses.

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Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds; Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Securities Exchange Act of 1934 during the three months ended September 30, 2011:

Period	Total Number of Shares	Average Price Paid		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Dollar Value that May Yet Be Purchased Under the Plans or
	Purchased(1)	Per Share		or Programs	Programs
07/01/11 — 07/31/11	6,990	$	46.20	—	—
08/1/2011 — 08/31/11	60,000	49.95		—	—
09/1/2011 — 09/30/11	71,965	44.90		—	—
Total	138,955			—	—

_____________________________

(1) Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program. Also includes shares of common stock withheld to satisfy income tax obligations upon the vesting of restricted stock.

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Item 6. — Exhibits

Exhibit
Number	Description
Exhibits filed herewith:
3-11	Amended Bylaws (as amended through May 5, 2011)
12-48	Computation of Ratio of Earnings to Fixed Charges
31-69	Chief Executive Officer Section 302 Form 10-Q Certification
31-70	Chief Financial Officer Section 302 Form 10-Q Certification
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Database
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase
Exhibits incorporated herein by reference:
4-271	Supplemental Indenture, dated as of August 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-276 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series GT)
4-272	Supplemental Indenture, dated as of August 15, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-277 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series D, 2011 Series E, 2011 Series F)
4-273	Supplemental Indenture, dated as of September 1, 2011, to the Mortgage and Deed of Trust, dated as of October 1, 1924, by and between The Detroit Edison Company and The Bank of New York Mellon Trust Company, N.A. as successor trustee (Exhibit 4-278 to Detroit Edison's Form 10-Q for the quarter ended September 30, 2011). (2011 Series H)
10-1	Form of Amended and Restated DTE Energy Five-Year Credit Agreement, dated as of August 20, 2010 and amended and restated as of October 21, 2011, by and among DTE Energy Company, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Capital, The Bank of Nova Scotia and JPMorgan Chase Bank, N.A., as Co-Syndication Agents (Exhibit 10.1 to Form 8-K filed on October 26, 2011).
10-2	Form of Amended and Restated MichCon Five-Year Credit Agreement, dated as of August 20, 2010 and amended and restated as of October 21, 2011, by and amongMichCon, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Barclays Capital, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents (Exhibit 10.2 to Form 8-K filed on October 26, 2011).

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10-3	Form of Amended and Restated Detroit Edison Five-Year Credit Agreement, dated as of August 20, 2010 and amended and restated as of October 21, 2011, by and among Detroit Edison, the lenders party thereto, Barclays Bank PLC, as Administrative Agent, and Citibank, N.A., JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland plc, as Co-Syndication Agents (Exhibit 10.1 to Detroit Edison's Form 8-K filed on October 26, 2011).
Exhibits furnished herewith:
32-69	Chief Executive Officer Section 906 Form 10-Q Certification
32-70	Chief Financial Officer Section 906 Form 10-Q Certification

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		DTE ENERGY COMPANY (Registrant)
Date:	November 4, 2011	/S/ PETER B. OLEKSIAK
		Peter B. Oleksiak
		Vice President and Controller and Chief Accounting Officer

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EX-3.11

Exhibit 3-11

AMENDED BYLAWS

of

DTE ENERGY COMPANY

As amended through May 5, 2011

ARTICLE I	1
ARTICLE II	4
ARTICLE 111	6
ARTICLE IV	7
ARTICLE V	7
ARTICLE VI	8
ARTICLE VII	8
ARTICLE VIII	8
ARTICLE IX	8

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AMENDED BYLAWS

of

DTE ENERGY COMPANY

As amended through May 5, 2011

ARTICLE I.

Shareholders

Section 1.    Annual Meeting. The annual meeting of the shareholders of the Company shall be held on such date and at such time and place as may be fixed by the Board of Directors and stated in the notice of meeting, for the purpose of electing directors and such other purpose or purposes as may be stated in the notice of meeting.

Section 2.    Special Meetings. Special meetings of the shareholders may be called by the Board of Directors, the Chairman of the Board, the Presiding Director, if one has been designated, or the holders of record of three-quarters of the outstanding shares of stock of the Company entitled to vote at such meeting, on such date and at such time and place as may designated and for such purpose or purposes as set forth in the notice of meeting.

Section 3.    Notice of Meetings. Written notice or notice by electronic transmission of the date, time, place and purpose or purposes of every meeting of the shareholders shall be given in the manner described in Article V. If a shareholder or proxy holder may be present and vote at a meeting by remote communication, the means of remote communication allowed shall be included in the notice. Notice of a special meeting shall also indicate that it is being issued by or at the direction of the Board of Directors, the Chairman of the Board, the Presiding Director, if one has been designated, or the holders of three-quarters of the outstanding shares of stock of the Company.

Notice of a meeting need not be given to any shareholder who submits a signed waiver of notice, in person or by proxy, or a waiver of notice by electronic transmission, whether before or after the meeting. The attendance of any shareholder at a meeting, in person or by proxy, will result in both of the following:

(a)    Waiver of objection to lack of notice or defective notice of the meeting, unless the shareholder at the beginning of the meeting objects to holding the meeting or transacting business at the meeting; and

(b)    Waiver of objection to consideration of a particular matter at the meeting that is not within the purpose or purposes described in the meeting notice, unless the shareholder objects to considering the matter when it is presented.

Section 4.    Adjournments. Any meeting of shareholders, annual or special, may adjourn from time to time to reconvene at the same or some other place. Notice need not be given of any adjourned meeting if the new date, time and place of the meeting are announced at the meeting at which the adjournment is taken. A shareholder or proxy holder may be present and vote at the adjourned meeting by means of remote communication if he or she were permitted to be present and vote by that means of remote communication in the original meeting notice. If a notice of the adjourned meeting is not given, the Company may only transact business that might have been transacted at the original meeting. If, after the adjournment, the Board of Directors fixes a new record date for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder entitled to notice under these Bylaws as of the new record date.

Section 5.    Quorum. Unless otherwise provided by law, the Articles of Incorporation or these Bylaws, the holders of a majority of the outstanding shares of stock of the Company entitled to vote at such meeting, whether present in person or by proxy, shall constitute a quorum at any meeting of shareholders. If at any meeting there shall be no quorum, the holders of a majority of the outstanding shares of stock so present or represented shall have the power to adjourn the meeting, without notice other than announcement at the meeting of the new meeting time and place, until a quorum has been obtained. When a quorum is present, the shareholders present in person or by proxy at such meeting may continue to do business until adjournment, notwithstanding the withdrawal of enough shareholders to leave less than a quorum.

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Section 6.    Voting. Except as otherwise provided in the Articles of Incorporation, each outstanding share of capital stock shall be entitled to one vote on each matter submitted to a vote. Votes may be cast orally, in writing or by any other means permitted under Michigan law, as the chair of the meeting may decide. All voting may be done either in person or by proxy appointed by instrument in writing or by electronic means (telephone or internet), signed, or identified by the shareholder's identification number or other unique identifier that is reasonably designed to ensure authenticity by such shareholder or his or her authorized agent. When a quorum is present:

(a)    Action on a matter is approved if the votes properly cast favoring the action exceed the votes properly cast opposing the action, unless the action is the election of directors, or is one upon which by express provision of law, the Articles of Incorporation or these Bylaws, a larger or different vote is required; and

(b)    Each director shall be elected by a majority of votes properly cast at any meeting of shareholders for the election of directors. However, if the number of director nominees for any director election exceeds the number of directors to be elected (a “Contested Election”), the nominees receiving a plurality of the votes cast by holders of the shares entitled to vote at any meeting for the election of directors at which a quorum is present will be elected. For purposes of this Section 6(b) of Article I, a majority of the votes properly cast means that the number of shares properly voted “for” a director must exceed fifty percent (50%) of the votes properly cast with respect to that director. The votes cast shall exclude abstentions with respect to that director's election.

Section 7.    Record of Shareholders. For the purpose of determining the shareholders entitled (a) to notice of, or to vote at, any meeting of shareholders or any adjournment thereof, (b) to express consent to, or dissent from, any proposal without a meeting, or (c) to receive payment of any dividend or the allotment of any rights, or for the purpose of any other action, the Board of Directors may fix, in advance, a date as the record date for any such determination of shareholders. The record date shall not precede the date upon which it is fixed and shall not be less than 10 days nor more than 60 days before the date of the meeting, or the taking of any other action. A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to any adjournment of the meeting, unless the Board of Directors chooses to fix a new record date for the adjourned meeting.

Section 8.    List of Shareholders. The Corporate Secretary shall prepare or have prepared before every meeting of shareholders a complete list of shareholders entitled to vote at the meeting in compliance with Michigan law.

Section 9.    Order of Business. At each meeting of shareholders, a chair shall preside. In the absence of a specific selection by the Board of Directors, the chair shall be the Chairman of the Board as provided in these Bylaws. The chair shall determine the order of business and shall have the authority in his or her sole discretion to regulate the conduct of any such meeting including, without limitation, by imposing restrictions on the persons (other than shareholders of the Company or their duly appointed proxies) who may attend any such shareholders' meeting, by ascertaining whether any shareholder or his proxy may be excluded from any meeting of shareholders based upon any determination by the chair in his or her sole discretion, that any such person has unduly disrupted or is likely to disrupt the proceedings of the meeting, and by determining the circumstances in which any person may make a statement or ask questions at any meeting of shareholders. The chair of the meeting shall announce at the meeting when the polls close for each matter voted upon. If no announcement is made, the polls shall be deemed to have closed upon the final adjournment of the meeting. After the polls close, no ballots, proxies or votes, nor any revocations or changes thereto may be accepted.

Section 10.    Director Nominations and Shareholder Business.

(a)    Annual Shareholder Meeting. At an annual meeting of shareholders, only such business will be conducted or considered as is properly brought before the meeting. To be properly brought before an annual meeting:

(i)    Nominations of persons for election as directors may be made only at an annual meeting (A) by or at the direction of the Board of Directors or a committee thereof, or (B) by any shareholder who is a shareholder of record at the time of giving notice, who is entitled to vote at the annual meeting and who complies with the notice requirements set forth in this Section.

(ii)    Other business to be considered at an annual meeting shall be: (A) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, Chairman of the Board, the President, a Vice President, the Corporate Secretary or an Assistant Corporate Secretary; (B) brought by or at the direction of the Board of Directors; or (C) properly requested by a shareholder of the Company in accordance with the law and with the notice requirements provided in this Section.

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(b)    A shareholder who intends to make a director nomination or to bring any other matter before an annual meeting must give notice of his or her intent in writing to the Corporate Secretary. A shareholder's notice must be received at the principal executive offices of the Company not less than 60 nor more than 90 calendar days prior to the annual meeting of shareholders. If the Company does not make a public announcement of an annual meeting date at least 70 calendar days prior to the date of the annual meeting, a shareholder's notice must be received at the principal executive offices of the Company by the close of business on the 10th day following the Company's first public announcement of the annual meeting date.

(c)    All shareholder notices must include:

(i)    the name and address, as they appear on the Company books, of the shareholder making the nomination or proposing the shareholder business, along with the class and number of shares of Company stock owned by the shareholder;

(ii)    a representation that the shareholder is a shareholder of record of Company stock entitled to vote at such annual meeting and intends to appear in person or by proxy at the annual meeting to make the nomination or propose the business specified in the notice;

(iii)    if the shareholder notice is to bring a matter up for vote at a shareholder meeting, (A) a description in reasonable detail of the business desired to be brought before the annual meeting, (B) the reasons for conducting such business at the annual meeting, (C) any material interest the shareholder has in the matter, and (D) compliance with all applicable requirements of the Securities Exchange Act of 1934, as amended (the “Act”), for shareholder proposals, including matters covered by Rule 14a-8;

(iv)    if a shareholder notice is to nominate a person for election as a director, a description of all arrangements or understandings between or among any of (A) the shareholder giving the notice, (B) the beneficial owner on whose behalf the notice is given, (C) each nominee, and (D) any other person or person (naming such person or persons) pursuant to which the nomination is to be made by the shareholder giving the notice; and

(v)    if a shareholder notice is to nominate a person for election as a director, the information that would be required to be disclosed in a proxy statement to comply with all applicable requirements of the Act and the rules and regulations thereunder as if each nominee had been nominated by the Board.

Any shareholder notice to nominate a person for the election as a director must be accompanied by a written and signed consent of each nominee to serve as a director of the Company if elected.

(d)    Special Shareholder Meetings. At a special meeting of shareholders, only such business may be conducted or considered as is properly brought before the meeting. To be properly brought before a special meeting, business must be (i) specified in the notice of the meeting (or any supplement thereto), given by or at the direction of the Board of Directors, Chairman of the Board, the Presiding Director, if one has been designated, or the holders of record of three-quarters of the outstanding shares of stock of the Company entitled to vote at such meeting, in accordance with Article I, Section 3 of these Bylaws; or (ii) otherwise brought before the meeting by the chair of the meeting or by or at the direction of the Board of Directors or a committee thereof.

(e)    The chair of any annual or special meeting of shareholders shall have the power to declare that any proposed nomination or business matter is not in compliance with these Bylaws and to declare that such defective nomination or proposal be disregarded.

(f)    For purposes of this Section, “public announcement” means disclosure in a press release to a national news service or financial news service or in a document publicly filed by the Company with the Securities and Exchange Commission pursuant to Sections 13, 14, or 15(d) of the Act, or publicly filed by the Company with any national securities exchange or quotation service through which the Company's stock is listed or traded, or furnished by the Company to its shareholders.

(g)    Nothing in this Section will be deemed to affect any rights of shareholders to request inclusion of proposals in the Company's proxy statement pursuant to Rule 14a-8 under the Act.

Section 11.    Inspectors.

In advance of any meeting of shareholders, the Board of Directors may appoint one or more inspectors for the

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meeting. If inspectors are not so appointed, the chair of the meeting may appoint such inspectors. No officer or director of the Company or candidate for director shall be appointed as an inspector.

ARTICLE II.

Board of Directors and Committees

Section 1.    Number and Time of Holding Office. The business and affairs of the Company shall be managed by or under the direction of a Board of Directors. The number of directors constituting the entire Board of Directors shall be determined from time to time by resolution of the Board of Directors; provided that no change in the number of directors shall serve to shorten the term of office of any incumbent director. Commencing with the 2012 annual meeting of shareholders and for each annual meeting of shareholders thereafter, directors whose terms are expiring at an annual meeting of shareholders shall be elected for terms of one year; for the avoidance of doubt, each director whose term of office for which he or she was elected has not expired as of the 2012 annual meeting of shareholders shall continue to hold office until such time as his or her term has expired. If at any time the holders of any series of the Company's Preferred Stock are entitled to elect directors pursuant to the Articles of Incorporation of the Company, then the provisions of such series of Preferred Stock with respect to their rights shall apply and such directors shall be elected in a manner and for terms expiring consistent with the Articles of Incorporation.

Each director shall serve for the term to which the director was elected, and until a successor shall have been elected and qualified or until the director's prior death, resignation, or removal. Except for the Chief Executive Officer of the Company, no person who has served as an employee of the Company or a subsidiary shall be elected a director after retiring from employment with the Company or a subsidiary.

Section 2.    Vacancies. Any vacancy in the Board of Directors may be filled by a majority vote of the remaining members of the Board of Directors then in office (even if constituting less than a quorum). Each person elected by the Board of Directors to fill a director vacancy shall be subject to election by a vote of the shareholders at the next annual shareholder meeting. During the existence of any vacancy, the remaining directors shall possess and may exercise all the powers of the full Board of Directors, unless otherwise required by law or these Bylaws.

Section 3.    Meetings of the Board.

(a)    Annual Meetings. An annual meeting of the Board of Directors shall be held without notice each year as soon as practicable after the adjournment of the annual meeting of shareholders for the purpose of election of officers and consideration of such business that may properly be brought before the meeting. If there is less than a quorum at the annual meeting of the Board of Directors, the meeting shall be adjourned and the matters which might have been taken up at the annual meeting may be taken up at any later special or annual meeting, or by consent resolution.

(b)    Regular Meetings. Regular meetings of the Board of Directors shall be held at such times and at such places as may from time to time be fixed by the Board of Directors.

(c)    Special Meetings. Special meetings of the Board of Directors may be called by the Chairman of the Board, the Presiding Director, if one has been designated, or, during the absence or incapacity of the Chairman of the Board or any designated Presiding Director, special meetings may be called by the Executive Committee, if one has been designated, by giving reasonable notice of the time and place of such meetings or by obtaining waivers of notice either signed or received by electronic transmission, before or after the meeting, from each absent director. A director's attendance at or participation in any meeting of the Board of Directors or a committee waives any required notice to him or her of the meeting unless he or she, at the beginning of the meeting or upon his or her arrival, objects to the meeting or the transacting of business at the meeting and does not thereafter vote for or assent to any action taken at the meeting.

(d)    A director may participate in a meeting by means of remote communications where all persons participating in the meeting can communicate with each other. Such participation shall constitute attendance at any meeting.

(e)    Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Board of Directors need be specified in the notice or waiver of notice of such meeting.

Section 4.    Quorum. A majority of the directors in office at the time of a meeting of the Board of Directors shall constitute a quorum for the transaction of business. If at any meeting of the Board of Directors there shall be less than a quorum present, a majority of the directors present may adjourn the meeting without notice other than announcement at the

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meeting of the new meeting time and place, until a quorum has been obtained. The acts of a majority of the directors present at any meeting at which there is a quorum shall be the acts of the Board of Directors, unless otherwise provided by law, by the Articles of Incorporation or by these Bylaws.

Section 5.    Chairman of the Board. From its members, the Board of Directors shall annually elect a Chairman of the Board. The Chairman of the Board may simultaneously serve as the Chief Executive Officer. Subject to Article I Section 9 and Article II Section 6, the Chairman of the Board shall preside at meetings of the Board of Directors and meetings of shareholders at which the Chairman of the Board is present.

Section 6.    Presiding Director. If the Chairman of the Board is not an independent director, the Board of Directors may elect a Presiding Director from among its members other than the Chairman of the Board. The Presiding Director shall have such authority and powers as the Board of Directors may from time to time prescribe.

Section 7.    Committees.

(a)    Executive Committee. The Board of Directors may, by resolution passed by a majority of the Board of Directors, designate an Executive Committee to consist of the Chairman of the Board, the Presiding Director, if one has been designated, and one or more of the other directors, and alternates, and shall designate the chair of the Executive Committee. Meetings of the Executive Committee may be called by the Chairman of the Board, or, in the event of the incapacity or absence of the Chairman of the Board, the Presiding Director, if one has been designated, or, in the incapacity or absence of the Chairman of the Board and of any designated Presiding Director, meetings may be called by one or more members of the Executive Committee by giving reasonable notice of the time and place of such meetings. The Executive Committee shall have and may exercise, when the Board of Directors is not in session, all of the powers of the Board of Directors in the management of the business and affairs of the Company, and shall have the power to authorize the seal of the Company to be affixed to all papers which may require it. The Executive Committee may make rules for the conduct of its business and may appoint such subcommittees and assistants, as it shall from time to time deem necessary. All action taken by the Executive Committee shall be reported to the Board of Directors at its next meeting succeeding such action. The Corporate Secretary or an Assistant Corporate Secretary shall attend and act as the secretary of all meetings of the Executive Committee and keep the minutes thereof.

(b)    Other Committees. The Board of Directors may, by resolution, appoint such other committees consisting of one or more directors, and alternates, and shall designate the chair of each such committee. Committees other than the Executive Committee shall have such authority as shall be specified by the Board of Directors in the resolution making such appointments.

(c)    The Board of Directors may designate one or more directors as alternate members of any committee who may replace an absent or disqualified member at any meeting of the committee. The Board shall have the power at any time to fill vacancies in, to change the membership of, or to dissolve any committee. A majority of the authorized number of members of any such committee shall constitute a quorum for the transaction of business, and the act of a majority of those present at any meeting at which a quorum is present shall be the act of such committee. Committees and each member shall serve at the pleasure of the Board.

(d)    Notwithstanding the foregoing, no committee of the Board shall have the power or authority to:

(i)    amend the Articles of Incorporation, except that a committee may prescribe the relative rights and preferences of the shares of a series if the Articles of Incorporation authorize the Board of Directors to do so;

(ii)    adopt an agreement of merger or plan of share exchange;

(iii)    recommend to shareholders the sale, lease or exchange of all or substantially all of the Company's property and assets;

(iv)    recommend to shareholders a dissolution of the Company or revocation of a dissolution;

(v)    amend these Bylaws;

(vi)    fill vacancies in the Board of Directors; or

(vii)    unless expressly authorized by the Board of Directors, declare a dividend or authorize the issuance

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of stock.

Section 8.    Action by Consent. Any action required or permitted at any meeting of directors or committee of directors may be taken without a meeting, without prior notice and without a vote, if all of the directors or committee members entitled to vote on the action consent to the action in writing or by electronic transmission, before or after the action is taken. Such consents shall be filed with the minutes of the proceedings of the Board of Directors or committee and shall have the same effect as a vote of the Board of Directors or committee for all purposes.

Section 9.    Compensation. Each director of the Company who is not a salaried officer or employee of the Company may receive reasonable compensation for services as a director, including a reasonable fee for attendance at meetings of the Board of Directors and committees thereof, service as a committee chair or as Presiding Director and attendance at the Company's request at other meetings or similar activities related to the Company.

ARTICLE III.

Officers

Section 1.    Officers and Agents. The officers of the Company shall be a President, a Corporate Secretary and a Treasurer. The Board of Directors may also, from time to time, elect a Chief Executive Officer and one or more Vice Presidents, a Controller, a General Auditor, a General Counsel and such other officers and agents, as it may deem proper or advisable in the conduct of the affairs of the Company. The Board of Directors may, in its discretion, leave vacant any office other than that of the President, Corporate Secretary, or Treasurer. Except as otherwise provided by law, the Articles of Incorporation or these Bylaws, one person may hold any number of offices.

Section 2.    Term of Office. The term of office of all officers shall be until the next annual meeting of the Board of Directors or until the officers' respective successors are chosen and qualified. Any officer or agent elected by the Board of Directors may be removed by the Board at any time, with or without cause.

Section 3.    Chief Executive Officer. The Chief Executive Officer of the Company shall have general charge of the business and affairs of the Company, subject to the control of the Board of Directors, may create in the name of the Company corporate obligations or other instruments and shall perform such other functions and acts as may be incident to the office of Chief Executive Officer or prescribed by the Board of Directors from time to time. The Chief Executive Officer may also simultaneously serve as the Chairman of the Board.

The Chief Executive Officer shall manage or supervise the conduct of the corporate finances and relations of the Company with its shareholders, with the public, and with regulatory authorities, and may exercise all powers conferred upon the President elsewhere in the Bylaws. The Chief Executive Officer may delegate from time to time to other officers, employees or positions of the Company, such powers as the Chief Executive Officer may specify in writing. A copy of each such delegation and of any revocation or change shall be filed with the Corporate Secretary.

Section 4.    President. The President shall have the power and authority, subject to the control of the Board of Directors and the Chief Executive Officer, if one has been appointed, to perform all acts incident to the President's office or prescribed by the Board of Directors or the Chief Executive Officer, or authorized or required by law. During the absence or disability of the Chief Executive Officer, if one has been elected, the President shall assume the duties and authority of the Chief Executive Officer of the Company.

Section 5.    Other Officers. The other officers, agents, and employees of the Company shall each have such powers and authority to perform such duties in the management of the property and affairs of the Company, subject to the control of the Board of Directors, as generally pertain to their respective offices, as well as such powers and duties that, from time to time, may be prescribed by the Board of Directors, by the Chief Executive Officer, or by the President, as the case may be.

Section 6.    Compensation. The compensation of all executive officers of the Company above the level of Assistant Vice President (or equivalent) and the General Auditor (whether or not he or she is above the level of Assistant Vice President) shall be fixed by the Board of Directors or by an authorized committee of the Board of Directors.

Section 7.    Voting of Shares and Securities of Other Corporations. Unless the Board of Directors otherwise directs, the Company's Chairman of the Board, Chief Executive Officer, President, Corporate Secretary and Assistant Corporate Secretary shall each be authorized to vote or to designate a proxy to vote all shares and other securities that the Company owns

6

in any other corporation or entity.

ARTICLE IV.

Capital Stock

Section 1.    Certificates of Shares. Shares of the Company's stock may be certificated or uncertificated, as provided under Michigan law at any time. The certificated shares shall be represented by certificates signed by the Chairman of the Board, the President or a Vice President and may also be signed by the Treasurer, an Assistant Treasurer, the Corporate Secretary or an Assistant Corporate Secretary of the Company, and shall be countersigned by a transfer agent for the stock and registered by a registrar for such stock. The signatures of the officers and the transfer agent and the registrar upon such certificates may be facsimiles, engraved, or printed, subject to the provisions of applicable law. In case any officer, transfer agent, or registrar shall cease to serve in that capacity after their facsimile signature has been placed on a certificate, the certificates may be issued with the same effect as if the officer, transfer agent, or registrar were still in office. A certificate representing shares shall state on its face that the Company is formed under the laws of the State of Michigan and shall also state the name of the person to whom it is issued, the number and class of shares and the designation of the series, if any, that the certificate represents, and any other provisions that may be required by the laws of the State of Michigan or by federal law or by the rules or regulations of any stock exchange or other organization applicable to the Company.

Section 2.    Uncertificated Shares. The Board of Directors may authorize, by resolution, the issuance of some or all of the shares of any class or series without certificates. The authorization will not affect shares already represented by certificates until the certificates are surrendered to the Company. Within a reasonable time after the issuance or transfer of shares without certificates, the Company shall send the shareholder a written statement of the information required on certificates by applicable law, rule or regulation.

Section 3.    Transfer of Shares. The Company shall make transfers of stock on the Company's books (a) upon the presentation of the certificates by the registered holder in person or by duly authorized agent or attorney, or upon presentation of proper evidence of succession, assignment or authority to transfer the stock and upon surrender of the appropriate certificates, or (b) in the case of uncertificated shares, upon receipt of proper transfer instructions from the registered owner of such uncertificated shares, or from a duly authorized agent or attorney or from an individual presenting proper evidence of succession, assignment or authority to transfer the stock.

Section 4.    Lost or Destroyed Stock Certificates. No certificate for shares of stock of the Company shall be issued in place of any certificate alleged to have been lost, stolen or destroyed, except upon production of such evidence of the loss, theft or destruction, and upon indemnification of the Company and its agents to such extent and in such manner as the Board of Directors may from time to time prescribe.

ARTICLE V.

Delivery of Notices

All notices to shareholders, directors and Board committee members shall be given (a) personally, (b) by mail (as provided in the Michigan Business Corporation Act, with postage pre‑paid), and addressed to such person at the address designated by him or her for that purpose, or, if none is designated, at his or her last known address, (c) by electronic transmission in a manner authorized by the person, or (d) as otherwise provided in the Michigan Business Corporation Act. In addition to any other form of notice to a shareholder permitted by the Articles of Incorporation, these Bylaws, or the Michigan Business Corporation Act, any notice given to a shareholder by a form of electronic transmission to which the shareholder has consented is effective. When a notice is required or permitted by the Michigan Business Corporation Act or these Bylaws to be given in writing, electronic transmission is written notice. Notices given pursuant to this Article V shall be deemed to be given when dispatched, or, if mailed, when deposited, with postage prepaid, in a post office or official depository under the exclusive care and custody of the United States Postal Service; provided that when a notice or communication is permitted by the Michigan Business Corporation Act or these Bylaws to be transmitted electronically, the notice or communication is given when electronically transmitted to the person entitled to the notice or communication in a manner authorized by the person. Further notice shall be given by mail, publication, electronic transmission, or otherwise, if and as required by law.

7

ARTICLE VI.

Checks, Notes, Bonds, Debentures, etc.

All checks and drafts on the Company's bank accounts, all bills of exchange and promissory notes, and all acceptances, obligations, and other instruments for the payment of money, shall be signed by such officer or officers or agent or agents, either manually or by facsimile signature or signatures, as shall be thereunto authorized from time to time by the Board of Directors either generally or in specific instances; provided that bonds, debentures, and other evidences of indebtedness of the Company bearing facsimile signatures of officers of the Company shall be issued only when authenticated by a manual signature on behalf of a trustee or an authenticating agent appointed by the Board of Directors. In case any such officer of the Company shall cease to be such after such officer's facsimile signature has been placed on the document, such bonds, debentures or other evidences of indebtedness may be issued with the same effect as if such person were still in office.

ARTICLE VII.

Corporate Seal

The Board of Directors may provide a suitable seal containing the name of the Company.

ARTICLE VIII.

Control Share Acquisitions

The Stacey, Bennett, and Randall Shareholder Equity Act (Chapter 7B of the Michigan Business Corporation Act) shall not apply to any control share acquisitions (as defined in such Act) of shares of the Company.

This Article VIII of the Bylaws may not be amended, altered, or repealed with respect to any control share acquisition of shares of the Company effected pursuant to a tender offer or other transaction commenced prior to the date of such amendment, alteration, or repeal.

ARTICLE IX.

Amendment of Bylaws

The Bylaws of the Company may be amended, repealed or adopted by vote of the holders of a majority of shares at the time entitled to vote in the election of any directors or by vote of a majority of the directors in office.

8

EX-12.48

											Exhibit 12-48
DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended			Twelve Months Ended December 31
(Millions of Dollars)	September 30, 2011			2010		2009		2008			2007			2006
Earnings:
Pretax earnings	$	738		$	944	$	782	$	819		$	1,155		$	536
Adjustments	(1		)	1		4		(3		)	(4		)	(4		)
Fixed Charges	385			567		572		540			562			558
Net earnings	$	1,122		$	1,512	$	1,358	$	1,356		$	1,713		$	1,090
Fixed charges:
Interest expense	$	367		$	543	$	545	$	503		$	533		$	525
Adjustments	18			24		27		37			29			33
Fixed Charges	$	385		$	567	$	572	$	540		$	562		$	558
Ratio of earnings to fixed charges	2.91			2.67		2.37		2.51			3.05			1.95

EX-31.69

Exhibit 31-69

FORM 10-Q CERTIFICATION

I, Gerard M. Anderson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of DTE Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/S/ GERARD M. ANDERSON	Date:	November 4, 2011
Gerard M. Anderson
Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

EX-31.70

Exhibit 31-70

FORM 10-Q CERTIFICATION

I, David E. Meador, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of DTE Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/S/ DAVID E. MEADOR	Date:	November 4, 2011
David E. Meador
Executive Vice President and Chief Financial Officer of DTE Energy Company

EX-32.69

Exhibit 32-69

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of DTE Energy Company (the “Company”) for the quarter ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gerard M. Anderson, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 4, 2011	/S/ GERARD M. ANDERSON
		Gerard M. Anderson
		Chairman of the Board, President and Chief Executive Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.70

Exhibit 32-70

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of DTE Energy Company (the “Company”) for the quarter ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David E. Meador, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge and belief:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 4, 2011	/S/ DAVID E. MEADOR
		David E. Meador
		Executive Vice President and Chief Financial Officer of DTE Energy Company

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Financial and Other Derivative Instruments (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	$ 109	$ 131
Derivative Assets, Noncurrent	59	77
Derivative Liabilities, Current	114	142
Derivative Liabilities, Noncurrent	62	110
Total derivatives:
Assets, Current	2,911	3,167
Assets, Noncurrent	7,027	7,280
Liabilities, Current	2,100	2,749
Liabilities, Noncurrent	8,174	8,291
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset		0
Derivative Liability Fair Value Gross Liability		(1)
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	0
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liability Fair Value Gross Liability	(1)
Not Designated as Hedging Instrument [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	2,174	2,848
Derivative Liability Fair Value Gross Liability	(2,185)	(2,936)
Not Designated as Hedging Instrument [Member] | Foreign Exchange Contract Member
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset		20
Derivative Liability Fair Value Gross Liability		(30)
Not Designated as Hedging Instrument [Member] | Foreign Exchange Contract Member | Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	6
Not Designated as Hedging Instrument [Member] | Foreign Exchange Contract Member | Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liability Fair Value Gross Liability	(9)
Not Designated as Hedging Instrument [Member] | Natural Gas [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset		1,986
Derivative Liability Fair Value Gross Liability		(2,118)
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	1,746
Not Designated as Hedging Instrument [Member] | Natural Gas [Member] | Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liability Fair Value Gross Liability	(1,795)
Not Designated as Hedging Instrument [Member] | Electricity [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset		766
Derivative Liability Fair Value Gross Liability		(716)
Not Designated as Hedging Instrument [Member] | Electricity [Member] | Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	393
Not Designated as Hedging Instrument [Member] | Electricity [Member] | Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liability Fair Value Gross Liability	(365)
Not Designated as Hedging Instrument [Member] | Other [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset		76
Derivative Liability Fair Value Gross Liability		(71)
Not Designated as Hedging Instrument [Member] | Other [Member] | Derivative Asset [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	29
Not Designated as Hedging Instrument [Member] | Other [Member] | Derivative Liabilities [Member]
Derivatives designated as hedging instruments:
Derivative Liability Fair Value Gross Liability	(15)
Not Designated as Hedging Instrument [Member] | Total [Member]
Derivatives designated as hedging instruments:
Derivative Asset Fair Value Gross Asset	2,174	2,848
Derivative Liability Fair Value Gross Liability	(2,184)	(2,935)
Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	109	131
Derivative Assets, Noncurrent	59	77
Derivative Liabilities, Current	(114)	(142)
Derivative Liabilities, Noncurrent	(62)	(110)
Derivative Asset [Member]
Total derivatives:
Assets, Current	1,635	2,011
Assets, Noncurrent	539	837
Derivative Liabilities [Member]
Total derivatives:
Liabilities, Current	(1,643)	(2,041)
Liabilities, Noncurrent	(542)	(895)
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	1,635	2,011
Derivative Assets, Noncurrent	539	837
Derivative Liabilities, Current	(1,643)	(2,041)
Derivative Liabilities, Noncurrent	(542)	(895)
Counterparty Netting [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	(1,526)	(1,871)
Derivative Assets, Noncurrent	(480)	(760)
Derivative Liabilities, Current	1,526	1,871
Derivative Liabilities, Noncurrent	480	760
Collateral Adjustment [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	0	(9)
Derivative Assets, Noncurrent	0	0
Derivative Liabilities, Current	3	28
Derivative Liabilities, Noncurrent	$ 0	$ 25

XML

Consolidated Statements of Financial Position (Unaudited) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 46	$ 65
Restricted cash, principally Securitization	73	120
Accounts receivable (less allowance for doubtful accounts of $168 and $196, respectively)
Customer	1,206	1,393
Other	121	402
Inventories
Fuel and gas	567	460
Materials and supplies	209	202
Deferred income taxes	130	139
Derivative assets	109	131
Regulatory assets	201	58
Other	249	197
Total Current Assets	2,911	3,167
Investments
Nuclear decommissioning trust funds	893	939
Other	527	518
Total Investments	1,420	1,457
Property
Property, plant and equipment	22,312	21,574
Less accumulated depreciation, depletion and amortization	(8,890)	(8,582)
Property, plant and equipment, net	13,422	12,992
Other Assets
Goodwill	2,020	2,020
Regulatory assets	3,940	4,058
Securitized regulatory assets	618	729
Intangible assets	74	67
Notes receivable	124	123
Derivative assets	59	77
Other	192	206
Total Noncurrent Assets	7,027	7,280
Total Assets	24,780	24,896
Current Liabilities
Accounts payable	708	729
Accrued interest	121	111
Dividends payable	99	95
Short-term borrowings	275	150
Current portion long-term debt, including capital leases	247	925
Derivative liabilities	114	142
Other	536	597
Total Current Liabilities	2,100	2,749
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other	6,702	6,114
Securitization bonds	479	643
Trust preferred-linked securities	289	289
Capital lease obligations	27	43
Total Long-Term Debt (net of current portion)	7,497	7,089
Other Liabilities
Deferred income taxes	3,076	2,632
Regulatory liabilities	1,040	1,328
Asset retirement obligations	1,560	1,498
Unamortized investment tax credit	68	75
Derivative liabilities	62	110
Liabilities from transportation and storage contracts	73	83
Accrued pension liability	680	866
Accrued postretirement liability	1,216	1,275
Nuclear decommissioning	141	149
Other	258	275
Total Noncurrent Liabilities	8,174	8,291
Commitments and Contingencies (Notes 6 and 10)
Equity
Common stock, without par value, 400,000,000 shares authorized, 169,250,934 and 169,428,406 shares issued and outstanding, respectively	3,418	3,440
Retained earnings	3,698	3,431
Accumulated other comprehensive loss	(146)	(149)
Total DTE Energy Company Equity	6,970	6,722
Noncontrolling interests	39	45
Total Equity	7,009	6,767
Total Liabilities and Equity	$ 24,780	$ 24,896

XML

Consolidated Statements of Financial Position Unaudited (Parentheticals) (USD $) In Millions, except Share data	Sep. 30, 2011	Dec. 31, 2010
Current Assets:
Allowance for doubtful accounts	$ 168	$ 196
Stockholders' Equity:
Common stock, par value	$ 0.00	$ 0.00
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	169,250,934	169,428,406
Common stock, shares outstanding	169,250,934	169,428,406

XML

Stock Based Compensation (Details 1) (USD $) In Millions, except Share data	9 Months Ended
	Sep. 30, 2011
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options outstanding at January 1, 2011	4,827,457
Granted	0
Exercised	(1,541,690)
Forfeitured and expired	(21,963)
Options outstanding at September 30, 2011	3,263,804
Options exercisable at September 30, 2011	2,597,318
Weighted Average Exercise Price Per Share - Options outstanding at January 1, 2011	$ 41.09
Weighted Average Exercise Price Per Share - Granted	$ 0.00
Weighted Average Exercise Price Per Share - Exercised	$ 40.52
Weighted Average Exercise Price Per Share - Forfeitured and expired	$ 43.41
Weighted Average Exercise Price Per Share - Options outstanding at September 30, 2011	$ 41.34
Weighted Average Exercise Price Per Share - Options exercisable at September 30, 2011	$ 42.30
Aggregate Intrinsic Value - Options outstanding at September 30, 2011	$ 26
Aggregate Intrinsic Value - Options exercisable at September 30, 2011	$ 18

XML

Financial and Other Derivative Instruements (Details Textuals) (USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Dec. 31, 2011
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net			$ 1
Derivative Instruments Recoverable Through PSCR Mechanism	0	3
Value of Transactions Company Would Have Been Exposed to if Credit Rating Below Investment Grade	$ 209	$ 209

XML

Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2011

Significant Accounting Policies (Policies) [Abstract]

Intangible Assets

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Emission allowances and renewable energy credits are charged to expense as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $9 million at September 30, 2011 and December 31, 2010. The Company’s intangible assets related to renewable energy credits were $26 million and $17 million at September 30, 2011 and December 31, 2010, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at September 30, 2011were $65 million and $26 million, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2010 were $63 million and $22 million, respectively. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years.

Income Taxes

Income Taxes

The Company’s effective tax rate for the three months ended September 30, 2011was 35 percent as compared to 36 percent for the three months ended September 30, 2010. The Company’s effective tax rate for the nine months ended September 30, 2011 was 24 percent as compared to 34 percent for the nine months ended September 30, 2010. The decrease in the effective tax rate in 2011 is due primarily to the recognition of an $88 million income tax benefit due to the enactment of the Michigan Corporate Income Tax which is discussed below.

The Company had $4 million of unrecognized tax benefits at September 30, 2011 and $5 million at December 31, 2010, that, if recognized, would favorably impact its effective tax rate. The Company has increased its unrecognized tax benefit by $40 million in the nine months ended September 30, 2011, as a result of a change in a tax position taken during a prior period. During the next twelve months, it is reasonably possible that the Company will settle certain federal tax audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $49 million.

Michigan Corporate Income Tax (MCIT)

On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and will become effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

Effective with the enactment of the MCIT in the second quarter of 2011, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $41 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT.

Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of net deferred tax assets of $307 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $88 million decrease in deferred tax liabilities attributable to our non-utility entities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $88 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy’s unitary Michigan tax return. The $88 million was recognized as a reduction to income tax expense in the second quarter of 2011.

Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statements of Cash Flows.

Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block]

Offsetting Amounts Related to Certain Contracts

The Company offsets 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 agreement, which reduces both the Company’s total assets and total liabilities. As of September 30, 2011, the total cash collateral posted, net of cash collateral received, was $66 million. Derivative liabilities are shown net of collateral of $3 million. At September 30, 2011, the Company recorded cash collateral received of $1 million and cash collateral paid of $64 million not related to derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

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Document Entity Information Document	9 Months Ended
	Sep. 30, 2011
Entity Registrant Name	DTE ENERGY CO
Entity Central Index Key	0000936340
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	169,250,934

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Fair Value (Details 6) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	$ 85	$ 133
Available-for-sale Securities	85	133
Equity [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Fair Value Disclosure	5	6
Available-for-sale Securities	$ 5	$ 6

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Financial and Other Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivative instruments

The following tables present the fair value of derivative instruments as of September 30, 2011:

(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	6	$	(9	)
Commodity Contracts:
Natural Gas	1,746		(1,795		)
Electricity	393		(365		)
Other	29		(15		)
Total derivatives not designated as hedging instruments	$	2,174	$	(2,184	)
Total derivatives:
Current	$	1,635	$	(1,643	)
Noncurrent	539		(542		)
Total derivatives	$	2,174	$	(2,185	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,635		$	539		$	(1,643	)	$	(542	)
Counterparty netting	(1,526		)	(480		)	1,526			480
Collateral adjustment	—			—			3			—
Total derivatives as reported	$	109		$	59		$	(114	)	$	(62	)

The following tables present the fair value of derivative instruments as of December 31, 2010:

(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas	1,986		(2,118		)
Electricity	766		(716		)
Other	76		(71		)
Total derivatives not designated as hedging instruments	$	2,848	$	(2,935	)
Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent	837		(895		)
Total derivatives	$	2,848	$	(2,936	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting	(1,871		)	(760		)	1,871			760
Collateral adjustment	(9		)	—			28			25
Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

Gain (Loss) Recognized in Income on Derivative

The income effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and September 30, 2010 is as follows:

	Location of Gain (Loss) Recognized	Gain (Loss) Recognized in Income on Derivatives for Three Months Ended					Gain (Loss) Recognized in Income on Derivatives for Nine Months Ended
(in Millions)	in Income	September 30					September 30
Derivatives Not Designated As Hedging Instruments	On Derivatives	2011		2010			2011			2010
Foreign currency exchange contracts	Operating Revenue	$	4	$	(8	)	$	(1	)	$	(5	)
Commodity Contracts:
Natural Gas	Operating Revenue	9		24			24			51
Natural Gas	Fuel, purchased power and gas	10		(1		)	—			(7		)
Electricity	Operating Revenue	35		(6		)	64			43
Other	Operating Revenue	1		5			9			6
Other	Operation and maintenance	—		(2		)	—			(3		)
Total		$	59	$	12		$	96		$	85

Volume of Commodity Contracts [Table Text Block]

The following table presents the cumulative gross volume of derivative contracts outstanding as of September 30, 2011:

Commodity	Number of Units
Natural Gas (MMBtu)	631,382,267
Electricity (MWh)	46,441,874
Foreign Currency Exchange ($ CAD)	60,992,581

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Fair Value (Details 5) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Debt Securities, Noncurrent	$ 395	$ 361
Available-for-sale Securities, Gross Unrealized Gains	74	88
Available-for-sale Securities, Equity Securities, Noncurrent	485	572
Nuclear decommissioning trusts	893	939
Available-for-sale Securities, Noncurrent	13	6
Cash and Cash Equivalents [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Gross Unrealized Gains	0	0
Equity Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Gross Unrealized Gains	52	77
Debt Securities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Gross Unrealized Gains	$ 22	$ 11

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Segment Information (Details1) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ 44	$ 63	$ 167	$ 163
Electric Utility [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	7	8	25	23
Gas Utility [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	1	1	2	1
Gas Storage and Pipelines [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	1	1	7	3
Power and Industrial Projects [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	30	50	119	122
Energy Trading [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	17	21	54	65
Corporate and Other [Member]
Inter-Segment Revenue [Line Items]
Segment Reporting Information, Intersegment Revenue	$ (12)	$ (18)	$ (40)	$ (51)

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Financial and Other Derivative Instruments

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedges, Assets [Abstract]

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

The Company recognizes all derivatives at their fair value as Derivative Assets or Liabilities on the Consolidated Statements of Financial Position unless they qualify for certain scope exceptions, including the 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 the derivative 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 exchange. The Company has risk management policies to monitor and manage 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. Contracts classified as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency exchange contracts. Items not classified as derivatives include natural gas inventory, unconventional gas reserves, power transmission, pipeline transportation and certain storage assets.

Electric Utility — 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. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. Other derivative contracts are recoverable through the PSCR mechanism when settled. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities until realized.

Gas Utility — MichCon purchases, stores, transports, distributes and sells natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through March 2014. Substantially all of these contracts meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward transportation and storage capacity contracts. Forward transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Gas Storage and Pipelines — This segment is primarily engaged in services related to the transportation, gathering and storage of natural gas. Primarily fixed-priced contracts are used in the marketing and management of transportation, gathering and storage services. Generally these contracts are not derivatives and are therefore accounted for under the accrual method.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional natural gas and oil project development and production. The Company may use derivative contracts to manage changes in the price of natural gas and crude oil.

Power and Industrial Projects — Business units within this segment manage and operate onsite energy and pulverized coal 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 segment 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 emission allowances. Certain of these physical and financial coal contracts and contracts for the purchase and sale of emission allowances are derivatives and are accounted for by recording changes in fair value to earnings.

Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity and natural gas physical products and energy financial instruments, and provides energy and asset 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 hedge accounting criteria are met.

Energy Trading — Foreign Currency Exchange Risk — Energy Trading has foreign currency exchange forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company enters into these contracts to mitigate price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. These derivatives are accounted for by recording changes in fair value to earnings unless hedge accounting criteria are met.

Corporate and Other — 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 through 2033. In 2011, the Company estimates reclassifying less than $1 million of losses to earnings.

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 September 30, 2011 provision for credit losses, the Company’s exposure to counterparty nonperformance is not expected to have a material adverse effect on the Company’s financial statements.

Derivative Activities

The Company manages its mark-to-market (MTM) risk on a portfolio basis based upon the delivery period of its contracts and the individual components of the risks within each contract. Accordingly, it records and manages the energy purchase and sale obligations under its contracts in separate components based on the commodity (e.g., electricity or gas), the product (e.g., electricity for delivery during peak or off-peak hours), the delivery location (e.g., by region), the risk profile (e.g., forward or option), and the delivery period (e.g., by month and year). The following describe the four categories of activities represented by their operating characteristics and key risks:

• Asset Optimization - Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with power transmission, gas transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility.

• Marketing and Origination - Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

• Fundamentals Based Trading - Represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

• Other - Includes derivative activity at Detroit Edison related to FTRs and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative Assets or Liabilities, with an offset to Regulatory Assets or Liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

The following tables present the fair value of derivative instruments as of September 30, 2011:

(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	6	$	(9	)
Commodity Contracts:
Natural Gas	1,746		(1,795		)
Electricity	393		(365		)
Other	29		(15		)
Total derivatives not designated as hedging instruments	$	2,174	$	(2,184	)
Total derivatives:
Current	$	1,635	$	(1,643	)
Noncurrent	539		(542		)
Total derivatives	$	2,174	$	(2,185	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,635		$	539		$	(1,643	)	$	(542	)
Counterparty netting	(1,526		)	(480		)	1,526			480
Collateral adjustment	—			—			3			—
Total derivatives as reported	$	109		$	59		$	(114	)	$	(62	)

The following tables present the fair value of derivative instruments as of December 31, 2010:

(in Millions)	Derivative Assets		Derivative Liabilities
Derivatives designated as hedging instruments:
Interest rate contracts	$	—	$	(1	)
Derivatives not designated as hedging instruments:
Foreign currency exchange contracts	$	20	$	(30	)
Commodity Contracts:
Natural Gas	1,986		(2,118		)
Electricity	766		(716		)
Other	76		(71		)
Total derivatives not designated as hedging instruments	$	2,848	$	(2,935	)
Total derivatives:
Current	$	2,011	$	(2,041	)
Noncurrent	837		(895		)
Total derivatives	$	2,848	$	(2,936	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	2,011		$	837		$	(2,041	)	$	(895	)
Counterparty netting	(1,871		)	(760		)	1,871			760
Collateral adjustment	(9		)	—			28			25
Total derivatives as reported	$	131		$	77		$	(142	)	$	(110	)

The income effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and September 30, 2010 is as follows:

	Location of Gain (Loss) Recognized	Gain (Loss) Recognized in Income on Derivatives for Three Months Ended					Gain (Loss) Recognized in Income on Derivatives for Nine Months Ended
(in Millions)	in Income	September 30					September 30
Derivatives Not Designated As Hedging Instruments	On Derivatives	2011		2010			2011			2010
Foreign currency exchange contracts	Operating Revenue	$	4	$	(8	)	$	(1	)	$	(5	)
Commodity Contracts:
Natural Gas	Operating Revenue	9		24			24			51
Natural Gas	Fuel, purchased power and gas	10		(1		)	—			(7		)
Electricity	Operating Revenue	35		(6		)	64			43
Other	Operating Revenue	1		5			9			6
Other	Operation and maintenance	—		(2		)	—			(3		)
Total		$	59	$	12		$	96		$	85

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position are $3 million in gains related to FTRs recognized in Regulatory liabilities for the nine months ended September 30, 2011. There was no material effect for the three months ended September 30, 2011.

The following table presents the cumulative gross volume of derivative contracts outstanding as of September 30, 2011:

Commodity	Number of Units
Natural Gas (MMBtu)	631,382,267
Electricity (MWh)	46,441,874
Foreign Currency Exchange ($ CAD)	60,992,581

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 September 30, 2011, the value of the transactions for which the Company would have been exposed to collateral requests had DTE Energy’s credit rating been below investment grade on such date under both hard trigger and soft trigger provisions was approximately $209 million. In circumstances where an entity is downgraded below investment grade and collateral requests are made as a result, the requesting parties often agree to accept less than the full amount of their exposure to the downgraded entity.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

A reconciliation of the asset retirement obligations for the nine months ended September 30, 2011 follows:

(in Millions)
Asset retirement obligations at December 31, 2010	$	1,514
Accretion	69
Liabilities incurred	3
Revision in estimated cash flows	(1		)
Liabilities settled	(15		)
Asset retirement obligations at September 30, 2011	1,570
Less amount included in current liabilities	(10		)
	$	1,560

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Fair Value (Details 1) (USD $) In Millions	3 Months Ended		9 Months Ended																										3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member]	Jun. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member]	Sep. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member]	Jun. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member]	Sep. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Natural Gas [Member]	Jun. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Natural Gas [Member]	Sep. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Natural Gas [Member]	Jun. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Natural Gas [Member]	Sep. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Electricity [Member]	Jun. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Electricity [Member]	Sep. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Electricity [Member]	Jun. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Electricity [Member]	Sep. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Other [Member]	Jun. 30, 2011 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Other [Member]	Sep. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Other [Member]	Jun. 30, 2010 Net Assets Vaule of Unobserable Inputs Beginning Balance [Member] Other [Member]	Sep. 30, 2011 Net Assets Value of Unobservable Inputs Ending Balance [Member]	Sep. 30, 2010 Net Assets Value of Unobservable Inputs Ending Balance [Member]	Sep. 30, 2011 Net Assets Value of Unobservable Inputs Ending Balance [Member] Natural Gas [Member]	Sep. 30, 2010 Net Assets Value of Unobservable Inputs Ending Balance [Member] Natural Gas [Member]	Sep. 30, 2011 Net Assets Value of Unobservable Inputs Ending Balance [Member] Electricity [Member]	Sep. 30, 2010 Net Assets Value of Unobservable Inputs Ending Balance [Member] Electricity [Member]	Sep. 30, 2011 Net Assets Value of Unobservable Inputs Ending Balance [Member] Other [Member]	Sep. 30, 2010 Net Assets Value of Unobservable Inputs Ending Balance [Member] Other [Member]	Sep. 30, 2011 Natural Gas [Member]	Sep. 30, 2010 Natural Gas [Member]	Sep. 30, 2011 Natural Gas [Member]	Sep. 30, 2010 Natural Gas [Member]	Sep. 30, 2011 Electricity [Member]	Sep. 30, 2010 Electricity [Member]	Sep. 30, 2011 Electricity [Member]	Sep. 30, 2010 Electricity [Member]	Sep. 30, 2011 Other [Member]	Sep. 30, 2010 Other [Member]	Sep. 30, 2011 Other [Member]	Sep. 30, 2010 Other [Member]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis
Beginning Balance					$ 59	$ 65	$ 24	$ 161	$ 1	$ 1	$ 2	$ 2	$ 54	$ 57	$ 19	$ 155	$ 4	$ 7	$ 3	$ 4	$ 9	$ 133	$ 5	$ 4	$ (3)	$ 125	$ 7	$ 4
Transfers into Level 3	(7)		(4)																										(1)		0		(6)		(4)		0		0
Transfer out of Level 3	(42)		(24)																										0		1		(42)		(25)		0		0
Included in earnings	29	25	39	122																									6	3	3	4	23	21	34	117	0	1	2	1
Fair Value Measurements with Unobservable Inputs Reconciliation In Regulatory Assets Liabilities			3	4																											0	0			0	0			3	4
Purchases			1																												0				1				0
Settlements	(36)		(65)																										(1)		0		(35)		(63)		0		(2)
Purchases, issuances and settlements		(31)		(69)																										(1)		(6)		(29)		(59)		(1)		(4)
Ending balance	9		9		59	65	24	161	1	1	2	2	54	57	19	155	4	7	3	4	9	133	5	4	(3)	125	7	4
The amount of total gains (losses) included in net income attributed to the change in unrealized gains or losses related to assets still held at the end of the period	11	(1)	24	57																									6	2	5	(2)	5	(4)	17	58	0	1	2	1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net		$ (22)		$ 52																										$ 0		$ 4		$ (22)		$ 48		$ 0		$ 0

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Organization and Basis of Presentation(Details 2) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Variable Interest Entity [Line Items]
Note receivable	$ 124	$ 123
Trust preferred-linked securities	289	289
Unconsolidated Variable Interest Entity [Member]
Variable Interest Entity [Line Items]
Other investments	121	98
Note receivable	5	6
Trust preferred-linked securities	$ 289	$ 289

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Fair Value (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Assets and liabilities measured and recorded at fair value on a recurring basis

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2011:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			September 30, 2011
Assets:
Nuclear decommissioning trusts	$	532		$	361		$	—		$	—		$	893
Other investments(1)	48			56			—			—			104
Derivative assets:
Foreign currency exchange contracts	—			6			—			(6		)	—
Commodity Contracts:
Natural Gas	1,650			79			17			(1,698		)	48
Electricity	—			326			67			(282		)	111
Other	22			—			7			(20		)	9
Total derivative assets	1,672			411			91			(2,006		)	168
Total	$	2,252		$	828		$	91		$	(2,006	)	$	1,165
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(9	)	$	—		$	6		$	(3	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,616		)	(167		)	(12		)	1,698			(97		)
Electricity	—			(295		)	(70		)	285			(80		)
Other	(14		)	(1		)	—			20			5
Total derivative liabilities	(1,630		)	(473		)	(82		)	2,009			(176		)
Total	$	(1,630	)	$	(473	)	$	(82	)	$	2,009		$	(176	)
Net Assets as of September 30, 2011	$	622		$	355		$	9		$	3		$	989
Assets:
Current	$	1,251		$	322		$	62		$	(1,526	)	$	109
Noncurrent(3)	1,001			506			29			(480		)	1,056
Total Assets	$	2,252		$	828		$	91		$	(2,006	)	$	1,165
Liabilities:
Current	$	(1,235	)	$	(348	)	$	(60	)	$	1,529		$	(114	)
Noncurrent	(395		)	(125		)	(22		)	480			(62		)
Total Liabilities	$	(1,630	)	$	(473	)	$	(82	)	$	2,009		$	(176	)
Net Assets as of September 30, 2011	$	622		$	355		$	9		$	3		$	989

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			December 31, 2010
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments(1)	56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			20			—			(20		)	—
Commodity Contracts:
Natural Gas	1,846			128			12			(1,960		)	26
Electricity	—			649			117			(589		)	177
Other	68			4			4			(71		)	5
Total derivative assets	1,914			801			133			(2,640		)	208
Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,844		)	(263		)	(11		)	1,955			(163		)
Electricity	—			(653		)	(63		)	643			(73		)
Other	(63		)	(8		)	—			66			(5		)
Total derivative liabilities	(1,907		)	(955		)	(74		)	2,684			(252		)
Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006
Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent(3)	1,270			533			84			(760		)	1,127
Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent	(617		)	(225		)	(53		)	785			(110		)
Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30, 2011
(in Millions)	Natural Gas			Electricity			Other		Total
Net Assets as of July 1, 2011	$	1		$	57		$	7	$	65
Transfers into Level 3	(1		)	(6		)	—		(7		)
Transfers out of Level 3	—			(42		)	—		(42		)
Total gains or (losses):
Included in earnings	6			23			—		29
Purchases, issuances, sales and settlements:
Settlements	(1		)	(35		)	—		(36		)
Net Assets (Liabilities) as of September 30, 2011	$	5		$	(3	)	$	7	$	9
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2011	$	6		$	5		$	—	$	11

	Three Months Ended September 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of July 1, 2010	$	2		$	155		$	4		$	161
Changes in fair value recorded in income	3			21			1			25
Purchases, issuances and settlements	(1		)	(29		)	(1		)	(31		)
Transfers in/out of Level 3	—			(22		)	—			(22		)
Net Assets as of September 30, 2010	$	4		$	125		$	4		$	133
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2010	$	2		$	(4	)	$	1		$	(1	)

	Nine Months Ended September 30, 2011
(in Millions)	Natural Gas		Electricity			Other			Total
Net Assets as of January 1, 2011	$	1	$	54		$	4		$	59
Transfers into Level 3	—		(4		)	—			(4		)
Transfers out of Level 3	1		(25		)	—			(24		)
Total gains or (losses):
Included in earnings	3		34			2			39
Recorded in regulatory assets/liabilities	—		—			3			3
Purchases, issuances, sales and settlements:
Purchases	—		1			—			1
Settlements	—		(63		)	(2		)	(65		)
Net Assets (Liabilities) as of September 30, 2011	$	5	$	(3	)	$	7		$	9
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2011	$	5	$	17		$	2		$	24

	Nine Months Ended September 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value recorded in income	4			117			1			122
Changes in fair value recorded in regulatory assets/liabilities	—			—			4			4
Purchases, issuances and settlements	(6		)	(59		)	(4		)	(69		)
Transfers in/out of Level 3	4			48			—			52
Net Assets as of September 30, 2010	$	4		$	125		$	4		$	133
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2010	$	(2	)	$	58		$	1		$	57

Fair Value of Long Term Debt [Table Text Block]

	September 30, 2011				December 31, 2010
(in Billions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-Term Debt	$	8.8	$	7.7	$	8.5	$	8.0

Fair Value of Nuclear Decommissioning Trust Fund Assets Text Block [Table]

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

	September 30,		December 31,
(in Millions)	2011		2010
Fermi 2	$	858	$	910
Fermi 1	3		3
Low level radioactive waste	32		26
Total	$	893	$	939

Schedule of Realized Gain (Loss) [Table Text Block]

The following table sets forth the gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Realized gains	$	8		$	8		$	34		$	29
Realized losses	(9		)	(6		)	(26		)	(25		)
Proceeds from sales of securities	10			51			69			179

Fair Value and Unrealized Gains for Nuclear Decommissioning Trust Fund Table [Table] [Table Text Block]

The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

	Fair		Unrealized
(in Millions)	Value		Gains
As of September 30, 2011
Equity securities	$	485	$	52
Debt securities	395		22
Cash and cash equivalents	13		—
	$	893	$	74
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities	361		11
Cash and cash equivalents	6		—
	$	939	$	88

Available-for-sale debt and equity securities

The following table summarizes the fair value of the Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:

	September 30, 2011				December 31, 2010
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	85	$	85	$	133	$	133
Equity securities	5		5		6		6

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Short-Term Credit Arrangements and Borrowings

9 Months Ended

Sep. 30, 2011

Short-Term Credit Arrangements and Borrowings [Abstract]

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly owned subsidiaries, Detroit Edison and MichCon have entered into unsecured revolving credit facilities with similar terms with a syndicate of 23 banks that may be used for general corporate borrowings, but are intended to provide liquidity support for each of the companies’ commercial paper programs. No one bank provides more than 8.25% of the commitment in any facility. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy has other facilities to support letter of credit issuance.

The above agreements require the Company to maintain a total funded debt to capitalization ratio of no more than 0.65 to 1. In the agreements, “total funded debt” means all indebtedness of the Company and its consolidated subsidiaries, including capital lease obligations, hedge agreements and guarantees of third parties’ debt, but excluding contingent obligations, nonrecourse and junior subordinated debt and certain equity-linked securities and, except for calculations at the end of the second quarter, certain MichCon short-term debt. “Capitalization” means the sum of (a) total funded debt plus (b) “consolidated net worth,” which is equal to consolidated total stockholders’ equity of the Company and its consolidated subsidiaries (excluding pension effects under certain FASB statements), as determined in accordance with accounting principles generally accepted in the United States of America. At September 30, 2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon were 0.49 to 1, 0.52 to 1 and 0.47 to 1, respectively, and were in compliance with this financial covenant. The availability under these combined facilities at September 30, 2011 is shown in the following table:

(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Unsecured revolving credit facility, expiring August 2012	$	538	$	212	$	250	$	1,000
Unsecured revolving credit facility, expiring August 2013	562		63		175		800
Unsecured letter of credit facility, expiring in May 2013	50		—		—		50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Total credit facilities at September 30, 2011	$	1,275	$	275	$	425	$	1,975
Amounts outstanding at September 30, 2011:
Commercial paper issuances	126		49		100		275
Letters of credit outstanding at September 30, 2011	144		—		—		144
	270		49		100		419
Net availability at September 30, 2011	$	1,005	$	226	$	325	$	1,556

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $38 million which are used for various corporate purposes.

In October 2011, the Company completed an early renewal of its $1.0 billion and $800 million syndicated unsecured revolving credit facilities before their scheduled expiration in August 2012 and August 2013, respectively. The new $1.8 billionfive-year facility will expire in October 2016 and has covenants similar to the prior facilities.

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 $100 million with its clearing agent. The agreement, as amended, also allows for up to $50 million of additional margin financing provided that the Company posts a letter of credit for the incremental amount. At September 30, 2011, a $15 million letter of credit was in place, raising the capacity under this facility to $115 million. The $15 million letter of credit is included in the table above. The amount outstanding under this agreement was $4 million and $39 million at September 30, 2011 and December 31, 2010, respectively.

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Consolidated Statements of Other Comprehensive Income Unaudited (Parentheticals) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Benefit obligations:
Tax effect on benefit obligation	$ 2	$ 3
Amounts reclassified to benefit obligations related to consolidation of VIEs	0	5
Net unrealized gains (losses) on derivatives:
Tax effect on gains (losses) during the period	0	1
Tax effect on amounts reclassified to income	0	1
Net Unrealized gains (losses) on investments:
Tax effect on gains (losses) during the period	0	(6)
Amounts reclassified to benefit obligations related to consolidation of VIEs	0	(5)
Tax effect on foreign currency translation	$ 0	$ 0

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Inter segment billing for goods and services [Table Text Block]

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:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Electric Utility	$	7		$	8		$	25		$	23
Gas Utility	1			1			2			1
Gas Storage and Pipelines	1			1			7			3
Power and Industrial Projects	30			50			119			122
Energy Trading	17			21			54			65
Corporate & Other	(12		)	(18		)	(40		)	(51		)
	$	44		$	63		$	167		$	163

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data of the business segments follows:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues
Electric Utility	$	1,517		$	1,444		$	3,950		$	3,798
Gas Utility	159			170			1,090			1,157
Gas Storage and Pipelines	21			20			69			62
Unconventional Gas Production	11			7			29			23
Power and Industrial Projects	259			303			781			846
Energy Trading	342			258			970			661
Corporate & Other	—			—			2			—
Reconciliation & Eliminations	(44		)	(63		)	(167		)	(163		)
Total	$	2,265		$	2,139		$	6,724		$	6,384
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	157		$	165		$	345		$	343
Gas Utility	(11		)	(6		)	69			92
Gas Storage and Pipelines	13			12			42			36
Unconventional Gas Production	(2		)	(4		)	(5		)	(9		)
Power and Industrial Projects	12			26			27			66
Energy Trading	22			(12		)	36			—
Corporate & Other (1)	(8		)	(18		)	47			(50		)
Net Income Attributable to DTE Energy	$	183		$	163		$	561		$	478

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Regulatory Matters

9 Months Ended

Sep. 30, 2011

Public Utilities, General Disclosures [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

2010 Electric Rate Case Filing

On October 20, 2011, the MPSC issued an order in Detroit Edison's October 29, 2010 rate case filing. The MPSC approved an annual revenue increase of $175 million. Included in the approved increase in revenues was a return on equity of 10.5% on an expected permanent capital structure of 49.2% equity and 50.8% debt.

Detroit Edison self-implemented a rate increase of $107 million on April 28, 2011. The MPSC stated the net revenue collected due to self-implementation be credited to the 2011 Choice Incentive Mechanism (CIM) regulatory asset. Self-implementation revenue of approximately $31 million was credited to the CIM Regulatory Asset as of September 30, 2011. The MPSC required that within ninety days, Detroit Edison file a report regarding the amount of revenue collected through application of its self-implemented rate increase and a proposed reconciliation with the final rates and rate design approved in the order. In addition, a 2011 CIM reconciliation is expected to be filed in early 2012.

Other key aspects of the MPSC order include the following:

• adopt a new Revenue Decoupling Mechanism (RDM) effective April 1, 2012, that will compare actual revenue (excluding the impacts of weather) by rate class with the base established in this rate case. The RDM has an annual collar of 1.5% in the first year and 3% in the second and subsequent years. The RDM established in the previous rate case, which considered the impact of weather, will be terminated effective October 31, 2011. Therefore, there will be no RDM in place from October 31, 2011 through April 1, 2012;

• recognition of the expiration of a wholesale contract. Since the expiration of the wholesale contract is not until December 31, 2011, the MPSC is requiring Detroit Edison to calculate a customer credit for each kWh sold under the wholesale contract from October 29, 2011 through December 31, 2011, with the credit to be applied in its next PSCR reconciliation;

• the Restoration Reconciliation Mechanism, Line Clearance Recovery Mechanism, Uncollectible Expense Tracking Mechanism and CIM are terminated as of the date of the order;

• due to uncertainty resulting from the Michigan Court of Appeals overturning collection of the Low Income Energy Efficiency Fund (LIEEF), the MPSC required the continued collection of LIEEF amounts in base rates and placement into escrow pending further orders by the MPSC;

• approval of Detroit Edison's proposal to reduce the Nuclear Decommissioning Surcharge by approximately $20 million annually; and

• implementation of lower depreciation rates previously approved in a June 2011 MPSC order.

Detroit Edison Uncollectible Expense True-Up Mechanism (UETM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its UETM for 2010 requesting authority to refund approximately $7 million consisting of costs related to 2010 uncollectible expense. In August 2011, the MPSC approved a settlement agreement for the 2010 UETM authorizing a refund of approximately $7 million to be applied as credits to customer bills beginning September 1, 2011.

Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line ClearanceTracker (LCT) Reconciliation

In March 2011, Detroit Edison filed an application with the MPSC for approval of the reconciliation of its 2010 RETM and LCT. The Company's 2010 restoration expenses were higher than the amount provided in rates. Accordingly, Detroit Edison requested recovery of $19.5 million. In October 2011, the MPSC approved a settlement agreement reconciling the RETM and approving the LCT report. The MPSC authorized surcharges to recover $19.5 million over a three-month period beginning November 1, 2011.

Detroit Edison Revenue Decoupling Mechanism (RDM)

In May 2011, Detroit Edison filed an application with the MPSC for approval of its RDM reconciliation for the period February 2010 through January 2011 requesting authority to refund approximately $56 million, plus interest. This is the initial reconciliation filing under the pilot RDM. In addition to the refund liability for the initial reconciliation filing, Detroit Edison has accrued an RDM refund for the February 2011 through September 2011 period of approximately $71 million, plus interest. There are various interpretations and alternative calculation methodologies relating to the RDM refund calculation that could ultimately be adopted by the MPSC that could result in significant adjustments in excess of the amounts accrued as of September 30, 2011. An MPSC order on the initial filing is expected in the first half of 2012.

Power Supply Cost Recovery (PSCR) Proceedings

The PSCR process is designed to allow Detroit Edison to recover all of its power supply costs if incurred under reasonable and prudent policies and practices. Detroit Edison’s power supply costs include fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowances costs, urea costs, transmission costs and MISO costs. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

The following table summarizes Detroit Edison’s PSCR reconciliation filing currently pending with the MPSC:

		Net Under-Recovery,		PSCR Cost of
		Including Interest		Power Sold
PSCR Year	Date Filed	(in Millions)		(in Billions)
2010	March 2011	$	52.6	$	1.2

2010 PSCR Year — The net under-recovery of $52.6 million includes an over-recovery of $15.6 million for the 2009 PSCR year. In addition, the 2010 PSCR reconciliation includes an under-recovery of $7.1 million for the reconciliation of the 2007-2008 Pension Equalization Mechanism, and an over-refund of $3.8 million for the 2011 refund of the self-implemented rate increase related to the 2009 electric rate case filing.

2011 Plan Year — In September 2010, Detroit Edison filed its 2011 PSCR plan case seeking approval of a levelized PSCR factor of 2.98 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.2 billion. The plan also includes approximately $36 million for the recovery of its projected 2010 PSCR under-recovery.

2012 Plan Year — In September 2011, Detroit Edison filed its 2012 PSCR plan case seeking approval of a levelized PSCR factor of 4.18 mills/kWh above the amount included in base rates for all PSCR customers. The filing supports a total power supply expense forecast of $1.4 billion. The plan also includes approximately $158 million for the recovery of its projected 2011 PSCR under-recovery.

Energy Optimization (EO) Plans

In September 2011, Detroit Edison and MichCon filed biennial EO Plans with the MPSC as required. Detroit Edison's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $294 million and further requested approval of surcharges to recover these costs. MichCon's EO Plan application proposed the recovery of EO expenditures for the period 2012-2015 of $103 million and further requested approval of surcharges to recover these costs.

Low Income Energy Efficiency Fund

The Customer Choice and Electricity Reliability Act of 2000 authorized the creation of the LIEEF administered by the MPSC. The purpose of the fund is to provide shut-off and other protection for low income customers and to promote energy efficiency by all customer classes. Detroit Edison and MichCon collect funding for the LIEEF as part of their base rates and remit the funds to the State of Michigan monthly. In July 2011, the Michigan Court of Appeals issued a decision reversing the portion of MichCon's June 2010 MPSC rate order that permitted MichCon to recover funding for the LIEEF in base rates. In response to the Court of Appeals decision, Detroit Edison and MichCon have ceased remitting payments for LIEEF funding to the State of Michigan. In October 2011, the MPSC issued orders directing Detroit Edison and MichCon to continue collecting funds for LIEEF in rates and to escrow the collected funds pending further order by the MPSC. As a result of these actions, Detroit Edison and MichCon no longer record Operation and Maintenance expense for the payments to the LIEEF fund, but record an offset to Revenues for the amounts that are being escrowed.

MichCon UETM

In March 2011, MichCon filed an application with the MPSC for approval of its UETM for 2010 requesting recovery of $31 million. The $31 million consists of $7 million related to 2010 uncollectible expense and $24 million related to the 2008 UETM under-collection. In September 2011, the MPSC approved a settlement agreement approving the 2010 UETM and the implementation of a surcharge beginning October 1, 2011.

MichCon Revenue Decoupling Mechanism (RDM)

In September 2011, MichCon filed an application with the MPSC for approval of its RDM reconciliation for the period July 1, 2010 through June 30, 2011. MichCon's RDM application proposed the recovery of approximately $20 million.

Gas Cost Recovery (GCR) Proceedings

The GCR process is designed to allow MichCon to recover all of its gas supply costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies and practices for prudence in annual plan and reconciliation filings.

The following table summarizes MichCon’s GCR reconciliation filing currently pending with the MPSC:

		Net Over-Recovery,		GCR Cost of
		Including Interest		Gas Sold
GCR Year	Date Filed	(in Millions)		(in Billions)
2009-2010	June 2010	$	5.9	$	1.0
2010-2011	June 2011	$	1.0	$	0.7

2011-2012 Plan Year — In December 2010, MichCon filed its GCR plan case for the 2011-2012 GCR plan year. MichCon filed for a maximum base GCR factor of $5.89 per Mcf adjustable monthly by a contingency factor.

Gas Main Renewal and Gas Meter Move Out Programs

The June 3, 2010 MPSC gas rate case order required MichCon to make filings related to gas main renewal and meter move-out programs. In a July 30, 2010 filing, MichCon proposed to implement a 10-year gas main renewal program beginning in 2012 which would require capital expenditures of approximately $17 million per year for renewing gas distribution mains, retiring gas mains, and where appropriate and when related to the gas main renewal or retirement activity, relocating inside meters to outside locations and renewing service lines. In a September 30, 2010 filing, MichCon proposed to implement a 10-year gas meter move out program beginning in 2012 which would require capital expenditures of approximately $22 million per year primarily for relocation of inside meters to the outside of residents' houses. In September 2011, the MPSC issued orders approving both programs and requested MichCon to include the recovery of costs associated with these two programs in future MichCon rate cases.

Other

The Company is unable to predict the outcome of the unresolved 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 Comp

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Retirement Benefits and Trusteed Assets

9 Months Ended

Sep. 30, 2011

Pension and Other Postretirement Benefit Expense [Abstract]

RETIREMENT BENEFITS AND TRUSTEED ASSETS

RETIREMENT BENEFITS AND TRUSTEED ASSETS

The following table details the components of net periodic benefit costs for pension benefits and other postretirement benefits:

							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Three Months Ended September 30
Service cost	$	15		$	16		$	14		$	15
Interest cost	51			51			28			31
Expected return on plan assets	(62		)	(65		)	(24		)	(18		)
Amortization of:
Net actuarial loss	41			25			12			13
Prior service cost (credit)	—			1			(7		)	(1		)
Net transition liability	—			—			1			1
Special termination benefits	—			—			—			—
Net periodic benefit cost	$	45		$	28		$	24		$	41

							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Nine Months Ended September 30
Service cost	$	52		$	48		$	48		$	46
Interest cost	152			152			90			94
Expected return on plan assets	(185		)	(194		)	(71		)	(56		)
Amortization of:
Net actuarial loss	107			75			42			40
Prior service cost (credit)	2			3			(20		)	(3		)
Net transition liability	—			—			2			2
Special termination benefits	2						—			—
Net periodic benefit cost	$	130		$	84		$	91		$	123

Pension and Other Postretirement Contributions

In January 2011, the Company contributed $200 million to its pension plans.

In January 2011, the Company contributed $81 million to its other postretirement benefit plans. At the discretion of management, the Company may make up to an additional $125 million contribution to its other postretirement benefit plans by the end of 2011.

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Stock Based Compensation (Details 3)	9 Months Ended
	Sep. 30, 2011
Performance Share Awards [Line Items]
Performance Shares - Balance at January 1, 2011	1,527,253
Performance Shares - Grants	611,844
Performance Shares - Forfeitures	(66,357)
Performance Shares - Payouts	(467,688)
Performance Shares - Balance at September 30, 2011	1,605,052

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Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

The Company reports both basic and diluted earnings per share. The calculation of diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period from the exercise of stock options.

	Three Months				Nine Months
	Ended September 30				Ended September 30
(in Millions, except per share amounts)	2011		2010		2011		2010
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	183	$	163	$	561	$	478
Average number of common shares outstanding	169		169		169		168
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	99	$	94	$	293	$	271
Dividends declared — net restricted shares	—		1		1		1
Total distributed earnings	$	99	$	95	$	294	$	272
Net income less distributed earnings	$	84	$	68	$	267	$	206
Distributed (dividends per common share)	0.59		0.56		$	1.74	$	1.62
Undistributed	0.49		0.41		1.57		1.23
Total Basic Earnings per Common Share	$	1.08	0.97		$	3.31	$	2.85
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	183	$	163	$	561	$	478
Average number of common shares outstanding	169		169		169		168
Average incremental shares from assumed exercise of options	1		1		1		—
Common shares for dilutive calculation	170		170		170		168
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	99	$	94	$	293	$	271
Dividends declared — net restricted shares	—		1		1		1
Total distributed earnings	$	99	$	95	$	294	$	272
Net income less distributed earnings	$	84	$	68	$	267	$	206
Distributed (dividends per common share)	$	0.59	$	0.56	$	1.74	$	1.62
Undistributed	0.48		0.40		1.56		1.22
Total Diluted Earnings per Common Share	$	1.07	$	0.96	$	3.30	$	2.84

Options to purchase approximately 0.4 million shares of common stock as of September 30, 2010, 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.

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Retirement Benefits and Trusteed Assets (Tables)

9 Months Ended

Sep. 30, 2011

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following table details the components of net periodic benefit costs for pension benefits and other postretirement benefits:

							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Three Months Ended September 30
Service cost	$	15		$	16		$	14		$	15
Interest cost	51			51			28			31
Expected return on plan assets	(62		)	(65		)	(24		)	(18		)
Amortization of:
Net actuarial loss	41			25			12			13
Prior service cost (credit)	—			1			(7		)	(1		)
Net transition liability	—			—			1			1
Special termination benefits	—			—			—			—
Net periodic benefit cost	$	45		$	28		$	24		$	41

							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2011			2010			2011			2010
Nine Months Ended September 30
Service cost	$	52		$	48		$	48		$	46
Interest cost	152			152			90			94
Expected return on plan assets	(185		)	(194		)	(71		)	(56		)
Amortization of:
Net actuarial loss	107			75			42			40
Prior service cost (credit)	2			3			(20		)	(3		)
Net transition liability	—			—			2			2
Special termination benefits	2						—			—
Net periodic benefit cost	$	130		$	84		$	91		$	123

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the nine months ended September 30, 2011 follows:

(in Millions)
Asset retirement obligations at December 31, 2010	$	1,514
Accretion	69
Liabilities incurred	3
Revision in estimated cash flows	(1		)
Liabilities settled	(15		)
Asset retirement obligations at September 30, 2011	1,570
Less amount included in current liabilities	(10		)
	$	1,560

In 2001, Detroit Edison began the final decommissioning of Fermi 1, with the goal of removing the remaining radioactive material and terminating the Fermi 1 license. In the first quarter of 2011, based on management decisions revising the timing and estimate of cash flows, Detroit Edison accrued an additional $19 million with respect to the decommissioning of Fermi 1. Management intends to suspend decommissioning activities and place the facility in safe storage status. The expense amount has been recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations. In the second quarter of 2011, based on updated studies revising the timing and estimate of cash flows, a reduction of approximately $20 million was made to the Detroit Edison asset retirement obligation for asbestos removal with approximately $6 million of the decrease associated with Fermi 1 recorded in Asset (gains) and losses, reserves and impairments, net on the Consolidated Statements of Operations.

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Financial and Other Derivative Instruments (Details 2)	Sep. 30, 2011
Natural Gas [Member]
Derivative [Line Items]
Investment Contract Volume	631,382,267
Electricity [Member]
Derivative [Line Items]
Investment Contract Volume	46,441,874
Foreign Exchange Contract [Member]
Derivative [Line Items]
Investment Contract Volume	60,992,581

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Consolidated Statements of Changes in Equity (Unaudited) (USD $) In Millions, except Share data	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Non-controlling Interest
Beginning Balance at Dec. 31, 2010	$ 6,767	$ 3,440	$ 3,431	$ (149)	$ 45
Beginning Balance, shares at Dec. 31, 2010	169,428,406	169,428,000
Net Income	563		561
Net Income (Loss) Attributable to Noncontrolling Interest	2				2
Dividends declared on common stock	(294)		(294)
Repurchase of common stock	(45)	(45)
Repurchase of common stock, shares		(928,000)
Benefit obligations, net of tax	5			5
Foreign currency translation, net of tax	(1)			(1)
Net change in unrealized losses on investments, net of tax	(1)			(1)
Stock-based compensation, distributions to noncontrolling interests and other	15	23
Payments of Dividends, Noncontrolling Interest					(8)
Stock-based compensation, distributions to noncontrolling interests and other, shares		751,000
Ending Balance at Sep. 30, 2011	$ 7,009	$ 3,418	$ 3,698	$ (146)	$ 39
Ending Balance, shares at Sep. 30, 2011	169,250,934	169,251,000

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Organization and Basis of Presentation

9 Months Ended

Sep. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

ORGANIZATION AND BASIS OF PRESENTATION

Corporate Structure

DTE Energy owns the following businesses:

• Detroit Edison, an electric utility engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan;

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

• Other businesses involved in (1) natural gas pipelines, gathering and storage; (2) unconventional gas and oil project 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. Certain activities of Detroit Edison and MichCon, as well as various other aspects of businesses under DTE Energy are regulated by the FERC. In addition, the Company is regulated by other federal and state regulatory agencies including the NRC, the EPA and the MDEQ.

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

Basis of Presentation

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2010 Annual Report on Form 10-K.

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.

The Consolidated Financial Statements are unaudited, but in the Company’s opinion include all adjustments necessary to a fair statement of the results for the interim periods. All adjustments are of a normal recurring nature, except as otherwise disclosed in these Consolidated Financial Statements and Notes to Consolidated Financial Statements. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2011.

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.

The Company evaluates whether an entity is a VIE whenever reconsideration events occur. The Company consolidates VIEs for which it is the primary beneficiary. If the Company is not the primary beneficiary and an ownership interest is held, the VIE is accounted for under the equity method of accounting. When assessing the determination of the primary beneficiary, the Company considers all relevant facts and circumstances, including: the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb the expected losses and/or the right to receive the expected returns of the VIE. The Company performs ongoing reassessments of all VIEs to determine if the primary beneficiary status has changed.

Legal entities within the Company’s Power and Industrial Projects segment enter into long-term contractual arrangements with customers to supply energy-related products or services. The entities are generally designed to pass-through the commodity risk associated with these contracts to the customers, with the Company retaining operational and customer default risk. These entities generally are VIEs. In addition, the Company has interests in certain VIEs that we share control of all significant activities for those entities with our partners, and therefore are accounted for under the equity method.

The Company has variable interests in VIEs through certain of its long-term purchase contracts. As of September 30, 2011, the carrying amount of assets and liabilities in the Consolidated Statement of Financial Position that relate to its variable interests under long-term purchase contracts are predominately related to working capital accounts and generally represent the amounts owed by the Company for the deliveries associated with the current billing cycle under the contracts. The Company has not provided any form of financial support associated with these long-term contracts. There is no significant potential exposure to loss as a result of its variable interests through these long-term purchase contracts.

In 2001, Detroit Edison financed a regulatory asset related to Fermi 2 and certain other regulatory assets through the sale of rate reduction bonds by a wholly owned special purpose entity, Securitization. Detroit Edison performs servicing activities including billing and collecting surcharge revenue for Securitization. This entity is a VIE, and is consolidated as the Company is the primary beneficiary.

DTE Energy has interests in two unconsolidated trusts that were formed for the purpose of issuing preferred securities and lending the gross proceeds to the Company. The 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. DTE Energy has reviewed these trusts and has determined they are VIEs, but the Company is not the primary beneficiary as it does not have variable interests in the trusts and therefore, the trusts are not consolidated by the Company.

The maximum risk exposure for consolidated VIEs is reflected on the Company’s Consolidated Statements of Financial Position. For non-consolidated VIEs, the maximum risk exposure is generally limited to its investment and amounts which it has guaranteed.

The following table summarizes the major balance sheet items for consolidated VIEs as of September 30, 2011 and December 31, 2010. Amounts at September 30, 2011 for consolidated VIEs that are either (1) assets that can be used only to settle obligations of the VIE or (2) liabilities for which creditors do not have recourse to the general credit of the primary beneficiary are segregated in the restricted amounts column. VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below.

	September 30, 2011
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	8	$	8	$	—
Restricted cash	58		7		65		64
Accounts receivable	38		14		52		40
Inventories	—		145		145		—
Other current assets	—		1		1		—
Property, plant and equipment	—		58		58		25
Securitized regulatory assets	618		—		618		618
Other assets	10		6		16		18
	$	724	$	239	$	963	$	765
LIABILITIES
Accounts payable and accrued current liabilities	$	4	$	38	$	42	$	4
Current portion long-term debt, including capital leases	164		7		171		171
Other current liabilities	62		1		63		64
Mortgage bonds, notes and other	—		31		31		31
Securitization bonds	479		—		479		479
Capital lease obligations	—		20		20		20
Other long term liabilities	6		2		8		7
	$	715	$	99	$	814	$	776

	December 31, 2010
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash	104		8		112		112
Accounts receivable	42		8		50		44
Inventories	—		99		99		—
Other current assets	—		1		1		—
Property, plant and equipment	—		54		54		38
Securitized regulatory assets	729		—		729		729
Other assets	13		9		22		21
	$	888	$	183	$	1,071	$	944
LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases	150		7		157		157
Other current liabilities	62		6		68		66
Mortgage bonds, notes and other	—		35		35		35
Securitization bonds	643		—		643		643
Capital lease obligations	—		23		23		23
Other long term liabilities	6		7		13		12
	$	878	$	105	$	983	$	954

Amounts for non-consolidated VIEs as September 30, 2011 and December 31, 2010 were as follows:

	September 30,		December 31,
(in Millions)	2011		2010
Other investments	$	121	$	98
Note receivable	5		6
Trust preferred — linked securities	289		289

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Significan Accounting Policies (Details Textuals 1) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Jun. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2011	Dec. 31, 2010	Jun. 30, 2010
Federal Income Tax Note [Line Items]
Effective Income Tax Rate, Continuing Operations	35.00%		36.00%	24.00%	34.00%
Income Tax Expense (Benefit)	$ 101,000,000	$ 88,000,000	$ 92,000,000	$ 180,000,000	$ 252,000,000
Unrecognized Tax Benefits	4,000,000			4,000,000			5,000,000
Unrecognized Tax Benefits, Period Increase (Decrease)				40,000,000
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit						49,000,000
Michigan Corporate Income Tax		6.00%
Deferred Tax Liabilities Attributable to Regulated Utilities								41,000,000
Reduction of Net Deferred Tax Assets		0
Reduction of Net Deferred Tax Assets		307,000,000
Decrease in Deferred Tax Liabilities Attributaable to Regulated Utilities		395,000,000
Consistnet with Orginal Treatment of Deferred Tax Liabilities No Cash Flow Impact		$ 0

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Short-Term Credit Arrangements and Borrowings (Tables)

9 Months Ended

Sep. 30, 2011

Short-Term Credit Arrangements and Borrowings [Abstract]

Schedule of Short-term Debt [Table Text Block]

The availability under these combined facilities at September 30, 2011 is shown in the following table:

(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Unsecured revolving credit facility, expiring August 2012	$	538	$	212	$	250	$	1,000
Unsecured revolving credit facility, expiring August 2013	562		63		175		800
Unsecured letter of credit facility, expiring in May 2013	50		—		—		50
Unsecured letter of credit facility, expiring in August 2015	125		—		—		125
Total credit facilities at September 30, 2011	$	1,275	$	275	$	425	$	1,975
Amounts outstanding at September 30, 2011:
Commercial paper issuances	126		49		100		275
Letters of credit outstanding at September 30, 2011	144		—		—		144
	270		49		100		419
Net availability at September 30, 2011	$	1,005	$	226	$	325	$	1,556

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Regulatory Matters (Details Textuals 1) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Mar. 31, 2011	Sep. 30, 2011 percent people years kWh Days weeks MCF banks customers ratio employees
Regulatory Assets and Liability [Line Items]
MPSC Authorized Recovery of Uncollectibe Expense	$ 31
Uncollectibe Expense Prior Year		7
Uncollectible Expense Tracking Mechanism Under Collection Three Years Prior		24
Requested Recovery for Revenue Decoupling Mechanism		20
GCR Plan Case Factory Current Year and Next Year		5.89
Gas Main Renewal Program Implentation Time Period		10
Gas Main Renewal Program Capital Expenditures		17
Gas Meter Move Out Program Implementation Time Period		10
Gas Meter Move Out Program Capital Expenditures		$ 22

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Earnings Per Share (Details) (USD $) Share data in Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Basic Earnings per Share
Net Income Attributable to DTE Energy Company	$ 183,000,000	$ 163,000,000	$ 561,000,000	$ 478,000,000
Average number of common shares outstanding	169	169	169	168
Weighted average net restricted shares outstanding	1	1	1	1
Dividends declared - common shares	99,000,000	94,000,000	293,000,000	271,000,000
Dividends declared - net restricted shares	0	1,000,000	1,000,000	1,000,000
Total distributed earnings	99,000,000	95,000,000	294,000,000	272,000,000
Net income less distributed earnings	84,000,000	68,000,000	267,000,000	206,000,000
Distributed (dividends per common share)	$ 0.59	$ 0.56	$ 1.74	$ 1.62
Undistributed	$ 0.49	$ 0.41	$ 1.57	$ 1.23
Total Basic Earnings per Common Share	$ 1.08	$ 0.97	$ 3.31	$ 2.85
Diluted Earnings per Share
Net Income Attributable to DTE Energy Company	183,000,000	163,000,000	561,000,000	478,000,000
Average number of common shares outstanding	169	169	169	168
Average incremental shares from assumed exercise of options	1	1	1	0
Common shares for dilutive calculation	170	170	170	168
Weighted average net restricted shares outstanding	1	1	1	1
Dividends declared - common shares	99,000,000	94,000,000	293,000,000	271,000,000
Dividends declared - net restricted shares	0	1,000,000	1,000,000	1,000,000
Total distributed earnings	99,000,000	95,000,000	294,000,000	272,000,000
Net income less distributed earnings	84,000,000	68,000,000	267,000,000	206,000,000
Earnings Per Share, Diluted, Distributed	$ 0.59	$ 0.56	$ 1.74	$ 1.62
Undistributed Earnings, Diluted	$ 0.48	$ 0.40	$ 1.56	$ 1.22
Total Diluted Earnings per Common Share	$ 1.07	$ 0.96	$ 3.30	$ 2.84

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Financial and Other Derivative Instruments (Details 1) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 59	$ 12	$ 96	$ 85
Foreign Exchange Contract [Member] | derivative operating revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	4	(8)	(1)	(5)
Natural Gas [Member] | derivative operating revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	9	24	24	51
Natural Gas [Member] | Fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	10	(1)	0	(7)
Electricity [Member] | derivative operating revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	35	(6)	64	43
Other [Member] | derivative operating revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1	5	9	6
Other [Member] | Operating Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 0	$ (2)	$ 0	$ (3)

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Long-Term Debt (Details Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended	60 Months Ended	3 Months Ended
	Jun. 30, 2011	Sep. 01, 2016 years	Jun. 30, 2011 Senior Notes2 [Member]	Sep. 30, 2011 Tax-Exempt Revenue Bonds4 [Member]
Debt Instrument [Line Items]
interest rate is reset every three months	3
Debt Instrument, Basis Spread on Variable Rate	7000.00%
Time Period Bonds were Remarketed for		5
Extinguishment of Debt, Amount	$ 991		$ 600	$ 140

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Accounting Policies [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

Intangible Assets

The Company has certain intangible assets relating to emission allowances, renewable energy credits and non-utility contracts. Emission allowances and renewable energy credits are charged to expense as the allowances and credits are consumed in the operation of the business. The Company’s intangible assets related to emission allowances were $9 million at September 30, 2011 and December 31, 2010. The Company’s intangible assets related to renewable energy credits were $26 million and $17 million at September 30, 2011 and December 31, 2010, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at September 30, 2011were $65 million and $26 million, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at December 31, 2010 were $63 million and $22 million, respectively. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years.

Income Taxes

The Company’s effective tax rate for the three months ended September 30, 2011was 35 percent as compared to 36 percent for the three months ended September 30, 2010. The Company’s effective tax rate for the nine months ended September 30, 2011 was 24 percent as compared to 34 percent for the nine months ended September 30, 2010. The decrease in the effective tax rate in 2011 is due primarily to the recognition of an $88 million income tax benefit due to the enactment of the Michigan Corporate Income Tax which is discussed below.

The Company had $4 million of unrecognized tax benefits at September 30, 2011 and $5 million at December 31, 2010, that, if recognized, would favorably impact its effective tax rate. The Company has increased its unrecognized tax benefit by $40 million in the nine months ended September 30, 2011, as a result of a change in a tax position taken during a prior period. During the next twelve months, it is reasonably possible that the Company will settle certain federal tax audits. As a result, the Company believes that it is possible that there will be a decrease in unrecognized tax benefits of up to $49 million.

Michigan Corporate Income Tax (MCIT)

On May 25, 2011, the Michigan Business Tax (MBT) was repealed and the MCIT was enacted and will become effective January 1, 2012. The MCIT subjects corporations with business activity in Michigan to a 6 percent tax rate on an apportioned income tax base and eliminates the modified gross receipts tax and nearly all credits available under the MBT. The MCIT also eliminated the future deductions allowed under MBT that enabled companies to establish a one-time deferred tax asset upon enactment of the MBT to offset deferred tax liabilities that resulted from enactment of the MBT.

Effective with the enactment of the MCIT in the second quarter of 2011, the net state deferred tax liability was remeasured to reflect the impact of the MCIT tax rate on cumulative temporary differences expected to reverse after the effective date. The net impact of this remeasurement was a decrease in deferred income tax liabilities of $41 million attributable to our regulated utilities that was offset against the regulatory asset established upon the enactment of the MBT.

Due to the elimination of the future tax deductions allowed under the MBT, the one-time MBT deferred tax asset that was established upon the enactment of the MBT has been remeasured to zero. The net impact of this remeasurement is a reduction of net deferred tax assets of $307 million, with $395 million of this decrease in deferred tax assets attributable to our regulated utilities, partially offset by an $88 million decrease in deferred tax liabilities attributable to our non-utility entities. The $395 million decrease in deferred tax assets at our regulated utilities was offset against the regulatory liabilities established upon enactment of the MBT. The $88 million is primarily due to a lower apportionment factor from inclusion of non-utility entities in DTE Energy’s unitary Michigan tax return. The $88 million was recognized as a reduction to income tax expense in the second quarter of 2011.

Consistent with the original establishment of these deferred tax liabilities (assets), no recognition of these non-cash transactions have been reflected in the Consolidated Statements of Cash Flows.

Offsetting Amounts Related to Certain Contracts

The Company offsets 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 agreement, which reduces both the Company’s total assets and total liabilities. As of September 30, 2011, the total cash collateral posted, net of cash collateral received, was $66 million. Derivative liabilities are shown net of collateral of $3 million. At September 30, 2011, the Company recorded cash collateral received of $1 million and cash collateral paid of $64 million not related to derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

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Segment Information (Details Textuals)	Sep. 30, 2011 banks customers years ratio employees
Entity Information [Line Items]
Number of Electric Utility Customers One	2,100,000
Number of Gas Utility Customers One	1,200,000
Number of Citizens Gas CustomersOne	17,000

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Fair Value (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Assets [Abstract]
Nuclear decommissioning trusts	$ 893	$ 939
Other investments	104	111
Derivative assets Abstract [Abstract]
Derivative Assets	1,165	1,258
Derivative Assets, Current	109	131
Derivative Assets, Noncurrent	59	77
Liabilities [Abstract]
Derivative Liabilities	(176)	(252)
Derivative Liabilities, Current	114	142
Derivative Liabilities, Noncurrent	62	110
Derivative Assets (Liabilities), at Fair Value, Net	989	1,006
Fair Value, Inputs, Level 1 [Member]
Assets [Abstract]
Nuclear decommissioning trusts	532	599
Other investments	48	56
Derivative assets Abstract [Abstract]
Derivative Assets	2,252	2,569
Derivative Assets, Current	1,251	1,299
Derivative Assets, Noncurrent	1,001	1,270
Liabilities [Abstract]
Derivative Liabilities	(1,630)	(1,907)
Derivative Liabilities, Current	(1,235)	(1,290)
Derivative Liabilities, Noncurrent	(395)	(617)
Derivative Assets (Liabilities), at Fair Value, Net	622	662
Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Exchange Contract [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,650	1,846
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1,616)	(1,844)
Fair Value, Inputs, Level 1 [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	22	68
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(14)	(63)
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instruments, Assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	1,672	1,914
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instruments, Liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(1,630)	(1,907)
Fair Value, Inputs, Level 2 [Member]
Assets [Abstract]
Nuclear decommissioning trusts	361	340
Other investments	56	55
Derivative assets Abstract [Abstract]
Derivative Assets	828	1,196
Derivative Assets, Current	322	663
Derivative Assets, Noncurrent	506	533
Liabilities [Abstract]
Derivative Liabilities	(473)	(955)
Derivative Liabilities, Current	(348)	(730)
Derivative Liabilities, Noncurrent	(125)	(225)
Derivative Assets (Liabilities), at Fair Value, Net	355	241
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Fair Value, Inputs, Level 2 [Member] | Foreign Exchange Contract [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	6	20
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(9)	(30)
Fair Value, Inputs, Level 2 [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	79	128
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(167)	(263)
Fair Value, Inputs, Level 2 [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	326	649
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(295)	(653)
Fair Value, Inputs, Level 2 [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	4
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(8)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instruments, Assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	411	801
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instruments, Liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(473)	(955)
Fair Value, Inputs, Level 3 [Member]
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets Abstract [Abstract]
Derivative Assets	91	133
Derivative Assets, Current	62	49
Derivative Assets, Noncurrent	29	84
Liabilities [Abstract]
Derivative Liabilities	(82)	(74)
Derivative Liabilities, Current	(60)	(21)
Derivative Liabilities, Noncurrent	(22)	(53)
Derivative Assets (Liabilities), at Fair Value, Net	9	59
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Exchange Contract [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	17	12
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(12)	(11)
Fair Value, Inputs, Level 3 [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	67	117
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(70)	(63)
Fair Value, Inputs, Level 3 [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	7	4
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	91	133
Fair Value, Inputs, Level 3 [Member] | Derivative Financial Instruments, Liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	(82)	(74)
Netting and Collateral [Member]
Assets [Abstract]
Nuclear decommissioning trusts	0	0
Other investments	0	0
Derivative assets Abstract [Abstract]
Derivative Assets	(2,006)	(2,640)
Derivative Assets, Current	(1,526)	(1,880)
Derivative Assets, Noncurrent	(480)	(760)
Liabilities [Abstract]
Derivative Liabilities	2,009	2,684
Derivative Liabilities, Current	1,529	1,899
Derivative Liabilities, Noncurrent	480	785
Derivative Assets (Liabilities), at Fair Value, Net	3	44
Netting and Collateral [Member] | Interest Rate Contract [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Netting and Collateral [Member] | Foreign Exchange Contract [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(6)	(20)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	6	20
Netting and Collateral [Member] | Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(1,698)	(1,960)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	1,698	1,955
Netting and Collateral [Member] | Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(282)	(589)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	285	643
Netting and Collateral [Member] | Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	(20)	(71)
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	20	66
Netting and Collateral [Member] | Derivative Financial Instruments, Assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	(2,006)	(2,640)
Netting and Collateral [Member] | Derivative Financial Instruments, Liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	2,009	2,684
Current Asset [Member]
Derivative assets Abstract [Abstract]
Derivative Assets, Current	109	131
Non Current Asset [Member]
Derivative assets Abstract [Abstract]
Derivative Assets, Noncurrent	1,056	1,127
Current Liability [Member]
Liabilities [Abstract]
Derivative Liabilities, Current	(114)	(142)
Noncurrent Liability [Member]
Liabilities [Abstract]
Derivative Liabilities, Noncurrent	(62)	(110)
Interest Rate Contract [Member]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(1)	(1)
Foreign Exchange Contract [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(3)	(10)
Natural Gas [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	48	26
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(97)	(163)
Electricity [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	111	177
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	(80)	(73)
Other [Member]
Derivative assets Abstract [Abstract]
Derivative Asset, Fair Value, Gross Asset	9	5
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	5	(5)
Derivative Financial Instruments, Assets [Member]
Derivative assets Abstract [Abstract]
Derivative Assets	168	208
Derivative Financial Instruments, Liabilities [Member]
Liabilities [Abstract]
Derivative Liabilities	$ (176)	$ (252)

XML

Regulatory Matters (Tables)

3 Months Ended

9 Months Ended

Mar. 31, 2011

Sep. 30, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Net Over Under Recovery Including Interest and Cost of Power Sold PSCR Reconcilation [Table Text Block]

The following table summarizes Detroit Edison’s PSCR reconciliation filing currently pending with the MPSC:

		Net Under-Recovery,		PSCR Cost of
		Including Interest		Power Sold
PSCR Year	Date Filed	(in Millions)		(in Billions)
2010	March 2011	$	52.6	$	1.2

Net Over Recover Including Interest and Cost of Gas Sold GCR Reconciliation [Table Text Block]

The following table summarizes MichCon’s GCR reconciliation filing currently pending with the MPSC:

		Net Over-Recovery,		GCR Cost of
		Including Interest		Gas Sold
GCR Year	Date Filed	(in Millions)		(in Billions)
2009-2010	June 2010	$	5.9	$	1.0
2010-2011	June 2011	$	1.0	$	0.7

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Short Term Credit Arrangements and Borrowings (Details Textuals) (USD $)	9 Months Ended	60 Months Ended
	Sep. 30, 2011 percent people years kWh Days weeks MCF banks customers ratio employees	Oct. 01, 2016 years banks customers ratio employees	Dec. 31, 2010
Short-term Debt [Line Items]
Revolving Credit Facilities with a Syndicate Number of Banks	23
Maximum Percentage of Commitment to Bank in any Facility	8.25%
Maximum Total Funded Debt to Total Capitalization Ratio	65.00%
Maximum Total Funded Debt to Total Capitilization Ration Denominator	100.00%
Letters of Credit Outstanding, Amount	$ 38,000,000
Line of Credit Facility, Current Borrowing Capacity	1,975,000,000
Renewal of Credit Facilities	1,800,000,000
Renewal of Credit Facility Time Period		5
Borrowing Capacity Under Financing Agreement With iss Clearing Agent	100,000,000
Maximum Additional Margin Financing	50,000,000
Line of Credit Facility, Increase, Additional Borrowings	15,000,000
Line of Credit Facility Current Borrowing	115,000,000
Other Short-term Borrowings	4,000,000		39,000,000
Parent [Member] | Unsecured Revolving Facility 1 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	538,000,000
Subsidiary 1 [Member] | Unsecured Revolving Facility 1 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	212,000,000
Subsidiary 2 [Member] | Unsecured Revolving Facility 1 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	250,000,000
Unsecured Revolving Facility 1 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	1,000,000,000
Parent [Member] | Unsecured Revolving Facility 2 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	562,000,000
Subsidiary 1 [Member] | Unsecured Revolving Facility 2 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	63,000,000
Subsidiary 2 [Member] | Unsecured Revolving Facility 2 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	175,000,000
Unsecured Revolving Facility 2 [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	800,000,000
Parent [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	49.00%
Total Funded Debt to Total Capitalization Ratio Denomenatory	100.00%
Line of Credit Facility, Current Borrowing Capacity	1,275,000,000
Subsidiary 1 [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	52.00%
Total Funded Debt to Total Capitalization Ratio Denomenatory	100.00%
Line of Credit Facility, Current Borrowing Capacity	275,000,000
Subsidiary 2 [Member]
Short-term Debt [Line Items]
Total Funded Debt to Total Capitalization Ratio	47.00%
Total Funded Debt to Total Capitalization Ratio Denomenatory	100.00%
Line of Credit Facility, Current Borrowing Capacity	$ 425,000,000

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Segment Information (Details2) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	$ 2,265	$ 2,139	$ 6,724	$ 6,384
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	183	163	561	478
Electric Utility [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	1,517	1,444	3,950	3,798
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	157	165	345	343
Gas Utility [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	159	170	1,090	1,157
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	(11)	(6)	69	92
Gas Storage and Pipelines [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	21	20	69	62
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	13	12	42	36
Unconventional Gas Production [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	11	7	29	23
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	(2)	(4)	(5)	(9)
Power and Industrial Projects [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	259	303	781	846
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	12	26	27	66
Energy Trading [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	342	258	970	661
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	22	(12)	36	0
Corporate and Other [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	0	0	2	0
Segment Reporting Information, Profit (Loss) [Abstract]
Net Income (Loss) Attributable to Parent	(8)	(18)	47	(50)
Corporate Elimination [Member]
Revenues [Abstract]
Segment Reporting Information, Revenue for Reportable Segment	$ (44)	$ (63)	$ (167)	$ (163)

XML

Long Term Debt (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Jun. 30, 2011	Sep. 30, 2011
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Basis for Effective Rate	Variable(5)
Debt Instrument, Face Amount		$ 1,028
Tax Exempt Revenue Bonds [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.35%
Debt Instrument, Face Amount	31
Mortgages2 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.50%
Debt Instrument, Face Amount		140
Mortgages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.90%	4.31%
Debt Instrument, Face Amount	250	102
Senior Notes1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	300
Mortages [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.46%
Debt Instrument, Face Amount		77
Mortgages1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.67%
Debt Instrument, Face Amount		46
Tax-Exempt Revenue Bonds1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.95%	2.13%
Debt Instrument, Face Amount		$ 82

XML

Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2011

STOCK-BASED COMPENSATION [Abstract]

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

The following table summarizes the components of stock-based compensation expense:

	Three Months Ended
	September 30
(in Millions)	2011		2010
Stock-based compensation expense	$	13	$	9
Tax benefit	5		4
Stock-based compensation cost capitalized in property, plant and equipment	1		1

	Nine Months Ended
	September 30
(in Millions)	2011		2010
Stock-based compensation expense	$	42	$	38
Tax benefit	16		15
Stock-based compensation cost capitalized in property, plant and equipment	3		2

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

The following table summarizes our stock option activity for the nine months ended September 30, 2011:

	Number of Options		Weighted Average Exercise Price Per Share		(in Millions) Aggregate Intrinsic Value
Options outstanding at January 1, 2011	4,827,457		$	41.09
Granted	—		$	—
Exercised	(1,541,690	)	$	40.52
Forfeited or expired	(21,963	)	$	43.41
Options outstanding at September 30, 2011	3,263,804		$	41.34	$	26
Options exercisable at September 30, 2011	2,597,318		$	42.30	$	18

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

The following summarizes stock awards activity for the nine months ended September 30, 2011:

	Restricted Stock		Weighted Average Grant Date Fair Value Per Share
Balance at January 1, 2011	757,414		$	37.32
Grants	381,840		$	47.98
Forfeitures	(65,592	)	$	40.84
Vested and issued	(339,138	)	$	38.25
Balance at September 30, 2011	734,524		$	42.22

Summary of Performance Share Activity [Table Text Block]

The following summarizes performance share activity for the nine months ended September 30, 2011:

	Performance Shares
Balance at January 1, 2011	1,527,253
Grants	611,844
Forfeitures	(66,357	)
Payouts	(467,688	)
Balance at September 30, 2011	1,605,052

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Significant Accounting Policies (Details Textuals 2) (USD $) In Millions	Sep. 30, 2011
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 66
Cash Collateral Paid or Received for Derivative Liabilities	3
Cash Collateral Received	1
Cash Collateral Paid	$ 64

XML

Long Term Debt (Tables)

9 Months Ended

Sep. 30, 2011

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

In 2011, the Company remarketed or issued the following long-term debt:

(in Millions)

Company	Month Issued	Type	Interest Rate		Maturity	Amount
Detroit Edison	April	Tax-Exempt Revenue Bonds(1)(2)	2.35	%	2024	$	31
Detroit Edison	May	Mortgage Bonds(3)	3.90	%	2021	250
DTE Energy	May	Senior Notes(4)	Variable(5)		2013	300
Detroit Edison	September	Mortgage Bonds(6)	4.31	%	2023	102
Detroit Edison	September	Mortgage Bonds(6)	4.46	%	2026	77
Detroit Edison	September	Mortgage Bonds(6)	5.67	%	2041	46
Detroit Edison	September	Tax-Exempt Revenue Bonds(2)(7)	2.13	%	2030	82
Detroit Edison	September	Mortgage Bonds (8)	4.50	%	2041	140
						$	1,028

Schedule of Extinguishment of Debt [Table Text Block]

In 2011, the following debt was retired:

(in Millions)

Company	Month Retired	Type	Interest Rate		Maturity	Amount
Detroit Edison	May	Tax-Exempt Revenue Bonds	6.95	%	2011	$	26
DTE Energy	June	Senior Notes	7.05	%	2011	600
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.55	%	2029	118
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65	%	2029	67
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65	%	2029	40
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.45	%	2029	140
						$	991

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to the EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, the EPA and the State of Michigan have issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The rules have led 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 $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of approximately $200 million in 2011 and up to $2 billion of additional capital expenditures through 2020 based on current regulations. Further, additional rulemakings are expected over the next few years which could require additional controls for sulfur dioxide, nitrogen oxides and hazardous air pollutants. The EPA’s proposed National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric Utility Steam Generating Units rule (covering mercury and other air pollutants) was issued on March 16, 2011 for review and comment. The EPA accepted comments on the proposal and may modify it prior to finalization, scheduled for November 2011. Also, on July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which replaces the Clean Air Interstate Rule (CAIR), requiring further reductions of sulfur dioxides and nitrogen oxides. DTE Energy is reviewing potential impacts of the proposed and recently finalized rules, but is not able to quantify the financial impact of these and other expected rulemakings at this time.

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (NOV/FOV) from the EPA alleging, among other things, that five Detroit Edison power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. An additional NOV/FOV was received in June 2010 related to a recent project and outage at Unit 2 of the Monroe Power Plant.

On August 5, 2010, the United States Department of Justice, at the request of the EPA, brought a civil suit in the U.S. District Court for the Eastern District of Michigan against DTE Energy and Detroit Edison, related to the June 2010 NOV/FOV and the outage work performed at Unit 2 of the Monroe Power Plant, but not relating to the July 2009 NOV/FOV. Among other relief, the EPA requested the court to require Detroit Edison to install and operate the best available control technology at Unit 2 of the Monroe Power Plant. Further, the EPA requested the court to issue a preliminary injunction to require Detroit Edison to (i) begin the process of obtaining the necessary permits for the Monroe Unit 2 modification and (ii) offset the pollution from Monroe Unit 2 through emissions reductions from Detroit Edison’s fleet of coal-fired power plants until the new control equipment is operating. In January 2011, the EPA’s motion for preliminary injunction was denied. On August 23, 2011, the U.S. District judge granted DTE Energy's motion for summary judgment in the civil case, dismissing the case and entering judgment in favor of DTE Energy and Detroit Edison. On October 20, 2011, the EPA caused to be filed a Notice of Appeal to the U.S. Court of Appeals for the Sixth Circuit.

DTE Energy and Detroit Edison believe that the plants identified by the EPA, including Unit 2 of the Monroe Power Plant, have complied with all applicable federal environmental regulations. Depending upon the outcome of discussions with the EPA regarding the NOV/FOV, Detroit Edison could also be required to install additional pollution control equipment at some or all of the power plants in question, implement early retirement of facilities where control equipment is not economical, engage in supplemental environmental programs, and/or pay fines. DTE Energy and Detroit Edison cannot predict the financial impact or outcome of these matters, or the timing of its resolution.

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 completed studies and expected future studies, 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 $80 million in additional capital expenditures over the 4 to 6 years subsequent to 2008 to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that has resulted 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 and in April 2009 upheld the EPA’s use of this provision in determining best technology available for reducing environmental impacts. On April 20, 2011, the EPA published a proposed rule. A final rule is scheduled to be issued in mid-2012. The EPA has also issued an information collection request to begin a review of steam electric effluent guidelines. It is not possible at this time to quantify the financial impacts of these developing requirements.

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. The facilities, which produced gas, have been designated as manufactured gas plant (MGP) sites. Detroit Edison conducted remedial investigations at contaminated sites, including three former MGP sites. The 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, including the area surrounding an ash landfill, electrical distribution substations, and 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 September 30, 2011 and December 31, 2010, the Company had $8 million and $9 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.

Landfill — Detroit Edison owns and operates a permitted engineered ash storage facility at the Monroe Power Plant to dispose of fly ash from the coal fired power plant. Detroit Edison performed an engineering analysis in 2009 and identified the need for embankment side slope repairs and reconstruction. Those repairs are ongoing and are expected to be completed by 2013.

The EPA has published proposed rules to regulate coal ash under the authority of the Resources Conservation and Recovery Act (RCRA). The proposed rule published on June 21, 2010 contains two primary regulatory options to regulate coal ash residue. The EPA is currently considering either designating coal ash as a “Hazardous Waste” as defined by RCRA or regulating coal ash as non-hazardous waste under RCRA. Agencies and legislatures have urged the EPA to regulate coal ash as a non-hazardous waste. If the EPA designates coal ash as a hazardous waste, the agency could apply some, or all, of the disposal and reuse standards that have been applied to other existing hazardous wastes to disposal and reuse of coal ash. Some of the regulatory actions currently being contemplated could have a significant impact on our operations and financial position and the rates we charge our customers. It is not possible to quantify the financial impact of those expected rulemakings at this time.

Gas Utility

Contaminated Sites — Gas Utility owns, or previously owned, 15 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. As of September 30, 2011 and December 31, 2010, the Company had $41 million and $36 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. The Company anticipates the cost amortization methodology approved by the MPSC for MichCon, which allows MichCon to amortize the MGP costs over a 10-year period beginning with the year subsequent to the year the MGP costs were incurred, and the cost deferral and rate recovery mechanism for Citizens approved by the City of Adrian, will prevent environmental costs from having a material adverse impact on the Company’s 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 Michigan coke battery facility received and responded to information requests from the EPA that resulted in the issuance of a Notice of Violation in June of 2007 alleging 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 financial impact of this issue. Furthermore, the Michigan coke battery facility is the subject of an investigation by the MDEQ concerning visible emissions readings that resulted from the Company self reporting to MDEQ questionable activities by an employee of a contractor hired by the Company to perform the visible emissions readings. At this time, the Company cannot predict the financial impact of this investigation.

In April 2006, the prior owners of the coke battery facility in Pennsylvania that the Company purchased in 2008 received a Notice of Violation/Finding of Violation from the EPA alleging violations of the lowest achievable emission rate requirements associated with visible emissions from the combustion stack, door leaks and charging activities at the coke battery facility. The EPA has also alleged certain violations of the Clean Water Act, but has not issued a notice of violation in connection with these alleged violations. The Company is in the process of negotiating a Consent Order with the EPA to settle these historic air and water issues. The Company expects to enter into the Consent Order during the fourth quarter of 2011.

The Company received two Notices of Violation from the Pennsylvania Department of Environmental Protection in 2010 alleging violations of the permit for the Pennsylvania coke battery facility in connection with coal pile storm water runoff. The Company has implemented best management practices to address this issue and is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment facility. The Company expects to spend less than $1.5 million on the existing waste water treatment system to comply with existing water discharge requirements and to upgrade its coal pile storm water runoff management program. The Company may spend an additional $13 million over the next few years to meet future regulatory requirements and gain other operational improvements savings.

The Company believes that its non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Other

In March 2011, the EPA finalized a new set of regulations regarding the identification of non-hazardous secondary materials that are considered solid waste, industrial boiler and process heater maximum achievable control technologies (IBMACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines (CISWI). Both IBMACT and CISWI regulations were stayed and a re-proposal is expected by the end of 2011. The re-proposed rules may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The re-proposed regulations will provide a minimum period of three years for compliance with the applicable standards. Based on the final approved regulations, anticipated in the first half of 2012, the Company will assess the financial impact, if any, on current operations for compliance with the applicable new standards.

In February 2008, DTE Energy was named as one of approximately 24 defendant oil, power and coal companies in a lawsuit filed in a United States District Court. DTE Energy was served with process in March 2008. The plaintiffs, the Native Village of Kivalina and City of Kivalina, which are home to approximately 400 people in Alaska, claim that the defendants’ business activities have contributed to global warming and, as a result, higher temperatures are damaging the local economy and leaving the island more vulnerable to storm activity in the fall and winter. As a result, the plaintiffs are seeking damages of up to $400 million for relocation costs associated with moving the village to a safer location, as well as unspecified attorney’s fees and expenses. On October 15, 2009, the U.S. District Court granted defendants’ motions dismissing all of plaintiffs’ federal claims in the case on two independent grounds: (1) the court lacks subject matter jurisdiction to hear the claims because of the political question doctrine; and (2) plaintiffs lack standing to bring their claims. The court also dismissed plaintiffs’ state law claims because the court lacked supplemental jurisdiction over them after it dismissed the federal claims; the dismissal of the state law claims was without prejudice. The plaintiffs have appealed to the U.S. Court of Appeals for the Ninth Circuit.

Nuclear Operations

Property Insurance

Detroit Edison maintains 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 $29 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 of January 1, 2011, as required by federal law, Detroit Edison maintains $375 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.

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 accounted for as 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 and the proposed fiscal year 2011 federal budget recommends termination of funding for completion of the government’s long-term storage facility. 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 spent nuclear fuel storage strategy utilizing a fuel pool. The Company continues to develop its on-site dry cask storage facility and has postponed the initial offload from the spent fuel pool until 2013. The dry cask storage facility is expected to provide sufficient spent fuel storage capability for the life of the plant as defined by the original operating license. Issues relating to long-term waste disposal policy and to the disposition of funds contributed by Detroit Edison ratepayers to the federal waste fund await future governmental action.

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. The Company’s guarantees are not individually material with maximum potential payments totaling $10 million at September 30, 2011.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of September 30, 2011, the Company had approximately $14 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 the Company’s approximately 5,000 represented employees. In the 2011 second quarter, a new three-year agreement was ratified covering approximately 400 represented employees. The majority of the remaining represented employees are under contracts that expire August 2012 and June and October 2013.

Purchase Commitments

As of September 30, 2011, 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 billion from 2011 through 2051.

The Company also estimates that 2011 capital expenditures will be approximately $1.7 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, financial and other industries. Certain of its 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 records provisions for amounts considered at risk of probable loss. The Company believes its accrued amounts are adequate for probable loss. The final resolution of these matters may have a material effect on its consolidated financial statements.

Other Contingencies

The Company is involved in certain other 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 that 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 Notes 4 and 6 for a discussion of contingencies related to derivatives and regulatory matters.

XML

Regulatory Matters (Details Textuals) (USD $)	3 Months Ended	6 Months Ended	9 Months Ended		48 Months Ended
	Mar. 31, 2011	Jun. 30, 2011	Sep. 30, 2011 percent people years kWh Days weeks MCF	Sep. 30, 2011 Electric Utility [Member]	Dec. 31, 2015 Gas Utility [Member]
Reglatory Asset and Liability [Line Items]
MPSC Approved Annual Rate Increase			$ 175,000,000
MPSC Approved Return on Equity			10.50%
Expected Permanent Capital Structure Equity Percent			49.20%
Expected Permanent Capital Structure Debt Percent			50.80%
Self Implemented Rate Increase		107,000,000
Period for Report to MPSC on Revenues Collected Through Self Implemented Rate Increase			90
Amount of Credit to CIM Regulatory Asset			31,000,000
Annual Revenue Decoupling Mechanism Collar on Surcharge and Refund Year 1			1.50%
Annual Revenue Decoupling Mechanism Collar on Surcharge and Refund Year 2 and Subsequent Years			3.00%
To Reduce Nuclear Decommisssioning Surcharge Annually			20,000,000
Requesting Authority to Refund Uncollectible Expense to Customers	7,000,000
MPSC Authorized Refund to Customer Bills			7,000,000
Requested Recovery of Restoration Expenses	19,500,000
MPSC Authorized Surcharges to Recover Restoration Expenses			19,500,000
Requested Authority to Refund Revenue Decoupling Mechanism		56,000,000
Possible Refund Calculations for Revenue Decoupling Mechanism Maximum			71,000,000
Under Recovery for the Pension Equalization Mechanism			7,100,000
Overy Recovery on Refund for Self Implemented Rates			3,800,000
Net Over Recovery of Power Supply Cost Recovery Expense			15,600,000
Power Supply Cost Recovery Plan Case Factor Current Year			2.98
Power Supply Cost Recovery Expense Forecast For Current Year			1,200,000,000
Power Supply Cost Recovery Under Collection One Year Prior			36,000,000
Power Supply cost Recovery Plan Case Factor Next Year			4.18
Power Supply Cost Recovery Expense Forecast Next Year			1,400,000,000
Projected Power Supply Cost Recovery Under Recovery for Current Year			158,000,000
Requested Recovery of Enery Optimization Expenses for Future Period				$ 294,000,000	$ 103,000,000

XML

Stock Based Compensation (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Schedule of Stock Based Compensation [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4.42
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 56
Non Vested Stock Options	666,486
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Number	687,061
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1.27
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	14
Stock or Unit Option Plan Expense	$ 1	$ 3

XML

Earnings Per Share (Details Textuals) In Millions	9 Months Ended
	Sep. 30, 2010
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0.4

XML

Fair Value

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

FAIR VALUE

FAIR VALUE

Fair value is defined 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 was immaterial at September 30, 2011 and December 31, 2010.

The Company believes it uses valuation techniques that maximize the use of observable market-based inputs and minimize the use of unobservable inputs.

A fair value hierarchy has been established, that 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. All assets and liabilities are required to 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 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 September 30, 2011:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			September 30, 2011
Assets:
Nuclear decommissioning trusts	$	532		$	361		$	—		$	—		$	893
Other investments(1)	48			56			—			—			104
Derivative assets:
Foreign currency exchange contracts	—			6			—			(6		)	—
Commodity Contracts:
Natural Gas	1,650			79			17			(1,698		)	48
Electricity	—			326			67			(282		)	111
Other	22			—			7			(20		)	9
Total derivative assets	1,672			411			91			(2,006		)	168
Total	$	2,252		$	828		$	91		$	(2,006	)	$	1,165
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(9	)	$	—		$	6		$	(3	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,616		)	(167		)	(12		)	1,698			(97		)
Electricity	—			(295		)	(70		)	285			(80		)
Other	(14		)	(1		)	—			20			5
Total derivative liabilities	(1,630		)	(473		)	(82		)	2,009			(176		)
Total	$	(1,630	)	$	(473	)	$	(82	)	$	2,009		$	(176	)
Net Assets as of September 30, 2011	$	622		$	355		$	9		$	3		$	989
Assets:
Current	$	1,251		$	322		$	62		$	(1,526	)	$	109
Noncurrent(3)	1,001			506			29			(480		)	1,056
Total Assets	$	2,252		$	828		$	91		$	(2,006	)	$	1,165
Liabilities:
Current	$	(1,235	)	$	(348	)	$	(60	)	$	1,529		$	(114	)
Noncurrent	(395		)	(125		)	(22		)	480			(62		)
Total Liabilities	$	(1,630	)	$	(473	)	$	(82	)	$	2,009		$	(176	)
Net Assets as of September 30, 2011	$	622		$	355		$	9		$	3		$	989

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2010:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			December 31, 2010
Assets:
Nuclear decommissioning trusts	$	599		$	340		$	—		$	—		$	939
Other investments(1)	56			55			—			—			111
Derivative assets:
Foreign currency exchange contracts	—			20			—			(20		)	—
Commodity Contracts:
Natural Gas	1,846			128			12			(1,960		)	26
Electricity	—			649			117			(589		)	177
Other	68			4			4			(71		)	5
Total derivative assets	1,914			801			133			(2,640		)	208
Total	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(30	)	$	—		$	20		$	(10	)
Interest rate contracts	—			(1		)	—			—			(1		)
Commodity Contracts:
Natural Gas	(1,844		)	(263		)	(11		)	1,955			(163		)
Electricity	—			(653		)	(63		)	643			(73		)
Other	(63		)	(8		)	—			66			(5		)
Total derivative liabilities	(1,907		)	(955		)	(74		)	2,684			(252		)
Total	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006
Assets:
Current	$	1,299		$	663		$	49		$	(1,880	)	$	131
Noncurrent(3)	1,270			533			84			(760		)	1,127
Total Assets	$	2,569		$	1,196		$	133		$	(2,640	)	$	1,258
Liabilities:
Current	$	(1,290	)	$	(730	)	$	(21	)	$	1,899		$	(142	)
Noncurrent	(617		)	(225		)	(53		)	785			(110		)
Total Liabilities	$	(1,907	)	$	(955	)	$	(74	)	$	2,684		$	(252	)
Net Assets as of December 31, 2010	$	662		$	241		$	59		$	44		$	1,006

_____________________________

(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.

(3) Includes $104 million and $111 million at September 30, 2011 and December 31, 2010, respectively, of other investments that are included in the Consolidated Statements of Financial Position in Other Investments.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30, 2011
(in Millions)	Natural Gas			Electricity			Other		Total
Net Assets as of July 1, 2011	$	1		$	57		$	7	$	65
Transfers into Level 3	(1		)	(6		)	—		(7		)
Transfers out of Level 3	—			(42		)	—		(42		)
Total gains or (losses):
Included in earnings	6			23			—		29
Purchases, issuances, sales and settlements:
Settlements	(1		)	(35		)	—		(36		)
Net Assets (Liabilities) as of September 30, 2011	$	5		$	(3	)	$	7	$	9
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2011	$	6		$	5		$	—	$	11

	Three Months Ended September 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of July 1, 2010	$	2		$	155		$	4		$	161
Changes in fair value recorded in income	3			21			1			25
Purchases, issuances and settlements	(1		)	(29		)	(1		)	(31		)
Transfers in/out of Level 3	—			(22		)	—			(22		)
Net Assets as of September 30, 2010	$	4		$	125		$	4		$	133
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2010	$	2		$	(4	)	$	1		$	(1	)

	Nine Months Ended September 30, 2011
(in Millions)	Natural Gas		Electricity			Other			Total
Net Assets as of January 1, 2011	$	1	$	54		$	4		$	59
Transfers into Level 3	—		(4		)	—			(4		)
Transfers out of Level 3	1		(25		)	—			(24		)
Total gains or (losses):
Included in earnings	3		34			2			39
Recorded in regulatory assets/liabilities	—		—			3			3
Purchases, issuances, sales and settlements:
Purchases	—		1			—			1
Settlements	—		(63		)	(2		)	(65		)
Net Assets (Liabilities) as of September 30, 2011	$	5	$	(3	)	$	7		$	9
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2011	$	5	$	17		$	2		$	24

	Nine Months Ended September 30, 2010
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of January 1, 2010	$	2		$	19		$	3		$	24
Changes in fair value recorded in income	4			117			1			122
Changes in fair value recorded in regulatory assets/liabilities	—			—			4			4
Purchases, issuances and settlements	(6		)	(59		)	(4		)	(69		)
Transfers in/out of Level 3	4			48			—			52
Net Assets as of September 30, 2010	$	4		$	125		$	4		$	133
The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2010	$	(2	)	$	58		$	1		$	57

Transfers in and transfers out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level and 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 and transfers out of Level 3 are reflected as if they had occurred at the beginning of the period. For the three and nine months ended September 30, 2011, $42 million and $25 million, respectively, of net assets reflecting inputs related to certain power transactions identified as observable due to available broker quotes were transferred from Level 3 to Level 2. For the three and nine months ended September 30, 2011, $6 million and $4 million, respectively, of net assets reflecting inputs related to certain power transactions identified as unobservable due to lack of available broker quotes were transferred from Level 2 to Level 3.

Transfers from Level 3 to Level 2 of $22 million reflect inputs related to certain power transactions identified as observable due to available broker quotes for the three months ended September 30, 2010. Transfers from Level 2 to Level 3 of $48 million reflect inputs related to certain power transactions identified as unobservable due to lack of available broker quotes for the nine months ended September 30, 2010. No significant transfers between Levels 1 and 2 occurred in the three and nine months ended September 30, 2011 and 2010.

Nuclear Decommissioning Trusts and Other Investments

The nuclear decommissioning trusts and other 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 in actively traded markets. The commingled funds and institutional mutual funds which hold exchange-traded equity or debt securities are valued based on the underlying securities, using quoted prices in actively traded markets. Non-exchange-traded fixed income securities are valued based upon quotations available from brokers or 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 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. DTE Energy considers the following criteria in determining whether a market is considered active: frequency in which pricing information is updated, variability in pricing between sources or over time and the availability of public information. Other derivative contracts are valued based upon a variety of inputs including commodity market prices, broker quotes, interest rates, credit ratings, default rates, market-based seasonality and basis differential factors. DTE Energy monitors the prices that are supplied by brokers and pricing services and may use a supplemental price source or change the primary price source of an index if prices become unavailable or another price source is determined to be more representative of fair value. DTE Energy has obtained an understanding of how these prices are derived. Additionally, DTE Energy selectively corroborates the fair value of its transactions by comparison of market-based price sources. 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.

Fair Value of Financial Instruments

The fair value of long-term debt is determined by using quoted market prices when available and a discounted cash flow analysis based upon estimated current borrowing rates when quoted market prices are not available. The table below shows the fair value and the carrying value for long-term debt securities. Certain other financial instruments, such as notes payable, customer deposits and notes receivable are not shown as carrying value approximates fair value. See Note 4 for further fair value information on financial and derivative instruments.

	September 30, 2011				December 31, 2010
(in Billions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-Term Debt	$	8.8	$	7.7	$	8.5	$	8.0

Nuclear Decommissioning Trust Funds

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. See Note 5.

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.

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:

	September 30,		December 31,
(in Millions)	2011		2010
Fermi 2	$	858	$	910
Fermi 1	3		3
Low level radioactive waste	32		26
Total	$	893	$	939

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:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Realized gains	$	8		$	8		$	34		$	29
Realized losses	(9		)	(6		)	(26		)	(25		)
Proceeds from sales of securities	10			51			69			179

Realized gains and losses from the sale of securities for the Fermi 2 and the low level radioactive waste funds are recorded to the Regulatory asset and Nuclear decommissioning liability. The following table sets forth the fair value and unrealized gains for the nuclear decommissioning trust funds:

	Fair		Unrealized
(in Millions)	Value		Gains
As of September 30, 2011
Equity securities	$	485	$	52
Debt securities	395		22
Cash and cash equivalents	13		—
	$	893	$	74
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities	361		11
Cash and cash equivalents	6		—
	$	939	$	88

The debt securities at September 30, 2011 and December 31, 2010 had an average maturity of approximately 7 and 6 years, respectively. 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.

Unrealized losses incurred by the Fermi 2 trust are recognized as a Regulatory asset. Detroit Edison recognized $87 million and $26 million of unrealized losses as Regulatory assets at September 30, 2011 and December 31, 2010, 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, unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no unrealized losses recognized for the three and nine months ended September 30, 2011 and September 30, 2010 for Fermi 1 trust assets.

Other Available-For-Sale Securities

The following table summarizes the fair value of the Company’s investment in available-for-sale debt and equity securities, excluding nuclear decommissioning trust fund assets:

	September 30, 2011				December 31, 2010
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	85	$	85	$	133	$	133
Equity securities	5		5		6		6

As of September 30, 2011, these securities were comprised primarily of money-market funds and equity securities. During the nine months ended September 30, 2011 and 2010, no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the period. Gains (losses) related to trading securities held at September 30, 2011 and September 30, 2010 were $(3) million and $3 million, respectively.

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2011

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

The following table details the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows, and supplementary non-cash information:

	Nine Months Ended
	September 30
(in Millions)	2011			2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	181		$	357
Inventories	(115		)	(200		)
Accrued/prepaid pensions	(186		)	(99		)
Accounts payable	(34		)	(14		)
Income taxes receivable/payable	267			19
Derivative assets and liabilities	(36		)	(58		)
Postretirement obligation	(59		)	20
Other assets	67			(11		)
Other liabilities	(37		)	59
	$	48		$	73
Noncash financing activities:
Common stock issued for employee benefit plans	$	1		$	147

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Short-Term Credit Arrangements and Borrowings (Details) (USD $) In Millions	Sep. 30, 2011
Availability under combined facilities
Total credit facilities at September 30, 2011	$ 1,975
Amounts Outstanding
Commercial paper issuances	275
Letters of credit outstanding at September 30, 2011	144
Total amounts outstanding	419
Net availability at September 30, 2011	1,556
DTE Energy [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	1,275
Amounts Outstanding
Commercial paper issuances	126
Letters of credit outstanding at September 30, 2011	144
Total amounts outstanding	270
Net availability at September 30, 2011	1,005
DTE Energy [Member] | Unsecured Revolving Facility 1 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	538
DTE Energy [Member] | Unsecured Revolving Facility 2 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	562
DTE Energy [Member] | Unsecured Revolving Facility 3 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	50
DTE Energy [Member] | Unsecured Revolving Facility 4 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	125
Subsidiary 1 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	275
Amounts Outstanding
Commercial paper issuances	49
Letters of credit outstanding at September 30, 2011	0
Total amounts outstanding	49
Net availability at September 30, 2011	226
Subsidiary 1 [Member] | Unsecured Revolving Facility 1 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	212
Subsidiary 1 [Member] | Unsecured Revolving Facility 2 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	63
Subsidiary 1 [Member] | Unsecured Revolving Facility 3 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	0
Subsidiary 1 [Member] | Unsecured Revolving Facility 4 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	0
Subsidiary 2 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	425
Amounts Outstanding
Commercial paper issuances	100
Letters of credit outstanding at September 30, 2011	0
Total amounts outstanding	100
Net availability at September 30, 2011	325
Subsidiary 2 [Member] | Unsecured Revolving Facility 1 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	250
Subsidiary 2 [Member] | Unsecured Revolving Facility 2 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	175
Subsidiary 2 [Member] | Unsecured Revolving Facility 3 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	0
Subsidiary 2 [Member] | Unsecured Revolving Facility 4 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	0
Unsecured Revolving Facility 1 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	1,000
Unsecured Revolving Facility 2 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	800
Unsecured Revolving Facility 3 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	50
Unsecured Revolving Facility 4 [Member]
Availability under combined facilities
Total credit facilities at September 30, 2011	$ 125

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Long-Term Debt (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended			3 Months Ended
	Jun. 30, 2011	Jun. 30, 2011 Tax-Exempt Revenue Bonds1 [Member]	Sep. 30, 2011 Tax-Exempt Revenue Bonds1 [Member]	Sep. 30, 2011 Tax-Exempt Revenue Bonds2 [Member]	Sep. 30, 2011 Tax-Exempt Revenue Bonds3 [Member]	Sep. 30, 2011 Tax Exempt Revenue Bonds 5 [Member]	Jun. 30, 2011 Senior Notes2 [Member]	Sep. 30, 2011 Tax-Exempt Revenue Bonds4 [Member]
Extinguishment of Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.95%	2.13%	5.65%	5.65%	5.55%	7.05%	5.45%
Extinguishment of Debt, Amount	$ 991	$ 26		$ 67	$ 40	$ 118	$ 600	$ 140

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Significant Accounting Policies (Details Textuals) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Finite-Lived Intangible Assets [Line Items]
Intangible Assets Emission Allowance	$ 9	$ 9
Intangible Assets Renewable Energy Credits	26	17
Gross Carrying amount of accumulated amortization of intangible assets	65	63
Accumulated amortization of intangible assets	$ 26	$ 22
Finite Lived Intangible Assets Useful Life Minimum	4
Finite Lived Intangible Assets Useful Life Maximum	30

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Stock Based Compensation (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 13	$ 9	$ 42	$ 38
Tax benefit	5	4	16	15
Stock-based compensation cost capitalized in property, plant and equipment	$ 1.0	$ 1.0	$ 3.0	$ 2.0

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share, Basic and Diluted [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Three Months				Nine Months
	Ended September 30				Ended September 30
(in Millions, except per share amounts)	2011		2010		2011		2010
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	183	$	163	$	561	$	478
Average number of common shares outstanding	169		169		169		168
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	99	$	94	$	293	$	271
Dividends declared — net restricted shares	—		1		1		1
Total distributed earnings	$	99	$	95	$	294	$	272
Net income less distributed earnings	$	84	$	68	$	267	$	206
Distributed (dividends per common share)	0.59		0.56		$	1.74	$	1.62
Undistributed	0.49		0.41		1.57		1.23
Total Basic Earnings per Common Share	$	1.08	0.97		$	3.31	$	2.85
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	183	$	163	$	561	$	478
Average number of common shares outstanding	169		169		169		168
Average incremental shares from assumed exercise of options	1		1		1		—
Common shares for dilutive calculation	170		170		170		168
Weighted average net restricted shares outstanding	1		1		1		1
Dividends declared — common shares	$	99	$	94	$	293	$	271
Dividends declared — net restricted shares	—		1		1		1
Total distributed earnings	$	99	$	95	$	294	$	272
Net income less distributed earnings	$	84	$	68	$	267	$	206
Distributed (dividends per common share)	$	0.59	$	0.56	$	1.74	$	1.62
Undistributed	0.48		0.40		1.56		1.22
Total Diluted Earnings per Common Share	$	1.07	$	0.96	$	3.30	$	2.84

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Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Operating Activities
Net Income	$ 563	$ 483
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization	752	775
Deferred income taxes	123	173
Assets losses, reserves and impairments, net	0	5
Changes in assets and liabilities, exclusive of changes shown separately (Note 13)	48	73
Net cash from operating activities	1,486	1,509
Investing Activities
Plant and equipment expenditures — utility	(968)	(743)
Plant and equipment expenditures — non-utility	(61)	(75)
Proceeds from sale of assets	13	28
Restricted cash for debt redemption, principally Securitization	47	33
Proceeds from sale of nuclear decommissioning trust fund assets	69	179
Investment in nuclear decommissioning trust funds	(97)	(204)
Consolidation of VIEs	0	19
Investment in Millennium Pipeline Project	0	(49)
Other	(55)	(22)
Net cash used for investing activities	(1,052)	(834)
Financing Activities
Issuance of long-term debt, net	908	595
Redemption of long-term debt	(1,161)	(660)
Short-term borrowings	126	(307)
Issuance of common stock	0	26
Repurchase of common stock	(18)	0
Dividends on common stock	(289)	(265)
Other	(19)	(32)
Net cash used for financing activities	(453)	(643)
Net Increase (Decrease) in Cash and Cash Equivalents	(19)	32
Cash and Cash Equivalents at Beginning of Period	65	52
Cash and Cash Equivalents at End of Period	$ 46	$ 84

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Segment Information

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

The Company sets strategic goals, allocates resources and evaluates performance based on the following structure:

Electric Utility segment consists principally of Detroit Edison, which is engaged in the generation, purchase, distribution and sale of electricity to approximately 2.1 million customers in southeastern Michigan.

Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transportation, distribution and sale of natural gas to approximately 1.2 million customers throughout Michigan and the sale of storage and transportation capacity. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Gas Storage and Pipelines consists of natural gas pipeline, gathering and storage businesses.

Unconventional Gas Production is engaged in unconventional gas and oil project development and production.

Power and Industrial Projects is comprised of coke batteries and pulverized coal projects, reduced emission fuel and steel industry fuel-related projects, on-site energy services, renewable power generation, landfill gas recovery and coal transportation, marketing and trading.

Energy Trading consists of energy marketing and trading operations.

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

The federal 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 if applicable. The MBT provision of the utility subsidiaries is determined on an individual company basis and recognizes the tax benefit of various tax credits and net operating losses if applicable. See Note 2 for a discussion of the MCIT, which replaces the MBT effective January 1, 2012. The subsidiaries record federal and state income taxes payable to or receivable from DTE Energy based on the federal and state tax provisions of each company.

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:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Electric Utility	$	7		$	8		$	25		$	23
Gas Utility	1			1			2			1
Gas Storage and Pipelines	1			1			7			3
Power and Industrial Projects	30			50			119			122
Energy Trading	17			21			54			65
Corporate & Other	(12		)	(18		)	(40		)	(51		)
	$	44		$	63		$	167		$	163

Financial data of the business segments follows:

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2011			2010			2011			2010
Operating Revenues
Electric Utility	$	1,517		$	1,444		$	3,950		$	3,798
Gas Utility	159			170			1,090			1,157
Gas Storage and Pipelines	21			20			69			62
Unconventional Gas Production	11			7			29			23
Power and Industrial Projects	259			303			781			846
Energy Trading	342			258			970			661
Corporate & Other	—			—			2			—
Reconciliation & Eliminations	(44		)	(63		)	(167		)	(163		)
Total	$	2,265		$	2,139		$	6,724		$	6,384
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	157		$	165		$	345		$	343
Gas Utility	(11		)	(6		)	69			92
Gas Storage and Pipelines	13			12			42			36
Unconventional Gas Production	(2		)	(4		)	(5		)	(9		)
Power and Industrial Projects	12			26			27			66
Energy Trading	22			(12		)	36			—
Corporate & Other (1)	(8		)	(18		)	47			(50		)
Net Income Attributable to DTE Energy	$	183		$	163		$	561		$	478

_____________________________

(1) The 2011 net income for Corporate & Other includes an income tax benefit of $88 million related to the enactment of the MCIT in the second quarter of 2011. See Note 2.

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Fair Value (Details 2) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Fair Value of Long Term Debt [Line Items]
Long-Term Debt, Fair value	$ 8,800,000,000	$ 8,500,000,000.0
Long-Term Debt, Carrying value	$ 7,700,000,000	$ 8,000,000,000.0

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Organization and Basis of Presentation (Tables)

9 Months Ended

Sep. 30, 2011

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

VIEs, in which the Company holds a majority voting interest and is the primary beneficiary, that meet the definition of a business and whose assets can be used for purposes other than the settlement of the VIE’s obligations have been excluded from the table below.

	September 30, 2011
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	8	$	8	$	—
Restricted cash	58		7		65		64
Accounts receivable	38		14		52		40
Inventories	—		145		145		—
Other current assets	—		1		1		—
Property, plant and equipment	—		58		58		25
Securitized regulatory assets	618		—		618		618
Other assets	10		6		16		18
	$	724	$	239	$	963	$	765
LIABILITIES
Accounts payable and accrued current liabilities	$	4	$	38	$	42	$	4
Current portion long-term debt, including capital leases	164		7		171		171
Other current liabilities	62		1		63		64
Mortgage bonds, notes and other	—		31		31		31
Securitization bonds	479		—		479		479
Capital lease obligations	—		20		20		20
Other long term liabilities	6		2		8		7
	$	715	$	99	$	814	$	776

	December 31, 2010
							Restricted
(in Millions)	Securitization		Other		Total		Amounts
ASSETS
Cash and cash equivalents	$	—	$	4	$	4	$	—
Restricted cash	104		8		112		112
Accounts receivable	42		8		50		44
Inventories	—		99		99		—
Other current assets	—		1		1		—
Property, plant and equipment	—		54		54		38
Securitized regulatory assets	729		—		729		729
Other assets	13		9		22		21
	$	888	$	183	$	1,071	$	944
LIABILITIES
Accounts payable and accrued current liabilities	$	17	$	27	$	44	$	18
Current portion long-term debt, including capital leases	150		7		157		157
Other current liabilities	62		6		68		66
Mortgage bonds, notes and other	—		35		35		35
Securitization bonds	643		—		643		643
Capital lease obligations	—		23		23		23
Other long term liabilities	6		7		13		12
	$	878	$	105	$	983	$	954

Summary of amounts for non-consolidated VIEs

Amounts for non-consolidated VIEs as September 30, 2011 and December 31, 2010 were as follows:

	September 30,		December 31,
(in Millions)	2011		2010
Other investments	$	121	$	98
Note receivable	5		6
Trust preferred — linked securities	289		289

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Stock Based Compensation (Details 2) (USD $)	9 Months Ended
	Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at January 1, 2011	757,414
Grants	381,840
Forfeitures	(65,592)
Vested and Issued	(339,138)
Balance at September 30, 2011	734,524
Weighted Average Grant Date Fair Value Per Share - Balance at January 1, 2011	$ 37.32
Weighted Average Grant Date Fair Value Per Share - Grants	$ 47.98
Weighted Average Grant Date Fair Value Per Share - Foreitures	$ 40.84
Weighted Average Grant Date Fair Value Per Share - Vested and issued	$ 38.25
Weighted Average Grant Date Fair Value Per Share - Balance at September 30, 2011	$ 42.22

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Retirement Benefits and Trusteed Assets (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 15	$ 16	$ 52	$ 48
Interest cost	51	51	152	152
Expected return on plan assets	(62)	(65)	(185)	(194)
Defined Benefit Plan Amortization [Abstract]
Net actuarial loss	41	25	107	75
Prior service cost (credit)	0	1	2	3
Net transition liability	0	0	0	0
Special termination benefits	0	0	2
Net periodic benefit cost	45	28	130	84
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	14	15	48	46
Interest cost	28	31	90	94
Expected return on plan assets	(24)	(18)	(71)	(56)
Defined Benefit Plan Amortization [Abstract]
Net actuarial loss	12	13	42	40
Prior service cost (credit)	(7)	(1)	(20)	(3)
Net transition liability	1	1	2	2
Special termination benefits	0	0	0	0
Net periodic benefit cost	$ 24	$ 41	$ 91	$ 123

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Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Statement of Income and Comprehensive Income [Abstract]
Net Income	$ 563	$ 483
Benefit obligations:
Benefit obligation, net of taxes of $2 and $3	5	6
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $- and $5	0	10
Total Benefit obligations	5	16
Net unrealized gains (losses) on derivatives:
Other Comprehensive Income Unrealized gains and losses net of tax	0	1
Amounts reclassified to income, net of taxes of $- and $1	0	1
Net unrealized gains (losses) on derivatives	0	2
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $- and $(6)	(1)	(11)
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $- and $(5)	0	(10)
Net unrealized gains (losses) on investments	(1)	(21)
Foreign currency translation, net of taxes of $- and $-	(1)	0
Comprehensive income	566	480
Less: Comprehensive income attributable to noncontrolling interests	2	5
Comprehensive income attributable to DTE Energy Company	$ 564	$ 475

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Long Term Debt

9 Months Ended

Sep. 30, 2011

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBT

Debt Issuances

In 2011, the Company remarketed or issued the following long-term debt:

(in Millions)

Company	Month Issued	Type	Interest Rate		Maturity	Amount
Detroit Edison	April	Tax-Exempt Revenue Bonds(1)(2)	2.35	%	2024	$	31
Detroit Edison	May	Mortgage Bonds(3)	3.90	%	2021	250
DTE Energy	May	Senior Notes(4)	Variable(5)		2013	300
Detroit Edison	September	Mortgage Bonds(6)	4.31	%	2023	102
Detroit Edison	September	Mortgage Bonds(6)	4.46	%	2026	77
Detroit Edison	September	Mortgage Bonds(6)	5.67	%	2041	46
Detroit Edison	September	Tax-Exempt Revenue Bonds(2)(7)	2.13	%	2030	82
Detroit Edison	September	Mortgage Bonds (8)	4.50	%	2041	140
						$	1,028

_____________________________

(1) These bonds were remarketed for a three-year term ending April 1, 2014. The final maturity of the issue is October 1, 2024.

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

(3) Proceeds were used for general corporate purposes.

(4) Proceeds were used to repay a portion of DTE Energy’s $600 million7.05% Senior Notes due June 1, 2011 and for general corporate purposes.

(5) The interest rate is reset quarterly at the three-month LIBOR plus 70 basis points.

(6) Proceeds were used to retire callable tax-exempt revenue bonds and for general corporate purposes.

(7) These bonds were remarketed for a five-year term ending September 1, 2016. The final maturity of the issue is September 1, 2030.

(8) Proceeds were used to retire approximately $140 million of callable tax-exempt revenue bonds and for general corporate purposes.

Debt Retirements and Redemptions

In 2011, the following debt was retired:

(in Millions)

Company	Month Retired	Type	Interest Rate		Maturity	Amount
Detroit Edison	May	Tax-Exempt Revenue Bonds	6.95	%	2011	$	26
DTE Energy	June	Senior Notes	7.05	%	2011	600
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.55	%	2029	118
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65	%	2029	67
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.65	%	2029	40
Detroit Edison	September	Tax-Exempt Revenue Bonds	5.45	%	2029	140
						$	991

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Asset Retirement Obligations (Details Textuals) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Sep. 30, 2011
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate		$ 19	$ (1)
Asset Retirement Obligation, Period Increase (Decrease)	20
Reserve and Impairment of Retirement Obligation	$ 6

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Regulatory Matters (Details 2) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Regulatory Assets and Liability [Line Items]
Net Over Recovery of Two and One Years Prior Gas Cost Recovery Expense		$ 5,900,000
Gas Cost Recovery Cos of Gas Gold Two and One Years Prior		1,000,000,000
Net Over Recovery of One Year Prior and Current Year Gas Cost Recovery Expense	1,000,000
Gas Cost Recovery Cost of Cost of Gas Sold One Year Prior and Current Year	$ 700,000,000

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Retirement Benefits and Trusteed Assets (Details Textuals) (USD $) In Millions	1 Months Ended	9 Months Ended
	Jan. 31, 2011	Sep. 30, 2011	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer		$ 200
Other Postretirement Benefits Payments	81
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year			$ 125

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2011

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

The following table details the changes in assets and liabilities that are reported in the Consolidated Statements of Cash Flows, and supplementary non-cash information:

	Nine Months Ended
	September 30
(in Millions)	2011			2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	181		$	357
Inventories	(115		)	(200		)
Accrued/prepaid pensions	(186		)	(99		)
Accounts payable	(34		)	(14		)
Income taxes receivable/payable	267			19
Derivative assets and liabilities	(36		)	(58		)
Postretirement obligation	(59		)	20
Other assets	67			(11		)
Other liabilities	(37		)	59
	$	48		$	73
Noncash financing activities:
Common stock issued for employee benefit plans	$	1		$	147

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2011

Share-based Compensation [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

The following table summarizes the components of stock-based compensation expense:

	Three Months Ended
	September 30
(in Millions)	2011		2010
Stock-based compensation expense	$	13	$	9
Tax benefit	5		4
Stock-based compensation cost capitalized in property, plant and equipment	1		1

	Nine Months Ended
	September 30
(in Millions)	2011		2010
Stock-based compensation expense	$	42	$	38
Tax benefit	16		15
Stock-based compensation cost capitalized in property, plant and equipment	3		2

Stock Options

The following table summarizes our stock option activity for the nine months ended September 30, 2011:

	Number of Options		Weighted Average Exercise Price Per Share		(in Millions) Aggregate Intrinsic Value
Options outstanding at January 1, 2011	4,827,457		$	41.09
Granted	—		$	—
Exercised	(1,541,690	)	$	40.52
Forfeited or expired	(21,963	)	$	43.41
Options outstanding at September 30, 2011	3,263,804		$	41.34	$	26
Options exercisable at September 30, 2011	2,597,318		$	42.30	$	18

As of September 30, 2011, the weighted average remaining contractual life for the exercisable shares was 4.42 years. As of September 30, 2011, 666,486 options were non-vested. During the nine months ended September 30, 2011, 687,061 options vested.

The intrinsic value of options exercised for the nine months ended September 30, 2011 was $14 million. Total option expense recognized was $1 million and $3 million for the nine months ended September 30, 2011 and 2010, respectively.

Restricted Stock Awards

The following summarizes stock awards activity for the nine months ended September 30, 2011:

	Restricted Stock		Weighted Average Grant Date Fair Value Per Share
Balance at January 1, 2011	757,414		$	37.32
Grants	381,840		$	47.98
Forfeitures	(65,592	)	$	40.84
Vested and issued	(339,138	)	$	38.25
Balance at September 30, 2011	734,524		$	42.22

Performance Share Awards

The following summarizes performance share activity for the nine months ended September 30, 2011:

	Performance Shares
Balance at January 1, 2011	1,527,253
Grants	611,844
Forfeitures	(66,357	)
Payouts	(467,688	)
Balance at September 30, 2011	1,605,052

Unrecognized Compensation Cost

As of September 30, 2011, the Company had $56 million of total unrecognized compensation cost related to non-vested stock incentive plan arrangements. These costs are expected to be recognized over a weighted-average period of 1.27 years.

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Consolidated Statements of Operations (Unaudited) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating Revenues	$ 2,265	$ 2,139	$ 6,724	$ 6,384
Operating Expenses
Fuel, purchased power and gas	866	763	2,708	2,366
Operation and maintenance	670	649	1,948	1,898
Depreciation, depletion and amortization	259	271	752	775
Taxes other than income	79	69	239	231
Asset (gains) and losses, reserves and impairments, net	(8)	1	0	0
Total operating expenses	1,866	1,753	5,647	5,270
Operating Income	399	386	1,077	1,114
Other (Income) and Deductions
Interest expense	120	142	370	418
Interest income	(3)	(3)	(8)	(9)
Other income	(20)	(20)	(59)	(62)
Other expenses	16	9	31	32
Total Other (Income) and Deductions	113	128	334	379
Income Before Income Taxes	286	258	743	735
Income Tax Expense	101	92	180	252
Net Income	185	166	563	483
Less: Net Income Attributable to Noncontrolling Interests	2	3	2	5
Net Income Attributable to DTE Energy Company	$ 183	$ 163	$ 561	$ 478
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 1.08	$ 0.97	$ 3.31	$ 2.85
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$ 1.07	$ 0.96	$ 3.30	$ 2.84
Weighted Average Common Shares Outstanding
Basic	169	169	169	168
Diluted	170	170	170	168
Dividends Declared per Common Share	$ 0.59	$ 0.56	$ 1.74	$ 1.62

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Organization and Basis of Presentation (Details Textuals)	Sep. 30, 2011 banks customers years ratio employees
Legal Entities [Line Items]
Number of Electric Utility Customers One	2,100,000
Number of Gas Utility Customers One	1,200,000

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Segment Information (Details Textuals1) (USD $) In Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2011	Jun. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Segment Reporting Information [Line Items]
Income Tax Expense	$ 101	$ 88	$ 92	$ 180	$ 252

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Supplemental Cash Flow Information (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$ 181	$ 357
Inventories	(115)	(200)
Accrued/prepaid pensions	(186)	(99)
Accounts payable	(34)	(14)
Income taxes receivable/payable	267	19
Derivative assets and liabilities	(36)	(58)
Postretirement obligation	(59)	20
Other assets	67	(11)
Other liabilities	(37)	59
Total Changes in Assets and Liabilities, Exclusive of Changes Shown Separately	48	73
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Common stock issued for employee benefit plans	$ 1	$ 147

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Fair Value (Details Textuals) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011 banks customers years ratio employees	Sep. 30, 2010	Sep. 30, 2011 percent people years kWh Days weeks MCF banks customers ratio employees	Sep. 30, 2010	Dec. 31, 2010 years
Fair Value, Option, Quantitative Disclosures [Line Items]
Average Maturity of Debt Securities	7		7		6
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, before Tax			$ 0	$ 0
Unrealized losses recognized as regulatory assets	87,000,000		87,000,000		26,000,000
Trading Securities, Change in Unrealized Holding Gain (Loss)			(3,000,000)	3,000,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	(42,000,000)		(24,000,000)
Other investments	104,000,000		104,000,000		111,000,000
Fair Value, Level 1 to level 2 Transfers, Amount	0	0	0	0
Transfers into Level 3	(7,000,000)		(4,000,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net		(22,000,000)		52,000,000
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net	$ 0	$ 0	$ 0	$ 0

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Regulatory Matters (Details 1) (USD $) In Millions	3 Months Ended
	Mar. 31, 2011
Regulatory Assets and Liability [Line Items]
Net Under Recovery of Power Suppy Cost Recovery Expense	$ 52.6
Power Supply Cost of Power Sold	$ 1,200.0

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Commitments and Contingencies (Details) (USD $)	3 Months Ended	6 Months Ended	9 Months Ended			9 Months Ended
	Mar. 31, 2011 years	Jun. 30, 2011 employees years	Sep. 30, 2011 percent people years kWh Days weeks MCF banks customers ratio employees	Sep. 30, 2011 Electric Utility [Member] facility	Dec. 31, 2010 Electric Utility [Member]	Sep. 30, 2011 Gas Utility [Member] facility	Dec. 31, 2010 Gas Utility [Member]
Loss Contingencies [Line Items]
Environmental Capital Expenditures Through Prior Year			$ 1,500,000,000
Environmental Capital Expenditures in Current Year			200,000,000
Environmental Capital Expenditures In Future Years			2,000,000,000
Possible Additional Capital Exepnditures for EPA Regulations			80,000,000
Minimum Amount of Years to Incur Additional Capital Expenditures			4
Maximum Amount of Years to Incur Additional Capital Expenditures			6
Number of Former MGP Sites				3		15
Accrued for remediation related to the sites				8,000,000	9,000,000	41,000,000	36,000,000
Period Gas Utility Can Amortize MGP Costs			10
Possible Environmental Capital Expenditures to Comply with Requirements			1,500,000
Capital Expenditures Over the Next Few Years			13,000,000
Re-proposed Regulations Minimum Period of Compliance with Applicable Standards	3
Number of Defendant Oil Power and Coal Companies In Domestic District Court on Basis of Which Company Named			24
Number of People In Country Claiming Business Activities Contributing to Global Warming Higher Temperatures and Storm Activity			400
Costs associated with relocating village and unspecified attorney's fees and expenses			400,000,000
Waiting Period of Policy			12
Insurance Coverage for Extra ExpenseWhen to Necessitate Power Plant when Unavailable			490,000,000
Period of Coverage of Policy for Extra Expenses			3
Primary Coverage			500,000,000
Coverage for Stabilization Decontamination Debris Removal Repair and Replacement of Property and Decommissioning			2,250,000,000
Combined Coverage Limit for Total Property Damage			2,750,000,000
NEIL Policies Against Terroism Loss			3,200,000,000
Amount per Event Loss Associated with Nuclear Power Plants			29,000,000
Maintenance of Public Liability Insurance for Nuclear Power Plants			375,000,000
Aggregate Limit of Liabilities Arises From Terroist Act Outside Scope of Trials Subject to One Industry			300,000,000
Deferred Premium Charged Leviied Against Each Licensed Nuclear Facility			117,500,000
Limit Deferred Premium Charges Per Year			17,500,000
Company Obligated to Pay DOE Fee of Fermi 2 Electricity Generated and Sold			1
Guarantee Obligations Maximum Exposure One			10,000,000
Performance Bonds Outstanding			14,000,000
Number of Represented Employees			5,000
Years for Bargaining Unit Contract		3
Number of Represented Employees Who Ratified New Contract		400
Long-term Purchase Commitment, Amount			5,000,000,000
estimated future capital expenditures for current year			$ 1,700,000,000

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Fair Value (Details 3) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 893	$ 939
Nuclear Plant [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	858	910
Nuclear Plant1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	3	3
Radioactive Waste [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Decommissioning Fund Investments	$ 32	$ 26

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Fair Value (Details 4) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Fair Value, Option, Quantitative Disclosures [Line Items]
Available-for-sale Securities, Gross Realized Gains	$ 8	$ 8	$ 34	$ 29
Available-for-sale Securities, Gross Realized Losses	(9)	(6)	(26)	(25)
Proceeds from Sale of Available-for-sale Securities	$ 10	$ 51	$ 69	$ 179

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Asset Retirement Obligations (Details) (USD $) In Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2011	Sep. 30, 2011	Dec. 31, 2010
Asset Retirement Obligations [Line Items]
Asset retirement obligations at December 31, 2010	$ 1,514	$ 1,514
Accretion		69
Liabilities incurred		3
Revision in estimated cash flows	19	(1)
Liabilities settled		(15)
Asset retirement obligations at September 30, 2011		1,570
Less amount included in current liabilities		(10)
Asset retirement obligations, net		$ 1,560	$ 1,498

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Organization and Basis of Presentation (Details 1) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2010	Dec. 31, 2009
Assets [Abstract]
Cash and cash equivalents	$ 46	$ 65	$ 84	$ 52
Restricted cash	73	120
Accounts receivable	1,206	1,393
Other current assets	249	197
Property, plant and equipment	13,422	12,992
Securitized regulatory assets	618	729
Other assets	192	206
Total Assets	24,780	24,896
Liabilities [Abstract]
Current portion long-term debt, including, capital leases	247	925
Other current liabilities	536	597
Mortgage bonds, notes and other	6,702	6,114
Securitization bonds	479	643
Capital lease obligations	27	43
Other long term liabilities	258	275
Variable Interest Entity Securitization [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	58	104
Accounts receivable	38	42
Inventories	0	0
Other current assets	0	0
Property, plant and equipment	0	0
Securitized regulatory assets	618	729
Other assets	10	13
Total Assets	724	888
Liabilities [Abstract]
Accounts payable and accrued current liabilities	4	17
Current portion long-term debt, including, capital leases	164	150
Other current liabilities	62	62
Mortgage bonds, notes and other	0	0
Securitization bonds	479	643
Capital lease obligations	0	0
Other long term liabilities	6	6
Total Liabilities	715	878
Variable Interest Entity, Primary Beneficiary [Member]
Assets [Abstract]
Cash and cash equivalents	8	4
Restricted cash	7	8
Accounts receivable	14	8
Inventories	145	99
Other current assets	1	1
Property, plant and equipment	58	54
Securitized regulatory assets	0	0
Other assets	6	9
Total Assets	239	183
Liabilities [Abstract]
Accounts payable and accrued current liabilities	38	27
Current portion long-term debt, including, capital leases	7	7
Other current liabilities	1	6
Mortgage bonds, notes and other	31	35
Securitization bonds	0	0
Capital lease obligations	20	23
Other long term liabilities	2	7
Total Liabilities	99	105
Consolidated Variable Interest Entity [Member]
Assets [Abstract]
Cash and cash equivalents	8	4
Restricted cash	65	112
Accounts receivable	52	50
Inventories	145	99
Other current assets	1	1
Property, plant and equipment	58	54
Securitized regulatory assets	618	729
Other assets	16	22
Total Assets	963	1,071
Liabilities [Abstract]
Accounts payable and accrued current liabilities	42	44
Current portion long-term debt, including, capital leases	171	157
Other current liabilities	63	68
Mortgage bonds, notes and other	31	35
Securitization bonds	479	643
Capital lease obligations	20	23
Other long term liabilities	8	13
Total Liabilities	814	983
Variable Interest Entity Restricted [Member]
Assets [Abstract]
Cash and cash equivalents	0	0
Restricted cash	64	112
Accounts receivable	40	44
Inventories	0	0
Other current assets	0	0
Property, plant and equipment	25	38
Securitized regulatory assets	618	729
Other assets	18	21
Total Assets	765	944
Liabilities [Abstract]
Accounts payable and accrued current liabilities	4	18
Current portion long-term debt, including, capital leases	171	157
Other current liabilities	64	66
Mortgage bonds, notes and other	31	35
Securitization bonds	479	643
Capital lease obligations	20	23
Other long term liabilities	7	12
Total Liabilities	$ 776	$ 954