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 March 31, 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.

Yes þ No o

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).

Yes þ No o

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 filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(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).

Yes o No þ

At March 31, 2011, 169,346,329 shares of DTE Energy’s common stock were outstanding, substantially all of which were held by non-affiliates.

DTE ENERGY COMPANY
QUARTERLY REPORT ON FORM 10-Q
QUARTER ENDED MARCH 31, 2011

TABLE OF CONTENTS

	Page
DEFINITIONS	1
FORWARD-LOOKING STATEMENTS	3
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
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	37
Item 3. Quantitative and Qualitative Disclosures About Market Risk	54
Item 4. Controls and Procedures	57
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	58
Item 1A. Risk Factors	58
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	62
EX-12.47
EX-31.65
EX-31.66
EX-32.65
EX-32.66
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.
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
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-Looking Statements

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. Forward-looking statements 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;

• 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;

3

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

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

• 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 business issues; and

• binding arbitration, litigation and related appeals.

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.

DTE Energy Company

Consolidated Statements of Operations (Unaudited)

	Three Months Ended
	March 31
(in Millions, Except per Share Amounts)	2011			2010
Operating Revenues	$	2,431		$	2,453
Operating Expenses
Fuel, purchased power and gas		1,071			995
Operation and maintenance		631			652
Depreciation, depletion and amortization		245			251
Taxes other than income		83			82
Asset (gains) and losses, reserves and impairments, net		11			1
		2,041			1,981
Operating Income		390			472
Other (Income) and Deductions
Interest expense		126			140
Interest income		(3	)		(3	)
Other income		(21	)		(19	)
Other expenses		7			8
		109			126
Income Before Income Taxes		281			346
Income Tax Provision		103			116
Net Income		178			230
Less: Net Income Attributable to Noncontrolling Interests		2			1
Net Income Attributable to DTE Energy Company	$	176		$	229
Basic Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	1.04		$	1.38
Diluted Earnings per Common Share
Net Income Attributable to DTE Energy Company	$	1.04		$	1.38
Weighted Average Common Shares Outstanding
Basic		169			166
Diluted		170			166
Dividends Declared per Common Share	$	.56		$	.53

See Notes to Consolidated Financial Statements (Unaudited)

5

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)

	March 31			December 31
(in Millions)	2011			2010
ASSETS
Current Assets
Cash and cash equivalents	$	197		$	65
Restricted cash		67			120
Accounts receivable (less allowance for doubtful accounts of $178 and $196, respectively)
Customer		1,401			1,393
Other		112			402
Inventories
Fuel and gas		328			460
Materials and supplies		208			202
Deferred income taxes		132			139
Derivative assets		122			131
Other		233			255
		2,800			3,167
Investments
Nuclear decommissioning trust funds		961			939
Other		521			518
		1,482			1,457
Property
Property, plant and equipment		21,729			21,574
Less accumulated depreciation, depletion and amortization		(8,676	)		(8,582	)
		13,053			12,992
Other Assets
Goodwill		2,020			2,020
Regulatory assets		3,980			4,058
Securitized regulatory assets		692			729
Intangible assets		69			67
Notes receivable		130			123
Derivative assets		59			77
Other		204			206
		7,154			7,280
Total Assets	$	24,489		$	24,896

See Notes to Consolidated Financial Statements (Unaudited)

6

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)

	March 31			December 31
(in Millions, Except Shares)	2011			2010
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	631		$	729
Accrued interest		134			111
Dividends payable		95			95
Short-term borrowings		—			150
Current portion long-term debt, including capital leases		899			925
Derivative liabilities		127			142
Gas inventory equalization		204			—
Other		465			597
		2,555			2,749
Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		6,129			6,114
Securitization bonds		559			643
Trust preferred-linked securities		289			289
Capital lease obligations		38			43
		7,015			7,089
Other Liabilities
Deferred income taxes		2,631			2,632
Regulatory liabilities		1,382			1,328
Asset retirement obligations		1,535			1,498
Unamortized investment tax credit		73			75
Derivative liabilities		90			110
Liabilities from transportation and storage contracts		79			83
Accrued pension liability		673			866
Accrued postretirement liability		1,222			1,275
Nuclear decommissioning		151			149
Other		246			275
		8,082			8,291
Commitments and Contingencies (Notes 7 and 11)
Equity
Common stock, without par value, 400,000,000 shares authorized, 169,346,329 and 169,428,406 shares issued and outstanding, respectively		3,428			3,440
Retained earnings		3,513			3,431
Accumulated other comprehensive loss		(148	)		(149	)
Total DTE Energy Company Equity		6,793			6,722
Noncontrolling interests		44			45
Total Equity		6,837			6,767
Total Liabilities and Equity	$	24,489		$	24,896

See Notes to Consolidated Financial Statements (Unaudited)

7

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31
(in Millions)	2011			2010
Operating Activities
Net income	$	178		$	230
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		245			251
Deferred income taxes		48			36
Asset (gains), losses and reserves, net		11			1
Changes in assets and liabilities, exclusive of changes shown separately (Note 14)		240			299
Net cash from operating activities		722			817
Investing Activities
Plant and equipment expenditures — utility		(253	)		(209	)
Plant and equipment expenditures — non-utility		(17	)		(30	)
Proceeds from sale of assets, net		4			13
Restricted cash for debt redemption		53			49
Proceeds from sale of nuclear decommissioning trust fund assets		20			59
Investment in nuclear decommissioning trust funds		(28	)		(68	)
Consolidation of VIEs		—			19
Other		(23	)		(4	)
Net cash used for investing activities		(244	)		(171	)
Financing Activities
Redemption of long-term debt		(94	)		(90	)
Short-term borrowings, net		(150	)		(327	)
Issuance of common stock		—			9
Repurchase of common stock		(9	)		—
Dividends on common stock		(95	)		(88	)
Other		2			(9	)
Net cash used for financing activities		(346	)		(505	)
Net Increase in Cash and Cash Equivalents		132			141
Cash and Cash Equivalents at Beginning of Period		65			52
Cash and Cash Equivalents at End of Period	$	197		$	193

See Notes to Consolidated Financial Statements (Unaudited)

8

DTE Energy Company

Consolidated Statements of Changes in Equity and
Comprehensive Income (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		—			—			176			—			2			178
Dividends declared on common stock		—			—			(94	)		—			—			(94	)
Repurchase of common stock		(559	)		(26	)		—			—			—			(26	)
Benefit obligations, net of tax		—			—			—			1			—			1
Stock-based compensation, distributions to noncontrolling interests and other		477			14			—			—			(3	)		11
Balance, March 31, 2011		169,346		$	3,428		$	3,513		$	(148	)	$	44		$	6,837

     The following table displays comprehensive income for the three-month periods ended March 31:

(in Millions)	2011		2010
Net income	$	178	$	230
Other comprehensive income (loss), net of tax:
Benefit obligations:
Benefit obligation, net of taxes of $1 and $1		1		2
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $- and $5		—		10
		1		12
Net unrealized gains (losses) on derivatives:
Gains (losses) during the period, net of taxes of $- and $-		—		1
Amounts reclassified to income, net of taxes of $- and $-		—		1
		—		2
Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $- and $(1)		—		(3	)
Amounts reclassified to benefit obligations related to consolidation of VIEs (Note 1), net of taxes of $- and $(5)		—		(10	)
		—		(13	)
Comprehensive income		179		231
Less: Comprehensive income attributable to noncontrolling interests		2		1
Comprehensive income attributable to DTE Energy Company	$	177	$	230

See Notes to Consolidated Financial Statements (Unaudited)

9

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

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 “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 for a fair presentation of such financial statements. 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.

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

10

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 March 31, 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 interests 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 March 31, 2011 and December 31, 2010. Amounts at March 31, 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. Entities, 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.

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	March 31, 2011
							Restricted
	Securitization		Other		Total		Amounts
(in Millions)
ASSETS
Cash and cash equivalents	$	—	$	3	$	3	$	—
Restricted cash		55		4		59		59
Accounts receivable		39		17		56		41
Inventories		—		72		72		—
Other current assets		—		1		1		—
Property, plant and equipment		—		61		61		27
Securitized regulatory assets		692		—		692		692
Other assets		12		8		20		20
	$	798	$	166	$	964	$	839
LIABILITIES
Accounts payable and accrued current liabilities	$	4	$	36	$	40	$	4
Current portion long-term debt, including capital leases		158		7		165		165
Other current liabilities		62		12		74		63
Mortgage bonds, notes and other		—		33		33		33
Securitization bonds		559		—		559		559
Capital lease obligations		—		21		21		21
Other long term liabilities		6		2		8		7
	$	789	$	111	$	900	$	852

	December 31, 2010
							Restricted
	Securitization		Other		Total		Amounts
(in Millions)
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 March 31, 2011 and December 31, 2010 are as follows:

	March 31,		December 31,
	2011		2010
(in Millions)
Other investments	$	105	$	98
Note receivable		5		6
Trust preferred — linked securities		289		289

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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 March 31, 2011 and December 31, 2010. The Company’s intangible assets related to renewable energy credits were $20 million and $17 million at March 31, 2011 and December 31, 2010, respectively. The gross carrying amount and accumulated amortization of contract intangible assets at March 31, 2011 were $63 million and $23 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 March 31, 2011 was 37 percent as compared to 34 percent for the three months ended March 31, 2010. The increase in the effective tax rate in 2011 is due primarily to the expiration of production tax credits for steel industry fuel as of December 31, 2010.

The Company had $5 million of unrecognized tax benefits at March 31, 2011 and 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 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.

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 March 31, 2011, the total cash collateral posted, net of cash collateral received, was $126 million. Derivative assets and derivative liabilities are shown net of collateral of $4 million and $92 million, respectively. At March 31, 2011, the Company recorded cash collateral received of $1 million and cash collateral paid of $39 million not related to unrealized derivative positions. These amounts are included in accounts receivable and accounts payable and are recorded net by counterparty.

NOTE 3 — NEW ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements and Disclosures

In January 2010, the FASB issued ASU 2010-06, Improving Disclosures about Fair Value Measurements. ASU 2010-06 requires details of transfers in and out of Level 1 and 2 fair value measurements and the gross presentation of activity within the Level 3 fair value measurement roll forward. The new disclosures are required of all entities that are required to provide disclosures about recurring and nonrecurring fair value measurements. The Company adopted ASU 2010-06 effective January 1, 2010, except for the gross presentation of the Level 3 fair value measurement roll forward provision which was adopted in the first quarter of 2011, as permitted.

NOTE 4 — 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 March 31, 2011 and December 31, 2010.

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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, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. 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.

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The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2011:

										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments(2)			March 31, 2011
Assets:
Nuclear decommissioning trusts		624			337			—			—			961
Other investments(1)		55			53			—			—			108
Derivative assets:
Foreign currency exchange contracts		—			23			—			(23	)		—
Commodity Contracts:
Natural Gas		1,251			89			8			(1,330	)		18
Electricity		—			578			62			(484	)		156
Other		47			2			5			(47	)		7
Total derivative assets		1,298			692			75			(1,884	)		181
Total	$	1,977		$	1,082		$	75		$	(1,884	)	$	1,250
Liabilities:
Derivative liabilities:
Foreign currency exchange contracts	$	—		$	(36	)	$	—		$	23		$	(13	)
Interest rate contracts		—			(1	)		—			—			(1	)
Commodity Contracts:
Natural Gas		(1,285	)		(213	)		(5	)		1,366			(137	)
Electricity		—			(551	)		(54	)		542			(63	)
Other		(39	)		(5	)		—			41			(3	)
Total derivative liabilities		(1,324	)		(806	)		(59	)		1,972			(217	)
Total	$	(1,324	)	$	(806	)	$	(59	)	$	1,972		$	(217	)
Net Assets as of March 31, 2011	$	653		$	276		$	16		$	88		$	1,033
Assets:
Current	$	872		$	526		$	43		$	(1,319	)	$	122
Noncurrent(3)		1,105			556			32			(565	)		1,128
Total Assets	$	1,977		$	1,082		$	75		$	(1,884	)	$	1,250
Liabilities:
Current	$	(894	)	$	(583	)	$	(33	)	$	1,383		$	(127	)
Noncurrent		(430	)		(223	)		(26	)		589			(90	)
Total Liabilities	$	(1,324	)	$	(806	)	$	(59	)	$	1,972		$	(217	)
Net Assets as of March 31, 2011	$	653		$	276		$	16		$	88		$	1,033

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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 $108 million and $111 million at March 31, 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 table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three months ended March 31, 2011 and 2010:

	March 31, 2011
(in Millions)	Natural Gas			Electricity			Other			Total
Net Assets as of January 1, 2011	$	1		$	54		$	4		$	59
Transfers into Level 3		—			2			—			2
Transfers out of Level 3		3			(25	)		—			(22	)
Total gains or (losses):
Included in earnings		(4	)		(15	)		2			(17	)
Recorded in regulatory assets/liabilities		—			—			(1	)		(1	)
Purchases, issuances, sales and settlements:
Settlements		3			(8	)		—			(5	)
Net Assets as of March 31, 2011	$	3		$	8		$	5		$	16
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 March 31, 2011	$	(1	)	$	(8	)	$	2		$	(7	)

	March 31, 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		6			79			—			85
Changes in fair value recorded in regulatory assets/liabilities		—			—			(1	)		(1	)
Purchases, issuances and settlements		(3	)		(9	)		—			(12	)
Net Assets as of March 31, 2010	$	5		$	89		$	2		$	96
The amount of total gains (losses) included in net income attributed to the change in unrealized gains related to assets and liabilities held at March 31, 2010	$	2		$	65		$	—		$	67

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 months ended March 31, 2011, $25 million 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. No significant transfers between Levels 1 and 2 occurred in the three months ended March 31, 2011, and no significant transfers between Levels 1, 2 and 3 occurred in the three months ended March 31, 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

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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 5 for further fair value information on financial and derivative instruments.

	March 31, 2011		December 31, 2010
	Fair Value	Carrying Value	Fair Value	Carrying Value
Long-Term Debt	$8.4 billion	$7.9 billion	$8.5 billion	$8.0 billion

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 6.

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. See Note 7.

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

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

	March 31,		December 31,
(in Millions)	2011		2010
Fermi 2	$	930	$	910
Fermi 1		3		3
Low level radioactive waste		28		26
Total	$	961	$	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
	March 31
(in Millions)	2011			2010
Realized gains	$	14		$	9
Realized losses		(8	)		(8	)
Proceeds from sales of securities		20			59

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 March 31, 2011
Equity securities	$	590	$	100
Debt securities		359		10
Cash and cash equivalents		12		—
	$	961	$	110
As of December 31, 2010
Equity securities	$	572	$	77
Debt securities		361		11
Cash and cash equivalents		6		—
	$	939	$	88

The debt securities at March 31, 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 $27 million and $26 million of unrealized losses as Regulatory assets at March 31, 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 months ended March 31, 2011 and March 31, 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:

	March 31, 2011				December 31, 2010
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	79	$	79	$	133	$	133
Equity securities		7		7		6		6

As of March 31, 2011, these securities are comprised primarily of money-market and equity securities. During the three months ended March 31, 2011, no amounts of unrealized losses on available for sale securities were reclassified out of other comprehensive income into losses for the period. During the three months ended March 31,

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2010, $1 million of unrealized losses on available for sale securities were reclassified out of other comprehensive income into earnings for the period. Gains related to trading securities held at March 31, 2011 and March 31, 2010 were $3 million and $2 million, respectively.

NOTE 5 — 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. 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.

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Energy Trading — Commodity Price Risk — Energy Trading markets and trades electricity and natural gas physical products and energy financial instruments, and provides risk management services utilizing energy commodity derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctuations in its operations. These derivatives are accounted for by recording changes in fair value to earnings unless 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 March 31, 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 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.

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• 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 represents the fair value of derivative instruments as of March 31, 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	$	23	$	(36	)
Commodity Contracts:
Natural Gas		1,348		(1,503	)
Electricity		640		(605	)
Other		54		(44	)
Total derivatives not designated as hedging instruments:	$	2,065	$	(2,188	)
Total derivatives:
Current	$	1,441	$	(1,510	)
Noncurrent		624		(679	)
Total derivatives	$	2,065	$	(2,189	)

	Derivative Assets						Derivative Liabilities
	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statements of Financial Position:
Total fair value of derivatives	$	1,441		$	624		$	(1,510	)	$	(679	)
Counterparty netting		(1,315	)		(565	)		1,315			565
Collateral adjustment		(4	)		—			68			24
Total derivatives as reported	$	122		$	59		$	(127	)	$	(90	)

The following represents 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	)
Total derivatives designated as hedging instruments:	$	—	$	(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	)

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The income effect of derivatives not designated as hedging instruments on the Consolidated Statements of Operations for the three months ended March 31, 2011 and March 31, 2010 is as follows:

		Gain (Loss)
		Recognized in
		Income on
	Location of Gain	Derivatives for
	(Loss) Recognized	Three Months Ended
(in Millions)	in Income	March 31
Derivatives Not Designated As Hedging Instruments	On Derivatives	2011			2010
Foreign currency exchange contracts	Operating Revenue	$	(6	)	$	(11	)
Commodity Contracts:
Natural Gas	Operating Revenue		6			10
Natural Gas	Fuel, purchased power and gas		(6	)		(7	)
Electricity	Operating Revenue		(1	)		71
Other	Operating Revenue		6			—
Total		$	(1	)	$	63

The effects of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statements of Financial Position were immaterial to both Regulatory assets and Regulatory liabilities for the three months ended March 31, 2011.

The following represents the cumulative gross volume of derivative contracts outstanding as of March 31, 2011:

Commodity	Number of Units
Natural Gas (MMBtu)		582,026,946
Electricity (MWh)		57,762,044
Foreign Currency Exchange ($ CAD)		165,934,113

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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 March 31, 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 $202 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.

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

A reconciliation of the asset retirement obligations for the three months ended March 31, 2011 follows:

(in Millions)
Asset retirement obligations at December 31, 2010	$	1,514
Accretion		23
Revision in estimated cash flows		19
Liabilities settled		(2	)
Asset retirement obligations at March 31, 2011		1,554
Less amount included in current liabilities		(19	)
	$	1,535

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. Subject to NRC notification, 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.

NOTE 7 — REGULATORY MATTERS

2010 Electric Rate Case Filing

Detroit Edison filed a rate case on October 29, 2010 based on a projected twelve-month period ending March 31, 2012. The filing with the MPSC requested a $443 million increase in base rates that is required to recover higher costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, inflation, the capital costs of plant additions, the reduction in territory sales, the impact from the expiration of certain wholesale for resale contracts and the increased migration of customers to the electric Customer Choice program. Detroit Edison also proposed certain adjustments which could reduce the net impact on the required increase in rates by approximately $190 million. These adjustments relate to electric Customer Choice migration, pension and other postretirement benefits expenses and the Nuclear Decommissioning surcharge.

Detroit Edison Restoration Expense Tracker Mechanism (RETM) and Line Clearance Tracker (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 has requested recovery of approximately $19.5 million.

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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 $7.2 million consisting of costs related to 2010 uncollectible expense.

Detroit Edison Choice Incentive Mechanism (CIM)

In March 2011, Detroit Edison filed an application with the MPSC for approval of its CIM reconciliation for 2010 requesting recovery of approximately $105.2 million.

Power Supply Cost Recovery 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 Over/(Under)-Recovery,	PSCR Cost of
PSCR Year	Date Filed	Including Interest	Power Sold
2009	March 2010	$15.6 million	$1.2 billion
2010	March 2011	$(52.6) million	$1.2 billion

2010 PSCR Year — The 2010 PSCR reconciliation includes $15.6 million net over-recovery for the 2009 PSCR year. In addition to the net under-recovery of $52.6 million, 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.

Energy Optimization (EO) Plans

In April 2011, Detroit Edison and MichCon both filed separate applications for approval of their respective reconciliations of their 2010 EO plan expenses. Specifically Detroit Edison’s EO reconciliation includes a cumulative $21 million net over-recovery at year end 2010 for the 2010 EO plan. MichCon’s EO reconciliation includes a cumulative $5.6 million net over-recovery at year end 2010 for the 2010 EO plan.

MichCon UETM

In March 2011, MichCon filed an application with the MPSC for approval of its UETM for 2010 requesting recovery of approximately $31.4 million consisting of costs related to 2010 uncollectible expense.

Gas Cost Recovery 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.

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

		Net Over-Recovery,
GCR Year	Date Filed	Including Interest	GCR Cost of Gas Sold
2009-2010	June 2010	$5.9 million	$1.0 billion

2010-2011 Plan Year — In December 2009, MichCon filed its GCR plan case for the 2010-2011 GCR plan year. The MPSC issued an order in this case in September 2010 authorizing MichCon to charge a maximum of $7.06 per Mcf, adjustable monthly by a contingent factor. The MPSC also approved MichCon’s proposed fixed price gas purchasing program and provided clarification regarding treatment of certain affiliate purchases.

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.

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.

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NOTE 8 — 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.

A reconciliation of both calculations is presented in the following table as of March 31:

(in Millions, except per share amounts)	2011		2010
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	176	$	229
Average number of common shares outstanding		169		166
Weighted average net restricted shares outstanding		1		1
Dividends declared — common shares	$	94	$	88
Dividends declared — net restricted shares		1		—
Total distributed earnings	$	95	$	88
Net income less distributed earnings	$	81	$	141
Distributed (dividends per common share)	$	.56	$	.53
Undistributed		.48		.85
Total Basic Earnings per Common Share	$	1.04	$	1.38
Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	176	$	229
Average number of common shares outstanding		169		166
Average incremental shares from assumed exercise of options		1		—
Common shares for dilutive calculation		170		166
Weighted average net restricted shares outstanding		1		1
Dividends declared — common shares	$	94	$	88
Dividends declared — net restricted shares		1		—
Total distributed earnings	$	95	$	88
Net income less distributed earnings	$	81	$	141
Distributed (dividends per common share)	$	.56	$	.53
Undistributed		.48		.85
Total Diluted Earnings per Common Share	$	1.04	$	1.38

Options to purchase approximately 0.4 million and 2 million shares of common stock as of March 31, 2011 and March 31, 2010, respectively, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 9 — LONG-TERM DEBT

In April 2011, Detroit Edison remarketed $31 million of Tax-Exempt Revenue Bonds in a long-term rate mode at 2.35% for a three-year term. The final maturity of the issue is October 1, 2024.

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NOTE 10 — 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 March 31, 2011, the total funded debt to total capitalization ratios for DTE Energy, Detroit Edison and MichCon are 0.49 to 1, 0.51 to 1 and 0.46 to 1, respectively, and are in compliance with this financial covenant. The availability under these combined facilities at March 31, 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 March 31, 2011	$	1,275	$	275	$	425	$	1,975
Amounts outstanding at March 31, 2011:
Letters of credit		134		—		—		134
Net availability at March 31, 2011	$	1,141	$	275	$	425	$	1,841

The Company has other outstanding letters of credit which are not included in the above described facilities totaling approximately $35 million which are used for various corporate purposes.

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 March 31, 2011, a $10 million letter of credit was in place, raising the capacity under this facility to $110 million. The $10 million letter of credit is included in the table above. The amount outstanding under this agreement was $11 million and $39 million at March 31, 2011 and December 31, 2010, respectively.

NOTE 11 — 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 new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of over $230 million in 2011 and up to $2.1 billion of additional capital expenditures through 2020 based on current regulations. Further,

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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. DTE Energy is reviewing potential impacts of the proposed rule. The EPA will be accepting input on the proposal and may modify it prior to finalization, scheduled for November 2011. It is not possible to quantify the impact of this 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 of Detroit Edison’s power plants violated New Source Performance standards, Prevention of Significant Deterioration requirements, and operating permit requirements under the Clean Air Act. In June 2010, the 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 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 is requesting 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 is requesting 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 and the liability phase of the civil suit has been scheduled for trial in September 2011.

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 and the result of the civil action, 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 this 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 $55 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 March 28, 2011, the EPA issued a revised rule, which is currently under review. 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 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 March 31, 2011 and December 31, 2010, the Company had $9 million accrued for remediation. Any significant change in

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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.

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 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 March 31, 2011 and December 31, 2010, the Company had $36 million 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 ten-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 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 impact of this investigation.

The Company is also in the process of settling historical air and water violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the impact of this settlement. 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

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biological treatment facility. The Company expects to spend less than $1 million on the existing waste water treatment system to comply with existing water discharge requirements. 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’s 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 (MACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines. This new set of regulations may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The new MACT regulations for industrial boilers provide three years for compliance with the major and area source standards. The Company is currently assessing the impact on current operations to determine the financial impact, if any, to comply with the 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.

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

Public Liability Insurance

As 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. In 2011, the Company expects to begin loading spent nuclear fuel into an on-site dry cask storage facility which is expected to provide sufficient storage capability for the life of the plant as defined by the original operating license. 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 March 31, 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 March 31, 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. Approximately 400 employees are under contracts that expire in June 2011. The majority of the remaining represented employees are under contracts that expire August 2012 and June and October 2013.

Purchase Commitments

As of March 31, 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 $6 billion from 2011 through 2051.

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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 5 and 7 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 12 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

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

							Other Postretirement
(in Millions)	Pension Benefits						Benefits
Three Months Ended March 31	2011			2010			2011			2010
Service cost	$	19		$	16		$	17		$	16
Interest cost		51			50			31			31
Expected return on plan assets		(62	)		(64	)		(24	)		(18	)
Amortization of:
Net actuarial loss		33			25			15			13
Prior service cost		1			1			(7	)		(1	)
Net transition liability		—			—			1			1
Net periodic benefit cost	$	42		$	28		$	33		$	42

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 $90 million contribution to its other postretirement benefit plans by the end of 2011.

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NOTE 13 — STOCK-BASED COMPENSATION

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

	Three Months Ended
	March 31
(in Millions)	2011		2010
Stock-based compensation expense	$	18	$	15
Tax benefit		7		6
Stock-based compensation cost capitalized in property, plant and equipment		1		1

Stock Options

The following table summarizes our stock option activity for the three months ended March 31, 2011:

						(in Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Options outstanding at January 1, 2011		4,827,457		$	41.09
Granted		—		$	—
Exercised		(557,063	)	$	40.11
Forfeited or expired		(4,184	)	$	43.33
Options outstanding at March 31, 2011		4,266,210		$	41.21	$	25.21
Options exercisable at March 31, 2011		3,596,318		$	41.89	$	18.85

As of March 31, 2011, the weighted average remaining contractual life for the exercisable shares was 4.71 years. As of March 31, 2011, 669,892 options were non-vested. During the three months ended March 31, 2011, 684,857 options vested.

There were no stock options granted during the three months ended March 31, 2011. The intrinsic value of options exercised for the three months ended March 31, 2011 was $4.3 million. Total option expense recognized was $0.5 million and $1.7 million for the three months ended March 31, 2011 and 2010, respectively.

Restricted Stock Awards

The following summarizes stock awards activity for the three months ended March 31, 2011:

				Weighted Average
	Restricted			Grant Date
	Stock			Fair Value
Balance at January 1, 2011		757,414		$	37.32
Grants		197,930		$	46.85
Forfeitures		(10,952	)	$	36.06
Vested and issued		(236,685	)	$	39.42
Balance at March 31, 2011		707,707		$	39.41

Performance Share Awards

The following summarizes performance share activity for the three months ended March 31, 2011:

	Performance Shares
Balance at January 1, 2011		1,527,253
Grants		589,100
Forfeitures		(1,010	)
Payouts		(467,688	)
Balance at March 31, 2011		1,647,655

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Unrecognized Compensation Cost

As of March 31, 2011, the Company had $73 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 1.83 years.

NOTE 14 — SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended
	March 31
(in Millions)	2011			2010
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(10	)	$	114
Inventories		125			88
Accrued/prepaid pensions		(194	)		(100	)
Accounts payable		(61	)		(47	)
Income taxes receivable/payable		245			79
Derivative assets and liabilities		(9	)		(86	)
Gas inventory equalization		204			190
Postretirement obligation		(52	)		39
Other assets		93			54
Other liabilities		(101	)		(32	)
	$	240		$	299
Noncash financing activities:
Common stock issued for employee benefit plans	$	1		$	124

NOTE 15 — SEGMENT INFORMATION

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

Electric Utility segment consists 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 Michigan Business Tax 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. 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.

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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
	March 31
(in Millions)	2011			2010
Electric Utility	$	9		$	6
Gas Utility		—			1
Gas Storage and Pipelines		2			2
Power and Industrial Projects		26			1
Energy Trading		22			26
Corporate & Other		(17	)		(21	)
	$	42		$	15

	Three Months Ended
	March 31
(in Millions)	2011			2010
Operating Revenues
Electric Utility	$	1,193		$	1,146
Gas Utility		689			755
Gas Storage and Pipelines		25			21
Unconventional Gas Production		8			8
Power and Industrial Projects		235			252
Energy Trading		322			286
Corporate & Other		1			—
Reconciliation & Eliminations		(42	)		(15	)
Total	$	2,431		$	2,453
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	85		$	91
Gas Utility		83			79
Gas Storage and Pipelines		15			14
Unconventional Gas Production		(2	)		(3	)
Power and Industrial Projects		10			18
Energy Trading		2			38
Corporate & Other		(17	)		(8	)
Net Income Attributable to DTE Energy	$	176		$	229

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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 first quarter of 2011 was $176 million, or $1.04 per diluted share, compared to net income attributable to DTE Energy of $229 million, or $1.38 per diluted share, in the first quarter of 2010. The decrease in net income is primarily due to lower earnings at the Energy Trading and Power and Industrial segments, partially offset by improved results at the Electric and Gas utilities.

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

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 2011 driven primarily by lower interconnection and industrial sales, partially offset by higher residential and commercial sales. 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 a result of colder winter weather. 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 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. To mitigate volatility of changes in the uncollectible expense, both utilities have uncollectible tracking mechanisms that enable them to recover or refund 80 percent of the difference between the actual uncollectible expense each year and the level established in their last rate cases. The uncollectible tracking mechanisms require annual reconciliation proceedings before the MPSC.

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	Three Months Ended
	March 31
(in Millions)	2011		2010
Uncollectible Expense
Detroit Edison	$	6	$	12
MichCon		9		22
	$	15	$	34

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. 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, two interstate pipelines serving the Midwest, Ontario and Northeast markets and gathering projects in northern Michigan. Much of the growth in demand for natural gas is expected to occur in the Eastern Canada and the Northeast U.S. regions. Our Vector and Millennium pipelines are well positioned to provide access routes and low-cost expansion options to these markets. In addition, Millennium Pipeline is well positioned for growth related to the Marcellus shale, especially with respect to Marcellus production in Northern Pennsylvania and along the southern tier of New York. We also have subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan.

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. The increasing number of states with renewable portfolio standards provides the opportunity to market the expertise of the Power and Industrial Projects segment in landfill gas, on-site energy management, waste-wood power generation, 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 which may include the management of associated storage and transportation contracts on the customers’ behalf.

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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. 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.

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. MichCon is seeking recovery of the costs resulting from these two programs with the MPSC.

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 continued investment 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 new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.5 billion through 2010. The Company estimates Detroit Edison will make capital expenditures of over $230 million in 2011 and up to $2.1 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. EPA’s proposed National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric Utility Steam Generating Units rule was issued on March 16, 2011 for review and comment. DTE Energy is reviewing potential impacts of the proposed rule. The EPA will be accepting input on the proposal and may modify it prior to finalization, scheduled for November 2011. It is not possible to quantify the impact of this 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

39

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 and the liability phase of the civil suit has been scheduled for trial in September 2011.

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 and the result of the civil action, the Company 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 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 $55 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 March 28, 2011, the EPA issued a revised rule, which is currently under review. 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 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, fifteen 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 ten-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.

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

40

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. 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 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 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 impact of this investigation. The Company is also in the process of settling historical air and water violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the impact of this settlement. The Company is currently seeking a permit from the Pennsylvania Department of Environmental Protection to upgrade its wastewater treatment technology to a biological treatment for the coke battery facility located in Pennsylvania. This upgrade is expected to be completed over the next two years to meet future regulatory requirements.

The Company’s 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 (MACT) for major and area sources, and commercial/industrial solid waste incinerator new source performance standard and emission guidelines. This new set of regulations may impact our existing operations and may require us, in certain instances, to install new air pollution control devices. The new MACT regulations for industrial boilers provide three years for compliance with the major and area source standards. The Company is currently assessing the impact on current operations to determine the financial impact, if any, to comply with the 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 GHG. In addition, the EPA will be issuing proposed GHG performance standards for new and modified electric generating units in July 2011. Comprehensive climate change and energy legislation was passed out of the U.S. House in 2009, but the Senate was unable to agree on passage of a climate bill. In the current 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 these impacts on DTE Energy or its customers at this time.

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OUTLOOK

The next few years will be a period of rapid change for DTE Energy and for the energy industry. 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 within a framework of managing customer affordability;

• optimizing our cost structure across all business segments;

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

• investing in businesses that integrate our assets and leverage our skills and expertise.

We will continue to pursue opportunities to grow our businesses in a disciplined manner if we can secure opportunities that meet our strategic, financial and risk criteria.

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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 is as follows:

	Three Months Ended
	March 31
(in Millions)	2011			2010
Net Income (Loss) Attributable to DTE Energy by Segment:
Electric Utility	$	85		$	91
Gas Utility		83			79
Gas Storage and Pipelines		15			14
Unconventional Gas Production		(2	)		(3	)
Power and Industrial Projects		10			18
Energy Trading		2			38
Corporate & Other		(17	)		(8	)
Net Income Attributable to DTE Energy	$	176		$	229

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Electric Utility results are discussed below:

	Three Months Ended
	March 31
(in Millions)	2011			2010
Operating Revenues	$	1,193		$	1,146
Fuel and Purchased Power		378			343
Gross Margin		815			803
Operation and Maintenance		330			309
Depreciation and Amortization		203			204
Taxes Other Than Income		59			65
Asset (Gains) and Losses, Net		19			(1	)
Operating Income		204			226
Other (Income) and Deductions		67			79
Income Tax Provision		52			56
Net Income Attributable to DTE Energy Company	$	85		$	91
Operating Income as a Percentage of Operating Revenues		17	%		20	%

Gross margin increased $12 million in the first quarter of 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
Base sales, net of RDM and CIM	$	7
Energy optimization incentive		9
Restoration tracker		5
Electric Choice implementation surcharge elimination		(6	)
Securitization bond and tax surcharge		(3	)
Increase in gross margin	$	12

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Electric Sales

	Three Months Ended
	March 31
(in Thousands of MWh)	2011		2010
Residential		3,889		3,665
Commercial		3,993		3,942
Industrial		2,341		2,475
Other		798		802
		11,021		10,884
Interconnection sales (1)		306		1,310
Total Electric Sales		11,327		12,194
Electric Deliveries
Retail and Wholesale		11,021		10,884
Electric Customer Choice, including self generators (2)		1,302		1,103
Total Electric Sales and Deliveries		12,323		11,987

(1)	Represents power that is not distributed by Detroit Edison.
(2)	Includes deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.

Power Generated and Purchased

	Three Months Ended
	March 31
(in Thousands of MWh)	2011			2010
Power Plant Generation
Fossil		8,058			9,520
Nuclear		1,706			2,200
		9,764			11,720
Purchased Power		2,477			1,322
System Output		12,241			13,042
Less Line Loss and Internal Use		(914	)		(848	)
Net System Output		11,327			12,194
Average Unit Cost ($/MWh)
Generation (1)	$	20.80		$	18.78
Purchased Power	$	40.79		$	32.30
Overall Average Unit Cost	$	24.84		$	20.15

(1) Represents fuel costs associated with power plants.

Operation and maintenance expense increased $21 million in the first quarter of 2011 due primarily to increased power plant generation outages of $9 million, higher employee benefit related expenses of $8 million, higher storm and line clearance expenses of $6 million and higher energy optimization and renewable energy expenses of $4 million, partially offset by reduced uncollectible expenses of $6 million.

Asset (gains) and losses, net decreased $20 million due 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. See Note 6 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. The 2010 MPSC order provided for an uncollectible expense tracking mechanism which financially 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, weather and conservation. These and other tracking mechanisms and surcharges are expected to result in lower earnings

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volatility. 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 volatility in prices for coal and other commodities, increased transportation costs, investment returns and changes in discount rate assumptions in benefit plans and health care costs, lower levels of wholesale sales due to contract expirations, 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.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results are discussed below:

	Three Months Ended
	March 31
(in Millions)	2011			2010
Operating Revenues	$	689		$	755
Cost of Gas		406			464
Gross Margin		283			291
Operation and Maintenance		101			109
Depreciation and Amortization		22			26
Taxes Other Than Income		17			17
Operating Income		143			139
Other (Income) and Deductions		13			16
Income Tax Provision		47			44
Net Income Attributable to DTE Energy Company	$	83		$	79
Operating Income as a Percentage of Operating Revenues		21	%		18	%

Gross margin decreased $8 million in the first quarter of 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
Uncollectible tracker mechanism	$	(23	)
2010 self implementation and rate order		(20	)
Weather		26
Revenue decoupling mechanism		10
Energy optimization revenue and incentive		6
Midstream storage and transportation revenues		(4	)
Other		(3	)
Decrease in gross margin	$	(8	)

	Three Months Ended
	March 31
	2011		2010
Gas Markets (in Millions)
Gas sales	$	571	$	638
End user transportation		77		73
Intermediate transportation		15		15
Storage and other		26		29
	$	689	$	755
Gas Markets (in Bcf)
Gas sales		62		57
End user transportation		52		44
		114		101
Intermediate transportation		83		99
		197		200

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Operation and maintenance expense decreased $8 million in the first quarter of 2011 due to $13 million of reduced uncollectible expenses, partially offset by increased maintenance and service repair expenses of $3 million and increased energy optimization expenses of $3 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, volatility in gas prices, 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
	March 31
(in Millions)	2011			2010
Operating Revenues	$	25		$	21
Operation and Maintenance		4			4
Depreciation and Amortization		1			1
Taxes Other Than Income		1			—
Operating Income		19			16
Other (Income) and Deductions		(7	)		(8	)
Income Tax Provision		10			9
Net Income		16			15
Noncontrolling interest		1			1
Net Income Attributable to DTE Energy Company	$	15		$	14

Net income attributable to Gas Storage and Pipelines increased $1 million in the first quarter of 2011 due primarily to 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 opportunities across its business lines. We have entered into a Letter of Intent with a natural gas exploration and production company to construct pipeline and gathering assets which will transport gas from the counterparty’s Marcellus Shale acreage. Terms of the definitive agreement are currently being negotiated. The project is expected to be operational in 2012.

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.

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Unconventional Gas Production results are discussed below:

	Three Months Ended
	March 31
(in Millions)	2011			2010
Operating Revenues	$	8		$	8
Operation and Maintenance		4			4
Depreciation, Depletion and Amortization		4			4
Taxes Other Than Income		1			—
Asset (Gains) and Losses, Net		—			4
Operating Income (Loss)		(1	)		(4	)
Other (Income) and Deductions		2			1
Income Tax Provision (Benefit)		(1	)		(2	)
Net Income (Loss) Attributable to DTE Energy Company	$	(2	)	$	(3	)

Unconventional Gas Production results were consistent with those of the prior period with the exception of a $4 million impairment of expired or expiring leasehold positions in the first quarter of 2010.

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 additional monetization of select properties when conditions are appropriate. Our strategy for 2011 is to maintain our focus on optimizing the productivity of our wells, which adds value to our asset base. Given the current outlook of low natural gas prices, drilling efforts will continue to target liquids rich gas and oil production. During 2011, we expect total capital investment of $25 million to drill approximately 20 new wells and continue to acquire select acreage and achieve production of approximately 6 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:

	Three Months Ended
	March 31
(in Millions)	2011			2010
Operating Revenues	$	235		$	252
Operation and Maintenance		206			214
Depreciation and Amortization		15			15
Taxes Other Than Income		4			4
Asset (Gains) Losses and Reserves and Impairments, Net		(9	)		(2	)
Operating Income		19			21
Other (Income) and Deductions		3			3
Income Taxes
Provision (Benefit)		6			7
Production Tax Credits		(1	)		(7	)
		5			—
Net Income		11			18
Noncontrolling Interests		1			—
Net Income Attributable to DTE Energy Company	$	10		$	18

Operating revenues decreased $17 million in the first quarter of 2011primarily due to $47 million of lower coal transportation and marketing services, partially offset by a $23 million increase in coke demand under contracted pricing, a $5 million increase in on-site energy services and a $2 million increase in waste-wood power generation.

Operation and maintenance expense decreased $8 million in the first quarter of 2011 primarily due to $40 million of lower coal transportation and marketing services, partially offset by a $30 million increase in coke demand under contracted pricing and a $2 million increase in waste-wood power generation.

Asset (Gains) Losses were higher by $7 million in 2011 due primarily due to gains from the sale of a coke battery.

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Production tax credits were lower by $6 million in 2011 due primarily due 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. Beginning in 2011, substantially all of the metallurgical coke is under long-term contracts. The tax credits associated with our steel industry fuels facilities expired at December 31, 2010 resulting in lower tax credits of approximately $29 million in 2011. We supply on-site energy services to the domestic automotive manufacturers who have also experienced stabilized demand for automobiles. Our on-site energy services will continue to be delivered in accordance with the terms of long-term contracts. In March 2011, the Company acquired a cogeneration facility and will provide electric and steam to customers in the chemical industry.

In late 2009, we began operating reduced emission fuel facilities located at Detroit Edison owned coal-fired power plants. The facilities reduce Nitrogen Oxides (NO_X) and Mercury (Hg) emissions and qualify for production tax credits when the fuel is sold to an unrelated party through 2019. We continue to optimize these facilities by seeking investors for facilities operating at Detroit Edison sites and intend to relocate other facilities to alternative sites which may provide increased production and emission 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 will convert and place into service two 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.

Effective January 1, 2011, our existing long-term rail transportation contract, at rates significantly below the current market, expired and we anticipate a decrease in transportation-related revenue of approximately $130 million as a result. The decrease in revenue will be mostly offset by lower variable costs incurred to provide the transportation.

We will continue to work with suppliers and the railroads to promote secure and competitive access to coal to meet the energy requirements of our customers. 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 which may include the management of associated storage and transportation contracts on the customers’ behalf.

Energy Trading results are discussed below:

	Three Months Ended
	March 31
(in Millions)	2011		2010
Operating Revenues	$	322	$	286
Fuel, Purchased Power and Gas		296		197
Gross Margin		26		89
Operation and Maintenance		19		19
Depreciation, Depletion and Amortization		1		1
Taxes Other Than Income		1		2
Operating Income		5		67
Other (Income) and Deductions		2		4
Income Tax Provision		1		25
Net Income Attributable to DTE Energy Company	$	2	$	38

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Gross margin decreased $63 million in the first quarter of 2011 as compared to the same period in 2010. The overall decrease in gross margin for the first quarter of 2011 was the result of lower economic performance due in part to lower volatility in the markets we participate in compared to the same period in 2010. We experienced timing-related earnings volatility based on market movement related to derivative contracts. The first quarter of 2011 decrease represents a $47 million decrease in unrealized margins and a $16 million decrease in realized margins. The $47 million decrease in unrealized margins is due to $62 million of unfavorable results, primarily in our power trading and gas trading strategies, and the absence of prior year timing-related gains in our power transmission strategy. This was offset by $15 million of favorable results, primarily in our gas full requirements strategy. The $16 million decrease in realized margins is due to $28 million of unfavorable results, primarily in our power full requirements and gas trading strategies, offset by $12 million of favorable results, primarily in our power trading strategy.

Income tax provision decreased $24 million in the first quarter of 2011 as compared to the same period in 2010. This decrease is due to a decrease in income taxes attributable to lower pretax income in 2011.

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 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 which may include the management of associated storage and transportation contracts on the customers’ behalf. 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 that follows.

CORPORATE & OTHER

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

The net loss for the first quarter of 2011 increased by $9 million due primarily to an unfavorable effective income tax rate adjustment of $6 million in 2011 and a favorable settlement of state and local taxes of $6 million in 2010, partially offset by lower interest expense of $3 million.

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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.

	Three Months Ended
	March 31
(in Millions)	2011			2010
Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	178		$	230
Depreciation, depletion and amortization		245			251
Deferred income taxes		48			36
Asset (gains), losses and reserves, net		11			1
Working capital and other		240			299
		722			817
Investing activities:
Plant and equipment expenditures — utility		(253	)		(209	)
Plant and equipment expenditures — non-utility		(17	)		(30	)
Proceeds from sale of other assets, net		4			13
Consolidation of VIE’s		—			19
Other		22			36
		(244	)		(171	)
Financing activities:
Redemption of long-term debt		(94	)		(90	)
Short-term borrowings, net		(150	)		(327	)
Issuance of common stock		—			9
Repurchase of common stock		(9	)		—
Dividends on common stock and other		(93	)		(97	)
		(346	)		(505	)
Net Increase in Cash and Cash Equivalents	$	132		$	141

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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 three months ended March 31, 2011 decreased $95 million from the comparable 2010 period primarily due to lower net income and lower cash provided by working capital. Increased pension and other postretirement benefit contributions and the payment of certain regulatory liabilities, partially offset by increased income tax refunds, contributed to the lower working capital cash. See Note 14 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 three months ended March 31, 2011 by $73 million primarily due to increased utility capital expenditures and increased non-utility investments, partially offset by the prior year impact of the consolidation of VIE’s. See Note 1 of the Notes to Consolidated Financial Statements.

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 $159 million during the three months ended March 31, 2011 due to decreased payments for net 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 underrecoveries 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.

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Detroit Edison filed a rate case on October 29, 2010 based on a projected twelve-month period ending March 31, 2012. The filing with the MPSC requested a $443 million increase in base rates. Detroit Edison also proposed certain adjustments which could reduce the net impact on the required increase in rates by approximately $190 million. Detroit Edison plans to self-implement $107 million of its requested annual increase on April 28, 2011. This increase will remain in place until a final order is issued by the MPSC, which is expected by October 2011. If the final rate case order does not support the self-implemented rate increase, Detroit Edison must refund the difference with interest.

We have approximately $900 million in long-term debt maturing in the next twelve months. DTE Energy has $600 million of unsecured debt maturing in June 2011 which is expected to be funded through a combination of internally generated funds and short-term debt. Substantially all of the remaining debt maturities relate to Securitization and other Detroit Edison issues. 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 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 has approximately $1.8 billion of available liquidity at March 31, 2011.

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 $90 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 $100 million to $200 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 cash flows.

See Notes 7, 9, 10, and 12 of the Notes to the Consolidated Financial Statements.

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 4 and 5 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.

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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 4 of the Notes to Consolidated Financial Statements.

The following tables provide details on changes in our MTM net asset (or liability) position for the three months ended March 31, 2011:

(in Millions)	Total
MTM at December 31, 2010	$	(44	)
Reclassify to realized upon settlement		(37	)
Changes in fair value recorded to income		(1	)
Amounts recorded to unrealized income		(38	)
Change in collateral held by (for) others		45
Option premiums paid and other		1
MTM at March 31, 2011	$	(36	)

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	$	(25	)	$	(23	)	$	11		$	11	$	(26	)
Level 2		(49	)		(34	)		(34	)		3		(114	)
Level 3		5			11			—			—		16
Total MTM before collateral adjustments	$	(69	)	$	(46	)	$	(23	)	$	14	$	(124	)
Collateral adjustments												$	88
Total MTM at March 31, 2011												$	(36	)

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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 and other risks associated with the weakened U.S. economy. 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

We have tracking mechanisms to mitigate a significant amount of losses related to uncollectible accounts receivable at Detroit Edison and MichCon. These mechanisms are subject to the jurisdiction of the MPSC and are periodically reviewed. See Note 7 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.

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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 March 31, 2011:

	Credit Exposure
	Before Cash		Cash			Net Credit
(in Millions)	Collateral		Collateral			Exposure
Investment Grade(1)
A- and Greater	$	182	$	(5	)	$	177
BBB+ and BBB		212		—			212
BBB-		107		—			107
Total Investment Grade		501		(5	)		496
Non-investment grade(2)		7		—			7
Internally Rated — investment grade(3)		167		—			167
Internally Rated — non-investment grade(4)		16		—			16
Total	$	691	$	(5	)	$	686

(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 28 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 approximately 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 19 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 2 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 March 31, 2011, we had a floating rate debt-to-total debt ratio of less than one 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 January 2013. Additionally, we may enter into fair value foreign currency exchange hedges to mitigate changes in the value of contracts or loans.

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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 March 31, 2011 and March 31, 2010 by a hypothetical 10% and calculating the resulting change in the fair values.

The results of the sensitivity analysis calculations as of March 31, 2011 and March 31, 2010:

	Assuming a						Assuming a
	10% Increase in Rates						10% Decrease in Rates
(in Millions)	As of March 31,						As of March 31
Activity	2011			2010			2011		2010			Change in the Fair Value of
Coal Contracts	$	1		$	—		$	—	$	—		Commodity contracts
Gas Contracts		(10	)		3			10		(2	)	Commodity contracts
Power Contracts		(12	)		(4	)		12		6		Commodity contracts
Interest Rate Risk		(288	)		(286	)		309		308		Long-term debt
Foreign Currency Exchange Risk		9			4			4		(4	)	Forward contracts
Discount Rates		—			—			—		—		Commodity contracts

For further discussion of market risk, see Note 5 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 March 31, 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 March 31, 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

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

In July 2009, DTE Energy received a Notice of Violation/Finding of Violation (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 operating permit requirements under the Clean Air Act. In June 2010, the 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 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 and the liability phase of the civil suit has been scheduled for trial in September 2011.

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 and the result of the civil action, 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 this matter, or the timing of its resolution.

For additional discussion on legal matters, see Note 11 of the Notes to Consolidated Financial Statements.

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 delay or

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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 March 31, 2011:

					Total Number of		Maximum Dollar
					Shares Purchased		Value that May Yet
	Total Number		Average		as Part of Publicly		Be Purchased Under
	of Shares		Price Paid		Announced Plans		the Plans or
Period	Purchased(1)		Per Share		or Programs		Programs
01/01/11 — 01/31/11		13,893	$	45.30		—		—
02/01/11 — 02/28/11		631,238		46.81		—		—
03/01/11 — 03/31/11		25,302		42.28		—		—
Total		670,433				—		—

(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:
12-47	Computation of Ratio of Earnings to Fixed Charges
31-65	Chief Executive Officer Section 302 Form 10-Q Certification
31-66	Chief Financial Officer Section 302 Form 10-Q Certification

Exhibits incorporated herein by reference:

4-268   Supplemental Indenture, dated as of March 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 4-274 to Detroit Edison’s Form 10-Q for the quarter ended March 31, 2011). (2011 Series AT)

Exhibits furnished herewith:

32-65	Chief Executive Officer Section 906 Form 10-Q Certification
32-66	Chief Financial Officer Section 906 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

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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: April 27, 2011	/S/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer

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EX-12.47

Exhibit 12-47

DTE ENERGY COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Three Months
	Ended March 31				Twelve Months Ended December 31
	2011		2010		2009		2008			2007			2006
(Millions of Dollars)
Earnings:
Pretax earnings	$	279	$	944	$	782	$	819		$	1,155		$	536
Adjustments		2		1		4		(3	)		(4	)		(4	)
Fixed charges		131		567		572		540			562			558
Net earnings	$	412	$	1,512	$	1,358	$	1,356		$	1,713		$	1,090
Fixed charges:
Interest expense	$	125	$	543	$	545	$	503		$	533		$	525
Adjustments		6		24		27		37			29			33
Fixed charges	$	131	$	567	$	572	$	540		$	562		$	558
Ratio of earnings to fixed charges		3.15		2.67		2.37		2.51			3.05			1.95

EX-31.65

Exhibit 31-65

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: April 27, 2011
Gerard M. Anderson
President and Chief Executive Officer of DTE Energy Company

EX-31.66

Exhibit 31-66

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: April 27, 2011
David E. Meador
Executive Vice President and Chief Financial Officer of DTE Energy Company

EX-32.65

Exhibit 32-65

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 March 31, 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: April 27, 2011	/S/ GERARD M. ANDERSON
	Gerard M. Anderson
	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-32.66

Exhibit 32-66

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 March 31, 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: April 27, 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.