Edgar Filing: DTE ENERGY CO

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended September 30, 2009

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 September 30, 2009, 164,928,049 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 September 30, 2009

TABLE OF CONTENTS


	Page
Definitions		1

Forward-Looking Statements		3

Part I — Financial Information

Item 1. Financial Statements

Consolidated Statements of Financial Position (Unaudited)		5

Consolidated Statements of Operations (Unaudited)		7

Consolidated Statements of Cash Flows (Unaudited)		8

Consolidated Statements of Changes in Shareholders’ 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		56

Item 4. Controls and Procedures		59

Part II — Other Information

Item 1. Legal Proceedings		60

Item 1A. Risk Factors		60

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		61

Item 6. Exhibits		62

Signature		63

EX-12.44
EX-31.53
EX-31.54
EX-32.53
EX-32.54
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

Company		DTE Energy Company and any subsidiary companies

Customer Choice		Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas

Detroit Edison		The Detroit Edison Company (a direct wholly-owned subsidiary of DTE Energy) 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

FSP		FASB Staff Position

FTRs		Financial Transmission Rights

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, a Regional Transmission Organization

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 or the FERC.

NRC		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.

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 expenses.

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.


SFAS		Statement of Financial Accounting Standards

Subsidiaries		The direct and indirect subsidiaries of DTE Energy Company

Synfuels		The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production through December 31, 2007 generated production tax credits.

Unconventional Gas		Includes those oil and gas deposits that originated and are stored in coal bed, tight sandstone and shale formations

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

GWh		Gigawatthour of electricity

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MMcf		Million cubic feet of gas

MW		Megawatt of electricity

MWh		Megawatthour of electricity

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:

•

the length and severity of ongoing economic decline resulting in lower demand, customer conservation and increased thefts of electricity and gas;

•

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

•

high levels of uncollectible accounts receivable;

•

access to capital markets and capital market conditions 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;

•

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

•

the timing and extent of changes in interest rates;

•

the level of borrowings;

•

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

•

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

•

economic climate and population growth or decline in the geographic areas where we do business;

•

environmental issues, laws, regulations, and the increasing costs of remediation and compliance, including actual and potential new federal and state requirements that include or could include carbon and more stringent mercury emission controls, a renewable portfolio standard, energy efficiency mandates, and a carbon tax or cap and trade structure;

•

nuclear regulations and operations associated with 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 gas shale resources and challenges in estimating gas reserves with certainty;

•

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;

•

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.

DTE Energy Company

Consolidated Statements of Financial Position (Unaudited)

Part 1 — Item 1.


	September 30			December 31
(in Millions)	2009			2008

ASSETS
Current Assets
Cash and cash equivalents	$	83		$	86
Restricted cash		28			86
Accounts receivable (less allowance for doubtful accounts of $288 and $265, respectively)
Customer		1,105			1,666
Other		112			166
Inventories
Fuel and gas		383			333
Materials and supplies		202			206
Deferred income taxes		226			227
Derivative assets		271			316
Other		244			242

		2,654			3,328


Investments
Nuclear decommissioning trust funds		791			685
Other		630			595

		1,421			1,280


Property
Property, plant and equipment		20,505			20,065
Less accumulated depreciation and depletion		(8,110	)		(7,834	)

		12,395			12,231


Other Assets
Goodwill		2,037			2,037
Regulatory assets		4,029			4,231
Securitized regulatory assets		905			1,001
Intangible assets		57			70
Notes receivable		114			115
Derivative assets		163			140
Other		184			157

		7,489			7,751


Total Assets	$	23,959		$	24,590

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statements of Financial Position (Unaudited)


	September 30			December 31
(in Millions, Except Shares)	2009			2008

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	578		$	899
Accrued interest		149			119
Dividends payable		87			86
Short-term borrowings		205			744
Current portion long-term debt, including capital leases		170			362
Derivative liabilities		257			285
Other		530			518

		1,976			3,013


Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		6,738			6,458
Securitization bonds		793			932
Trust preferred-linked securities		289			289
Capital lease obligations		54			62

		7,874			7,741


Other Liabilities
Deferred income taxes		2,091			1,958
Regulatory liabilities		1,251			1,202
Asset retirement obligations		1,405			1,340
Unamortized investment tax credit		88			96
Derivative liabilities		252			344
Liabilities from transportation and storage contracts		100			111
Accrued pension liability		776			871
Accrued postretirement liability		1,424			1,434
Nuclear decommissioning		131			114
Other		319			328

		7,837			7,798


Commitments and Contingencies (Notes 5 and 9)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 164,928,049 and 163,019,596 shares issued and outstanding, respectively		3,235			3,175
Retained earnings		3,142			2,985
Accumulated other comprehensive loss		(141	)		(165	)

Total DTE Energy Company Shareholders’ Equity		6,236			5,995
Noncontrolling interests		36			43

Total Equity		6,272			6,038

Total Liabilities and Equity	$	23,959		$	24,590

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Operations (Unaudited)


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions, Except per Share Amounts)	2009			2008			2009			2008

Operating Revenues	$	1,961		$	2,338		$	5,904		$	7,159


Operating Expenses
Fuel, purchased power and gas		735			1,034			2,272			3,332
Operation and maintenance		554			628			1,740			2,081
Depreciation, depletion and amortization		266			235			738			677
Taxes other than income		63			71			204			229
Gain on sale of non-utility assets		—			—			—			(128	)
Other asset (gains) and losses, reserves and impairments, net		—			(5	)		(3	)		7

		1,618			1,963			4,951			6,198


Operating Income		343			375			953			961


Other (Income) and Deductions
Interest expense		143			125			409			371
Interest income		(11	)		(5	)		(17	)		(13	)
Other income		(28	)		(34	)		(74	)		(74	)
Other expenses		8			22			17			45

		112			108			335			329


Income Before Income Taxes		231			267			618			632

Income Tax Provision		73			97			197			231


Income from Continuing Operations		158			170			421			401

Discontinued Operations Income, net of tax		—			8			—			22


Net Income		158			178			421			423

Less: Net Income Attributable to Noncontrolling Interests From
Continuing operations		—			1			2			4
Discontinued operations		—			—			—			2

		—			1			2			6

Net Income Attributable to DTE Energy Company	$	158		$	177		$	419		$	417


Basic Earnings per Common Share
Income from continuing operations	$	0.96		$	1.03		$	2.55		$	2.43
Discontinued operations		—			.05			—			.12

Total	$	0.96		$	1.08		$	2.55		$	2.55


Diluted Earnings per Common Share
Income from continuing operations	$	0.96		$	1.03		$	2.55		$	2.43
Discontinued operations		—			.05			—			.12

Total	$	0.96		$	1.08		$	2.55		$	2.55


Weighted Average Common Shares Outstanding
Basic		165			163			164			163
Diluted		165			163			164			163
Dividends Declared per Common Share	$	.53		$	.53		$	1.59		$	1.59

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended
	September 30
(in Millions)	2009			2008

Operating Activities
Net income	$	421		$	423
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		738			675
Deferred income taxes		141			280
Gain on sale of non-utility assets		—			(128	)
Other asset (gains), losses and reserves, net		4			12
Gain on sale of interests in synfuel projects		—			(31	)
Contributions from synfuel partners		—			14
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		370			(227	)

Net cash from operating activities		1,674			1,018


Investing Activities
Plant and equipment expenditures — utility		(772	)		(842	)
Plant and equipment expenditures — non-utility		(47	)		(154	)
Proceeds from sale of interests in synfuel projects		—			84
Refunds to synfuel partners		—			(387	)
Proceeds from sale of non-utility assets		—			253
Proceeds from sale of other assets, net		35			21
Restricted cash for debt redemptions		58			104
Proceeds from sale of nuclear decommissioning trust fund assets		237			180
Investment in nuclear decommissioning trust funds		(251	)		(202	)
Other investments		(55	)		(105	)

Net cash used for investing activities		(795	)		(1,048	)


Financing Activities
Issuance of long-term debt		363			1,013
Redemption of long-term debt		(420	)		(446	)
Repurchase of long-term debt		—			(238	)
Short-term borrowings, net		(574	)		71
Issuance of common stock		27			—
Repurchase of common stock		—			(16	)
Dividends on common stock		(260	)		(258	)
Other		(18	)		(7	)

Net cash from (used) for financing activities		(882	)		119


Net Increase (Decrease) in Cash and Cash Equivalents		(3	)		89
Cash and Cash Equivalents Reclassified from Assets Held for Sale		—			11
Cash and Cash Equivalents at Beginning of Period		86			123

Cash and Cash Equivalents at End of Period	$	83		$	223

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statements of Changes in Shareholders’ Equity and
Comprehensive Income (Unaudited)


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

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

Net income		—		—		419			—			2			421
Benefit obligations, net of tax		—		—		—			7			—			7
Foreign currency translation, net of tax		—		—		—			2			—			2
Dividends declared on common stock		—		—		(262	)		—			—			(262	)
Issuance of common stock		862		27		—			—			—			27
Net change in unrealized losses on derivatives, net of tax		—		—		—			1			—			1
Net change in unrealized losses on investments, net of tax		—		—		—			14			—			14
Stock-based compensation, distributions to noncontrolling interests and other		1,046		33		—			—			(9	)		24

Balance, September 30, 2009		164,928	$	3,235	$	3,142		$	(141	)	$	36		$	6,272

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


(in Millions)	2009			2008

Net income	$	421		$	423

Other comprehensive income (loss), net of tax:
Benefit obligations, net of taxes of $4		7			—
Foreign currency translation, net of taxes of $1		2			—
Net unrealized gains (losses) on derivatives:
Gains (losses) during the period, net of taxes of $1 and $-, respectively		2			(1	)
Amounts reclassified to income, net of taxes of $(1) and $2, respectively		(1	)		3

		1			2


Net unrealized gains (losses) on investments:
Gains (losses) during the period, net of taxes of $8 and $(9), respectively		14			(17	)

Comprehensive income		445			408


Less: Comprehensive income attributable to noncontrolling interests		2			6

Comprehensive income attributable to DTE Energy Company	$	443		$	402

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Notes to Consolidated Financial Statements (Unaudited)

NOTE 1 — GENERAL

The Company is a diversified energy company. It 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. The Company also operates four energy-related non-utility segments with operations throughout the United States.

These Consolidated Financial Statements should be read in conjunction with the Notes to Consolidated Financial Statements included in the 2008 Annual Report on Form 10-K, as updated to reflect certain accounting changes on Form 8-K dated August 20, 2009.

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 our 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, 2009.

Certain prior year amounts have been reclassified to reflect current year classifications.

Asset Retirement Obligations

The Company has a legal retirement obligation for the decommissioning costs for its Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, the Company has legal retirement obligations for gas production facilities, gas gathering facilities and various other operations. The Company has conditional retirement obligations for gas pipeline retirement costs and disposal of asbestos at certain of its power plants. To a lesser extent, the Company has conditional retirement obligations at certain service centers, compressor and gate stations, and disposal costs for PCB contained within transformers and circuit breakers. The Company recognizes such obligations as liabilities at fair market value when they are incurred, which generally is at the time the associated assets are placed in service. Fair value is measured using expected future cash outflows discounted at our credit-adjusted risk-free rate. In its regulated operations, the Company defers timing differences that arise in the expense recognition of legal asset retirement costs that are currently recovered in rates.

A reconciliation of the asset retirement obligations for the nine months ended September 30, 2009 follows:


(in Millions)
Asset retirement obligations at January 1, 2009	$	1,361
Accretion		66
Liabilities settled		(10	)
Revision in estimated cash flows		5

Asset retirement obligations at September 30, 2009		1,422
Less amount included in current liabilities		17

	$	1,405

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

Goodwill

We performed our annual goodwill impairment test as of October 1, 2008 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. In the period from October 1, 2008 to March 31, 2009, DTE Energy’s stock price declined 31 percent and at March 31, 2009 was approximately 26 percent below its book value per share of $37.29. We deemed the duration and severity of the decline in DTE Energy’s stock price to be a triggering event to test for potential goodwill impairment for the first quarter. In performing Step 1 of the impairment test, we compared the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including goodwill were to exceed the fair value of a reporting unit, Step 2

of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date. All reporting units passed Step 1 of the impairment test.

For the quarters ended June 30, 2009 and September 30, 2009, DTE Energy’s closing stock price increased 16 percent and 27 percent, respectively, as compared to the closing stock price at March 31, 2009. Although DTE is still trading at a discount to book value at the end of the third quarter, the discount improved to 7 percent at September 30, 2009 from 26 percent at March 31, 2009. In assessing whether the continuing discount to book value was an indication of impairment, we considered the following factors: (1) the severity of the decline in DTE Energy’s share price experienced since the fourth quarter of 2008 has diminished and is continuing to recover; and (2) the assumptions incorporated in the first quarter impairment test have either improved or have not changed significantly during the second and third quarters such that they would change the results of Step 1. As a result of this assessment, we determined that the continuing discount to book value was not a triggering event for impairment testing purposes for the second and third quarters.

We did, however, identify a goodwill impairment test trigger for our Energy Services reporting unit related to the long-lived asset impairment tests that were performed during the second quarter of 2009 on certain automotive-related project companies. Accordingly, we performed an interim goodwill impairment test for Energy Services as of June 30, 2009. The fair value of the reporting unit exceeded its carrying value including goodwill. Therefore, the reporting unit passed Step 1 of the impairment test. No new trigger was identified during the third quarter of 2009.

Intangible Assets

The Company has certain intangible assets relating to emission allowances and non-utility contracts. Emission allowances are charged to expense as the allowances are consumed in the operation of the business. The Company amortizes contract intangible assets on a straight-line basis over the expected period of benefit, ranging from 4 to 30 years. The gross carrying amount and accumulated amortization of intangible assets at September 30, 2009 were $75 million and $18 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2008 were $85 million and $15 million, respectively. Amortization expense of intangible assets is estimated to be $4 million annually for the years 2009 through 2013.

Retirement Benefits and Trusteed Assets

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


							Other Postretirement
Three Months Ended September 30	Pension Benefits						Benefits
(in Millions)	2009			2008			2009			2008
Service cost	$	13		$	13		$	15		$	15
Interest cost		51			48			33			30
Expected return on plan assets		(64	)		(64	)		(14	)		(19	)
Amortization of:
Net actuarial loss		13			8			18			10
Prior service cost		2			1			(2	)		(2	)
Net transition liability		—			—			1			1

Net periodic benefit cost	$	15		$	6		$	51		$	35


							Other Postretirement
Nine Months Ended September 30	Pension Benefits						Benefits
(in Millions)	2009			2008			2009			2008
Service cost	$	40		$	41		$	44		$	46
Interest cost		152			143			100			91
Expected return on plan assets		(191	)		(194	)		(42	)		(57	)
Amortization of:
Net actuarial loss		39			24			54			29
Prior service cost		4			4			(5	)		(5	)
Net transition liability		—			—			2			2

Net periodic benefit cost	$	44		$	18		$	153		$	106

The Company expects to contribute up to $250 million to its pension plans during 2009. A $20 million contribution was made to the plans in the third quarter of 2009 and approximately $90 million of contributions were made to the plans in the nine-month period ended September 30, 2009.

The Company expects to contribute up to $170 million to its postretirement medical and life insurance benefit plans during 2009. No contributions were made in the third quarter of 2009. Approximately $40 million of contributions were made to the plans in the nine-month period ended September 30, 2009.

Income Taxes

The Company’s effective tax rate from continuing operations for the three months ended September 30, 2009 was 32 percent as compared to 36 percent for the three months ended September 30, 2008, and for the nine months ended September 30, 2009 was 32 percent as compared to 37 percent for the nine months ended September 30, 2008. The 2009 rate is lower than 2008 due primarily to the recognition of tax benefits from the settlement of tax audits.

The Company had $8 million of unrecognized tax benefits at September 30, 2009 and $18 million at December 31, 2008 that, if recognized, would favorably impact its effective tax rate. During the quarter ended June 30, 2009, the Company settled a federal tax audit for the 2004 through 2006 tax years, which resulted in the recognition of $9 million of unrecognized tax benefits. During the next twelve months, it is reasonably possible that the Company will settle certain state examinations and audits. Furthermore, the statutes of limitations will expire for the Company’s tax returns in various states. Therefore, the Company believes that it is reasonably possible that there will be a decrease in unrecognized tax benefits of $1 million to $2 million within the next twelve months.

Stock-Based Compensation

The Company’s stock incentive program permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. Participants in the Plan include the Company’s employees and members of its Board of Directors.

The Company recorded stock-based compensation expense of $14 million and $8 million, with an associated tax benefit of $5 million and $3 million for the three months ended September 30, 2009 and 2008, respectively. The Company recorded stock-based compensation expense of $27 million and $33 million, with an associated tax benefit of $10 million and $12 million for the nine months ended September 30, 2009 and 2008, respectively. Stock-based compensation cost capitalized in property, plant and equipment was $0.8 million and $0.4 million during the three months ended September 30, 2009 and 2008, respectively. Stock-based compensation cost capitalized in property, plant and equipment was $1.7 million and $1.4 million during the nine months ended September 30, 2009 and 2008, respectively.

Stock Options

The following table summarizes our stock option activity for the nine months ended September 30, 2009:


						(in Millions)
				Weighted		Aggregate
	Number of			Average		Intrinsic
	Options			Exercise Price		Value
Options outstanding at January 1, 2009		5,013,699		$	42.45
Granted		812,500		$	27.75
Exercised		(36,495	)	$	31.24
Forfeited or expired		(131,250	)	$	40.81

Options outstanding at September 30, 2009		5,658,454		$	40.44	$	5.3

Options exercisable at September 30, 2009		4,190,771		$	42.50	$	0.1

As of September 30, 2009, the weighted average remaining contractual life for the exercisable shares was 4.38 years. As of September 30, 2009, 1,467,683 options were non-vested. During the nine months ended September 30, 2009, 588,105 options vested.

The weighted average grant date fair value of options granted during the nine months ended September 30, 2009 was $4.41 per share. The intrinsic value of options exercised for the nine months ended September 30, 2009 was

$0.1 million. Total option expense recognized was $3 million in the nine months ended September 30, 2009 and 2008.

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


	Nine Months Ended
	September 30, 2009			September 30, 2008
Risk-free interest rate		2.04	%		3.05	%
Dividend yield		4.98	%		5.20	%
Expected volatility		27.88	%		20.45	%

Expected life	6 years			6 years

Restricted Stock Awards

The following summarizes restricted stock award activity for the nine months ended September 30, 2009:


				Weighted Average
	Restricted			Grant Date
	Stock			Fair Value
Balance at January 1, 2009		931,722		$	45.31
Grants		515,610		$	28.63
Forfeitures		(22,669	)	$	39.37
Vested and issued		(393,060	)	$	45.07

Balance at September 30, 2009		1,031,603		$	37.19

Performance Share Awards

The following summarizes performance share activity for the nine months ended September 30, 2009:


	Performance Shares
Balance at January 1, 2009		1,321,501
Grants		564,340
Forfeitures		(34,102	)
Payouts		(390,656	)

Balance at September 30, 2009		1,461,083

Unrecognized Compensation Cost

As of September 30, 2009, the Company had $40 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 1.29 years.

Offsetting Amounts Related to Certain Contracts

The Company offsets the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting agreement, which reduces both the Company’s total assets and total liabilities. As of September 30, 2009, the total cash collateral received, net of cash collateral posted, was $15 million. Derivative assets and derivative liabilities are shown net of collateral of $45 million and $28 million, respectively. At September 30, 2009, amounts of cash collateral received or paid not related to unrealized derivative positions totaling $3 million and $1 million were included in accounts receivable and accounts payable, respectively.

Consolidated Statements of Cash Flows

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


	Nine Months Ended
	September 30
(in Millions)	2009			2008
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	527		$	456
Accrued GCR revenue		25			(102	)
Inventories		(47	)		(134	)
Accrued/prepaid pensions		(94	)		(15	)
Accounts payable		(214	)		(221	)
Accrued PSCR refund		56			22
Exchange gas payable		(1	)		(35	)
Income taxes payable		80			(31	)
General taxes		(11	)		2
Derivative assets and liabilities		(99	)		(103	)
Deferred gains from asset sales		—			39
Postretirement obligation		(10	)		(30	)
Other assets		97			(67	)
Other liabilities		61			(8	)

	$	370		$	(227	)

In connection with maintaining certain traded risk management positions, the Company may be required to post cash collateral with its clearing agent. For a further discussion of this arrangement, see Note 8.

Subsequent Events

The Company has evaluated subsequent events through October 30, 2009, the date that these financial statements were issued.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

FASB Accounting Standards Codification™ (Codification)

In June 2009, the FASB voted to approve that on July 1, 2009, the Codification will become the single source of authoritative nongovernmental U.S. GAAP. The Codification is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes two levels of guidance — authoritative and non-authoritative. According to the FASB, all “non-grandfathered, non-SEC accounting literature” that is not included in the Codification would be considered non-authoritative. The FASB has indicated that the Codification does not change current GAAP. Instead, the proposed changes aim to (1) reduce the time and effort it takes for users to

research accounting questions and (2) improve the usability of current accounting standards. The Codification is effective for interim and annual periods ending after September 15, 2009.

Fair Value Accounting

In September 2006, the FASB issued ASC 820 (SFAS No. 157, Fair Value Measurements). The standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. It emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Fair value measurement should be determined based on the assumptions that market participants would use in pricing an asset or liability. Effective January 1, 2008, the Company adopted ASC 820 (SFAS No. 157). As permitted by ASC 820-10 (FSP No. 157-2), the Company elected to defer the effective date of the standard as it pertains to measurement and disclosures about the fair value of non-financial assets and liabilities made on a nonrecurring basis. The Company has adopted the recognition provisions for non-financial assets and liabilities as of January 1, 2009. See Note 3.

In April 2009, the FASB issued three FSPs intended to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. The FSPs are effective for interim and annual periods ending after June 15, 2009.

•

ASC 825-10 (FSP No. 107-1 and APB No. 28-1), Interim Disclosures about Fair Value of Financial Instruments, expands the fair value disclosures required for all financial instruments within the scope of SFAS No. 107 to interim periods.

•

ASC 820-10 (FSP No. 157-4), Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which applies to all assets and liabilities, i.e., financial and nonfinancial, reemphasizes that the objective of fair value remains unchanged (i.e., an exit price notion). The FSP provides application guidance on measuring fair value when the volume and level of activity has significantly decreased and identifying transactions that are not orderly. The FSP also emphasizes that an entity cannot presume that an observable transaction price is not orderly even when there has been a significant decline in the volume and level of activity.

•

ASC 320-10 (FSP No. 115-2 and SFAS No. 124-2), Recognition and Presentation of Other-Than-Temporary Impairments, is intended to bring greater consistency to the timing of impairment recognition, and provide greater clarity to investors about the credit and noncredit components of impaired debt securities that are not expected to be sold.

The Company adopted these FSPs in the second quarter of 2009. The adoption of these FSPs did not have a significant impact on DTE Energy’s consolidated financial statements.

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

In June 2008, the FASB issued ASC 260-10 (FSP EITF No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities). This FSP addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in ASC 260-10, section 45, paragraphs 59A and 60B (SFAS No. 128, Earnings Per Share). Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. Stock awards granted by the Company under its stock-based compensation plan qualify as a participating security. This FSP is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and will be applied retrospectively. The Company adopted the requirements of the FSP effective January 1, 2009. See Note 6.

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued ASC 810-10 (SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51). This standard establishes accounting and reporting standards for the noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as

equity in the consolidated financial statements. The standard is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008. This standard shall be applied prospectively as of the beginning of the fiscal year in which this standard is initially applied, except for the presentation and disclosure requirements which shall be applied retrospectively for all periods presented. The Company adopted the standard as of January 1, 2009. Adoption of ASC 810-10 (SFAS No. 160) did not have a material effect on the Company’s consolidated financial statements.

Disclosures about Derivative Instruments and Guarantees

In March 2008, the FASB issued ASC 815-10 (SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133). This standard requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under ASC 815 (SFAS No. 133) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Comparative disclosures for earlier periods at initial adoption are encouraged but not required. The Company adopted the standard effective January 1, 2009. See Note 3.

Subsequent Events

In May 2009, the FASB issued ASC 855 (SFAS No. 165, Subsequent Events). This standard provides guidance on management’s assessment of subsequent events. The new standard clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” Management must perform its assessment for both interim and annual financial reporting periods. The standard does not significantly change the Company’s practice for evaluating such events. ASC 855 (SFAS No. 165) is effective prospectively for interim and annual periods ending after June 15, 2009 and requires disclosure of the date subsequent events are evaluated through. The Company adopted the standard during the quarter ended June 30, 2009. See Note 1.

Transfers of Financial Assets

In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets — an amendment of FASB No. 140 (not yet effective nor codified). This standard amends ASC 860, (SFAS No. 140), eliminates the concept of a “qualifying special-purpose entity” (QSPE) and associated guidance and creates more stringent conditions for reporting a transfer of a portion of a financial asset as a sale. SFAS No. 166 is intended to enhance reporting in the wake of the subprime mortgage crisis and the deterioration in the global credit markets. The standard is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009. Early adoption is prohibited. SFAS No. 166 must be applied prospectively to transfers of financial assets occurring on or after its effective date. The adoption of SFAS No. 166 will not have a material impact on DTE Energy’s consolidated financial statements.

Variable Interest Entities (VIE)

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation 46(R) (not yet effective nor codified). This standard amends the consolidation guidance that applies to VIEs and affects the overall consolidation analysis under ASC 810 -10(Interpretation 46(R)). The amendments to the consolidation guidance affect all entities and enterprises currently within the scope of ASC 810-10, as well as qualifying special purpose entities that are currently outside the scope of ASC 810-10. Accordingly, the Company will need to reconsider its previous ASC 810-10 conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required. SFAS No. 167 is effective as of the beginning of the first fiscal year that begins after November 15, 2009. Early adoption is prohibited. The Company is currently assessing the impact of SFAS No. 167 on DTE Energy’s consolidated financial statements.

Fair Value Measurements and Disclosures

In September and August 2009, respectively, the FASB issued Accounting Standards Update (ASU) 2009-12, Fair Value Measurements and Disclosure, and ASU 2009-05, Measuring Liabilities at Fair Value. ASU 2009-12 provides guidance for the fair value measurement of investments in certain entities that calculate the net asset value per share (or its equivalent) determined as of the reporting entity’s measurement date. Certain attributes of the investment (such as restrictions on redemption) and transaction prices from principal-to-principal or brokered transactions will not be considered in measuring the fair value of the investment. The amendments in this standard are effective for interim and annual periods ending after December 15, 2009.

ASU 2009-05 provides guidance on measuring the fair value of liabilities under ASC 820. This standard clarifies that in the absence of a quoted price in an active market for an identical liability at the measurement date, companies may apply approaches that use the quoted price of an investment in the identical liability or similar liabilities traded as assets or other valuation techniques consistent with the fair-value measurement principles in ASC 820. The standard permits fair value measurements of liabilities that are based on the price that a company would pay to transfer the liability to a new obligor. It also permits a company to measure the fair value of liabilities using an estimate of the price it would receive to enter into the liability at that date. The new standard is effective for interim and annual periods beginning after August 27, 2009 and applies to all fair-value measurements of liabilities required by GAAP. The Company is currently assessing the impact of ASU 2009-12 and ASU 2009-05 on DTE Energy’s consolidated financial statements.

Revenue Arrangements

In September 2009, the FASB ratified Issue No. 08-1, Revenue Arrangements with Multiple Deliverables (not yet codified). Issue 08-1 provides principles and application guidance on whether multiple deliverables exist, how the arrangement should be separated, and the consideration allocated. This standard shall be applied prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, with earlier application permitted. Alternatively, an entity may elect to adopt this standard on a retrospective basis. The Company is currently assessing the impact of Issue No. 08-1 on DTE Energy’s consolidated financial statements.

NOTE 3 — FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS AND FAIR VALUE

Financial and Other Derivative Instruments

The Company recognizes all derivatives on the Consolidated Statement of Financial Position at their fair value unless they qualify for certain scope exceptions, including normal purchases and normal sales exception. Further, derivatives that qualify and are designated for hedge accounting are classified as either hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), or as hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge). For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the value of the underlying exposure is deferred in Accumulated other comprehensive income and later reclassified into earnings when the underlying transaction occurs. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivatives that do not qualify or are not designated for hedge accounting, changes in the fair value are recognized in earnings each period.

The Company’s primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. The Company has risk management policies to monitor and 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 the Company typically classifies as derivative instruments include power, gas, oil and certain coal forwards, futures, options and swaps, and foreign currency contracts. Items not generally classified as derivatives include proprietary gas inventory, gas storage and transportation arrangements, and gas and oil reserves. The fair value of all derivatives is included in Derivative assets or liabilities on the Consolidated Statements of Financial Position.

Utility Operations

Detroit Edison — Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy and capacity contracts to manage changes in the price of electricity and fuel. 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 realized. This results in the deferral of unrealized gains and losses as Regulatory assets or liabilities, until realized.

MichCon — MichCon purchases, stores, transports and distributes natural gas and sells storage and transportation capacity. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2013. These gas-supply contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method. MichCon may also sell forward storage and transportation capacity contracts. Forward transportation and storage contracts are not derivatives and are therefore accounted for under the accrual method.

Non-Utility Operations

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 emissions 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.

Unconventional Gas Production — The Unconventional Gas Production business is engaged in unconventional gas project development and production. The Company uses derivative contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in Accumulated other comprehensive income will be reclassified to earnings as the related production affects earnings through 2010. Management estimates reclassifying an after-tax gain of approximately $1 million to earnings within the next twelve months.

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

Energy Trading — Foreign Currency Risk — Energy Trading has foreign currency forward contracts to economically hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation contracts. The Company 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 certain hedge accounting criteria are met.

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

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:

	•		Economic Hedges — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned 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.

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

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

	•		Other — Includes derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through 2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein. Other also 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 September 30, 2009:


	Balance Sheet			Balance Sheet
(in Millions)	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:

Commodity Contracts:
Natural Gas	Derivative assets	$	3	Derivative liabilities	$	—


Derivatives not designated as hedging instruments:

Foreign exchange contracts	Derivative assets	$	29	Derivative liabilities	$	(32	)

Commodity Contracts:
Electricity	Derivative assets		1,651	Derivative liabilities		(1,590	)
Natural Gas	Derivative assets		1,635	Derivative liabilities		(1,751	)
Coal	Derivative assets		36	Derivative liabilities		(38	)
Oil	Derivative assets		14	Derivative liabilities		(12	)
Emissions	Derivative assets		8	Derivative liabilities		(11	)


Total derivatives not designated as hedging instruments:		$	3,373		$	(3,434	)


Total derivatives:

Current		$	2,426		$	(2,403	)
Noncurrent			950			(1,031	)

Total derivatives		$	3,376		$	(3,434	)


(in Millions)	Current			Noncurrent			Current			Noncurrent
Reconciliation of derivative instruments to Consolidated Statement of Financial Position:
Total fair value of derivatives	$	2,426		$	950		$	(2,403	)	$	(1,031	)
Counterparty netting		(2,130	)		(767	)		2,130			767
Collateral adjustment		(25	)		(20	)		16			12

Total derivatives as reported	$	271		$	163		$	(257	)	$	(252	)

The effect of derivative instruments on the Consolidated Statement of Operations for the three and nine months ended September 30, 2009 is as follows:

Location of Gain

Gain (Loss)

(Loss) Recognized

Recognized in

in Income on

Income on

Gain (Loss)

Location of

Derivative

(in Millions)

Recognized

Gain (Loss)

(Ineffective

in OCI on

Reclassified from

Portion and Amount

Derivatives

Derivative

Accumulated OCI

Excluded from

Cash Flow Hedging

(Effective Portion)

into Income

Effectiveness

Relationships

(1)

(Effective Portion)

(Effective Portion) (1)

Testing)

Testing) (1)

Three Months Ended September 30, 2009:

Natural Gas

—

Operating Revenue

—

Interest Swap ⁽²⁾

Interest Expense

)

Interest Expense

—

Total

—

Total

—

Nine Months Ended September 30, 2009:

Natural Gas

Operating Revenue

—

Interest Swap ⁽²⁾

Interest Expense

)

Interest Expense

—

Total

—


⁽¹⁾		Gain (loss) reported after taxes.

⁽²⁾		Related to discontinued cash flow hedge.


		Gain (Loss)			Gain (Loss)
		Recognized in			Recognized in
(in Millions)	Location of Gain	Income on			Income on
	(Loss) Recognized	Derivative for			Derivative for
Derivatives Not Designated	in Income On	Three Months Ended			Nine Months Ended
As Hedging Instruments	Derivative	September 30, 2009			September 30, 2009
Foreign exchange contracts	Operating Revenue	$	(9	)	$	(20	)

Commodity Contracts:
Electricity	Operating Revenue		(47	)		(24	)
Natural Gas	Operating Revenue		(6	)		168
Natural Gas	Fuel, purchased power and gas		5			3
Oil	Operating Revenue		(1	)		(1	)
Coal	Operating Revenue		(3	)		(7	)
Coal	Operation and maintenance		2			4
Emissions	Operating Revenue		2			7

Total		$	(57	)	$	130

The effect of derivative instruments recoverable through the PSCR mechanism when realized on the Consolidated Statement of Financial Position for the three and nine months ended September 30, 2009 is as follows:


		Three Months Ended			Nine Months Ended
	Location of Gain	Gain (Loss)			Gain (Loss)
	(Loss) Recognized	Recognized in			Recognized in
	in Regulatory	Regulatory Assets			Regulatory Assets
	Assets / Liabilities	/ Liabilities on			/ Liabilities on
(in Millions)	On Derivative	Derivative			Derivative
FTRs and Emissions	Regulatory Asset	$	(1	)	$	(14	)
	Regulatory Liability		—			(4	)


Total		$	(1	)	$	(18	)

The following represents the cumulative gross volume of derivative contracts outstanding as of September 30, 2009:


Commodity	Number of Units
Electricity (MWh)		37,606,110
FTRs (MW)		100,338
Natural Gas (MMBtu)		481,992,205
Coal (Tons)		1,078,106
Oil (bbl)		450,000
Foreign Exchange ($ CAD)		174,060,155
Emissions (Tons)		2,554,346

Various non-utility subsidiaries of the Company have entered into contracts which contain ratings triggers and are guaranteed by DTE Energy. These contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit as collateral in the event that DTE Energy’s credit rating is downgraded below investment grade. Certain of these provisions (known as “hard triggers”) state specific circumstances under which the Company can be asked to post collateral upon the occurrence of a credit downgrade, while other provisions (known as “soft triggers”) are not as specific. For contracts with soft triggers, it is difficult to estimate the amount of collateral which may be requested by counterparties and/or which the Company may ultimately be required to post. The amount of such collateral which could be requested fluctuates based on commodity prices (primarily gas, power and coal) and the provisions and maturities of the underlying transactions. As of September 30, 2009, 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 was approximately $230 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.

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 is immaterial for the three and nine months ended September 30, 2009. 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.

The following table presents assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2009:


										Netting			Net Balance at
(in Millions)	Level 1			Level 2			Level 3			Adjustments⁽²⁾			September 30, 2009
Assets:
Cash equivalents	$	50		$	—		$	—		$	—		$	50
Nuclear decommissioning trusts and Other Investments ⁽¹⁾		591			320			1			—			912
Derivative assets		1,441			1,389			546			(2,942	)		434

Total	$	2,082		$	1,709		$	547		$	(2,942	)	$	1,396


Liabilities:
Derivative liabilities	$	(1,350	)	$	(1,319	)	$	(765	)	$	2,925		$	(509	)

Total	$	(1,350	)	$	(1,319	)	$	(765	)	$	2,925		$	(509	)

Net Assets (Liabilities) at September 30, 2009	$	732		$	390		$	(218	)	$	(17	)	$	887


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

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

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis for the three and nine months ended September 30, 2009 and 2008:


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Liability balance as of beginning of the period ⁽¹⁾	$	(194	)	$	(840	)	$	(183	)	$	(366	)
Changes in fair value recorded in income		(47	)		582			152			262
Changes in fair value recorded in regulatory assets/liabilities		(1	)		—			(2	)		—
Changes in fair value recorded in other comprehensive income		2			11			7			(6	)
Purchases, issuances and settlements		23			(99	)		(41	)		(242	)
Transfers in/out of Level 3		(1	)		(48	)		(151	)		(42	)

Liability balance as of September 30	$	(218	)	$	(394	)	$	(218	)	$	(394	)

The amount of total gains (losses) included in net income attributed to the change in unrealized gains (losses) related to assets and liabilities held at September 30, 2009 and 2008	$	(3	)	$	523		$	186		$	10


(1)		Balance as of January 1, 2008 includes a cumulative effect adjustment which represents an increase to the beginning retained earnings related to Level 3 derivatives.

Transfers in/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/out of Level 3 are reflected as if they had occurred at the beginning of the period. Transfers out of Level 3 in 2009 reflect increased reliance on broker quotes for certain gas transactions.

Cash Equivalents

Cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value table are comprised of investments in money market funds. The fair values of the shares of

these funds are based on observable market prices and, therefore, have been categorized as Level 1 in the fair value hierarchy.

Nuclear Decommissioning Trusts and Other Investments

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

Derivative Assets and Liabilities

Derivative assets and liabilities are comprised of physical and financial derivative contracts, including futures, forwards, options and swaps that are both exchange-traded and over-the-counter traded contracts. Various inputs are used to value derivatives depending on the type of contract and availability of market data. Exchange-traded derivative contracts are valued using quoted prices in active markets. 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 relative to 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.

September 30, 2009

December 31, 2008

Fair Value

Carrying Value

Fair Value

Carrying Value

Long-Term Debt

$8.4 billion

$8.0 billion

$7.7 billion

$8.0 billion

Investments in Debt and Equity Securities

The Company generally classifies investments in debt and equity securities as either trading or available-for-sale and has recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of Fermi 2 nuclear decommissioning investments are recorded as adjustments to regulatory assets or liabilities, due to a recovery mechanism from customers. The Company’s investments are reviewed for impairment each reporting period. If the assessment

indicates that the impairment is other than temporary, a loss is recognized resulting in the investment being written down to its estimated fair value.

Decommissioning

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


	September 30		December 31
(in Millions)	2009		2008
Fermi 2	$	762	$	649
Fermi 1		3		3
Low level radioactive waste		26		33

Total	$	791	$	685

At September 30, 2009, investments in the nuclear decommissioning trust funds consisted of approximately 51% in publicly traded equity securities, 48% in fixed debt instruments and 1% in cash equivalents. At December 31, 2008, investments in the nuclear decommissioning trust funds consisted of approximately 42% in publicly traded equity securities, 57% in fixed income and 1% in cash equivalents. The debt securities at both September 30, 2009 and December 31, 2008 had an average maturity of approximately 5 years.

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


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008
Realized gains	$	9		$	7		$	28		$	18
Realized losses	$	(12	)	$	(15	)	$	(45	)	$	(31	)
Proceeds from sales of securities	$	55		$	68		$	237		$	180

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


	Fair		Unrealized
(in Millions)	Value		Gains
As of September 30, 2009
Equity securities	$	400	$	118
Debt securities		381		19
Cash and cash equivalents		10		—

	$	791	$	137


As of December 31, 2008
Equity securities	$	288	$	65
Debt securities		388		17
Cash and cash equivalents		9		—

	$	685	$	82

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

Impairment charges for unrealized losses incurred by the Fermi 2 trust are recognized as a regulatory asset. Detroit Edison recognized $52 million and $56 million of unrealized losses as regulatory assets at September 30, 2009 and 2008, respectively. Since the decommissioning of Fermi 1 is funded by Detroit Edison rather than through a regulatory recovery mechanism, there is no corresponding regulatory asset treatment. Therefore, impairment charges for unrealized losses incurred by the Fermi 1 trust are recognized in earnings immediately. There were no impairment charges for the nine months ended September 30, 2009 and 2008 for Fermi 1 due to an immaterial amount remaining in the fund as a result of ongoing decommissioning activities.

Other

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


	September 30, 2009				December 31, 2008
(in Millions)	Fair Value		Carrying value		Fair Value		Carrying Value
Cash equivalents	$	48	$	48	$	99	$	99
Equity securities	$	14	$	14	$	28	$	28

As of September 30, 2009, these securities are comprised primarily of money-market and equity instruments. During the nine-month period ended September 30, 2009, $3 million of unrealized losses on available-for-sale securities were reclassified out of other comprehensive income into losses for the period. This reclassification includes an other than temporary impairment of equity securities of $4 million. Additionally, gains related to trading securities held at September 30, 2009 were $6 million.

NOTE 4 — DISPOSALS AND DISCONTINUED OPERATIONS

Sale of Interest in Barnett Shale Properties

In 2008, the Company sold a portion of its Barnett shale properties for gross proceeds of approximately $260 million. The Company recognized a gain of $128 million ($80 million after-tax) on the sale in the nine months ended September 30, 2008.

Synthetic Fuel Business

Due to the expiration of synfuel production tax credits in 2007, the Synthetic Fuel business ceased operations and was classified as a discontinued operation as of December 31, 2007. The favorable impact of reserve adjustments for the final phase-out percentage of approximately $32 million, the final settlement of other miscellaneous assets and liabilities and related tax impacts resulted in net income of $20 million for the first nine months of 2008.

The Company has provided certain guarantees and indemnities in conjunction with the sales of interests in its synfuel facilities. The guarantees cover potential tax-related obligations and will survive until 90 days after expiration of all applicable statutes of limitations. The Company estimates that its maximum potential liability under these guarantees at September 30, 2009 is $2.9 billion.

NOTE 5 — REGULATORY MATTERS

2009 Electric Rate Case Filing

Detroit Edison filed a general rate case on January 26, 2009 based on a twelve months ended June 2008 historical test year. The filing with the MPSC requested a $378 million, or 8.1 percent average increase in Detroit Edison’s annual revenues for the twelve months ended June 30, 2010 projected test year. The requested $378 million increase in revenues is required to recover the increased costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, customer uncollectible accounts, inflation, the capital costs of plant additions and the reduction in territory sales.

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

•

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

•

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

•

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

•

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

•

Implementation of a revenue decoupling mechanism. Revenue decoupling is an adjustment mechanism that would provide revenues consistent with the allowed revenue requirement with a periodic adjustment for changes in sales levels.

Pursuant to an MPSC order issued May 26, 2009, Detroit Edison filed proposed tariffs on June 26, 2009 to implement $280 million of its requested annual increase on July 26, 2009. On July 16, 2009, the MPSC issued an order requiring Detroit Edison to implement the increase by applying the rate design reflected in its January 26, 2009 application. This increase will remain in place until a final order is issued by the MPSC, which is expected in January 2010. Detroit Edison recorded approximately $40 million of increased revenues in the third quarter of 2009 as a result of the self-implemented rates. If the final rate case order does not support the self-implemented rate increase, Detroit Edison must refund the difference with interest. We have assessed whether a refund will be likely in accordance with the requirements of ASC 450-20 “Loss Contingencies” and believe that it is reasonably possible, but not probable, that Detroit Edison will be required to refund some or all of its self-implemented rate increase and therefore have not recorded a refund liability as of September 30, 2009.

Renewable Energy Plan

In March 2009, Detroit Edison filed its Renewable Energy Plan with the MPSC as required under 2008 PA 295. The Renewable Energy Plan application requests authority to recover approximately $35 million of additional revenue in 2009. The proposed revenue increase is necessary in order to properly implement Detroit Edison’s 20-year renewable energy plan to address the provisions of 2008 PA 295, to deliver new, cleaner, renewable electric generation to its customers, to further diversify Detroit Edison’s and the State of Michigan’s sources of electric supply, and to address the state and national goals of increasing energy independence. An MPSC order was issued June 2, 2009 approving the renewable energy plan and customer surcharges. The Renewable Energy Plan surcharges became effective in September 2009.

Energy Optimization Plans

In March 2009, Detroit Edison and MichCon filed Energy Optimization Plans with the MPSC as required under 2008 PA 295. The Energy Optimization Plan applications are designed to help each customer class reduce their electric and gas usage by: (1) building customer awareness of energy efficiency options and (2) offering a diverse set of programs and participation options that result in energy savings for each customer class. Detroit Edison’s Energy Optimization Plan application proposed energy optimization expenditures for the period 2009-2011 of $134 million and further requests approval of surcharges that are designed to recover these costs. MichCon’s Energy Optimization Plan application proposed energy optimization expenditures for the period 2009-2011 of $55 million and further requests approval of surcharges that are designed to recover these costs. An MPSC order was issued June 2, 2009 approving the Energy Optimization Plans of $117 million and $48 million for Detroit Edison and MichCon, respectively. The surcharges to recover these costs were implemented effective June 3, 2009. New financial incentive proposals were filed on July 2, 2009. An MPSC order was issued September 29, 2009 approving incentive mechanisms for both utilities. The mechanism allows a maximum payout of 15% of program expenditures when the utility meets or exceeds the savings target by 15%.

Power Supply Cost Recovery Proceedings

2008 Plan Year — In September 2007, Detroit Edison filed its 2008 PSCR plan case seeking approval of a levelized PSCR factor of 9.23 mills/kWh above the amount included in base rates for all PSCR customers. Also included in the filing was a request for approval of the Company’s emission compliance strategy which included pre-purchases of emission allowances as well as a request for pre-approval of a contract for capacity and energy associated with a renewable (wind) energy project. On January 31, 2008, Detroit Edison filed a revised PSCR plan case seeking approval of a levelized PSCR factor of 11.22 mills/kWh above the amount included in base rates for all PSCR customers. The revised filing supports a 2008 power supply expense forecast of $1.4 billion and includes $43 million for the recovery of a projected 2007 PSCR under-collection. On July 29, 2008, the MPSC issued a temporary order approving Detroit Edison’s request to increase the PSCR factor to 11.22 mills/kWh. In January 2009, the MPSC approved the Company’s 2008 PSCR plan and authorized the Company to charge a maximum PSCR factor of 11.22 mills/kWh for 2008. The Company filed its 2008 PSCR reconciliation case in March 2009. The filing requests recovery of a $19 million PSCR under-collection. In addition, the filing requests authorization to refund its total 2005 PSCR under-collection surcharge at year-end 2008 of $10 million, including interest, to all commercial and industrial customers. Included in the 2008 PSCR reconciliation filing was the Company’s 2008

pension expense mechanism reconciliation that reflects a $50 million over-collection. The Company expects an order in this proceeding in the second quarter of 2010.

2009 Plan Year — In September 2008, Detroit Edison filed its 2009 PSCR plan case seeking approval of a levelized PSCR factor of 17.67 mills/kWh above the amount included in base rates for residential customers and a levelized PSCR factor of 17.29 mills/kWh above the amount included in base rates for commercial and industrial customers. The Company is supporting a total power supply expense forecast of $1.73 billion. The plan also includes approximately $69 million for the recovery of its projected 2008 PSCR under-collection from all customers and approximately $12 million for the refund of its 2005 PSCR reconciliation surcharge over-collection to commercial and industrial customers only. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a renewable (wind) energy project. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including, fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowance costs, transmission costs and MISO costs. The Company self-implemented a PSCR factor of 11.64 mills/kWh above the amount included in base rates for residential customers and a PSCR factor of 11.22 mills/kWh above the amount included in base rates for commercial and industrial customers on bills rendered in January 2009. Subsequently, as a result of the December 23, 2008 MPSC order in the 2007 Detroit Edison rate case, the Company implemented a PSCR factor of 3.18 mills/kWh below the amount included in base rates for residential customers and a PSCR factor of 3.60 mills/kWh below the amount included in base rates for commercial and industrial customers for service rendered effective January 14, 2009. The Company self-implemented a PSCR factor of 10.18 mills/kWh below the amount included in base rates for residential customers and a PSCR factor of 10.46 mills/kWh below the amount included in base rates for commercial and industrial customers for bills rendered effective August 1, 2009. On June 29, 2009, the parties to this proceeding executed a Settlement Agreement in this matter agreeing to maximum PSCR factors of 1.67 mills/kWh for residential customers and 1.35 mills/kWh for commercial and industrial customers and otherwise resolving this 2009 PSCR Plan case. The Company awaits an MPSC order approving the settlement.

2010 Plan Year — In September 2009, Detroit Edison filed its 2010 PSCR plan case seeking approval of a levelized PSCR factor of 5.64 mills/kWh below the amount included in base rates for all PSCR customers. The filing supports a 2010 power supply expense forecast of $1.2 billion. Also included in the filing is a request for approval of the Company’s expense associated with the use of urea in the selective catalytic reduction units at Monroe power plant as well as a request for approval of a contract for capacity and energy associated with a wind energy project. The Company’s PSCR Plan will allow the Company to recover its reasonably and prudently incurred power supply expense including, fuel costs, purchased and net interchange power costs, nitrogen oxide and sulfur dioxide emission allowance costs, transmission costs and MISO costs. The Company has also requested authority to recover transfer prices for renewable energy, coke oven gas expense and other potential expenses.

Gas Rate Case Filings

2003 Gas Rate Case / Motion for Commission Decision and Remand for Control Premium Recovery — MichCon filed a motion with the MPSC on June 1, 2009 requesting a decision on remand from the Court of Appeals for MichCon’s control premium recovery. This motion concerns the control premium that DTE Energy paid to acquire MCN. DTE Energy apportioned the control premium primarily between its Detroit Edison and MichCon subsidiaries. The MPSC denied MichCon’s request to recover its $25 million portion of the control premium in its 2003 rate case. On September 29, 2009, the MPSC granted MichCon’s June 1, 2009 Motion for Commission’s Decision and Remand for Control Premium Recovery but denied MichCon’s requested rate relief by reaffirming the MPSC’s denial of recovery of MichCon’s portion of the control premium in MichCon’s last rate case.

2009 Gas Rate Case - MichCon filed a general rate case on June 9, 2009 based on a 2008 historical test year. The filing with the MPSC requested a $193 million, or 11.5 percent average increase in MichCon’s annual revenues for a 2010 projected test year. The requested $193 million increase in revenues is required to recover the increased costs associated with increased investments in net plant and working capital, the impact of high levels of uncollectible expense and the cost of natural gas theft primarily due to economic conditions in Michigan, sales reductions due to customer conservation and the trend of warmer weather on MichCon’s market, and increasing operating costs, largely due to inflation.

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

•

Implementation of a Lost Gas and Company Use — Expense True-up Mechanism;

•

Continued application of an uncollectible expense true-up mechanism based on a $70 million expense level of uncollectible expenses; and,

•

Pursuant to the October 2008 Michigan legislation, and the settlement in MichCon’s last base gas sale case, MichCon anticipates self-implementing a rate increase on January 1, 2010.

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

2008 UETM — In March 2009, MichCon filed an application with the MPSC for approval of its UETM for 2008 requesting approximately $87 million consisting of $83 million of costs related to 2008 uncollectible expense and associated carrying charges and $4 million of under-collections for the 2006 UETM. The March 2009 application included a report of MichCon’s 2008 annual safety and training-related expenses, which showed no refund was necessary because actual expenditures exceeded the amount included in base rates. In May 2009, the Michigan Supreme Court denied the Attorney General’s leave to appeal the Court of Appeal’s decision that the MPSC had statutory authority to approve a UETM in a general rate case. In response to this denial, the Attorney General withdrew as an intervenor in this case. MichCon and the MPSC Staff reached a settlement agreement establishing a UETM surcharge to collect the requested amount on a 15-month basis. On August 25, 2009, the Commission issued an order approving the settlement agreement. MichCon began charging the surcharge with service rendered September 1, 2009.

Gas Cost Recovery Proceedings

2007-2008 Plan Year / Base Gas Sale Consolidated —In June 2008, MichCon filed its GCR reconciliation for the 2007-2008 GCR year. The filing supported a total under-recovery, including interest through March 2008, of $10 million. In June 2009, the parties filed a settlement agreement including MichCon’s under-recovery, as filed, plus interest. The MPSC issued an order approving the settlement agreement on July 1, 2009.

2008- 2009 Plan Year GCR Reconciliation —In June 2009, MichCon filed its GCR reconciliation case for the 2008 — 2009 GCR year. The filing includes a $5 million overrecovery that has already been rolled into the 2009 — 2010 GCR plan year. An MPSC order in this case is expected in 2010.

2009-2010 Plan Year — In December 2008, MichCon filed its GCR plan case for the 2009-2010 GCR plan year. MichCon filed for a maximum GCR factor of $8.46 per Mcf, adjustable by a contingent mechanism. In April 2009, MichCon, MPSC Staff and Intervenors filed a partial settlement agreement in the case establishing the fixed price purchase guidelines MichCon filed in its case are reasonable and prudent for MichCon to use until an MPSC order is issued establishing otherwise. On April 30, 2009, the MPSC issued an order approving the partial settlement agreement. An MPSC order in this case is expected in 2009.

2009 Proposed Base Gas Sale — In July 2008, MichCon filed an application with the MPSC requesting permission to sell an additional 4 Bcf of base gas that will become available for sale as a result of better than expected operations at its storage fields. In February 2009, a settlement agreement was filed with the MPSC, which will allow MichCon to sell and retain the profits of 2 Bcf of base gas, with the remaining 2 Bcf to be used for the benefit of GCR/GCC customers as colder-than-normal weather protection. The settlement also included a provision that MichCon was subject to a moratorium on a general rate case filing until June 2009. An MPSC order was issued March 5, 2009 approving the settlement.

Merger Control Premium Costs

In July 2007, the State of Michigan Court of Appeals published its decision with respect to an appeal by Detroit Edison and others of certain provisions of a November 2004 MPSC order, including reversing the MPSC’s denial of recovery of merger control premium costs. In its published decision, the Court of Appeals held that Detroit Edison is entitled to recover its allocated share of the merger control premium and remanded this matter to the MPSC for

further proceedings to establish the precise amount and timing of this recovery. In September 2007, the Court of Appeals remanded to the MPSC, for reconsideration, the MichCon recovery of merger control premium costs. Other parties filed requests for leave to appeal to the Michigan Supreme Court from the Court of Appeals decision and in September 2008, the Michigan Supreme Court granted the requests to address the merger control premium as well as the recovery of transmission costs through the PSCR. On May 1, 2009, the Michigan Supreme Court issued an order reversing the Court of Appeals decision with respect to recovery of the merger control premium, and reinstated the MPSC’s decision excluding the control premium costs from Detroit Edison’s general rates. The Court affirmed the lower court’s decision upholding the right of Detroit Edison to recover electric transmission costs through the Company’s PSCR clause. The Company requested rehearing of the Supreme Court order on the merger premium and the Michigan Attorney General requested rehearing of the transmission portion of the order. On June 26, 2009, the Michigan Supreme Court denied both requests for rehearing. On September 29, 2009, the MPSC granted MichCon’s June 1, 2009 Motion for Commission’s Decision and Remand for Control Premium Recovery but denied MichCon’s requested rate relief by reaffirming the MPSC’s denial of recovery of MichCon’s portion of the control premium in MichCon’s last rate case.

Other

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

NOTE 6 — COMMON STOCK AND 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. Effective January 1, 2009, the adoption of new accounting requirements clarifying the definition of participating securities to be included in the earnings per share calculation had the effect of reducing previously reported 2008 amounts for basic and diluted earnings per share by $.02 and $.01, respectively. A reconciliation of both calculations is presented in the following table as of September 30:


	Three Months				Nine Months
	Ended September 30				Ended September 30
(in Millions, except per share amounts)	2009		2008		2009		2008
Basic Earnings per Share
Net income attributable to DTE Energy Company	$	158	$	177	$	419	$	417


Average number of common shares outstanding		165		163		164		163

Weighted average net restricted shares outstanding		1		1		1		1


Dividends paid to common shares	$	87	$	86	$	259	$	258
Dividends paid to net restricted shares		—		—		2		1

Total distributed earnings	$	87	$	86	$	261	$	259

Net income less distributed earnings	$	71	$	91	$	158	$	158


Distributed (dividends per common share)	$	.53	$	.53	$	1.59	$	1.59
Undistributed		.43		.55		.96		.96

Total Basic Earnings per Common Share	$	.96	$	1.08	$	2.55	$	2.55


Diluted Earnings per Share
Net income attributable to DTE Energy Company	$	158	$	177	$	419	$	417


Average number of common shares outstanding		165		163		164		163

Average incremental shares from assumed exercise of options		—		—		—		—

Common shares for dilutive calculation		165		163		164		163


Weighted average net restricted shares outstanding		1		1		1		1


Dividends paid to common shares	$	87	$	86	$	259	$	258
Dividends paid to net restricted shares		—		—		2		1


	Three Months				Nine Months
	Ended September 30				Ended September 30
(in Millions, except per share amounts)	2009		2008		2009		2008
Total distributed earnings	$	87	$	86	$	261	$	259

Net income less distributed earnings	$	71	$	91	$	158	$	158


Distributed (dividends per common share)	$	.53	$	.53	$	1.59	$	1.59
Undistributed		.43		.55		.96		.96

Total Diluted Earnings per Common Share	$	.96	$	1.08	$	2.55	$	2.55

Options to purchase approximately 5 million and 2 million shares of common stock as of September 30, 2009 and 2008, 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 7 — LONG-TERM DEBT

Debt Issuances

In 2009, the Company has issued or remarketed the following long-term debt:

(in Millions)


Company	Month Issued	Type	Interest Rate			Maturity		Amount

Detroit Edison	April	Tax-Exempt Revenue Bonds (1)(2)		6.00	%		2036	$	69
DTE Energy	May	Senior Notes (3)		7.625	%		2014		300
Detroit Edison	June	Tax-Exempt Revenue Bonds (1)(4)		5.625	%		2020		32
Detroit Edison	June	Tax-Exempt Revenue Bonds (1)(5)		5.25	%		2029		60
Detroit Edison	June	Tax-Exempt Revenue Bonds (1)(6)		5.50	%		2029		59

								$	520


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

(2)		Proceeds were used to refund existing Tax-Exempt Revenue Bonds.

(3)		Proceeds were used to repay short-term borrowings.

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

(5)		These Tax-Exempt Revenue Bonds were converted from a variable rate mode and remarketed in a fixed rate mode with a five-year mandatory put.

(6)		These Tax-Exempt Revenue Bonds were converted from a variable rate mode and remarketed in a fixed rate mode with a seven-year mandatory put.

Debt Retirements and Redemptions

In 2009, the following debt has been retired, through optional redemption or payment at maturity:

(in Millions)

Company

Month Retired

Type

Interest Rate

Maturity

Amount

Detroit Edison

April

Tax-Exempt Revenue Bonds (1)

Variable

2036

DTE Energy

April

Senior Notes

6.65

2009

200

269


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

NOTE 8 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar terms. The five-year and two-year revolving credit facilities are with a syndicate of 22 banks

and 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 8.5% of the combined credit facilities. Borrowings under the facilities are available at prevailing short-term interest rates. Additionally, DTE Energy, Detroit Edison and MichCon have various other bank loans and facilities. The above agreements require the Company to maintain a debt to total capitalization ratio of no more than 0.65 to 1. DTE Energy, Detroit Edison and MichCon are in compliance with this financial covenant. The availability under these combined facilities at September 30, 2009 is shown in the following table:


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Five-year unsecured revolving facility, expiring October 2010	$	675	$	69	$	181	$	925
Two-year unsecured revolving facility, expiring April 2011		538		212		250		1,000
One-year unsecured letter of credit facility, expiring in November 2009		30		—		—		30
One-year unsecured letter of credit facility, expiring in June 2010		70		—		—		70
Two-year unsecured letter of credit facility, expiring in May 2011		50		—		—		50

Total credit facilities at September 30, 2009		1,363		281		431		2,075


Amounts outstanding at September 30, 2009:

Commercial paper issuances		—		—		205		205
Borrowings		—		—		—		—
Letters of credit		228		—		—		228

		228		—		205		433

Net availability at September 30, 2009	$	1,135	$	281	$	226	$	1,642

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

In April 2009, the Company completed an early renewal of $975 million of its syndicated revolving credit facilities before their scheduled expiration in October 2009. The new $1 billion two-year facility will expire in April 2011 and has similar covenants to the prior facility. A new two-year $50 million credit facility was completed in April 2009 and a new one-year $70 million credit facility was completed in June 2009.

In conjunction with maintaining certain exchange traded risk management positions, the Company may be required to post cash collateral with its clearing agent. At September 30, 2009, the Company had a demand financing agreement for up to $120 million with its clearing agent. In addition to the amounts shown above, the amount outstanding under this agreement was $7 million and $26 million at September 30, 2009 and December 31, 2008, respectively.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Environmental

Electric Utility

Air — Detroit Edison is subject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. Since 2005, EPA and the State of Michigan issued additional emission reduction regulations and continue to develop additional rules and emission standards relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $1.4 billion through 2008. The Company estimates Detroit Edison’s future undiscounted capital expenditures at up to approximately $100 million in 2009 and up to approximately $2.3 billion of additional capital expenditures through 2019 based on current regulations.

outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. We could also be required to install additional pollution control equipment at some or all of the power plants in question, engage in Supplemental Environmental Programs, and/or pay fines. We 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 the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the water intakes. Initially, it was estimated that Detroit Edison could incur up to approximately $55 million over the four to six years subsequent to 2008 in additional capital expenditures to comply with these requirements. However, a January 2007 circuit court decision remanded back to the EPA several provisions of the federal regulation that may result in a delay in compliance dates. The decision also raised the possibility that Detroit Edison may have to install cooling towers at some facilities at a cost substantially greater than was initially estimated for other mitigative technologies. In 2008, the Supreme Court agreed to review the remanded cost-benefit analysis provision of the rule. In April 2009, the Supreme Court ruled that a cost-benefit analysis is a permissible provision of the rule. Concurrently, the EPA continues to develop a revised rule, which is expected to be published later in 2009.

Landfill— Detroit Edison owns and operates a permitted slurry landfill 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 results of the engineering study show that the estimated cost to perform the embankment repairs are $20 million which we expect to incur over the next five years.

Contaminated Sites — Detroit Edison conducted remedial investigations at contaminated sites, including three former manufactured gas plant (MGP) sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is expected to be incurred over the next several years. At September 30, 2009 and December 31, 2008, the Company had $10 million and $12 million, respectively, accrued for remediation.

Gas Utility

Contaminated Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally from processes involving coal, coke or oil. Gas Utility owns, or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. In addition to the MGP sites, the Company is also in the process of cleaning up other contaminated sites. Cleanup activities associated with these sites will be conducted over the next several years.

The MPSC has established a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites. Accordingly, Gas Utility recognizes a liability and corresponding regulatory asset for estimated investigation and remediation costs at former MGP sites. As of September 30, 2009 and December 31, 2008, the Company had approximately $37 million and $38 million, respectively, accrued for remediation.

Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and affect the Company’s financial position and cash flows. However, the Company anticipates the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Non-Utility

The Company’s non-utility affiliates are subject to a number of environmental laws and regulations dealing with the protection of the environment from various pollutants. The Company has completed the installation of new environmental equipment at our coke battery facility in Michigan. The Michigan coke battery facility received and responded to information requests from the EPA resulting in the issuance of a notice of violation regarding potential maximum achievable control technologies and new source review violations. The EPA is in the process of reviewing the Company’s position of demonstrated compliance and has not initiated escalated enforcement. At this time, the Company cannot predict the

impact of this issue. Furthermore, the Company is in the process of settling historical air violations at its coke battery facility located in Pennsylvania. At this time, the Company cannot predict the impact of this settlement. The Company has also received and responded to information requests from the EPA with respect to wastewater treatment at the coke battery facility located in Pennsylvania. The Company is investigating wastewater treatment technologies for this facility. This investigation may result in capital expenditures to meet regulatory requirements. The Company’s non-utility affiliates are substantially in compliance with all environmental requirements, other than as noted above.

Guarantees

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

Millennium Pipeline Project Guarantee

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

On August 29, 2007, Millennium entered into a borrowing facility to finance the construction costs of the project. The total facility amounts to $800 million and is guaranteed by the project partners, based upon their respective ownership percentages. The facility expires on August 29, 2010 and was fully drawn as of September 30, 2009.

The Company has agreed to guarantee 26 percent of the borrowing facility and in the event of default by Millennium the maximum potential amount of future payments under this guarantee is approximately $210 million. The guarantee includes DTE Energy’s revolving credit facility’s covenant and default provisions by reference. Related to this facility, the Company has also agreed to guarantee 26 percent of Millennium’s forward-starting interest rate swaps with a notional amount of $420 million. The Company’s exposure on the forward-starting interest rate swaps varies with changes in Treasury rates and credit swap spreads and was approximately $17 million at September 30, 2009. Because the Company is unable to accurately anticipate changes in Treasury rates and credit swap spreads, it is unable to estimate its maximum exposure under its share of Millennium’s forward-starting interest rate swaps. An incremental 0.25 percent decrease in the forward interest rate swap rates will increase its exposure by approximately $3 million. There are no recourse provisions or collateral that would enable the Company to recover any amounts paid under the guarantees, other than its share of project assets.

Other Guarantees

In January 2003, the Company sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Under the terms of sale, Detroit Edison guaranteed a bank term loan of $12 million that was used for capital improvements to the steam heating system. At September 30, 2009, the Company has reserves for the entire amount of the bank loan guarantee.

The Company’s other guarantees are not individually material with maximum potential payments totaling $10 million at September 30, 2009.

The Company is periodically required to obtain performance surety bonds in support of obligations to various governmental entities and other companies in connection with its operations. As of September 30, 2009, the Company had approximately $12 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 union employees. The majority of our union employees are under contracts that expire in June and October 2010 and August 2012.

Purchase Commitments

Detroit Edison has an Energy Purchase Agreement to purchase electricity from the Greater Detroit Resource Recovery Authority (GDRRA). The term of the Energy Purchase Agreement for the purchase of electricity runs through June 2024. The Company estimates electric purchase commitments from 2009 through 2024 will not exceed $300 million in the aggregate.

As of September 30, 2009, the Company was party to numerous long-term purchase commitments relating to a variety of goods and services required for the Company’s business. These agreements primarily consist of fuel supply commitments and energy trading contracts. The Company estimates that these commitments will be approximately $5.9 billion from 2009 through 2051. The Company also estimates that 2009 capital expenditures will be approximately $1.1 billion. The Company has made certain commitments in connection with expected capital expenditures.

Bankruptcies

The Company purchases and sells electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail, 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.

The Company’s utilities and certain non-utility businesses provide services to the domestic automotive industry, including General Motors Corporation (GM), Ford Motor Company (Ford) and Chrysler LLC (Chrysler) and many of their vendors and suppliers. Chrysler filed for bankruptcy protection on April 30, 2009. We have reserved approximately $9 million of pre-petition accounts receivable related to Chrysler as of September 30, 2009. GM filed for bankruptcy protection on June 1, 2009. We have reserved or written off approximately $5 million of pre-petition accounts and notes receivable related to GM as of September 30, 2009.

The Company’s Power and Industrial Projects segment has long-term contracts with GM to provide onsite energy services at certain of its manufacturing and administrative facilities. The long-term contracts provide for full recovery of its investment in the event of early termination. At September 30, 2009, the book value of long-lived assets used in the servicing of these facilities was approximately $68 million. Certain of these long-lived assets have been funded by non-recourse financing totaling approximately $57 million at September 30, 2009.

The Company’s Power and Industrial Projects segment also has an equity investment of approximately $53 million in an entity which provides onsite services to Chrysler manufacturing facilities. Chrysler’s performance under the long-term contracts for services is guaranteed by Daimler North America Corporation (Daimler), a subsidiary of Daimler AG. The long-term contracts and the supporting Daimler guarantee provide for full recovery of the Company’s investment in the event of early termination or default. Chrysler has announced the closure of one site that is under a long-term service contract with the Company. Through September 30, 2009, to the extent that Chrysler has not been performing in accordance with its contracts, Daimler has been performing under its guarantee. Therefore, the Company believes that it will recover its investment in the event of a facility closure or a Chrysler default.

The Company determined that the GM and Chrysler bankruptcy filings were triggering events to assess certain automotive-related long-lived assets for impairment and as of June 30, 2009, the Company performed an impairment analysis on these assets. Based on its undiscounted cash flow projections and fair value calculations, the Company determined that it did not have an impairment loss at June 30, 2009. We also determined that we did not have an other than temporary decline in our Chrysler-related equity investment. There were no new events occurring during the third quarter that would negatively impact the assumptions made for the second quarter impairment analysis. Therefore, no triggering events were identified in the third quarter of 2009. The Company’s assumptions and conclusions may change in the future and we could have an impairment loss if certain facilities are not utilized as currently anticipated.

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 it can estimate and are considered probable of loss. The resolution of these pending proceedings is not expected to have a material effect on the Company’s operations or financial statements in the periods they are resolved.

See Note 3 and 5 for a discussion of contingencies related to derivatives and regulatory matters.

NOTE 10 — SEGMENT INFORMATION

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

Electric Utility

•

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

Gas Utility

•

The Gas Utility segment consists of MichCon and Citizens. MichCon is engaged in the purchase, storage, transmission, distribution and sale of natural gas to approximately 1.2 million residential, commercial and industrial customers throughout Michigan. A significant portion of the storage and transmission business within MichCon relates to customers who ultimately move the gas to other states and Canada. MichCon also has subsidiaries involved in the gathering, processing and transmission of natural gas in northern Michigan. Citizens distributes natural gas in Adrian, Michigan to approximately 17,000 customers.

Non-utility Operations

•

Gas Midstream consists of gas pipelines and storage businesses;

•

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

•

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

•

Energy Trading primarily consists of energy marketing and trading operations.

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

The income tax provisions or benefits of DTE Energy’s subsidiaries are determined on an individual company basis and recognize the tax benefit of production tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy’s consolidated federal tax return.

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


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008
Electric Utility	$	8		$	5		$	22		$	11
Gas Utility		—			3			—			6
Gas Midstream		1			2			4			7
Unconventional Gas Production		—			—			—			—
Power and Industrial Projects		10			8			7			17
Energy Trading		17			24			70			96
Corporate & Other		(17	)		(18	)		(56	)		(60	)

	$	19		$	24		$	47		$	77

Financial data of the business segments follows:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008
Operating Revenues
Electric Utility	$	1,300		$	1,440		$	3,526		$	3,766
Gas Utility		190			225			1,253			1,537
Non-utility Operations:
Gas Midstream		19			19			61			53
Unconventional Gas Production		8			14			23			37
Power and Industrial Projects		157			264			450			778
Energy Trading		306			405			638			1,128

		490			702			1,172			1,996


Corporate & Other		—			(5	)		—			(3	)
Reconciliation & Eliminations		(19	)		(24	)		(47	)		(137	)

Total From Continuing Operations	$	1,961		$	2,338		$	5,904		$	7,159


Net Income (Loss) by Segment:
Electric Utility	$	156		$	159		$	313		$	251
Gas Utility		(23	)		(15	)		23			33
Non-utility Operations:
Gas Midstream		13			11			37			27
Unconventional Gas Production (1)		(2	)		3			(6	)		89
Power and Industrial Projects		10			26			8			30
Energy Trading		6			19			73			36

Corporate & Other		(2	)		(34	)		(29	)		(69	)

Income (Loss) from Continuing Operations
Utility		133			144			336			284
Non-utility		27			59			112			182
Corporate & Other		(2	)		(34	)		(29	)		(69	)

		158			169			419			397


Discontinued Operations (Note 4)		—			8			—			20

Net Income attributable to DTE Energy	$	158		$	177		$	419		$	417


(1)		Net Income of the Unconventional Gas Production segment in the 2008 nine-month period reflects the gain on the sale of a portion of the Barnett shale properties. See Note 4.

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 with 2008 revenues in excess of $9 billion and approximately $24 billion of assets. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales, distribution and storage services throughout southeastern Michigan. We operate four energy-related non-utility segments with operations throughout the United States.

Net income attributable to DTE Energy in the third quarter of 2009 was $158 million, or $0.96 per diluted share, compared to net income attributable to DTE Energy of $177 million, or $1.08 per diluted share, in the third quarter of 2008. Net income attributable to DTE Energy for the nine months ended September 30, 2009 was $419 million, or $2.55 per diluted share, compared to net income attributable to DTE Energy of $417 million, or $2.55 per diluted share, in the comparable period of 2008. The decrease in the 2009 third quarter was due primarily to lower earnings in the power and industrial projects, energy trading and gas utility segments. The increase in the nine-month period ended September 30, 2009 was primarily due to higher earnings in the electric utility and energy trading segments, partially offset by the $80 million after-tax gain recorded in the Unconventional Gas production segment on the 2008 sale of a portion of Barnett shale properties.

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

The items discussed below influenced our current financial performance and may affect future results:

•

Impacts of national and regional economic conditions on utility and non-utility operations, including automotive industry uncertainty;

•

Effects of weather on utility operations;

•

Collectibility of accounts receivable on utility operations;

•

Impact of regulatory decisions on utility operations;

•

Results in our Energy Trading business; and

•

Required renewable, energy-efficiency, environmental and reliability-related capital investments and other costs.

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 2.2 million customers in southeastern Michigan.

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

Impact of National and Regional Economic Conditions on our Utility Operations

Revenues from our utility operations follow the economic cycles of the customers we serve. Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and high levels of uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies. Direct and indirect effects of further automotive and other industrial plant closures could have a significant impact on the results of Detroit Edison. As discussed further below, deteriorating economic conditions impact our ability to

collect amounts due from our electric and gas customers and drive increased thefts of electricity and natural gas. In the face of these economic conditions, we are actively managing our cash, capital expenditures, cost structure and liquidity to maintain our financial strength.

Effects of Weather on Utility Operations

Earnings from our utility operations are seasonal and sensitive to weather. Electric utility earnings are favorably impacted by hot summer weather, while the gas utility’s results are favorably impacted by cold winter weather.

Collectibility of Accounts Receivable on Utility Operations

Both utilities continue to experience high levels of past due receivables, which is primarily attributable to economic conditions. Our service territories continue to experience high levels of unemployment, underemployment and low income households, home foreclosures and a lack of adequate levels of assistance for low-income customers. We have taken actions to manage the level of past due receivables, including increasing customer disconnections, contracting with collection agencies and working with Michigan officials and others to increase the share of low-income funding allocated to our customers. The April 2005 MPSC gas rate order provided for an uncollectible true-up mechanism for MichCon. The uncollectible true-up mechanism enables MichCon to recover ninety percent of the difference between the actual uncollectible expense for each year and $37 million after an annual reconciliation proceeding before the MPSC. We experienced an increase in our uncollectible accounts expense for the two utilities to approximately $37 million in the 2009 third quarter from approximately $32 million in the 2008 third quarter. Uncollectible accounts expense was approximately $151 million during the nine months ended September 30, 2009, in comparison to $168 million during the nine months ended September 30, 2008. The 2008 nine-month period experienced higher expense due to an analysis of our greater than ninety day receivables that indicated a change in the mix of customers in that group and therefore an increased risk of collection. The bankruptcies of General Motors Corporation (GM) and Chrysler LLC (Chrysler) did not have a significant impact to our uncollectible expense in the 2009 periods.

Impact of Regulatory Decisions on Utility Operations

Detroit Edison filed a general rate case on January 26, 2009 based on a twelve months ended June 30, 2008 historical test year. The filing with the MPSC requested a $378 million, or 8.1 percent average increase in Detroit Edison’s annual revenues for the twelve months ended June 30, 2010 projected test year. The requested $378 million increase in revenues is required to recover the increased costs associated with environmental compliance, operation and maintenance of the Company’s electric distribution system and generation plants, customer uncollectible accounts, inflation, the capital costs of plant additions and the reduction in territory sales. Pursuant to an MPSC order issued May 26, 2009, Detroit Edison filed proposed tariffs on June 26, 2009 to implement $280 million of its requested annual increase on July 26, 2009. On July 16, 2009, the MPSC issued an order requiring Detroit Edison to implement the increase by applying the rate design reflected in its January 26, 2009 application. This increase will remain in place until a final order is issued by the MPSC, which is expected in January 2010. Detroit Edison recorded approximately $40 million of increased revenues in the third quarter of 2009 as a result of the self-implemented rates. If the final rate case order does not support the self-implemented rate increase, Detroit Edison must refund the difference with interest. We have assessed whether a refund will be likely in accordance with the requirements of ASC 450-20 “Loss Contingencies” and believe that it is reasonably possible, but not probable, that Detroit Edison will be required to refund some or all of its self-implemented rate increase and therefore have not recorded a refund liability as of September 30, 2009.

MichCon filed a general rate case on June 9, 2009 based on a 2008 historical test year. The filing with the MPSC requested a $193 million, or 11.5 percent average increase in MichCon’s annual revenues for a 2010 projected test year. The requested $193 million increase in revenues is required to recover the increased costs associated with increased investments in net plant and working capital, an increase in the base level of the uncollectible expense tracking mechanism and the cost of natural gas theft primarily due to economic conditions in Michigan, sales reductions due to customer conservation and the trend of warmer weather on MichCon’s market, and increasing operating costs, largely due to inflation. Pursuant to the October 2008 Michigan legislation, and the settlement in MichCon’s last base gas sale case, MichCon anticipates self-implementing a rate increase on January 1, 2010. See Note 5 of the Notes to Consolidated Financial Statements.

Global Climate Change

Proposals for voluntary initiatives and mandatory controls are being discussed in the United States to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs for emissions of greenhouse gases (e.g. carbon dioxide). A discussion draft of climate legislation that retains some of the ACESA provisions was introduced in the U.S. Senate in September. Meanwhile, the EPA is beginning to implement regulatory action under the Clean Air Act to address climate change. There may be further legislative and/ or regulatory action to address the issue of changes in climate that may result from the build-up of greenhouse gases in the atmosphere. If passed, legislative or regulatory actions as currently being discussed could have a material adverse impact on our operations and financial position and the rates we charge our customers.

NON-UTILITY OPERATIONS

We have significant investments in non-utility asset-intensive 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.

Gas Midstream

Gas Midstream owns partnership interests in two interstate transmission pipelines and two natural gas storage fields. The pipeline and storage assets are primarily supported by long-term, fixed-price revenue contracts. We have a partnership interest in Vector Pipeline (Vector), an interstate transmission pipeline, which connects Michigan to Chicago and Ontario. We also have a partnership interest in Millennium Pipeline Company (Millennium), which was placed in service in December 2008. Millennium indirectly connects southern New York State to Upper Midwest/Canadian supply, while providing transportation service into the New York City markets. We have storage assets in Michigan capable of storing up to 89 Bcf in natural gas storage fields located in Southeast Michigan. The Washington 10 and 28 storage facilities are high deliverability storage fields having bi-directional interconnections with Vector and MichCon providing our customers access to the Chicago, Michigan, other Midwest and Ontario market centers. The pipeline and storage business is expanding capacity to serve markets throughout the Midwest and Northeast United States regions.

Unconventional Gas Production

Our Unconventional Gas Production business is engaged in natural gas exploration, development and production within the Barnett shale in north Texas. We continue to develop our position, with total leasehold acreage of 65,081 (61,989 acres, net of impairment and interest of others). Due to economic conditions and lower natural gas prices, we have chosen to do minimal lease acquisitions this year. However, we continue to evaluate leasing opportunities in active development areas in the Barnett shale to optimize our existing portfolio.

In 2008, we sold a portion of our Barnett shale properties for gross proceeds of approximately $260 million. The properties sold included 75 Bcfe of proved reserves on approximately 11,000 net acres in the core area of the Barnett shale.

We continue to develop our holdings in the western portion of the Barnett shale and to seek opportunities for additional monetization of select properties within our Barnett shale holdings, when conditions are appropriate. We expect to invest approximately $20 million to $25 million in 2009. During 2009, we expect to drill 10 to 15 new wells and achieve Barnett shale production of approximately 5 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.

As a component of our risk management strategy for our Barnett shale reserves, we hedged a portion of anticipated production from our reserves to secure an attractive investment return. As of September 30, 2009, we have a series of cash flow hedges for approximately 1.7 Bcf of anticipated Barnett gas production through 2010 at an average price of $7.24 per Mcf.

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 and marketing; and sell electricity from biomass-fired energy projects. This business segment provides utility- type services using project assets usually located on or near the customers’ premises in the steel, automotive, pulp and paper, airport and other industries.

Products and services provided include pulverized coal and petroleum coke supply, metallurgical coke supply, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. We own and operate one gas-fired peaking electric generating plant, two biomass-fired electric generating plants and operate one coal-fired power plant. A third biomass-fired electric generating plant is currently under development with an expected in-service date of June 2010. This business segment also develops, owns and operates landfill gas recovery systems throughout the United States and produces metallurgical coke from three coke batteries. The production of coke from two of the coke batteries generates production tax credits. The business provides coal related services including fuel, transportation, storage, blending and rail equipment management services. Additionally, we participate in coal marketing and trading and the purchase and sale of emissions credits. This business segment performs coal mine methane extraction, in which we recover methane gas from mine voids for processing and delivery to natural gas pipelines.

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. Our customer base is predominantly utilities, local distribution companies, pipelines, and other marketing and trading companies. We enter into derivative financial instruments as part of our marketing and hedging activities. We also enter into contracts for the purchase or sale of commodities which may also qualify as derivative contracts. Our derivative instruments and contracts are accounted for under the mark-to-market method, which results in the recognition of unrealized gains and losses from changes in the fair value of the derivatives, unless specific hedge criteria are met. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity as well as for proprietary trading within defined risk guidelines. Energy Trading also provides commodity risk management services to the other businesses within DTE Energy.

Significant portions of the power and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as contracted natural gas pipeline transportation and storage and power generation capacity positions. Most financial instruments are deemed derivatives, whereas proprietary gas inventory, power transmission, pipelines and storage assets are not derivatives. As a result, this segment may experience earnings volatility as derivatives are marked-to-market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different accounting periods. We may incur mark-to-market accounting gains or losses in one period that could reverse in subsequent periods.

CAPITAL INVESTMENT

We anticipate significant capital investment across all of our business segments during the next five years. Most of our capital expenditures will be concentrated within our utility segments. Our electric utility segment currently expects to invest approximately $6 billion (excluding investments in new base-load generation capacity, if any), including renewable and energy-efficiency related expenditures, increased environmental requirements and reliability enhancement projects during the period of 2009 through 2013. Our gas utility segment currently expects to invest approximately $850 million on system expansion, pipeline safety and reliability enhancement projects through the same period. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment. Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.

ENVIRONMENTAL MATTERS

Proposals for voluntary initiatives and mandatory controls are being discussed in the United States to reduce greenhouse gases such as carbon dioxide, a by-product of burning fossil fuels. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act (ACESA). The ACESA includes a cap and trade program that would start in 2012 and provides for costs for emissions of greenhouse gases (e.g. carbon dioxide). A discussion draft of climate legislation that retains some of the ACESA provisions was introduced in the U.S. Senate in September. Meanwhile, the EPA is beginning to implement regulatory action under the Clean Air Act to address climate change. There may be further legislative and/or regulatory action to address the issue of changes in climate that may result from the build-up of greenhouse gases in the atmosphere. If passed, legislative or regulatory actions as currently being discussed could have a material impact on our operations and financial position and the rates we charge our customers.

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 Title V operating permit requirements under the Clean Air Act. We believe that the plants identified by the EPA have complied with applicable regulations. Depending upon the outcome of our discussions with the EPA regarding the NOV/FOV, the EPA could bring legal action against Detroit Edison. We could also be required to install additional pollution control equipment at some or all of the power plants in question, engage in Supplemental Environmental Programs, and/or pay fines. We cannot predict the financial impact or outcome of this matter, or the timing of its resolution.

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:

•

continuing to pursue regulatory stability and investment recovery for our utilities;

•

managing the growth of our utility asset base;

•

enhancing our cost structure across all business segments;

•

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

•

improving Electric and Gas Utility customer satisfaction; 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.

RESULTS OF OPERATIONS

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

Net income attributable to DTE Energy by segment for the three and nine month periods ended September 30, 2009 and 2008 is as follows:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008

Net Income Attributable to DTE Energy Company:
Electric Utility	$	156		$	159		$	313		$	251
Gas Utility		(23	)		(15	)		23			33
Non-utility Operations:
Gas Midstream		13			11			37			27
Unconventional Gas Production (1)		(2	)		3			(6	)		89
Power and Industrial Projects		10			26			8			30
Energy Trading		6			19			73			36

Corporate & Other		(2	)		(34	)		(29	)		(69	)

Income (Loss) from Continuing Operations:
Utility		133			144			336			284
Non-utility		27			59			112			182
Corporate & Other		(2	)		(34	)		(29	)		(69	)

		158			169			419			397
Discontinued Operations		—			8			—			20

Net Income Attributable to DTE Energy Company	$	158		$	177		$	419		$	417


(1)		Results of the Unconventional Gas Production segment in the 2008 nine-month period reflects the gain on the sale of a portion of the Barnett shale properties. See Note 4 of the Notes to Consolidated Financial Statements.

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison.

Electric Utility results for the three and nine months ended September 30, 2009 as compared to the comparable periods in 2008 are discussed below:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008

Operating Revenues	$	1,300		$	1,440		$	3,526		$	3,766
Fuel and Purchased Power		400			586			1,112			1,403

Gross Margin		900			854			2,414			2,363
Operation and Maintenance		306			292			928			1,019
Depreciation and Amortization		222			193			607			563
Taxes Other Than Income		43			54			147			176
Other Asset (Gains) and Losses, Reserves, Net		—			(1	)		—			(1	)

Operating Income		329			316			732			606
Other (Income) and Deductions		75			67			220			212
Income Tax Provision		98			90			199			143

Net Income Attributable to DTE Energy Company	$	156		$	159		$	313		$	251


Operating Income as a Percentage of Operating Revenues		25	%		22	%		21	%		16	%

Gross margin increased $46 million in the third quarter of 2009 and increased $51 million in the nine-month period ended September 30, 2009. The following table details changes in various gross margin components relative to the comparable prior period:


(in Millions)	Three Months			Nine Months

December 2008 rate order	$	33		$	94
Securitization bond and tax surcharge rate increase		20			45
July 2009 rate self-implementation		40			40
Energy Optimization and Renewable Energy surcharge		17			19
Weather		(41	)		(57	)
Reduction in customer demand and other		(23	)		(90	)

Increase in gross margin	$	46		$	51

Electric Sales

Three Months Ended

Nine Months Ended

September 30

(in Thousands of MWh)

2009

2008

2009

2008

Residential

4,107

4,595

10,992

11,955

Commercial

4,806

5,072

13,764

14,347

Industrial

2,562

3,327

7,584

10,074

Wholesale

720

700

2,119

2,123

Other

280

285

12,274

13,783

34,739

38,784

Interconnections sales (1)

1,644

618

3,868

2,627

Total Electric Sales

13,918

14,401

38,607

41,411

Electric Deliveries

Retail and Wholesale

12,274

13,783

34,739

38,784

Electric Customer Choice (2)

337

329

998

1,081

Total Electric Sales and Deliveries

12,611

14,112

35,737

39,865


(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						Nine Months Ended
	September 30						September 30
(in Thousands of MWh)	2009			2008			2009			2008

Power Plant Generation
Fossil		10,729			10,566			30,424			31,153
Nuclear		2,367			2,405			6,106			7,156

		13,096			12,971			36,530			38,309
Purchased Power		1,753			2,486			4,569			5,725

System Output		14,849			15,457			41,099			44,034
Less Line Loss and Internal Use		(931	)		(1,056	)		(2,492	)		(2,623	)

Net System Output		13,918			14,401			38,607			41,411


Average Unit Cost ($/MWh)
Generation (1)	$	18.01		$	19.32		$	18.07		$	17.98

Purchased Power	$	35.50		$	88.43		$	37.07		$	73.23

Overall Average Unit Cost	$	20.08		$	30.43		$	20.18		$	25.16


(1)		Represents fuel costs associated with power plants.

Operation and maintenance expense increased $14 million in the third quarter of 2009 and decreased $91 million in the nine-month period ended September 30, 2009. The increase in the third quarter is primarily due to higher pension and healthcare costs of $10 million, and $6 million of energy optimization and renewable energy expenses. The decrease for the nine-month period is primarily due to $61 million from continuous improvement initiatives resulting in lower contract labor and outside services expense, information technology and other staff expenses, $38 million from the timing of maintenance activities, $19 million of employee benefit-related expenses and lower storm expenses of $22 million, partially offset by higher pension and healthcare costs of $41 million and $6 million of energy optimization and renewable energy expenses.

Taxes other than income were lower by $11 million in the 2009 third quarter and $29 million in the 2009 nine-month period due primarily to a $17 million and $30 million, respectively, reduction in property tax expense due to refunds received in partial settlement of appeals of assessments for prior years.

Outlook — We will move forward in our efforts to continue to improve the operating performance and cash flow of Detroit Edison. We continue to resolve outstanding regulatory issues. Many of these issues have been addressed by the October 2008 Michigan legislation. Looking forward, additional issues, such as higher levels of capital spending, volatility in prices for coal and other commodities, investment returns and changes in discount rate assumptions in benefit plans and health care costs, will result in us continuing to pursue opportunities to improve productivity, remove waste and decrease our costs while improving customer satisfaction.

Unfavorable national and regional economic trends have resulted in reduced demand for electricity in our service territory and increases in our uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies. Direct and indirect effects of further automotive and other industrial plant closures could have a significant impact on the results of Detroit Edison. We continue to monitor developments in this sector. Due to the economy and credit market conditions, in the near term, we are reviewing our capital expenditure commitments for potential adjustments as appropriate.

GAS UTILITY

Our Gas Utility segment consists of MichCon and Citizens.

Gas Utility results for the three and nine months ended September 30, 2009 as compared to the comparable periods in 2008 are discussed below:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008

Operating Revenues	$	190		$	225		$	1,253		$	1,537
Cost of Gas		69			105			720			975

Gross Margin		121			120			533			562
Operation and Maintenance		99			94			341			365
Depreciation and Amortization		27			25			80			75
Taxes Other Than Income		12			9			38			35
Other Asset (Gains) Losses and Reserves, Net		—			(2	)		(1	)		(2	)

Operating Income (Loss)		(17	)		(6	)		75			89
Other (Income) and Deductions		16			15			44			40
Income Tax Provision		(10	)		(6	)		8			16

Net Income (Loss) Attributable to DTE Energy Company	$	(23	)	$	(15	)	$	23		$	33


Operating Income as a Percentage of Operating Revenues		(9	)%		(3	)%		6	%		6	%

Gross margin increased $1 million in the third quarter of 2009 and decreased $29 million in the nine-month period ended September 30, 2009. For the third quarter, this increase reflects $5 million of higher midstream transportation and storage revenues, and $1 million of higher appliance service revenues, partially offset by $2 million of realized hedging losses covering company facility use of gas resulting from lower gas prices, $1 million of decreased late payment fees and $2 million of decreases in other miscellaneous revenue activities.

For the nine-month period, the decrease reflects $16 million of lower revenues from the uncollectible tracking mechanism, $14 million unfavorable result from lost and stolen gas, $10 million of continued customer conservation efforts, lower end user transportation revenue of $6 million and $5 million of realized hedging losses covering company facility use of gas resulting from lower gas prices, partially offset by $14 million higher midstream

transportation and storage revenues, the effects of favorable weather of $5 million and $3 million higher appliance service revenues.


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2009		2008		2009		2008
Gas Markets (in Millions)
Gas sales	$	121	$	156	$	1,013	$	1,297
End user transportation		24		22		102		105

		145		178		1,115		1,402
Intermediate transportation		16		18		50		53
Storage and other		29		29		88		82

	$	190	$	225	$	1,253	$	1,537


Gas Markets (in Bcf)
Gas sales		10		9		96		99
End user transportation		23		23		86		90

		33		32		182		189
Intermediate transportation		104		94		371		332

		137		126		553		521

Operation and maintenance expense increased $5 million in the third quarter of 2009 and decreased $24 million in the nine-month period ended September 30, 2009. The increase for the third quarter is primarily due to higher pension and healthcare costs. The decrease for the nine-month period is primarily due to $19 million of lower uncollectible expense, $11 million from continuous improvement initiatives resulting in lower contract labor and outside services expense, information technology and other staff expenses, $10 million of employee benefit-related changes, partially offset by higher pension and healthcare costs of $19 million. Uncollectible expense was higher in 2008 due to an analysis of our greater than ninety day receivables that indicated a change in the mix of customers in that group and therefore an increased risk of collection.

Outlook — Volatile gas prices and deteriorating economic conditions have resulted in continued pressure on receivables and working capital requirements that are partially mitigated by the MPSC’s GCR and uncollectible true-up mechanisms. We will continue to seek opportunities to improve productivity, minimize lost and stolen gas, remove waste and decrease our costs while improving customer satisfaction.

Unfavorable national and regional economic trends have resulted in a decrease in the number of customers in our service territory and continued high levels of uncollectible accounts receivable. The magnitude of these trends will be driven by the impacts of the challenges in the domestic automotive industry and the timing and level of recovery in the national and regional economies.

NON-UTILITY OPERATIONS

Gas Midstream

Our Gas Midstream segment consists of our gas pipelines and storage business.

Gas Midstream results for the three and nine months ended September 30, 2009 as compared to the comparable periods in 2008 are discussed below:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008

Operating Revenues	$	19		$	19		$	61		$	53
Operation and Maintenance		3			3			10			10
Depreciation and Amortization		2			1			4			4
Taxes Other Than Income		—			1			2			2

Operating Income		14			14			45			37
Other (Income) and Deductions		(6	)		(4	)		(17	)		(9	)
Income Tax Provision		7			7			24			19

Net Income		13			11			38			27
Attributable to Noncontrolling Interests		—			—			1			—

Net Income Attributable to DTE Energy Company	$	13		$	11		$	37		$	27

Net income attributable to DTE Energy increased $2 million and $10 million for the 2009 third quarter and nine-month periods, respectively. The increases were driven by higher operating revenues resulting from increased capacity sold and higher rates from renewing storage contracts related to long-term agreements. In addition, there were higher pipeline operating earnings from both Vector and Millennium.

Outlook — Our Gas Midstream business expects to continue its steady growth plan. In April 2008, an additional 7 Bcf of storage capacity was placed in service, which was followed by an additional 2 Bcf in April 2009. The Vector Pipeline Phase 2 expansion is currently under construction and will add approximately 100 MMcf/day, with an expected in-service date of November 2009. The 2009 expansion project is supported by customers under long-term contracts. Millennium Pipeline was placed in service in December 2008 and currently has nearly 85 percent of its capacity sold to customers under long-term contracts. We are also a 50 percent owner in the proposed Dawn Gateway Pipeline which will provide transport between our Michigan storage facilities and the Dawn Hub in Ontario, Canada.

Unconventional Gas Production

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

Unconventional Gas Production results for the three and nine months ended September 30, 2009 as compared to the comparable periods in 2008 are discussed below:


	Three Months Ended					Nine Months Ended
	September 30					September 30
(in Millions)	2009			2008		2009			2008

Operating Revenues	$	8		$	14	$	23		$	37
Operation and Maintenance		4			5		11			16
Depreciation, Depletion and Amortization		4			2		13			7
Taxes Other Than Income		—			—		1			—
Other Asset (Gains) and Losses, Reserves and Impairments, net		2			—		3			(128	)

Operating Income (Loss)		(2	)		7		(5	)		142
Other (Income) and Deductions		1			2		4			3
Income Tax Provision (Benefit)		(1	)		2		(3	)		50

Net Income (Loss) Attributable to DTE Energy Company	$	(2	)	$	3	$	(6	)	$	89

Operating revenues decreased $6 million in the third quarter of 2009 and $14 million in the 2009 nine-month period as a result of lower commodity prices, while production remained relatively flat.

Operation and maintenance expense was lower by $1 million and $5 million in the third quarter and nine-month period ended September 30, 2009, respectively, due to the ample supply of service companies available and our ability to secure lower prices for oilfield services. For the nine-month period of 2009, Barnett shale production was approximately 4 Bcfe of natural gas.

Other asset (gains) and losses, reserves and impairments, net decreased in the nine-month period ended September 30, 2009 as compared to 2008 due to the gain of $128 million ($80 million after-tax) on the 2008 sale of a portion of our Barnett shale properties and $3 million impairment in 2009 of expired or expiring leasehold positions that the company does not intend to drill at current commodity prices.

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 within our Barnett shale holdings, when conditions are appropriate. Our strategy for 2009 continues to center on reducing operating expenses and optimizing production volume. During 2009, we expect to invest approximately $20 million to $25 million to drill 10 to 15 new wells and achieve Barnett shale production of approximately 5 Bcfe of natural gas, compared with approximately 5 Bcfe in 2008.

Power and Industrial Projects

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

Power and Industrial Projects results for the three and nine months ended September 30, 2009 as compared to the comparable periods in 2008 are discussed below:


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2009			2008			2009			2008

Operating Revenues	$	157		$	264		$	450		$	718
Operation and Maintenance		136			223			417			647
Depreciation and Amortization		10			12			30			23
Taxes Other Than Income		3			3			9			10
Asset (Gains) Losses and Reserves, Net		(1	)		(4	)		(5	)		9

Operating Income (Loss)		9			30			(1	)		29
Other (Income) and Deductions		(3	)		(12	)		2			(15	)
Income Taxes
Provision (Benefit)		3			15			(4	)		16
Production Tax Credits		(1	)		(2	)		(8	)		(6	)

		2			13			(12	)		10

Net Income		10			29			9			34
Noncontrolling Interests		—			3			1			4

Net Income Attributable to DTE Energy Company	$	10		$	26		$	8		$	30

Operating revenues decreased $107 million in the third quarter of 2009 and $268 million in the nine-month period ended September 30, 2009. The 2009 third quarter decrease is attributed to $26 million representing a reduction in coal structured transactions, $71 million of lower pricing and volumes of coal and emissions and $31 million of lower coke demand, partially offset by a $27 million increase in coal transportation services. The 2009 nine-month decrease is attributable to $91 million representing a reduction in coal structured transactions, $161 million of lower pricing and volumes of coal and emissions and $94 million of lower coke demand, partially offset by a $78 million increase in coal related services.

Operation and maintenance expense decreased $87 million in the third quarter of 2009 and $230 million in the nine-month period ended September 30, 2009. The 2009 third quarter decrease is due primarily to $26 million representing a decrease in coal structured transactions and $20 million of lower coke demand, $58 million of lower pricing and volumes of coal and emissions, and operating expenses, partially offset by $19 million of higher coal transportation services. The 2009 nine-month decrease is due primarily to $91 million representing a decrease in coal structured transactions and $61 million of lower coke demand, $133 million of lower pricing and volumes of coal and emissions, and operating expenses, partially offset by $57 million of higher coal related services.

Depreciation and amortization expense increased $7 million in the nine-month period ended September 30, 2009. In 2007, we announced our plans to sell a 50% interest in a portfolio of select Power and Industrial Projects. As a result, the assets and liabilities of the Projects were classified as held for sale at that time and the Company ceased recording depreciation and amortization expense related to these assets. During the second quarter of 2008, our work on this planned monetization was discontinued and the assets and liabilities of the Projects were no longer classified as held for sale. Depreciation and amortization resumed in June 2008 when the assets were reclassified as held and used.

Assets (gains) losses and reserves, net expense improved $14 million in the nine-month period ended September 30, 2009. This increase was primarily attributable to a loss recorded in the 2008 periods of approximately $19 million related to the valuation adjustment for the cumulative depreciation and amortization upon reclassification of certain project assets as held for sale and gains attributable to the sale of one of our coke battery projects where the proceeds were dependent on future production.

Outlook — The stabilization in the U.S. economy is having a positive impact on our customers in the steel industry and we expect a corresponding improvement in demand for metallurgical coke and pulverized coal supplied to these customers for the remainder of 2009 and into 2010. We supply onsite energy services to the domestic automotive manufacturers who have also experienced stabilized demand for autos. Chrysler and GM have emerged from Chapter 11 bankruptcy protection on June 10, 2009 and July 10, 2009, respectively. We have been in discussions with both automakers and do not anticipate significant impacts to onsite energy services. Our onsite energy services will continue to be delivered in accordance with the terms of long-term contracts. We continue to monitor developments in this sector.

Our existing long-term rail transportation contract which gives us a competitive advantage will expire in 2011. 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. We will also continue to look for opportunities to acquire energy projects and biomass fired generating projects for advantageous prices.

Energy Trading

Energy Trading results for the three and nine months ended September 30, 2009 as compared to the comparable periods in 2008 are discussed below:


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2009		2008		2009		2008

Operating Revenues	$	306	$	405	$	638	$	1,128
Fuel, Purchased Power and Gas		274		355		464		1,004

Gross Margin		32		50		174		124
Operation and Maintenance		18		17		53		50
Depreciation, Depletion and Amortization		1		1		4		4
Taxes Other Than Income		—		1		2		2

Operating Income		13		31		115		68
Other (Income) and Deductions		3		—		7		3
Income Tax Provision		4		12		35		29

Net Income Attributable to DTE Energy Company	$	6	$	19	$	73	$	36

Gross margin decreased $18 million in the third quarter of 2009 and increased $50 million in the nine-month period ended September 30, 2009. Overall gross margin was impacted by a decrease in gas and power commodity prices in the nine months ended September 30, 2009 as compared to the same period in the prior year. The third quarter 2009 decrease of $18 million is due to decreases in realized margins of $20 million, offset by increases in unrealized margins of $2 million. The $20 million decrease in realized margin consisted of a decrease of $18 million in our gas strategies and $4 million in our power strategies, partially offset by $2 million of timing related gains in our oil trading portfolio. The increase in unrealized margins primarily consisted of $28 million of improvement in our power strategies; offset by declines of $25 million and $1 million in our gas and oil strategies, respectively.

The increase of $50 million for the nine-month period is due to an increase in unrealized margins of $56 million, partially offset by lower realized margins of $6 million. The increase in unrealized gains primarily consisted of $31 million of improvement in our power strategies; $23 million improvement in our gas strategies, primarily due to timing related gains in our gas transportation strategy; and $2 million of timing related gains on our oil strategies. The $6 million decrease in realized margin is caused by a decrease in gas margin of $28 million, primarily in our gas storage strategy, offset by an increase of realized power margin of $21 million and timing related gains in our oil trading portfolio of $1 million.

Other (income) and deductions increased $3 million in the third quarter of 2009 and $4 million in the nine-month period ended September 30, 2009 due to increased interest expense.

Income tax provision decreased $8 million in the third quarter of 2009 and increased $6 million in the nine-month period ended September 30, 2009. The third quarter 2009 decrease of $8 million is due to a decrease in income taxes attributable to lower pretax income. The nine-month period ended September 30, 2009 increase of $6 million is due to an increase in income taxes resulting from higher pretax income, partially offset by $10 million of favorable tax-related adjustments primarily resulting from the settlement of federal income tax audits.

Outlook — Significant portions of the Energy Trading portfolio are economically hedged. The portfolio includes financial instruments, physical commodity contracts and gas inventory, as well as contracted natural gas pipeline transportation and storage, and power generation capacity positions. Energy Trading also provides power and ancillary services and natural gas to various utilities which may include the management of associated storage and transport contracts on the customers’ behalf. Most financial instruments and physical power and gas contracts are deemed derivatives, whereas proprietary 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 third quarter 2009 net loss decreased $32 million due to $20 million of lower inter-company interest, $13 million of favorable tax related adjustments and $4 million lower costs related to natural gas forward contracts associated with the 2007 sale of the Antrim Shale properties. These favorable variances were partially offset by $6 million increase in financing fees.

The nine month period ended September 30, 2009 net loss decreased $40 million due to $25 million of favorable tax related adjustments, $25 million lower inter-company interest and $3 million lower costs related to natural gas forward contracts associated with the 2007 sale of the Antrim Shale properties. These favorable variances were partially offset by $9 million increase in financing fees and a $4 million impairment of an investment in an available-for-sale security.

DISCONTINUED OPERATIONS

Synthetic Fuel

the final phase-out percentage of approximately $32 million, the final settlement of other miscellaneous assets and liabilities and related tax impacts resulted in net income of $20 million for the first nine months of 2008.

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.

Our strategic direction anticipates capital investments and expenditures for existing businesses in 2009 of up to $1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures. We expect over $2.9 billion of future capital expenditures through 2018 to satisfy both existing and known new requirements, not including any potential requirements related to climate change. We plan to seek regulatory approval to include these capital expenditures within our regulatory rate base consistent with prior treatment.

We expect non-utility capital spending will approximate $200 million to $300 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

Due to the economy and credit market conditions, we are continually reviewing our capital expenditure commitments for potential reductions and deferrals and plan to adjust spending as appropriate.


	Nine Months Ended
	September 30
(in Millions)	2009			2008

Cash and Cash Equivalents
Cash Flow From (Used For)
Operating activities:
Net income	$	421		$	423
Depreciation, depletion and amortization		738			675
Deferred income taxes		141			280
Gain on sale of non-utility assets		—			(128	)
Gain on sale of synfuel and other assets, net		4			(19	)
Working capital and other		370			(213	)

		1,674			1,018


Investing activities:
Plant and equipment expenditures — utility		(772	)		(842	)
Plant and equipment expenditures — non-utility		(47	)		(154	)
Proceeds from sale of non-utility assets		—			253
Proceeds from sale of synfuels and other assets		35			(282	)
Restricted cash and other investments		(11	)		(23	)

		(795	)		(1,048	)


Financing activities:
Issuance of long-term debt		363			1,013
Redemption of long-term debt		(420	)		(446	)
Repurchase of long-term debt		—			(238	)
Short-term borrowings, net		(574	)		71
Issuance of common stock		27			—
Repurchase of common stock		—			(16	)
Dividends on common stock and other		(278	)		(265	)

		(882	)		119

Net Increase (Decrease) in Cash and Cash Equivalents	$	(3	)	$	89

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.

Net cash from operating activities in the nine months ended September 30, 2009, increased $656 million from the comparable 2008 period due to higher cash from working capital and other items, primarily the recovery of gas supply costs, income taxes, accounts receivable and inventories.

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, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is primarily to maintain our existing facilities and for 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 was $795 million for the nine months ended September 30, 2009, compared with net cash used for investing activities of $1,048 million in the same period in 2008. This decrease is primarily attributable to lower plant and equipment expenditures in both utility and non-utility segments.

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. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet.

Net cash used for financing activities was $882 million for the nine months ended September 30, 2009 compared to net cash from financing activities of $119 million for the same period in 2008. This change was primarily due to higher short-term debt repayments and a lower issuance of long-term debt partially offset by the 2008 repurchase of tax-exempt bonds.

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-regulated 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. Our non-utility growth is expected from additional investments in energy projects as economic conditions improve. We are actively developing joint venture opportunities to produce reduced emissions fuel for coal-fired power plants. The reduced emissions fuel technology reduces stack emissions at coal-fired power plants and is expected to qualify for tax credits benefits. We expect to invest $37 million in these joint ventures and related facilities by December 31, 2009.

We have been impacted by unfavorable national and regional economic trends that have reduced demand for electricity in our service territory. We may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas accounts receivable as a result 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.

In April 2009 we completed an early renewal of $975 million of our syndicated revolving credit facilities before their scheduled expiration in October 2009. The new $1 billion two-year facility will expire in 2011 and has similar covenants to the prior facility. A new two-year $50 million credit facility was completed in May 2009 and a new one-year $70 million credit facility was completed in June 2009. We have a $925 million five-year facility that expires in October 2010. See Note 8 of Notes to Consolidated Financial Statements.

As a result of losses experienced in the 2008 financial markets, our benefit plan assets experienced negative returns, which will result in higher benefit costs and contributions in 2009 and potentially in future years relative to the recent past. During the first nine months of 2009, our pension plan and other postretirement benefit plans assets experienced positive returns of approximately 15 percent and 17 percent, respectively. During 2009, we expect to contribute up to $250 million to our pension plans and up to $170 million to our postretirement medical and life insurance benefit plans.

While the impact of continued market volatility and turmoil in the credit markets cannot be predicted, 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.

As part of the normal course of business, Detroit Edison, MichCon and various non-utility subsidiaries of the Company routinely enter into physical or financially settled contracts for the purchase and sale of electricity, natural gas, coal, capacity, storage and other energy-related products and services. Certain of these contracts contain provisions which allow the counterparties to request that the Company post cash or letters of credit in the event that the credit rating of DTE Energy is downgraded below investment grade. Certain of these contracts for Detroit Edison and MichCon contain similar provisions in the event that the credit rating of the particular utility is downgraded below investment grade. The amount of such collateral which could be requested fluctuates based upon commodity prices and the provisions and maturities of the underlying transactions and could be substantial. Also, upon a downgrade below investment grade, we could have restricted access to the commercial paper market and if DTE Energy is downgraded below investment grade our non-utility businesses, especially the Energy Trading and Power and Industrial Projects segments, could be required to restrict operations due to a lack of available liquidity. A downgrade below investment grade could potentially increase the borrowing costs of DTE Energy and its subsidiaries and may limit access to the capital markets. The impact of a downgrade will not affect our ability to comply with our existing debt covenants. Our current credit ratings, as determined by three nationally recognized credit rating agencies, are considered investment grade.

In May 2009, Standard & Poor’s Rating Group (Standard & Poor’s) revised the outlook on DTE Energy and its subsidiaries to negative from stable, and lowered the short-term corporate credit and commercial paper ratings for DTE Energy, Detroit Edison and MichCon to A-3 from A-2. The revision is primarily due to concerns over Michigan’s economic climate. Moody’s Investors Service (Moody’s) affirmed our existing short-term ratings of P-2. Short-term borrowings, principally in the form of commercial paper, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities. The resulting split (A-3/P-2) rating has weakened our ability to issue commercial paper, however, to date, we have met our short-term borrowing requirements in the commercial paper market without drawing on back-up credit facilities. Potential instability in the credit markets and the result of our lower rating may impact future access to the commercial paper markets, which may require us to draw on our back-up facilities.

In August 2009, Moody’s upgraded the majority of senior secured debt ratings of investment-grade regulated utilities by one notch as a result of revised notching guidelines between senior secured debt ratings and senior unsecured debt ratings. Both Detroit Edison’s and MichCon’s senior debt ratings were upgraded to A2 from A3.

CRITICAL ACCOUNTING ESTIMATES

Asset Impairments — Goodwill

Certain of our reporting units have goodwill or allocated goodwill resulting from purchase business combinations. We perform an impairment test for each of our reporting units with goodwill annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In performing Step 1 of the impairment test, we compare the fair value of the reporting unit to its carrying value including goodwill. If the carrying value including

goodwill were to exceed the fair value of a reporting unit, Step 2 of the test would be performed. Step 2 of the impairment test requires the carrying value of goodwill to be reduced to its fair value, if lower, as of the test date.

For Step 1 of the test, we estimate the reporting unit’s fair value using standard valuation techniques, including techniques which use estimates of projected future results and cash flows to be generated by the reporting unit. Such techniques generally include a terminal value that utilizes an earnings multiple approach, which incorporates the current market values of comparable entities. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. We also employ market-based valuation techniques to test the reasonableness of the indications of value for the reporting units determined under the cash flow technique.

We performed our annual impairment test as of October 1, 2008 and determined that the estimated fair value of each reporting unit exceeded its carrying value, and no impairment existed. In the period from October 1, 2008 to March 31, 2009, DTE Energy’s stock price declined by 31 percent and at March 31, 2009 was approximately 26 percent below its book value per share of $37.29. We deemed the duration and severity of the decline in DTE Energy’s stock price to be a triggering event to test for potential goodwill impairment for the first quarter.

A first quarter interim test was performed for all reporting units with allocated goodwill as of February 28, 2009. The results of the test and key estimates that were incorporated are as follows.

As of February 28, 2009 Valuation Date
($ in millions)


			Fair Value			Discount			Terminal
Reporting Unit	Goodwill		Reduction % (a)			Rate			Multiple (b)		Valuation Methodology (c)
Electric Utility	$	1,206		17	%		7	%		7.0x	DCF, assuming stock sale
Gas Utilities		772		6	%		7	%		9.0x	DCF, assuming stock sale
Energy Services		28		55	%		14	%		4.5x	DCF, assuming asset sale
Coal Services		4		15	%		11	%		5.5x	DCF, assuming asset sale
Gas Midstream		7		59	%		10	%		7.5x	DCF, assuming asset sale
Energy Trading		17		100	%		n/a			n/a	Economic value of trading portfolio
Unconventional Gas Production		2		56	%		14	%		n/a	Blended — DCF, transaction multiples

	$	2,036


(a)		Percentage by which the fair value of the reporting unit would need to decline to equal its carrying value.

(b)		Multiple of enterprise value (sum of debt plus equity value) to earnings before interest, taxes, depreciation and amortization (EBITDA)

(c)		Discounted cash flows (“DCF”) incorporated 2009-2013 projected cash flows plus a calculated terminal value.

For the first quarter interim test, we updated projected future results, cash flows and discount rates to reflect recent regulatory actions and negative impacts from the deterioration in the regional and national economy. Terminal values that utilize an earnings multiple approach were updated to incorporate the current market values of comparable entities. As compared to the annual test performed in the fourth quarter of 2008, the valuations were negatively impacted by current market factors with particular downward pressure on market multiples. We also compared the aggregate fair value of our reporting units to our overall market capitalization. The implied premium of the aggregate fair value over market capitalization is likely attributable to factors such as (1) an acquisition control premium (the price in excess of a stock’s market price that investors typically pay to gain control of an entity), and (2) the market’s apparent discounting of DTE Energy’s stock price due to uncertainty regarding the current regulatory and automotive industry environment and DTE Energy’s diverse non-utility business portfolio. All reporting units passed Step 1 of the impairment test.

The excess of fair value over carrying value for our Gas Utilities reporting unit narrowed considerably since the fourth quarter 2008 test, largely due to declines in the market values and resulting market multiples of comparable entities referenced in our valuation. Further declines in market multiples, negative regulatory actions or other disruptions in cash flows for the Gas Utility reporting unit could result in an impairment charge in the foreseeable future. For example, at the current discount rate and holding all other variables constant, a 0.5x decrease in the terminal multiple would lower the fair value by approximately $130 million. At the lower fair value, the Gas Utility reporting unit would likely fail Step 1 of the test potentially resulting in a charge for impairment of goodwill following completion of the Step 2 analysis.

For the quarters ended June 30, 2009 and September 30, 2009, DTE Energy’s closing stock price increased 16 percent and 27 percent, respectively, as compared to the closing stock price at March 31, 2009. Although DTE Energy is still trading at a discount to book value at the end of the third quarter, the discount improved to 7 percent at September 30, 2009 from 26 percent at March 31, 2009. In assessing whether the continuing discount to book value was an indication of impairment, we considered the following factors: (1) the severity of the decline in DTE Energy’s share price experienced since the fourth quarter of 2008 has diminished and is continuing to recover; and (2) the assumptions incorporated in the first quarter impairment test have either improved or have not changed significantly during the second and third quarters such that they would change the results of Step 1. As a result of this assessment, we determined that the continuing discount to book value was not a triggering event for impairment testing purposes for the second and third quarters.

We did, however, identify a trigger for our Energy Services reporting unit related to the long-lived asset impairment tests that were performed during the second quarter on certain automotive-related project companies. The fair value of the reporting unit exceeded its carrying value including goodwill, therefore, the reporting unit passed Step 1 of the impairment test. As compared to the first quarter interim test, the second quarter valuation was favorably impacted by increased market multiples and an improved discount rate.

We perform an annual impairment test each October. In between annual tests, we monitor our estimates and assumptions regarding estimated future cash flows, including the impact of movements in market indicators in future quarters and will update our impairment analyses if a triggering event occurs. While we believe our assumptions are reasonable, actual results may differ from our projections. To the extent projected results or cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

FAIR VALUE

All contracts considered to be derivative instruments are recorded on the balance sheet at their fair value, 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 contracts. Items we do not generally account for as derivatives include proprietary gas inventory, gas storage and transportation arrangements, and gas and oil reserves. See Note 3 of the Notes to Consolidated Financial Statements.

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

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

•

Economic Hedges — Represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned 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.

•

Structured Contracts — Represents derivative activity transacted by originating substantially hedged positions with wholesale energy marketers, producers, end users, utilities, retail aggregators and alternative energy suppliers.

•

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

•

Other — Includes derivative activity associated with our Unconventional Gas reserves. A portion of the price risk associated with anticipated production from the Barnett natural gas reserves has been mitigated through

2010. Changes in the value of the hedges are recorded as Derivative assets or liabilities, with an offset in Other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves including changes therein. Other also includes derivative activity at Detroit Edison related to Financial Transmission Rights (FTR) and forward contracts related to emissions. Changes in the value of derivative contracts at Detroit Edison are recorded as Derivative assets or liabilities, with an offset to Regulatory assets or liabilities as the settlement value of these contracts will be included in the PSCR mechanism when realized.

The following tables provide details on changes in our MTM net asset (or liability) position for the nine months ended September 30, 2009:


	Economic			Structured			Proprietary
(in Millions)	Hedges			Contracts			Trading			Other			Total

MTM at December 31, 2008	$	18		$	(222	)	$	22		$	9		$	(173	)

Reclassify to realized upon settlement		19			73			(83	)		(6	)		3
Changes in fair value recorded to income		4			(10	)		105			—			99
Amortization of option premiums		—			—			31			—			31

Amounts recorded to unrealized income		23			63			53			(6	)		133
Changes in fair value recorded in regulatory assets/ liabilities		—			—			—			(12	)		(12	)
Amounts recorded in other comprehensive income		—			—			—			4			4
Change in collateral held by (for) others		(12	)		16			(8	)		—			(4	)
Option premiums and other		—			—			(23	)		—			(23	)

MTM at September 30, 2009	$	29		$	(143	)	$	44		$	(5	)	$	(75	)

A substantial portion of the Company’s price risk related to its Antrim shale gas exploration and production business was mitigated by financial contracts that hedged our price risk exposure through 2013. The contracts were retained when the Antrim business was sold and offsetting financial contracts were put into place to effectively settle these positions. The contracts will require payments through 2013. These contracts represent a significant portion of the above net mark-to-market liability.

The following table provides a current and noncurrent analysis of Derivative assets and liabilities, as reflected on the Consolidated Statements of Financial Position as of September 30, 2009. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.


	Economic			Structured			Proprietary									Assets
(in Millions)	Hedges			Contracts			Trading			Other			Eliminations			(Liabilities)

Current assets	$	12		$	197		$	64		$	4		$	(6	)	$	271
Noncurrent assets		23			125			17			—			(2	)		163

Total MTM assets		35			322			81			4			(8	)		434


Current liabilities		(5	)		(223	)		(33	)		(2	)		6			(257	)
Noncurrent liabilities		(1	)		(242	)		(4	)		(7	)		2			(252	)

Total MTM liabilities		(6	)		(465	)		(37	)		(9	)		8			(509	)


Total MTM net assets (liabilities)	$	29		$	(143	)	$	44		$	(5	)	$	—		$	(75	)

The table below shows the maturity of our MTM positions:


										2012
(in Millions)										and			Total Fair
Source of Fair Value	2009			2010			2011			Beyond			Value

Economic Hedges	$	37		$	(9	)	$	(3	)	$	4		$	29
Structured Contracts		(1	)		(38	)		(39	)		(65	)		(143	)
Proprietary Trading		68			(29	)		6			(1	)		44
Other		1			(3	)		(3	)		—			(5	)

Total	$	105		$	(79	)	$	(39	)	$	(62	)	$	(75	)

Part I — Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Price Risk

DTE Energy has commodity price risk in both utility and non-utility businesses arising from market price fluctuations.

The 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 form of 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 has a tracking mechanism to mitigate a portion of losses related to uncollectible accounts receivable at MichCon. 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 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 Unconventional Gas Production business segment has exposure to natural gas and, to a lesser extent, 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 Energy Trading business segment has exposure to electricity, natural gas, crude oil, heating oil, and foreign currency 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.

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

Credit Risk

Bankruptcies

The Company’s utilities and certain non-utility businesses provide services to the domestic automotive industry, including GM, Ford Motor Company (Ford) and Chrysler and many of their vendors and suppliers. Chrysler filed for bankruptcy protection on April 30, 2009. We have reserved approximately $9 million of pre-petition accounts receivable related to Chrysler as of September 30, 2009. GM filed for bankruptcy protection on June 1, 2009. We have reserved or written off approximately $5 million of pre-petition accounts and notes receivable related to GM as of September 30, 2009. Closing of GM or Chrysler plants or other facilities that operate within Detroit Edison’s service territory will also negatively impact the Company’s operating revenues in future periods. In 2008, GM and Chrysler represented 3 percent and 2 percent of its annual electric sales volumes, respectively. GM and Chrysler have an immaterial impact to MichCon’s revenues.

long-term contracts for services is guaranteed by Daimler North America Corporation (Daimler), a subsidiary of Daimler AG. The long-term contracts and the supporting Daimler guarantee provide for full recovery of the Company’s investment in the event of early termination or default. Chrysler has announced the closure of one site that is under a long-term service contract with the Company. Through September 30, 2009, to the extent that Chrysler has not been performing in accordance with its contracts, Daimler has been performing under its guarantee. Therefore, the Company believes that it will recover its investment in the event of a facility closure or a Chrysler default.

Other

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

Trading Activities

We are exposed to credit risk through trading activities. Credit risk is the potential loss that may result if our trading counterparties fail to meet their contractual obligations. We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of September 30, 2009:


	Credit Exposure
	before Cash		Cash		Net Credit
(in Millions)	Collateral		Collateral		Exposure

Investment Grade (1)
A- and Greater	$	315	$	11	$	304
BBB+ and BBB		191		—		191
BBB-		69		—		69

Total Investment Grade		575		11		564

Non-investment grade (2)		5		—		5
Internally Rated — investment grade (3)		80		—		80
Internally Rated — non-investment grade (4)		9		—		9

Total	$	669	$	11	$	658


(1)		This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody’s and BBB- assigned by Standard & Poor’s. The five largest counterparty exposures combined for this category represented approximately 34 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 represent less than one 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 ten 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 one percent of the total gross credit exposure.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we may use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of September 30, 2009, we had a floating rate debt-to-total debt ratio of approximately three percent (excluding securitized debt).

Foreign Currency 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 fluctuations, we have entered into a series of currency forward contracts through January 2013. Additionally, we may enter into fair value currency hedges to mitigate changes in the value of contracts or loans.

Summary of Sensitivity Analysis

We performed a sensitivity analysis on the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at September 30, 2009 by a hypothetical 10 percent and calculating the resulting change in the fair values. The results of the sensitivity analysis calculations follow:


(in Millions)	Assuming a 10%			Assuming a 10%
Activity	increase in rates			decrease in rates			Change in the fair value of
Coal Contracts	$	2		$	(1	)	Commodity contracts
Gas Contracts	$	(8	)	$	9		Commodity contracts
Oil Contracts	$	2		$	(1	)	Commodity contracts
Power Contracts	$	(4	)	$	4		Commodity contracts
Interest Rate Risk	$	(295	)	$	317		Long-term debt
Foreign Currency Risk	$	3		$	(3	)	Forward contracts
Discount Rates	$	1		$	(1	)	Commodity contracts

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 and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2009, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such 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 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be attained.

(b) Changes in internal control over financial reporting

There have been no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II — Other Information


Item 1. — Legal Proceedings

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. The defendants filed motions to dismiss. 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.


Item 1A. — Risk Factors

In addition to the other information set forth in this report, the risk factors discussed in Part 1, Item 1A. Risk Factors in the Company’s 2008 Form 10-K, which could materially affect the Company’s businesses, financial condition, future operating results and/ or cash flows should be carefully considered. Additional risks and uncertainties not currently known to the Company, or that are currently deemed to be immaterial, also may materially adversely affect the Company’s business, financial condition, and/ or future operating results.

We may be required to refund amounts we collect under self-implemented rates. Recent Michigan legislation allows us to self-implement rate changes six months after a rate filing, subject to certain limitations. However, if the final rate case order provides for lower rates than we have self-implemented, we must refund the difference, with interest. Our financial performance may be negatively affected if the MPSC sets lower rates than those we have self-implemented, thereby forcing us to issue refunds. We cannot predict what rates the MPSC order will adopt.

Adverse changes in our credit ratings may negatively affect us. Regional and national economic conditions, increased scrutiny of the energy industry and regulatory changes, as well as changes in our economic performance, could result in credit agencies reexamining our credit rating. While credit ratings reflect the opinions of the credit agencies issuing such ratings and may not necessarily reflect actual performance, a downgrade in our credit rating could restrict or discontinue our ability to access capital markets, including commercial paper markets, and could result in an increase in our borrowing costs, a reduced level of capital expenditures and could impact future earnings and cash flows. In addition, a reduction in credit rating may require us to post collateral related to various physical or financially settled contracts for the purchase of energy-related commodities, products and services, which would impact our liquidity.


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

The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Securities Exchange Act of 1934 during the three months ended September 30, 2009:


					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 (2)
07/01/09 — 07/31/09		—	$	—		—	$	822,895,623
08/01/09 — 08/31/09		25,000	$	35.01		—	$	822,895,623
09/01/09 — 09/30/09		—	$	—		—	$	822,895,623

Total		25,000	$	—		—


(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.

(2)		In May 2007, the DTE Energy Board of Directors authorized the repurchase of up to $850 million of common stock through 2009. During 2009, no repurchases of common stock were made under this authorization. This authorization provides management with flexibility to pursue share repurchases from time to time, and will depend on actual and future asset monetization, cash flows and investment opportunities.


Item 6. — Exhibits


Exhibit
Number		Description

Exhibits filed herewith:

12-44		Computation of Ratio of Earnings to Fixed Charges.

31-53		Chief Executive Officer Section 302 Form 10-Q Certification.

31-54		Chief Financial Officer Section 302 Form 10-Q Certification.

Exhibits furnished herewith:

32-53		Chief Executive Officer Section 906 Form 10-Q Certification.

32-54		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

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: October 30, 2009	/S/ PETER B. OLEKSIAK
	Peter B. Oleksiak
	Vice President and Controller and Chief Accounting Officer