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, 2003

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.)
2000 2nd Avenue, 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 (Exchange Act) 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 is an accelerated filer as defined in Rule 12b-2 of the Exchange Act.

Yes þ     No o

      At September 30, 2003, 168,301,400 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.

TABLE OF CONTENTS

DEFINITIONS
FORWARD-LOOKING STATEMENTS
	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	CONTROLS AND PROCEDURES
		CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
		CONSOLIDATED STATEMENT OF FINANCIAL POSITION
		CONSOLIDATED STATEMENT OF FINANCIAL POSITION
		CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
		CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (Unaudited)
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)
CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)
CONSOLIDATING STATEMENTS OF FINANCIAL POSITION (Unaudited)
CONSOLIDATING STATEMENTS OF FINANCIAL POSITION
CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)
CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)
INDEPENDENT ACCOUNTANTS’ REPORT
OTHER INFORMATION
	Legal Proceedings
	Exhibits and Reports on Form 8-K
SIGNATURE
Awareness of Deloitte & Touche LLP
Chief Executive Officer Section 302 Certification
Chief Financial Officer Section 302 Certification
Chief Executive Officer Section 906 Certification
Chief Financial Officer Section 906 Certification
364-Day Credit Agreement
Three Year Credit Agreement

DTE ENERGY COMPANY

QUARTERLY REPORT ON FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2003

TABLE OF CONTENTS

		Page
		Number
Definitions			2
Forward-Looking Statements			3
PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statement of Operations		19
	Consolidated Statement of Financial Position		20
	Consolidated Statement of Cash Flows		22
	Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		23
	Notes to Consolidated Financial Statements		24
	Independent Accountants’ Report		46
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		4
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		17
Item 4.	Controls and Procedures		18
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		47
Item 6.	Exhibits and Reports on Form 8-K		47
Signature			48

1

DEFINITIONS

Company	DTE Energy Company and 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 wholly owned subsidiary of DTE Energy Company) and subsidiary companies
DTE Energy	DTE Energy Company, the parent of Detroit Edison and Enterprises
Enterprises	DTE Enterprises, Inc. (successor to MCN Energy) and subsidiaries
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GCR	A gas cost recovery mechanism authorized by the MPSC that was reinstated by MichCon in January 2002, permitting MichCon to pass the cost of natural gas to its customers.
ITC	International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)
MichCon	Michigan Consolidated Gas Company and subsidiary companies
MPSC	Michigan Public Service Commission
MWh	Megawatthour
PLR	A private letter ruling issued by the Internal Revenue Service interpreting a statute or administrative rule and its application to a particular set of facts and circumstances, typically addressing an unusual or complex transaction.
PSCR	A power supply cost recovery mechanism authorized by the MPSC that allowed Detroit Edison to recover through rates its fuel, fuel-related and purchased power electric expenses. The clause was suspended under Michigan’s restructuring legislation signed into law June 5, 2000, which lowered and froze electric customer rates.
Section 29 Tax Credits	Tax credits authorized under Section 29 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources.
SFAS	Statement of Financial Accounting Standards
Stranded Costs	Costs incurred by utilities in order to serve customers in a regulated environment that are not expected to be recoverable if customers switch to alternative suppliers of electricity and gas.
Synfuels	Synthetic fuels produced by chemically modifying and binding particles of coal to produce a fuel that is used for power generation and coke production.

2

FORWARD-LOOKING STATEMENTS

      Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those contemplated, projected, estimated or budgeted in such forward-looking statements. There are many factors that may impact forward-looking statements including, but not limited to, the following:

•  the effects of weather and other natural phenomena on operations and sales to customers;

•  economic climate and growth in the geographic areas where we do business;

•  environmental issues, including changes in the climate, and regulations;

•  nuclear regulations and risks associated with nuclear operations;

•  ability to utilize Section 29 tax credits and sell interests in facilities producing such credits;

•  implementation of Customer Choice programs;

•  implementation of electric and gas utility restructuring in Michigan;

•  employee relations and the impact of collective bargaining agreements;

•  unplanned outages;

•  capital market conditions and access to capital markets and other financing efforts that can be affected by credit agency ratings;

•  the timing and extent of changes in interest rates;

•  the level of borrowings;

•  changes in the cost of fuel, purchased power and natural gas;

•  effects of competition;

•  impact of FERC and MPSC proceedings and regulations;

•  contributions to earnings by non-regulated businesses;

•  changes in federal or state tax laws and their interpretations, including the code, regulations, rulings, court proceedings and audits;

•  ability to recover costs through rate increases;

•  property insurance;

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

•  changes in accounting standards and financial reporting regulations; and

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

      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 statement speaks only as of the date on which such statement is 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.

3

DTE ENERGY COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations

      We had income of $176 million in the 2003 third quarter, or $1.04 per diluted share, compared to income of $161 million, or $.96 per diluted share, for the 2002 third quarter. For the nine-month period, our income was $292 million, or $1.73 per diluted share, compared to income of $429 million, or $2.62 per diluted share, for the same 2002 period. The comparability of earnings was impacted by the sale of our transmission business, International Transmission Company (ITC), and the adoption of two new accounting rules in the 2003 first quarter. Upon selling ITC in February 2003, we classified this business as a discontinued operation. Earnings from this discontinued operation decreased by $26 million in the 2003 third quarter, whereas earnings increased by $31 million in the 2003 nine-month period reflecting a $63 million net of tax gain recorded on the sale. As required by generally accepted accounting principles, on January 1, 2003 we adopted new accounting rules for asset retirement obligations and energy trading activities as discussed in Note 2. The cumulative effect of adopting these new accounting rules reduced earnings for the 2003 nine-month period by $27 million.

      Excluding discontinued operations and the cumulative effect of accounting changes, our income from continuing operations for the 2003 third quarter was $180 million or $1.06 per diluted share, compared to income of $139 million, or $.83 per diluted share, in the 2002 third quarter. For the 2003 nine-month period, we had income from continuing operations of $251 million, or $1.49 per diluted share, compared to income of $392 million, or $2.39 per diluted share, for the same 2002 period. The table below details several significant items impacting comparability, which increased earnings by $66 million, or $.39 per diluted share, and $19 million, or $.11 per diluted share, for the third quarter of 2003 and 2002, respectively. Significant items also impacted the 2003 and 2002 nine-month periods reducing earnings by $111 million, or $.66 per diluted share, and increasing earnings by $5 million, or $.03 per diluted share, respectively.

		Three Months					Nine Months
		Ended					Ended
		September 30					September 30
		2003			2002		2003			2002
		(In millions, except per share
		amounts)
Significant Items Impacting Comparability
Energy Resources —
	August 2003 blackout costs(1)	$	(16	)	$	—	$	(16	)	$	—
	Margins resulting from accounting change(2)		—			—		16			—
Energy Distribution —
	Loss on sale of steam business(3)		—			—		(14	)		—
Energy Gas —
	Disallowance of gas costs(4)		—			—		(17	)		—
Corporate —
	Contribution to DTE Energy Foundation(5)		—			—		(10	)		—
	Tax credit driven normalization(6)		82			19		(70	)		5
Increase (Decrease) in Net Income (Loss)		$	66		$	19	$	(111	)	$	5
Increase (Decrease) in Diluted Earnings (Loss) Per Share		$	.39		$	.11	$	(.66	)	$	.03

(1)	Costs associated with the August 2003 blackout (Note 4).
(2)	DTE Energy realized additional margins as a result of the change in accounting for energy trading activities (Note 2).

4

(3)	The Detroit Edison steam heating business was sold in January 2003 (Note 3).
(4)	MichCon established a reserve for the potential disallowance of procured gas costs (Note 4).
(5)	DTE Energy used a portion of the proceeds from the ITC sale to fund the DTE Energy Foundation.
(6)	Quarterly tax adjustment to DTE Energy’s effective tax rate. Annual results are not affected.

      As discussed in DTE Energy’s 2002 Annual Report on Form 10-K, we operate our business through nine reportable segments. The following tables and related discussion depict the operations of each of these segments.

			Three Months						Nine Months
			Ended						Ended
			September 30						September 30
			2003			2002			2003			2002
			(In millions)
Net Income (Loss)
Energy Resources
	Regulated — Power Generation		$	61		$	54		$	132		$	171
	Non-regulated
		Energy Services		23			45			151			107
		Energy Marketing & Trading		23			(1	)		52			12
		Other		(1	)		1			(1	)		—
	Total Non-regulated			45			45			202			119
				106			99			334			290
Energy Distribution
	Regulated — Power Distribution			35			51			15			97
	Non-regulated			(3	)		(4	)		(12	)		(11	)
				32			47			3			86
Energy Gas
	Regulated — Gas Distribution			(45	)		(23	)		5			30
	Non-regulated			12			6			26			20
				(33	)		(17	)		31			50
Corporate & Other				75			10			(117	)		(34	)
Income from Continuing Operations
	Regulated			51			82			152			298
	Non-regulated(1)			129			57			99			94
				180			139			251			392
Discontinued Operations				(4	)		22			68			37
Cumulative Effect of Accounting Changes				—			—			(27	)		—
Net Income			$	176		$	161		$	292		$	429
Diluted Earnings (Loss) per Common Share
	Regulated		$	.30		$	.49		$	.91		$	1.82
	Non-regulated(1)			.76			.34			.58			.57
Income from Continuing Operations				1.06			.83			1.49			2.39
Discontinued Operations				(.02	)		.13			.40			.23
Cumulative Effect of Accounting Changes				—			—			(.16	)		—
Net Income			$	1.04		$	.96		$	1.73		$	2.62

(1)  Includes Corporate & Other

5

Energy Resources

Power Generation

      The power generation plants of Detroit Edison comprise our regulated power generation business. Detroit Edison’s numerous fossil plants, hydroelectric pumped storage plant and its nuclear plant generate electricity that is sold principally throughout Michigan and the Midwest to residential, commercial, industrial and wholesale customers.

      Power Generation earnings increased $7 million during the 2003 third quarter and decreased $39 million in the 2003 nine-month period compared to the 2002 periods. Results for both periods were affected by lower gross margins, varying operation and maintenance expenses and lower depreciation and amortization expense. The reduced gross margins were driven by decreased cooling demand due to mild weather, lost margins from customers choosing to purchase power from alternative suppliers under the electric Customer Choice program and lost margins from the August 2003 blackout. As a result of the electric Customer Choice program, Detroit Edison has lost 11% of retail sales during 2003 resulting in lost margins of approximately $70 million. To partially offset the impact of these lost margins, Detroit Edison recorded regulatory assets totaling $8 million in the 2003 third quarter and $30 million in the 2003 nine-month period representing stranded costs that we believe are recoverable under Michigan legislation. Gross margins benefited from lower fuel unit costs reflecting the use of a more favorable power supply mix. We increased the usage of lower-cost power from our generating plants and reduced our usage of higher-cost purchased power. Operation and maintenance expenses were affected by costs associated with the August 2003 blackout (Note 4), higher employee pension and health care benefit costs and expenses due to the timing of planned reliability and maintenance work done to improve the production and availability of the generation fleet. Operation and maintenance expenses benefited from our Company-wide initiative to reduce or defer costs and enhance operating performance. The DTE Operating System involves the rigorous disciplined application of tools and operating practices which have resulted in improvements in plant efficiency and technology systems, among other enhancements. The decrease in depreciation and amortization expense is attributable to the income effect of recording regulatory assets representing net stranded costs and the deferral of other costs recoverable under Public Act 141.

	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2003			2002			2003			2002
	(In millions)
Operating Revenues	$	669		$	806		$	1,874		$	2,082
Fuel and Purchased Power		284			381			749			824
Gross Margin		385			425			1,125			1,258
Operation and Maintenance		147			158			487			469
Depreciation and Amortization		65			102			199			263
Taxes other than Income		40			38			121			116
Operating Income		133			127			318			410
Other Deductions		39			45			115			149
Income Tax Provision		33			28			71			90
Net Income	$	61		$	54		$	132		$	171
Operating Income as a Percent of Operating Revenues		20	%		16	%		17	%		20	%

6

      System output and average fuel and purchased power costs were as follows:

		Three Months				Nine Months
		Ended September 30				Ended September 30
		2003		2002		2003		2002
		(In thousands of MWh)
Power generated and purchased
Power plant generation
	Fossil		10,308		11,183		28,649		29,813
	Nuclear		2,096		2,384		5,645		7,008
Purchased power			1,868		3,439		5,599		7,257
System output			14,272		17,006		39,893		44,078
Average unit cost ($/MWh)
Generation(1)		$	13.21	$	12.98	$	13.34	$	12.62
Purchased power(2)		$	55.38	$	52.96	$	43.79	$	43.24
Overall Average Unit Cost		$	18.73	$	21.36	$	17.62	$	17.63

(1)	Represents fuel costs associated with power plants.
(2)	Includes hedging activities.

      Outlook — Detroit Edison lost 6% of retail sales in 2002 and estimates losing up to 13% of such sales in 2003 as a result of customers choosing to purchase power from alternative suppliers under the electric Customer Choice program. We estimate that we will lose between $80 million and $100 million of margins in 2003 under the Customer Choice program. Unrecovered generation-related fixed costs due to electric Customer Choice are considered stranded and are recoverable under Michigan legislation as determined by the MPSC. We estimate that we will record approximately $40 million of regulatory assets relating to these stranded costs in 2003. There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix and wholesale prices. As a result, our estimate of stranded costs could increase or decrease. The regulatory asset will be subject to review by the MPSC in future regulatory proceedings, and we cannot predict the outcome of this matter. See Note 4 — Regulatory Matters.

      The June 2000 Michigan legislation imposed a rate freeze for all classes of customers through 2003. In addition, the MPSC determined that adjusting rates for changes in fuel and purchased power through continuance of the Power Supply Cost Recovery (PSCR) clause would be inconsistent with the rate freeze, therefore the MPSC suspended the PSCR clause. It is unclear at this time whether the PSCR clause will remain suspended beyond 2003. Detroit Edison filed a rate case in June 2003 addressing this and other issues. We cannot predict the outcome of this matter. See Note 4 — Regulatory Matters.

      Future operating results are expected to vary as a result of factors such as regulatory proceedings, weather, changes in economic conditions and the level of customer participation in the electric Customer Choice program.

Energy Services

      Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and Merchant Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. Both processes generate tax credits under Section 29 of the Internal Revenue Code. Synfuel-related Section 29 tax credits expire in 2007. Section 29 tax credits for two of our three coke batteries expired at the end of 2002, and the third expires in 2007. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and

7

compressed air supply. Merchant Generation owns and operates four gas-fired peaking electric generating plants and develops and acquires gas and coal-fired generation.

	Three Months					Nine Months
	Ended					Ended
	September 30					September 30
	2003			2002		2003			2002
	(In millions)
Operating Revenues	$	229		$	166	$	696		$	427
Operation and Maintenance		204			135		669			406
Depreciation and Amortization		11			21		64			65
Taxes other than Income		1			3		12			8
Operating Income (Loss)		13			7		(49	)		(52	)
Other (Income) and Deductions		(1	)		1		3			4
Income Tax Benefit		9			39		203			163
Net Income	$	23		$	45	$	151		$	107

      Energy Services earnings decreased $22 million for the 2003 third quarter and increased $44 million in the 2003 nine-month period. The 2003 third quarter period decline is a result of decreased synfuel production. As discussed in Note 9, we reduced synthetic fuel production by approximately one-half in June 2003 to optimize the tax credits generated from our synfuel facilities. The 2003 third quarter also reflects decreased tolling revenue and the expiration of tax credits at two of our three coke battery facilities when compared to the same period in 2002. The 2003 nine-month period increase as compared to the prior year is a result of increased synfuel production and a $19 million net of tax gain from the settlement of a tolling agreement at one of our generating facilities, partially offset by a $10 million net of tax reserve that was established for receivables associated with a large customer that filed for bankruptcy. During 2002, four synfuel facilities became fully operational and interests in two facilities were sold. These two events resulted in significantly higher operating revenues and expenses in the first nine months of 2003 relative to the same period in 2002. Synfuel projects generate operating losses, which are more than offset by the resulting tax credits. The income tax benefit includes tax credits actually earned based on synfuel production and sales. The level of tax credits has been adjusted at the Corporate & Other segment in order that the DTE Energy consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. See Notes 5 and 9 for further detail.

      Outlook — Energy Services’ strategy is to continue leveraging our extensive energy-related operating experience and project management capability to develop and grow the on-site energy and merchant generating businesses. We continue to explore growth opportunities that will not require significant initial capital investment. We are currently negotiating an on-site energy business arrangement with a major manufacturer in the Midwest.

      A significant portion of Energy Services’ earnings consist of synfuel-related Section 29 tax credits. The level of tax credits generated in future periods will be affected by fluctuations in estimated annual taxable earnings and the number of synfuel projects owned. We are aggressively pursuing opportunities to sell interests in some or all of our synfuel plants. See “Synthetic Fuel Operations” section that follows.

      There is a bill currently before the United States Congress that includes provisions extending or reinstating tax credits for various types of energy facilities and processes, including coke batteries, antrim shale gas, coal bed methane, refined coal and landfill gas. We are unable to predict the outcome of the legislative process, however, the passage of the current version of this legislation is expected to be favorable to the Company.

8

Energy Marketing & Trading

      Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading and CoEnergy. DTE Energy Trading focuses on physical power marketing and structured transactions, as well as the enhancement of returns from DTE Energy’s power plants. CoEnergy focuses on physical gas marketing and optimization of DTE Energy’s owned and contracted natural gas pipelines and storage assets. To this end, both companies enter into derivative financial instruments as part of their strategies, including forwards, futures, swaps and option contracts.

      Energy Marketing & Trading’s earnings increased $24 million in the 2003 third quarter from the comparable 2002 period, of which $20 million was attributable to CoEnergy and $4 million to DTE Energy Trading. Earnings for the 2003 nine-month period increased $40 million, of which $25 million was attributable to CoEnergy and $15 million to DTE Energy Trading. Increases at CoEnergy are primarily due to favorable mark-to-market earnings associated with storage and transport contracts, partially offset by the impact of inventory valuation adjustments made under a different basis of accounting as discussed below. Increases at DTE Energy Trading were due mainly to short-term origination activities and short-term physical trades, partially offset by reduced proprietary trading profits. Proprietary trading represents derivative activity transacted with the intent of capturing profits on forward price movements. CoEnergy earnings were also impacted by the effect of changing our accounting for gas inventory as discussed below.

      Through December 2002, our physical gas in storage was marked to the current spot price under fair value accounting rules. To comply with new accounting requirements resulting from the rescission of Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” we changed to the average cost method for our gas inventories, effective January 2003. As a result of discontinuing the application of the fair value method to our gas inventories and the effect of the rescission of EITF 98-10 on our energy contracts, we recorded a cumulative effect of accounting change that reduced earnings in January 2003 (Note 2). The impact of the cumulative effect accounting charge was offset in operating results as a significant portion of the revalued gas inventory was sold in the 2003 first quarter, thereby increasing gross margins.

      Outlook — Energy Marketing & Trading will seek to gradually expand its business in a manner consistent with and complementary to the growth of our other business segments. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to capitalize on opportunities for expansion of its market base.

      Significant portions of the Energy Marketing & Trading portfolio are economically hedged, and include financial instruments, gas inventory, as well as owned and contracted natural gas pipelines and storage assets. These financial instruments are deemed derivatives whereas the gas inventory, pipelines and storage assets are not considered derivatives for accounting purposes. As a result, Energy Marketing & Trading will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets.

      A significant portion of the earnings volatility in this segment is associated with the natural gas storage cycle, which runs from June to March. Injections of gas into inventory takes place in the summer and gas is withdrawn in the winter. DTE Energy’s policy is to hedge the price risk of all purchases for storage with sales in the “over the counter” and futures markets, eliminating the price risk for the storage business. As previously discussed, current accounting rules do allow for the marking to market of forward sales, but do not allow for the marking to market of the related gas inventory. This results in gains and losses which are recognized in different interim periods, but even out by the end of the storage cycle.

Other Non-regulated

      We have formed a subsidiary, DTE PepTec Inc. that will utilize proprietary technology to produce high quality coal products from fine coal slurries that are typically discarded from coal mining operations. The technology has the additional benefit of improving the environment by allowing us to restore the land in

9

accordance with reclamation requirements of each state we operate in. The technology produces a fine-coal fuel by removing mineral matter, clay-sized impurities and oxides from waste material. The fine-coal fuel can be used in power plants, as a feedstock for synthetic fuel production and for other industrial applications. Our first operating facility in Ohio has the capacity to produce more than 500,000 tons of fine coal per year. A significant portion of the production is transported to an operating synfuel plant in Ohio. We anticipate a substantial market for this technology and plan to aggressively pursue expansion opportunities.

Energy Distribution

Power Distribution

      Power Distribution is comprised of the electric distribution services of Detroit Edison. Power Distribution distributes electricity generated by Energy Resources and alternative electric suppliers to Detroit Edison’s 2.1 million customers.

      Power Distribution earnings decreased $16 million during the 2003 third quarter and $82 million in the 2003 nine-month period. Both periods experienced reduced electric deliveries and operating revenues due to milder weather and the impact of a slower economy on manufacturing and commercial customers operations. Restoration costs associated with an April 2003 catastrophic ice storm, resulting in more than 400,000 customers losing power, and a July 2003 windstorm, affecting over 190,000 customers, also contributed to the decline in earnings in the 2003 nine-month period. The operation and maintenance expense comparison in the current quarter was also impacted by heat-related maintenance costs incurred in the 2002 third quarter due to prolonged periods of above normal temperatures and the related stress placed on the distribution system. Operation and maintenance expenses for both periods were also affected by higher employee pension and health care benefit costs and costs associated with customer service process improvements. Operation and maintenance expenses benefited from our Company-wide initiative to reduce or defer costs and enhance operating performance. The DTE Operating System involves the rigorous disciplined application of tools and operating practices which have resulted in inventory reductions and improvements in technology systems, among other enhancements. Results for the 2003 nine-month period also reflect a net of tax loss of $14 million on the sale of our unprofitable steam heating business (Note 3).

	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2003			2002			2003			2002
	(In millions)
Operating Revenues	$	348		$	394		$	950		$	1,010
Fuel and Purchased Power		4			5			13			17
Operation and Maintenance		169			183			538			468
Depreciation and Amortization		62			62			187			186
Taxes other than Income		27			31			83			90
Operating Income		86			113			129			249
Other Deductions		33			36			107			104
Income Tax Provision		18			26			7			48
Net Income	$	35		$	51		$	15		$	97
Operating Income as a Percent of Operating Revenues		25	%		29	%		14	%		25	%

10

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
Electric Deliveries	2003		2002		2003		2002
	(In thousands of MWh)
Residential		4,457		5,131		11,555		12,377
Commercial		4,162		5,076		12,251		14,135
Industrial		3,044		3,472		9,264		10,342
Wholesale		556		578		1,682		1,670
Other		97		100		294		298
		12,316		14,357		35,046		38,822
Electric Choice		2,141		935		5,192		2,577
Total Electric Sales and Deliveries		14,457		15,292		40,238		41,399

      Outlook — Operating results are expected to vary as a result of external factors such as weather, changes in economic conditions and the severity and frequency of storms. Economic conditions and prior billing issues have resulted in an increase in past due receivables. We believe our allowance for doubtful accounts is based on reasonable estimates; however, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results. As previously mentioned, Detroit Edison filed a rate case in June 2003 to address future operating costs and other issues.

     Non-Regulated

      Non-regulated Energy Distribution operations consist primarily of DTE Energy Technologies which markets and distributes a portfolio of distributed generation products, provides application engineering, and monitors and manages generation system operations.

      Non-regulated losses decreased $1 million in the 2003 third quarter and increased $1 million in the 2003 nine-month period from the comparable 2002 periods.

      Outlook — Although revenues from our technology related businesses are increasing, they are below our expectations. Accordingly, we have taken actions to reduce our expenses and streamline our operations, including exiting from some non-strategic business lines and activities.

      DTE Energy Technologies expects to continue the expansion of its product portfolios and support capabilities in North America and the development of marketing relationships in other parts of the world. This year’s severe storms in North America and blackouts in the United States, Italy and England, which resulted in the loss of electrical service to commercial, industrial and residential customers, have increased awareness and interest in our product portfolio, especially our on-site energy systems that keep customers’ power on when power from the grid is not available. In 2003 and 2004, we plan to launch additional new products which have been under development and are critical to our plan to increase revenues and generate operating profits in late 2004.

Energy Gas

     Gas Distribution

      Gas Distribution operations include gas distribution services primarily provided by MichCon, our gas utility which purchases, stores and distributes natural gas to 1.2 million residential, commercial and industrial customers located throughout Michigan.

      Gas Distribution’s loss increased $22 million during the 2003 third quarter and net income declined $25 million for the 2003 nine-month period. Earnings reflect higher operation and maintenance expenses and a $26.5 million reserve recorded in the first quarter of 2003 for the potential disallowance in gas costs pursuant to a March 2003 MPSC order in MichCon’s 2002 GCR plan case (Note 4). The increases in operation and maintenance expenses were due to higher employee pension and health care benefit costs, increased costs

11

associated with customer service process improvements and increased uncollectible accounts expense. Operation and maintenance expenses benefited from our Company-wide initiative to reduce or defer costs and enhance operating performance. The DTE Operating System involves the rigorous disciplined application of tools and operating practices which have resulted in inventory reductions and improvements in technology systems, among other enhancements. Operating revenues in the 2003 nine-month period were higher due to colder than normal weather. Also impacting the comparison was increased gas costs which were offset by higher revenues under the GCR mechanism. The income tax provision was favorably affected by an increase in the amortization of tax benefits previously deferred in accordance with MPSC regulations.

	Three Months						Nine Months
	Ended						Ended
	September 30						September 30
	2003			2002			2003			2002
	(In millions)
Operating Revenues	$	146		$	122		$	1,074			963
Cost of Gas		58			39			651			545
Gross Margin		88			83			423			418
Operation and Maintenance		98			73			265			225
Depreciation and Amortization		26			25			76			76
Taxes other than Income		11			11			42			39
Operating Income (Loss)		(47	)		(26	)		40			78
Other Deductions		10			9			33			30
Income Tax (Benefit) Provision		(12	)		(12	)		2			18
Net Income (Loss)	$	(45	)	$	(23	)	$	5		$	30
Operating Income (Loss) as a Percent of Operating Revenues		(32	)%		(21	)%		4	%		8	%

      Outlook — In December 2001, the MPSC issued an order that continues the gas Customer Choice program on a permanent and expanding basis beginning with the conclusion of the three-year temporary program in March 2002. Beginning in April 2003, up to approximately 60% of customers could participate and beginning April 2004, all 1.2 million of MichCon’s gas customers may choose to participate. Since MichCon continues to transport and deliver the gas to the participating customer premises at prices comparable to margins earned on gas sales, customers switching to other suppliers have little impact on MichCon’s earnings. As of September 2003, approximately 124,000 customers were participating in the gas Customer Choice program, compared with approximately 190,000 customers at December 31, 2002.

      As a result of the continued increase in operating costs, MichCon filed a rate case in September 2003 to address future operating costs and other issues. See Note 4 — Regulatory Matters.

      Operating results are expected to vary as a result of external factors such as regulatory proceedings, weather and changes in economic conditions. Economic conditions and prior billing issues have resulted in an increase in past due receivables. We believe our allowance for doubtful accounts is based on reasonable estimates; however, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results.

     Non-Regulated

      Non-regulated operations include the gas and oil production business, and the gas Pipelines & Processing business. Our production business produces gas from proven reserves owned in northern Michigan and sells the gas to the Energy Marketing & Trading segment. Pipelines & Processing has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing facilities and a natural gas storage field, as well as contract rights to another natural gas storage field. The assets of these businesses are well integrated with other DTE Energy regulated and non-regulated entities.

12

      Non-regulated earnings increased $6 million during both the 2003 third quarter and the nine-month periods as compared to the same 2002 periods. The earnings improvement primarily reflects the gain from the sale of our 16% pipeline interest in the Portland Natural Gas Transmission System.

      Outlook — We expect to further develop our gas production properties in northern Michigan and our pipelines, processing and storage assets to support other DTE Energy businesses. Additionally, we expect to continue exploring opportunities in the coal bed methane gas production business to leverage our production, coal and low cost operating capabilities.

      In October 2003, we acquired an additional 15% interest in the Vector Pipeline LP bringing our total ownership interest to 40%. The purchase of the additional interest in the Vector Pipeline complements our existing gas distribution and storage facilities in Michigan.

Corporate & Other

      Corporate & Other earnings increased $65 million for the 2003 third quarter and losses increased $83 million in the 2003 nine-month period due primarily to effective income tax rate adjustments. Corporate & Other records necessary adjustments in order that the consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. The higher adjustments were necessary because our estimated annual pre-tax income and ability to utilize synfuel-related Section 29 tax credits generated differed from earlier estimates. Due to the suspension of the issuance of private letter rulings (PLRs) by the Internal Revenue Service (IRS), we reduced planned synthetic fuel production for the second half of the year. The suspension and reduced production have resulted in a higher anticipated effective tax rate for the year. The quarterly effective tax rate adjustment does not impact total year earnings (Notes 5 and 8). The 2003 nine-month period was also affected by a $15 million cash contribution to the DTE Energy Foundation that was funded with proceeds received from the sale of ITC (Note 3).

Capital Resources and Liquidity

			Nine Months
			Ended
			September 30
			2003			2002
			(In millions)
Cash and Cash Equivalents
Cash Flow From (Used For)
	Operating activities:
		Net income, depreciation, depletion, amortization and deferred taxes	$	788		$	876
		Pension contribution		(222	)		—
		Working capital and other		(324	)		(360	)
				242			516
	Investing activities			219			(656	)
	Financing activities			(504	)		(16	)
Net Decrease in Cash and Cash Equivalents			$	(43	)	$	(156	)

Operating Activities

      Net cash from operating activities decreased $274 million during the nine months of 2003 as compared to the same 2002 period. The decrease reflects a decline of $88 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, and deferred taxes). Working capital and other requirements include seasonal increases in fuel and gas inventories and a $222 million cash contribution to Detroit Edison’s pension plan.

13

      Economic conditions and prior billing issues have resulted in an increase in past due receivables. We are focusing our collection efforts; however, failure to make continued progress in collecting our past due receivables would unfavorably affect operating cash flows.

Investing Activities

      Net cash relating to investing activities improved $875 million in the nine months of 2003 as compared to the same 2002 period primarily due to the sale of ITC and interest in synfuel projects and lower contractually designated funds for debt service. Non-regulated plant expenditures also decreased in 2003, reflecting expenditures associated with the funding of the synfuel business in 2002.

Financing Activities

      Net cash used for financing activities increased $488 million during the nine months of 2003 as compared to the same 2002 period due to higher redemptions of long-term debt and lower proceeds from issuances of common stock.

      In February 2003, MichCon issued $200 million of 5.7% senior notes due in March 2033. The proceeds were used for debt redemption and general corporate purposes.

      In April 2003, DTE Energy issued $400 million of 6 3/8% senior notes due in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing DTE Enterprises Inc. debt due April 2008. The proceeds were used for debt redemptions and general corporate purposes.

      In June 2003, DTE Energy redeemed $100 million principal amount of 6.17% Remarketed Notes due in 2038.

      In August 2003, Detroit Edison issued $49 million of 5.5% tax exempt bonds due in 2030. The proceeds were used to redeem $49 million of 6.55% tax-exempt bonds due 2024.

      Credit Rating Review — Various credit rating agencies are currently reviewing our credit rating. A change in our rating could restrict our ability to access capital markets at attractive rates and increase our borrowing costs. However, we cannot predict the outcome of such review.

Synthetic Fuel Operations

      We operate nine synthetic fuel production facilities, seven of which are wholly owned. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In May 2003, the IRS suspended the issuance of PLRs relating to synthetic fuel projects pending their review of issues concerning chemical change which is the basis for earning Section 29 tax credits. On October 29, 2003, the IRS announced that it has concluded its assessment of the chemical change process involved in synfuel production and resumed issuances of rulings. The IRS determined that the test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 credits. We have begun implementing a series of initiatives, including selling interests in our synfuel projects and monetizing in-the-money gas swap derivative contracts, which we expect to improve cash flow as well as our ability to fully utilize the $225 million in estimated tax credits to be generated in 2003. We will closely monitor taxable income through the remainder of 2003 and assess synfuel production levels accordingly. See Note 9 for a further discussion of synthetic fuel matters.

14

Electric Customer Choice Program

      The electric Customer Choice program as originally structured in Michigan anticipated an eventual transition to a totally competitive environment where customers would be charged market-based rates for their electricity. Various developments in the energy industry have caused the deregulation of electric generation to proceed at a much slower rate. As a result, Detroit Edison’s rates continue to be regulated by the MPSC. This continued regulation has hindered Detroit Edison’s ability to retain customers that are choosing alternative suppliers under the electric Customer Choice program. Detroit Edison’s results have been unfavorably impacted by the lack of recovery of lost margins and other costs associated with the electric Customer Choice program. To date, the MPSC has not fully implemented various provisions of Michigan’s restructuring legislation. Specifically, the MPSC:

•  has not finalized all the components for calculating net stranded costs;

•  has created a process whereby net stranded costs would be recovered two years after the net stranded costs were actually incurred;

•  has not authorized Detroit Edison to recover any Customer Choice program implementation costs; and,

•  has created incentives to encourage participation in electric Customer Choice.

      In addition, the MPSC has historically maintained regulated rates for certain groups of customers that exceed those customers’ cost of service. This has resulted in high levels of participation by these customers in the Customer Choice program. As a result of these factors, retail choice penetration continues to rise beyond original estimates.

      In December 2002, the MPSC initiated a collaborative process to address the issue of stranded costs. Detroit Edison actively participated in the collaborative process. However, this process failed to produce any agreement regarding net stranded cost recovery.

      Detroit Edison addressed the issue of stranded costs in its June 2003 rate filing and is also pursuing a legislative solution to address this issue. The continued delay in the timely and full recovery of stranded costs unfavorably impacts operating results. See Note 4 for a further discussion of the electric Customer Choice program.

Blackout Costs

      On August 14, 2003, failures in the regional power transmission grid caused nine of Detroit Edison’s power plants to trip offline, which left virtually all of its 2.1 million customers without power. On October 24, 2003, Detroit Edison filed an application with the MPSC requesting approval to defer the blackout costs until ratemaking treatment of the costs can be determined. See Note 4 for further discussion of the blackout costs filing.

Environmental Matters

      The Environmental Protection Agency (EPA) ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution will continue to impact us. Detroit Edison spent approximately $512 million through September 2003 and estimates that it will incur approximately $300 to $400 million of future capital expenditures over the next five to eight years to comply with the existing air quality standards. Recovery of costs to be incurred through December 2004 is included in our June 2003 electric rate case. In addition, we maintain the option to securitize these costs after the completion of this rate case.

      The EPA has initiated enforcement actions against several major electric utilities citing violations of the Clean Air Act, asserting that older, coal-fired power plants have been modified in ways that would then require them to comply with the more restrictive “new source” provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated

15

proceedings against Detroit Edison. The United States District Court for the Southern District of Ohio Eastern Division issued a decision in August 2003 finding Ohio Edison in violation of the new source provisions of the Clean Air Act. If the Court’s decision is upheld, the electric utility industry could be required to invest substantial amounts in pollution control equipment. During the same month, however, a district court in a different division rendered a conflicting decision on the matter. On August 27, 2003, the EPA released new rules, effective December 26, 2003, allowing repair, replacement or upgrade of production equipment without triggering source requirement controls if the cost of the parts and repairs do not exceed 20% of the replacement value of the equipment being upgraded. Such repairs will be considered routine maintenance, however any changes in emissions would be subject to existing pollution permit limits and other state and federal programs for pollutants.

      We cannot predict the future impact of this issue upon Detroit Edison.

New Accounting Pronouncements

      See Note 2 — New Accounting Pronouncements for discussion of new accounting pronouncements.

Fair Value of Contracts

      The following disclosures are voluntary and have been developed through efforts of the Committee of Chief Risk Officers, a working group of chief risk officers from companies active in both physical and financial energy trading and marketing. We believe the disclosures provide enhanced transparency of the activities and position of our Energy Trading & Marketing segment.

Roll-Forward of Mark-to-Market Energy Contract Net Assets

      The following tables provide details on changes in our mark-to-market (MTM) net asset or (liability) position during 2003.

		Proprietary			Structured			Owned
		Trading(1)			Contracts(2)			Assets(3)			Total
		(In millions)
Energy Marketing & Trading Segment MTM at December 31, 2002		$	15		$	19		$	(50	)	$	(16	)
	Cumulative effect adjustment(4)		(2	)		(1	)		17			14
	Reclassification to realized at settlement of contract(5)		(5	)		(6	)		16			5
	Net change in option premiums		(11	)		—			—			(11	)
	Other changes in fair value		9			5			(1	)		13
	MTM at September 30, 2003	$	6		$	17		$	(18	)		5
Other DTE Energy segments and non-trading activities of the Energy Marketing & Trading segment												(94	)
											$	(89	)

(1)	“Proprietary Trading” represents derivative activity transacted with the intent of capturing profits on forward price movements.
(2)	“Structured Contracts” represent derivative activity transacted with the intent to capture profits by originating substantially offsetting positions with wholesale energy marketers, utilities, retail aggregators and end-users. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting trade can be executed.
(3)	“Owned Assets” represent derivative activity associated with assets owned by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity.

16

	Derivatives are generally executed with the intent of locking in and optimizing profits without creating additional risk.
(4)	Excludes the cumulative effect adjustment associated with the change in accounting for gas inventory (Note 2).
(5)	In conjunction with our overall tax planning and cash initiatives, we monetized certain in-the-money contracts in the 2003 third quarter while simultaneously entering into at-the-market contracts with various counterparties. This had the impact of optimizing taxable income and cash flow while having no impact on reported earnings. We anticipate continuing this activity in the 2003 fourth quarter. (Note 9).

	Proprietary			Structured			Owned
	Trading			Contracts			Assets			Eliminations			Total
	(In millions)
Current assets	$	87		$	53		$	143		$	(22	)	$	261
Noncurrent assets		28			25			95			(5	)		143
Total MTM assets		115			78			238			(27	)		404
Current liabilities		(79	)		(41	)		(125	)		20			(225	)
Noncurrent liabilities		(30	)		(20	)		(131	)		7			(174	)
Total MTM liabilities		(109	)		(61	)		(256	)		27			(399	)
Total MTM net assets (liabilities)	$	6		$	17		$	(18	)	$	—		$	5

Maturity of Fair Value of MTM Energy Contract Net Assets

      Effective January 1, 2003, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading time frame. Our intent is to recognize MTM activity only when pricing data is obtained from active quotes and published indexes.

      The table below shows the maturity of the MTM positions of our energy contracts.

													Total
										2006 &			Fair
	2003			2004			2005			Beyond			Value
	(In millions)
Proprietary Trading	$	4		$	3		$	(1	)	$	—		$	6
Structured Contracts		4			9			5			(1	)		17
Owned Assets		(3	)		(9	)		2			(8	)		(18	)
Total	$	5		$	3		$	6		$	(9	)	$	5

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

      DTE Energy has commodity price risk arising from market price fluctuations in conjunction with the anticipated purchase of electricity to meet its obligations during periods of peak demand. We also are exposed to the risk of market price fluctuations on gas sales and purchase contracts, gas production and gas inventories. To limit our exposure to commodity price fluctuations, we have entered into a series of electricity and gas futures, forwards, option and swap contracts.

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 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).

17

Summary of Sensitivity Analysis

      We performed a sensitivity analysis calculating the impact of changes in fair values utilizing applicable forward commodity rates if they occurred at September 30, 2003:

	Increase of			Decrease of
Activity	10%			10%		Change in the fair value of
	(In millions)
Gas Contracts	$	(14	)	$	15		Commodity contracts
Power Contracts	$	(6	)	$	3		Commodity contracts
Interest Rate Risk	$	(273	)	$	323		Long-term debt

CONTROLS AND PROCEDURES

(a)     Evaluation of disclosure controls and procedures

      The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a — 15(e) and 15d — 15(e)) as of September 30, 2003, which is the end of the period covered by this report, and have concluded that such controls and procedures are effectively designed to ensure that required information disclosed by the Company in reports that it files or submits under the Act is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms.

18

DTE ENERGY COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

			Three Months						Nine Months
			Ended						Ended
			September 30						September 30
			2003			2002			2003			2002
			(In millions, except per share amounts)
Operating Revenues			$	1,654		$	1,657		$	5,349		$	5,025
Operating Expenses
	Fuel, purchased power and gas			452			501			1,758			1,639
	Operation and maintenance			709			615			2,197			1,781
	Depreciation, depletion and amortization			170			204			547			573
	Taxes other than income			71			87			255			261
				1,402			1,407			4,757			4,254
Operating Income				252			250			592			771
Other (Income) and Deductions
	Interest expense			130			135			395			407
	Interest expense from preferred securities of subsidiaries			5			—			5			—
	Preferred stock dividends of subsidiaries			—			6			12			19
	Interest income			(7	)		(9	)		(22	)		(20	)
	Other income			(44	)		(4	)		(75	)		(22	)
	Other expenses			31			8			82			31
				115			136			397			415
Income Before Income Taxes				137			114			195			356
Income Tax Benefit				(43	)		(25	)		(56	)		(36	)
Income from Continuing Operations				180			139			251			392
Discontinued Operations — ITC (Note 3):
	Income from operations			—			22			5			37
	Gain on sale			(4	)		—			63			—
				(4	)		22			68			37
Cumulative Effect of Accounting Changes (Note 2):
	Asset retirement obligations			—			—			(11	)		—
	Energy trading activities			—			—			(16	)		—
				—			—			(27	)		—
Net Income			$	176		$	161		$	292		$	429
Basic Earnings per Common Share
	Income from continuing operations		$	1.07		$	.83		$	1.49		$	2.40
	Discontinued operations			(.02	)		.13			.41			.23
	Cumulative effect of accounting changes			—			—			(.16	)		—
		Total	$	1.05		$	.96		$	1.74		$	2.63
Diluted Earnings per Common Share
	Income from continuing operations		$	1.06		$	.83		$	1.49		$	2.39
	Discontinued operations			(.02	)		.13			.40			.23
	Cumulative effect of accounting changes			—			—			(.16	)		—
		Total	$	1.04		$	.96		$	1.73		$	2.62
Average Common Shares
	Basic			168			167			168			163
	Diluted			168			168			168			164
Dividends Declared per Common Share			$	.515		$	.515		$	1.545		$	1.545

See Notes to Consolidated Financial Statements (Unaudited)

19

DTE ENERGY COMPANY

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

			(Unaudited)
			September 30			December 31
			2003			2002
			(In millions)
ASSETS
Current Assets
	Cash and cash equivalents		$	90		$	133
	Restricted cash			100			237
	Accounts receivable
		Customer (less allowance for doubtful accounts of $121 and $82, respectively)		825			902
		Accrued unbilled revenues		187			296
		Other		329			237
	Inventories
		Fuel and gas		596			413
		Materials and supplies		170			163
	Assets from risk management and trading activities			261			224
	Other			199			159
				2,757			2,764
Investments
	Nuclear decommissioning trust funds			484			417
	Other			468			487
				952			904
Property
	Property, plant and equipment			17,631			17,862
	Less accumulated depreciation and depletion			(7,961	)		(8,049	)
				9,670			9,813
Other Assets
	Goodwill			2,084			2,119
	Regulatory assets (Notes 2 and 4)			2,088			1,197
	Securitized regulatory assets			1,550			1,613
	Assets from risk management and trading activities			141			152
	Prepaid pension assets			179			172
	Other			515			504
				6,557			5,757
Total Assets			$	19,936		$	19,238

See Notes to Consolidated Financial Statements (Unaudited)

20

DTE ENERGY COMPANY

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

		(Unaudited)
		September 30			December 31
		2003			2002
		(In millions, except shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
	Accounts payable	$	650		$	647
	Accrued interest		120			115
	Dividends payable		91			90
	Accrued payroll		33			49
	Short-term borrowings		469			414
	Current portion of long-term debt, including capital leases		752			1,018
	Liabilities from risk management and trading activities		279			284
	Other		633			596
			3,027			3,213
Other Liabilities
	Deferred income taxes		1,115			916
	Regulatory liabilities		161			179
	Asset retirement obligations (Note 2)		854			—
	Unamortized investment tax credit		159			168
	Liabilities from risk management and trading activities		212			208
	Liabilities from transportation and storage contracts		486			523
	Accrued pension liability		404			582
	Nuclear decommissioning (Note 2)		61			416
	Other		683			683
			4,135			3,675
Long-Term Debt (net of current portion)
	Mortgage bonds, notes and other		5,660			5,656
	Securitization bonds		1,496			1,585
	Preferred securities of subsidiaries (Note 2)		280			—
	Equity-linked securities		186			191
	Capital lease obligations		78			82
			7,700			7,514
Contingencies (Notes 4 and 9)
Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises (Note 2)			—			271
Shareholders’ Equity
	Common stock, without par value, 400,000,000 shares authorized, 168,301,400 and 167,462,430 shares issued and outstanding, respectively		3,091			3,052
	Retained earnings		2,168			2,132
	Accumulated other comprehensive loss		(185	)		(619	)
			5,074			4,565
Total Liabilities and Shareholders’ Equity		$	19,936		$	19,238

See Notes to Consolidated Financial Statements (Unaudited)

21

DTE ENERGY COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

			Nine Months
			Ended
			September 30
			2003			2002
			(In millions)
Operating Activities
	Net Income		$	292		$	429
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation, depletion and amortization		551			590
		Deferred income taxes		(55	)		(143	)
		Gain on sale of assets, net		(132	)		—
		Partners’ share of synfuel project losses		(58	)		(24	)
		Cumulative effect of accounting changes		27			—
		Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(383	)		(336	)
		Net cash from operating activities		242			516
Investing Activities
	Plant and equipment expenditures — regulated			(504	)		(500	)
	Plant and equipment expenditures — non-regulated			(58	)		(150	)
	Proceeds from sale of interests in synfuel projects			67			11
	Proceeds from sale of ITC and other assets (Note 3)			643			8
	Restricted cash for debt redemptions			137			34
	Other investments			(66	)		(59	)
		Net cash from (used for) investing activities		219			(656	)
Financing Activities
	Issuance of long-term debt			529			388
	Redemption of long-term debt			(897	)		(512	)
	Issuance of preferred securities			—			180
	Redemption of preferred securities			—			(180	)
	Short-term borrowings, net			55			107
	Issuance of common stock			33			265
	Dividends on common stock			(259	)		(252	)
	Contributions from synfuel partners			44			10
	Other			(9	)		(22	)
		Net cash used for financing activities		(504	)		(16	)
Net Decrease in Cash and Cash Equivalents				(43	)		(156	)
Cash and Cash Equivalents at Beginning of the Period				133			268
Cash and Cash Equivalents at End of the Period			$	90		$	112

See Notes to Consolidated Financial Statements (Unaudited)

22

DTE ENERGY COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’

EQUITY AND COMPREHENSIVE INCOME (Unaudited)

											Accumulated
		Common Stock									Other
								Retained			Comprehensive
		Shares			Amount			Earnings			Loss			Total
		(Dollars in millions, shares in thousands)
Balance, January 1, 2003			167,462		$	3,052		$	2,132		$	(619	)	$	4,565
	Net income		—			—			292			—			292
	Issuance of new shares		915			41			—			—			41
	Dividends declared on common stock		—			—			(261	)		—			(261	)
	Repurchase and retirement of common stock		(76	)		(2	)		(2	)		—			(4	)
	Pension obligations (Note 4)		—			—			—			417			417
	Net change in unrealized losses on derivatives, net of tax		—			—			—			17			17
	Other		—			—			7			—			7
Balance, September 30, 2003			168,301		$	3,091		$	2,168		$	(185	)	$	5,074

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

		2003			2002
		(In millions)
Net income		$	292		$	429
Other comprehensive income (loss), net of tax:
	Net unrealized income (losses) on derivatives:
	Gains (losses) arising during the period, net of taxes of $(10) and $23, respectively		19			(42	)
	Amounts reclassified to earnings, net of taxes of $(1) and $16, respectively		(2	)		30
			17			(12	)
	Foreign currency translation loss, net of taxes of $1		—			(1	)
	Pension obligations, net of taxes of $224 (Note 4)		417			—
			434			(13	)
Comprehensive income		$	726		$	416

See Notes to Consolidated Financial Statements (Unaudited)

23

DTE ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Note 1 — General

      These consolidated financial statements should be read in conjunction with the notes to consolidated financial statements included in the 2002 Annual Report on Form 10-K and the July 14, 2003 Current Report on Form 8-K.

      The accompanying consolidated financial statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

      The consolidated financial statements are unaudited, but in our opinion include all adjustments necessary for a fair statement of the results for the interim periods. 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.

      We reclassified some prior year balances to match the current year’s presentation.

Stock-Based Compensation

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

		Three Months						Nine Months
		Ended						Ended
		September 30						September 30
		2003			2002			2003			2002
		(In millions, except per share
		amounts)
Net Income As Reported		$	176		$	161		$	292		$	429
Less: Total stock-based expense(1)			(2	)		(2	)		(6	)		(6	)
Pro Forma Net Income (Loss)		$	174		$	159		$	286		$	423
Income (Loss) Per Share
	Basic — as reported	$	1.05		$	.96		$	1.74		$	2.63
	Basic — pro forma	$	1.04		$	.95		$	1.71		$	2.60
	Diluted — as reported	$	1.04		$	.96		$	1.73		$	2.62
	Diluted — pro forma	$	1.03		$	.95		$	1.70		$	2.58

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

24

Issuance of Stock by Equity Investees

      In 1997, DTE Energy and Mechanical Technology Incorporated formed Plug Power Inc. to design and develop on-site electric fuel cell power generation systems. Since Plug Power is considered a development stage company, accounting principles generally accepted in the United States of America require us to record gains and losses from Plug Power stock issuances as an adjustment to equity. In March 2003, Plug Power issued approximately 8.95 million shares of common stock in conjunction with its acquisition of H Power Corp.

      As a result of Plug Power’s common stock issuance, we recorded an increase of $8 million in our investment and an after-tax increase of $5 million to equity. At September 30, 2003, we owned approximately 23% of Plug Power’s common stock.

Consolidated Statement of Cash Flows

      We consider investments purchased with a maturity of three months or less to be cash equivalents. Cash contractually designated for debt service is classified as restricted cash. The components of changes in assets and liabilities follow.

		Nine Months
		Ended
		September 30
		2003			2002
		(In millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
	Accounts receivable, net	$	(41	)	$	(69	)
	Accrued unbilled receivables		109			40
	Accrued gas cost recovery revenue		(15	)		(18	)
	Inventories		(198	)		(192	)
	Accrued/Prepaid pensions		88			65
	Accounts payable		3			(8	)
	Income taxes payable		22			(55	)
	General taxes		(29	)		(56	)
	Risk management and trading activities		(28	)		66
	Pension contributions		(222	)		(35	)
	Other		(72	)		(74	)
		$	(383	)	$	(336	)

      Other cash and non-cash investing and financing activities for the nine-months ended September 30 were as follows:

		Nine Months
		Ended
		September 30
		2003		2002
		(In millions)
Supplementary Cash Flow Information
	Interest paid (excluding interest capitalized)	$	391	$	418
	Income taxes paid	$	27	$	134
Non-cash Financing Activities
	Issuance of equity linked debt securities	$	—	$	21
	Exchange of debt	$	100	$	—

25

Note 2 — New Accounting Pronouncements

      Asset Retirement Obligations — On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred. It applies to legal obligations associated with the retirement of long-lived assets resulting from the acquisition, construction, development and (or) the normal operation of a long-lived asset. When a new liability is recorded, an entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

      We have identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to regulated operations, we believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and will be deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

      As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $306 million with offsetting accumulated depreciation of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to regulated operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million for 2003.

      If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as assets with an indeterminate life, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, distribution assets have an indeterminate life, retirement cash flows cannot be determined and there is a low probability of retirement, therefore no liability has been recorded for these assets.

      The impact of SFAS No. 143 reduced earnings from continuing operations by $1.2 million or $.01 per diluted share and $3.6 million or $.02 per diluted share for the third quarter and nine-month period of 2003, respectively. Additionally, had SFAS No. 143 been adopted at January 1, 2002 the pro forma effect on earnings would have been a charge against earnings of $1.2 million or $.01 per diluted share and $3.6 million or $.02 per diluted share for the third quarter and nine-month period of 2002, respectively.

      A reconciliation of the asset retirement obligation for the 2003 nine-month period follows:

	(In millions)
Asset retirement obligations at January 1, 2003	$	815
Accretion		41
Liabilities settled		(2	)
Asset retirement obligations at September 30, 2003	$	854

      SFAS No. 143 also requires the quantification of the estimated cost of removal obligations arising from other than legal obligations, which have been accrued through depreciation charges. At January 1, 2003, we had approximately $700 million of previously accrued asset removal costs related to our regulated operations, for other than legal obligations, included in accumulated depreciation.

      Energy Trading Activities — Under Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” companies were required to use mark-to-market accounting for contracts utilized in energy trading activities. EITF Issue No. 98-10 was rescinded in October 2002, and energy trading contracts must now be reviewed to determine if they meet the definition of a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities measured at their fair value and sets forth conditions in which a derivative instrument

26

may be designated and recognized as a hedge. SFAS No. 133 also requires that changes in the fair value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts.

      Additionally, inventory utilized in energy trading activities accounted for under the fair value method of accounting as prescribed by Accounting Research Bulletin (ARB) No. 43 is no longer permitted. DTE Energy’s Energy Marketing & Trading segment uses gas inventory in its trading operations and switched to the average cost inventory accounting method in January 2003.

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

      Derivative Instrument and Hedging Activities — Effective July 1, 2003, we adopted SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” The statement amends and clarifies financial accounting and reporting for derivative instruments, including derivative instruments embedded in other contracts and for hedging activities. Our financial statements were not impacted by the adoption of SFAS No. 149.

      In August 2003, the EITF released Issue No. 03-11, which provides guidance on whether to report realized gains or losses on a gross or net basis on physically settled derivative contracts not held for trading purposes. The new guidance will be applied to financial statement periods after September 30, 2003. We are evaluating the effect this new guidance will have on our financial statements.

      Financial Instruments with Characteristics of Liabilities and Equity — SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Effective July 1, 2003, we have adopted the provisions of SFAS No. 150.

      As a result of adopting SFAS No. 150, $280 million of obligated mandatorily redeemable preferred securities that previously were classified in the Consolidated Statement of Financial Position between liabilities and equity, net of unamortized issuance costs of $9 million, have been reclassified as a liability. The unamortized issuance costs have been reclassified as “other noncurrent assets”, and continue to be amortized over the life of the issuance. In addition, payments made to preferred security holders, which had been recognized in the Consolidated Statement of Operations as “preferred stock dividends of subsidiaries” prior to adoption, are now required to be recognized prospectively as “interest expense from preferred securities of subsidiaries.” The adoption of SFAS No. 150 did not result in the recognition of any cumulative effect of a change in accounting principle adjustments.

      Consolidation of Variable Interest Entities — In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51,” which requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses. Interpretation No. 46 is applicable (i) immediately for all variable interest entities created after January 31, 2003; or (ii) in the first fiscal year or interim period beginning after June 15, 2003 for variable interest entities created before February 1, 2003.

      In October 2003, the FASB issued Staff Position No. FIN 46-6, which allows for the deferral of the effective date for applying the provisions of Interpretation No. 46 for all interests in variable interest entities or potential variable interest entities created before February 1, 2003, until the end of the first interim or annual period ending after December 15, 2003. Consequently, we have deferred the application of the provisions of Interpretation No. 46 until December 31, 2003 for all entities created prior to February 1, 2003.

27

      Consistent with the provisions of Interpretation No. 46, as currently interpreted, we have initially determined that the Trusts formed related to our obligated mandatorily redeemable preferred securities are variable interest entities, as our common equity investment is considered not at risk. Currently, we consolidate these Trusts, which are classified as Long-Term Debt in our Consolidated Statement of Financial Position, consistent with the provisions of SFAS No. 150. If no modifications are made to Interpretation No. 46 before we apply its provisions on December 31, 2003, we will most likely be required to de-consolidate these Trusts. The effects of this potential de-consolidation are not expected to be material.

      As of June 30, 2003, Detroit Edison had a ‘synthetic lease,’ relating to certain railcars and other coal transportation-related equipment. Under Interpretation No. 46, we would have been required to consolidate the related leasing company. However, during the 2003 third quarter, Detroit Edison refinanced this lease into a traditional operating lease; therefore, consolidation is not required.

      We continue to evaluate all of our cost and equity method investments acquired prior to February 1, 2003 to determine whether those entities are variable interest entities, and if so, whether we are required to consolidate any of those entities. The effects of adopting the provisions of Interpretation No. 46, however, are not expected to have a material effect on our financial position or results of operations.

Note 3 — Dispositions

     Disposition of Detroit Edison’s Steam Heating Business

      In January 2003, we sold Detroit Edison’s steam heating business to Thermal Ventures II, LLP. This disposition is consistent with DTE Energy’s strategy to divest non-strategic assets. Due to the continuing involvement of Detroit Edison in the steam heating business, including the commitment to purchase $176 million in steam for resale through 2008, fund certain capital improvements and guarantee the buyer’s credit facility, we recorded a net of tax loss of $14 million in the first quarter of 2003. As a result of Detroit Edison’s continuing involvement, this transaction is not considered a sale for accounting purposes. The steam heating business had assets of $6 million at December 31, 2002, and net losses of $12 million in 2002, net income of $3 million in 2001 and a net loss of $18 million in 2000.

Disposition of International Transmission Company — Discontinued Operation

      In December 2002, we entered into a definitive agreement with affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC to sell ITC for $610 million in cash. The sale closed on February 28, 2003 following approval of the transaction by the FERC and resolution of all other contingencies and generated a preliminary net of tax gain of $69 million that was subsequently reduced to $63 million as of September 30, 2003. The sale price is subject to review and further adjustment in the fourth quarter of 2003.

      The FERC has encouraged integrated electric utilities to transfer operating control of their transmission facilities to independent operators or sell the facilities to an independent company. DTE Energy’s decision to sell ITC is consistent with our strategic view that maximization of shareholder value and high levels of customer service are best achieved with assets we own, operate and exercise significant control. As provided in FERC regulations, Detroit Edison continues to have fair and open access to Michigan’s electric transmission network. The ITC electric transmission system continues to be operated by the Midwest Independent System Operator, a regional transmission operator. ITC received FERC approval to cap transmission rates charged to Detroit Edison’s customers at current levels until December 31, 2004. Thereafter, rates are subject to adjustment by the FERC.

      SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” provides that the results of operations of a component of an entity that has been disposed of should be reported as a discontinued operation when the operations and cash flows of the component have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the

28

operations of the component after the disposal transaction. As a result, we have reported the operations of ITC as a discontinued operation for the periods ended September 30, as shown in the following table:

	Three Months				Nine Months
	Ended				Ended
	September 30				September 30
	2003		2002		2003(3)		2002
	(In millions)
Revenues(1)	$	—	$	51	$	21	$	105
Expenses(2)		—		17		13		48
Operating income		—		34		8		57
Income tax provision		—		12		3		20
Income from discontinued operations	$	—	$	22	$	5	$	37

(1)	Includes intercompany revenues for the 2002 three-month period of $42 million. For the nine-month period, intercompany revenues are $18 million for 2003 and $90 million for 2002.
(2)	Excludes general corporate overhead costs that were previously allocated to ITC. Includes imputed interest of $1 million for both the three months ended September 30, 2002 and nine months ended September 30, 2003. For the nine months ended September 30, 2002, the imputed interest was $3 million.
(3)	Represents activity from January 1, 2003 through February 28, 2003 when ITC was sold.

      ITC had net fixed assets of approximately $390 million at February 28, 2003 and $388 million at December 31, 2002. For segment reporting purposes, ITC was reported as a component of Energy Distribution — Regulated Power Distribution and Transmission. In conjunction with the sale of ITC, approximately $44 million of goodwill allocated to this segment was written off and reduced the preliminary net of tax gain to $63 million.

Note 4 — Regulatory Matters

     Electric Transitional Rate Plan

      On June 20, 2003, Detroit Edison filed an application for a change in retail electric rates, resumption of the Power Supply Cost Recovery (PSCR) mechanism, and recovery of net stranded costs with the MPSC. Detroit Edison is specifically requesting authority to increase rates on an interim basis by $274 million annually to all customers not subject to a rate cap. Public Act 141 (PA141) became effective in June 2000 and contains provisions freezing rates through 2003 and preventing rate increases for residential customers through 2005 and for small business customers through 2004. Detroit Edison has requested the MPSC act on our interim request in order to be effective January 1, 2004. Concurrent with the order for interim rate relief, Detroit Edison requested reinstatement of the PSCR mechanism. The PSCR mechanism allowed Detroit Edison to recover through rates its fuel, fuel-related and purchased power electric expenses and was suspended under PA 141. Detroit Edison is also proposing that base rates for the customer classes still subject to rate caps in 2004 and 2005 remain frozen and not subject to the PSCR mechanism. Also, the interim request seeks a five-year surcharge from both full service and electric Customer Choice customers to recover certain deferred regulatory asset balances including electric Customer Choice program implementation costs, return on and of clean air investments made prior to inclusion in rates and net stranded costs for years prior to 2004. This surcharge would be phased in by customer class between 2004 and 2006 as rate caps expire, and would total $109 million annually in 2006.

      The application also is requesting a base rate increase for both full service and electric Customer Choice customers totaling $416 million annually (approximately 12% increase) in 2006, after the expiration of all customer rate caps. Detroit Edison is proposing that the $416 million increase be allocated between full service customers ($265 million) and electric Customer Choice customers ($151 million). The filing also requests a permanent capital structure based on 50% debt and 50% equity, and a proposed return on equity (ROE) of

29

11.5%. Detroit Edison is also proposing a symmetrical ROE sharing mechanism, which will apply to full service and electric Customer Choice customers whose rates are no longer capped under PA 141. The sharing proposal would provide that shareholders retain all earnings within a 1% band above and below the authorized ROE. If the actual ROE falls outside of the band, customers would share between 20% and 80% of the excess or shortfall of earnings, depending on actual ROE. The ROE sharing mechanism would be effective for the calendar year in which a final order is received in this case.

      The MPSC’s current schedule regarding this application requires the MPSC Staff report to be filed in December 2003, with an interim order expected in February or March of 2004.

      On August 18, 2003, the MPSC issued an order directing interested parties to file briefs by October 17, 2003, and reply briefs by October 31, 2003 in response to the Company’s request that its PSCR clause remain suspended and that implementation of a new PSCR factor not begin until the date of the MPSC order authorizing adequate and compensatory relief. The MPSC has recognized that this issue needs to be addressed before January 1, 2004. The MPSC Staff and interveners contend that the PSCR clause should restart January 1, 2004 and apply to both capped and uncapped rate classes. They do not support the mitigation adjustment proposed by Detroit Edison. The differences between Detroit Edison and the opposing parties positions average approximately $10 million per month in PSCR revenue.

     Blackout Costs

      On August 14, 2003, failures in the regional power transmission grid caused nine of Detroit Edison’s power plants to trip offline, which left virtually all of its 2.1 million customers without power. We estimate that amounts expensed in the 2003 third quarter related to the blackout, excluding lost margins, were approximately $25 million pre-tax ($16 million net of tax). On October 24, 2003, Detroit Edison filed an accounting application with the MPSC requesting authority to defer outage related costs associated with the blackout until a future rate proceeding to recover outage costs from customers in a manner consistent with the provisions of PA 141. We anticipate an accounting order in the fourth quarter of 2003 or the first quarter of 2004, but we cannot predict the ultimate outcome or timing of this proceeding.

     Electric Industry Restructuring

      Electric Rates, Customer Choice and Stranded Costs — PA 141 provided Detroit Edison with the right to recover net stranded costs, codified and established January 1, 2002 as the date for full implementation of the MPSC’s existing electric Customer Choice program, and required the MPSC to reduce residential electric rates by 5%. At that time, Public Act 142 (PA 142) also became effective. PA 142 provided for the recovery through securitization of “qualified costs” which consist of an electric utility’s regulatory assets, plus various costs associated with, or resulting from, the establishment of a competitive electric market and the issuance of securitization bonds.

      Acting pursuant to PA 141, in an order issued in June 2000, the MPSC reduced Detroit Edison’s residential electric rates by 5% and imposed a rate freeze for all classes of customers through 2003. In April 2001, commercial and industrial rates were lowered by 5% as a result of savings derived from the issuance of securitization bonds in March 2001, as subsequently discussed.

      Certain costs may be deferred and recovered once rates can be increased. This rate cap may be lifted when certain market test provisions are met, specifically, when an electric utility has no more than 30% of generation capacity in its relevant market, with consideration for capacity needed to meet a utility’s responsibility to serve its retail customers. Statewide, multi-utility transmission system improvements also are required. In May 2003, Detroit Edison submitted filings with the MPSC regarding its compliance with the provisions of PA 141 related to market test and transmission system improvements. If the MPSC finds that Detroit Edison has complied with the PA 141 provisions, the rate caps established under PA 141 will not continue after the dates specified in the legislation. Detroit Edison has entered into a settlement agreement in regards to the market power test provisions of PA 141. All intervening parties have signed the settlement agreement. Detroit Edison is awaiting MPSC approval, which is expected by year-end 2003.

30

      As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating the net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual filing with the MPSC comparing the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital. Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC, in its December 2001 order, also determined that Detroit Edison had no net stranded costs in 2000 and consequently established a zero net stranded cost transition charge for billing purposes in 2002. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding. The MPSC also determined that Detroit Edison should provide a full and offsetting credit for the securitization and tax charges applied to electric Customer Choice bills in 2002. In addition, the MPSC ordered an additional credit on bills equal to the 5% rate reduction realized by full service customers. Both credits were to be funded from savings derived from securitization. The December 2001 order, coupled with lower wholesale power prices in 2002, has encouraged additional customer participation in the electric Customer Choice program and has resulted in the loss of margins attributable to generation services. In May 2002, the MPSC denied Detroit Edison’s request for rehearing and clarification of the December 2001 order. In June 2002, Detroit Edison filed an appeal of the MPSC order at the Michigan Court of Appeals, challenging the legality of specific aspects of the MPSC order. The Court of Appeals has not yet issued a decision on this appeal.

      In May 2002, Detroit Edison submitted its 2001 net stranded cost filing with the MPSC. The filing provided refinements to the MPSC Staff’s calculation of net stranded costs that was adopted in the December 2001 order, sought more timely recovery of net stranded costs, and addressed issues raised by the continuation of securitization offsets and rate reduction equalization credits. The filing supported that Detroit Edison had no net stranded costs in 2000 and $13 million of recoverable net stranded costs attributable to electric Customer Choice in 2001. On July 31, 2003, the MPSC issued an order finding that Detroit Edison had no net stranded costs in 2000 and 2001 and established a zero net stranded cost transition charge for billing purposes in 2003. In addition, this order clarified the inclusion of revenue discounts granted customers under special contracts in the net stranded cost calculation, but deferred finalizing the methods for determining net stranded costs. In the fourth quarter of 2002, Detroit Edison recorded a regulatory asset of $21 million, of which $10 million represented an estimate of net stranded costs during 2001, and the remaining balance represented the deferral of environmental expenditures recoverable under PA 141. The effect of recording the regulatory asset increased 2002 earnings by $14 million, net of tax. During the 2003 nine-month period, Detroit Edison recorded a regulatory asset of $54 million, of which $30 million represented an adjustment for net stranded costs for 2003, and the remainder representing the deferral of environmental expenditures. The effect for the 2003 nine-month period was an increase in earnings of $35 million, net of tax. As a result of the MPSC July 31, 2003, order and the related clarifying language, we recalculated net stranded costs for 2002 and 2003. Our revised and ongoing calculations conclude that the $30 million of net stranded costs recorded as of September 30, 2003 is appropriate. Detroit Edison has filed a petition for rehearing of the July 31, 2003 order.

      Low-Income Energy Assistance Credit — On October 20, 2003, Detroit Edison filed an application with the MPSC to implement a low-income energy assistance credit for residential electric customers. The credit is expected to assist many low-income customers who are experiencing difficulties in paying their electric bills due to poor economic conditions in Detroit Edison’s service area. Detroit Edison has proposed to fund the low-income energy assistance credit by utilizing excess securitization savings currently being used to provide credits to electric Choice Customers.

     Gas Rate Plan

      On September 30, 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. Although a final order relating to the base rate increase request is not anticipated prior to the

31

fourth quarter of 2004, MichCon has requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004. The interim request is based on a projected revenue deficiency for the test year 2004.

      Primary factors that necessitate MichCon’s request for increased base rates include significant increases in routine and mandated infrastructure improvements, increased operation and maintenance expenses, including employee pension and health care costs, and a decline in customer consumption. The filing also requests a permanent capital structure based on 50% debt and 50% equity, and a proposed ROE of 11.5%. MichCon is also proposing a symmetrical ROE sharing mechanism which would provide that shareholders retain all earnings within a 1% band above and below the authorized ROE. If the actual ROE falls outside of the band, customers would share between 20% and 80 % of the excess or shortfall of earnings, depending on actual ROE.

      On September 30, 2003, MichCon also filed an application with the MPSC for the approval of depreciation rates, which will result in a modest increase in its composite depreciation rate. The Company anticipates that any depreciation change will be implemented contemporaneously with a MPSC order in MichCon’s base rate case.

     Gas Industry Restructuring

      In December 2001, the MPSC approved MichCon’s application for a voluntary, expanded permanent gas Customer Choice program, which replaced the experimental program that expired in March 2002. Effective April 2002, up to 40% of MichCon’s customers could elect to purchase gas from suppliers other than MichCon. Effective April 2003, up to 60% of customers are eligible and by April 2004, all of MichCon’s 1.2 million customers may participate in the program. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the Customer Choice program. As of September 2003, approximately 124,000 customers are participating in the Customer Choice program.

     Gas Cost Recovery Proceedings

      2002 Plan Year — In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per Mcf for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset of approximately $14 million representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset will be subject to the 2002 GCR reconciliation process. In July 2002, in response to a petition for rehearing filed by the Michigan Attorney General, the MPSC directed the parties to address MichCon’s implementation of the December 2001 order and the impact of that implementation on rates charged to MichCon’s customers. On March 12, 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year. Although we have recorded a $26.5 million reserve in the first quarter of 2003 to reflect the impact of this order, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment will be decided in MichCon’s 2002 GCR reconciliation case. In addition, we filed an appeal of the March 12, 2003 MPSC order with the Michigan Court of Appeals. The 2002 GCR reconciliation case was filed with the MPSC in February 2003. Intervening parties in this proceeding are seeking to have the MPSC disallow an additional approximately $34 million representing unbilled revenues at December 2001 and the Enron bankruptcy settlement. A final order in this proceeding is not expected until 2004.

      2003 Plan Year — On July 23, 2003, the MPSC approved an increase in MichCon’s 2003 GCR rate to a maximum of $5.75 per Mcf for the billing months of August 2003 through December 2003. As of September 30, 2003, MichCon has accrued a $64 million regulatory asset representing the under-recovery of actual gas costs incurred. It is expected that the billing of the $5.75 GCR rate will substantially eliminate the under-recovery by year-end 2003.

32

      2004 Plan Year — On September 30, 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf. MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR Plan Case. The operational GCR year would run from April to March of the following year. To accomplish the switch, the 2004 GCR Plan Case reflects a 15-month transitional period, January 2004 through March 2005. Under our transition proposal, MichCon would file two reconciliations pertaining to the transition period; one addressing the January 2004 to March 2004 period, the other addressing the remaining April 2004 to March 2005 period. The plan also proposes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices thereby minimizing the possibility of a GCR under recovery.

     Minimum Pension Liability

      In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, “Employers’ Accounting for Pensions,” with offsetting amounts to an intangible asset and other comprehensive income. During the first quarter of 2003, the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff opinion, management believes that it will be allowed to recover in rates the minimum pension liability associated with its regulated operations. Accordingly, in the first quarter of 2003 we reclassified approximately $641 million ($417 million net of tax) of other comprehensive loss associated with the minimum pension liability to a regulatory asset.

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

Note 5 — Effective Tax Rate Adjustment

      Under Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” we are required to adjust our effective tax rate each quarter to be consistent with the estimated annual effective tax rate. This quarterly adjustment had the effect of decreasing income tax expense by $82 million for the 2003 third quarter and increasing income tax expense for the nine month period ending September 30, 2003 by $70 million and decreasing income tax expense by $19 million and $5 million in the corresponding 2002 third quarter and nine-month period. Fluctuations in estimated annual earnings and tax credits were the primary variables that resulted in the larger adjustments in the 2003 periods. Annual results are not affected.

Note 6 — Earnings Per Share

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

33

stock awards and the issuance of performance share awards. A reconciliation of both calculations for the 2003 and 2002 quarter and nine-month period is presented in the table below:

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2003		2002		2003		2002
	(Thousands, except per share amounts)
Basic Earnings Per Share
Income from continuing operations	$	179,700	$	138,900	$	250,500	$	391,650
Average number of common shares outstanding		167,836		167,060		167,541		163,003
Income per share of common stock based on weighted average number of shares outstanding	$	1.07	$	.83	$	1.49	$	2.40
Diluted Earnings Per Share
Income from continuing operations	$	179,700	$	138,900	$	250,500	$	391,650
Average number of common shares outstanding		167,836		167,060		167,541		163,003
Incremental shares from stock based awards		539		653		540		772
Average number of dilutive shares outstanding		168,375		167,713		168,081		163,775
Income per share of common stock assuming issuance of incremental shares	$	1.06	$	.83	$	1.49	$	2.39

Note 7 — Long-Term Debt

      In February 2003, MichCon issued $200 million of 5.7% senior notes due in March 2033. The proceeds were used for debt redemptions.

      In April 2003, DTE Energy issued $400 million of 6 3/8% senior notes due in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing Enterprises debt due April 2008. The exchange premium and other costs associated with the original debt will be deferred and amortized to interest expense over the term of the new debt.

      In June 2003, DTE Energy redeemed $100 million principal amount of 6.17% Remarketed Notes due in 2038.

      In August 2003, Detroit Edison issued $49 million of 5.5% tax exempt bonds due in 2030. The proceeds were used to redeem $49 million 6.55% tax-exempt bonds due 2024.

Note 8 — Short Term Credit Arrangements and Borrowings

      On October 24, 2003, DTE Energy entered into a $350 million 364-day revolving credit facility and a $350 million three-year revolving credit facility with a syndicate of banks. These credit facilities may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for DTE Energy’s commercial paper program up to $700 million. These agreements require the Company to maintain a debt to total capitalization ratio of no more than .65 to l and “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1. DTE Energy is currently in compliance with these financial covenants. Also, in October 2003, DTE Energy’s wholly-owned subsidiaries, Detroit Edison and MichCon, entered into similar revolving credit facilities. Detroit Edison entered into a $137.5 million, 364-day facility and a $137.5 million, three-year facility. MichCon entered into a $162.5 million, 364-day facility and a $162.5 million, three-year facility. Should either Detroit Edison or MichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default under DTE Energy’s credit agreements.

34

Note 9 — Contingencies

Synthetic Fuel Operations

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

      In May 2003, the IRS suspended the issuance of PLRs relating to synthetic fuel projects pending their review of issues concerning chemical change which is the basis for earning Section 29 tax credits. The IRS announced at that time that it had reason to question the scientific validity of test procedures and results that had been presented in the industry as evidence that the coal feedstock underwent a significant chemical change. The IRS indicated that it might have revoked existing PLRs that relied on procedures and results under review if it determined that those procedures and results did not demonstrate that significant chemical change had occurred. On October 29, 2003, the IRS announced that it has concluded its assessment of the chemical change process involved in synfuel production and resumed issuance of PLRs. The IRS determined that the test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner. The Company believes that its synthetic fuel facilities currently meet the new, more stringent sampling and data/record retention requirements announced by the IRS. We had previously received favorable PLRs from the IRS on 7 of our 9 synfuel plants. In November 2003, we received favorable PLRs for the remaining two synfuel plants. The IRS is currently reviewing procedures and results at four of our synfuels plants in conjunction with their audits of our federal income tax returns. We believe our synthetic fuel plants operate in accordance with the PLRs. Through September 30, 2003, we have generated approximately $440 million of synfuel tax credits and the credits have been carried forward as alternative minimum tax credits.

      We will continue our efforts to sell interests in some or all of our synfuel projects now that the IRS has resumed issuing PLRs. Sales of interests in synfuel projects allow us to accelerate cash flow and taxable income, while maintaining a stable net income base. As the sale of interests in synfuel projects usually requires the reconfirmation of the PLR, the timing and number of our synfuel project interest sales has been influenced by the IRS’ five month suspension of issuing new and reconfirming PLRs.

      The temporary delay in selling interests in the synfuel projects has resulted in our capacity to generate more credits than we can utilize. In addition, cool spring and summer weather, combined with cost and margin pressures, have contributed to lower forecasted taxable earnings. Therefore, we reduced synthetic fuel production by approximately one-half in June 2003 to optimize the tax credits generated from these facilities. We have begun implementing a series of initiatives, including selling interests in our synfuel projects and monetizing in-the-money gas swap derivative contracts, which we expect to improve cash flow as well as our ability to fully utilize the $225 million in estimated tax credits to be generated in 2003. We will closely monitor taxable income through the remainder of 2003 and assess synfuel production levels accordingly.

Bankruptcies

      We purchase and sell electricity, gas, coal and coke to numerous companies operating in the steel, automotive, energy and retail industries. A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of loss. We believe our accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

35

Other

      We are involved in certain legal (including commercial matters), administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our financial statements in the period they are resolved.

      See Note 4 for a discussion of contingencies related to Regulatory Matters.

Note 10 — Segment Information

      DTE Energy has the following nine reportable segments. Inter-segment revenues are not material.

			Three Months						Nine Months
			Ended						Ended
			September 30						September 30
			2003			2002			2003			2002
			(In millions)
Operating Revenues
Energy Resources
	Regulated — Power Generation		$	669		$	806		$	1,874		$	2,082
	Non-regulated
		Energy Services		229			166			696			427
		Energy Marketing & Trading		230			126			713			442
		Other		77			37			209			105
	Total Non-regulated			536			329			1,618			974
				1,205			1,135			3,492			3,056
Energy Distribution
	Regulated — Power Distribution			348			394			950			1,010
	Non-regulated			11			10			25			24
				359			404			975			1,034
Energy Gas
	Regulated — Gas Distribution			146			122			1,074			963
	Non-regulated			26			24			70			69
				172			146			1,144			1,032
Corporate & Other				4			4			10			13
Reconciliations and eliminations				(86	)		(32	)		(272	)		(110	)
Total
	Regulated			1,163			1,322			3,898			4,055
	Non-regulated(1)			491			335			1,451			970
			$	1,654		$	1,657		$	5,349		$	5,025

(1)  Includes Corporate & Other.

36

			Three Months						Nine Months
			Ended						Ended
			September 30						September 30
			2003			2002			2003			2002
			(In millions)
Net Income (Loss)
Energy Resources
	Regulated — Power Generation		$	61		$	54		$	132		$	171
	Non-regulated
		Energy Services		23			45			151			107
		Energy Marketing & Trading		23			(1	)		52			12
		Other		(1	)		1			(1	)		—
	Total Non-regulated			45			45			202			119
				106			99			334			290
Energy Distribution
	Regulated — Power Distribution			35			51			15			97
	Non-regulated			(3	)		(4	)		(12	)		(11	)
				32			47			3			86
Energy Gas
	Regulated — Gas Distribution			(45	)		(23	)		5			30
	Non-regulated			12			6			26			20
				(33	)		(17	)		31			50
Corporate & Other				75			10			(117	)		(34	)
Income from Continuing Operations
	Regulated			51			82			152			298
	Non-regulated(1)			129			57			99			94
				180			139			251			392
Discontinued Operations				(4	)		22			68			37
Cumulative Effect of Accounting Changes				—			—			(27	)		—
Net Income			$	176		$	161		$	292		$	429
Diluted Earnings per Common Share
	Regulated		$	.30		$	.49		$	.91		$	1.82
	Non-regulated(1)			.76			.34			.58			.57
Income from Continuing Operations				1.06			.83			1.49			2.39
Discontinued Operations				(.02	)		.13			.40			.23
Cumulative Effect of Accounting Changes				—			—			(.16	)		—
Net Income			$	1.04		$	.96		$	1.73		$	2.62

(1)  Includes Corporate & Other.

37

Note 11 — Consolidating Financial Statements

      Debt securities issued by Enterprises are subject to a full and unconditional guaranty by DTE Energy. The following DTE Energy consolidating financial statements are presented and include separately Corporate & Other, Enterprises and all other subsidiaries. Enterprises includes MichCon and other non-regulated gas subsidiaries. The other subsidiaries include Detroit Edison and other non-regulated electric subsidiaries.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

		Three Months Ended September 30, 2003
		DTE									Eliminations
		Energy			DTE			Other			and			Consolidated
		Company			Enterprises			Subsidiaries			Reclasses			Total
		(In millions)
Operating Revenues		$	—		$	351		$	1,342		$	(39	)	$	1,654
Operating Expenses
	Fuel, purchased power and gas		—			213			276			(37	)		452
	Operation and maintenance		(25	)		113			624			(3	)		709
	Depreciation, depletion and amortization		—			29			141			—			170
	Taxes other than income		(12	)		13			70			—			71
			(37	)		368			1,111			(40	)		1,402
Operating Income (Loss)			37			(17	)		231			1			252
Other (Income) and Deductions
	Interest expense		47			21			77			(15	)		130
	Interest expense from preferred securities of subsidiaries		—			1			4			—			5
	Interest income		(11	)		(3	)		(7	)		14			(7	)
	Other income		(98	)		(15	)		(29	)		98			(44	)
	Other expense		—			—			31			—			31
			(62	)		4			76			97			115
Income (Loss) Before Income Taxes			99			(21	)		155			(96	)		137
Income Tax Expense (Benefit)			(81	)		1			37			—			(43	)
Income (Loss) from Continuing Operations			180			(22	)		118			(96	)		180
Discontinued Operations
	Income from operations		—			—			—			—			—
	Gain on sale		(4	)		—			—			—			(4	)
			(4	)		—			—			—			(4	)
Net Income (Loss)		$	176		$	(22	)	$	118		$	(96	)	$	176

38

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

		Three Months Ended September 30, 2002
		DTE									Eliminations
		Energy			DTE			Other			and			Consolidated
		Company			Enterprises			Subsidiaries			Reclasses			Total
		(In millions)
Operating Revenues		$	—		$	226		$	1,407		$	24		$	1,657
Operating Expenses
	Fuel, purchased power and gas		—			118			402			(19	)		501
	Operation and maintenance		(27	)		80			520			42			615
	Depreciation, depletion and amortization		—			31			173			—			204
	Taxes other than income		—			13			74			—			87
			(27	)		242			1,169			23			1,407
Operating Income			27			(16	)		238			1			250
Other (Income) and Deductions
	Interest expense		45			22			79			(11	)		135
	Preferred stock dividends of subsidiaries		—			2			4			—			6
	Interest income		(9	)		(4	)		(9	)		13			(9	)
	Other income		(145	)		2			12			127			(4	)
	Other expense		(2	)		(9	)		(3	)		22			8
			(111	)		13			83			151			136
Income (Loss) Before Income Taxes			138			(29	)		155			(150	)		114
Income Tax Expense (Benefit)			(23	)		(10	)		8			—			(25	)
Income (Loss) from Continuing Operations			161			(19	)		147			(150	)		139
Discontinued Operations			—			—			22			—			22
Net Income (Loss)		$	161		$	(19	)	$	169		$	(150	)	$	161

39

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

		Nine Months Ended September 30, 2003
		DTE									Eliminations
		Energy			DTE			Other			and			Consolidated
		Company			Enterprises			Subsidiaries			Reclasses			Total
		(In millions)
Operating Revenues		$	—		$	1,672		$	3,817		$	(140	)	$	5,349
Operating Expenses
	Fuel, purchased power and gas		—			1,141			748			(131	)		1,758
	Operation and maintenance		(115	)		337			1,985			(10	)		2,197
	Depreciation, depletion and amortization		—			89			458			—			547
	Taxes other than income		(12	)		49			218			—			255
			(127	)		1,616			3,409			(141	)		4,757
Operating Income			127			56			408			1			592
Other (Income) and Deductions
	Interest expense		141			64			237			(47	)		395
	Interest expense from preferred securities of subsidiaries		—			1			4			—			5
	Preferred stock dividends of subsidiaries		—			5			7			—			12
	Interest income		(35	)		(10	)		(23	)		46			(22	)
	Other income		(279	)		(24	)		(51	)		279			(75	)
	Other expense		15			(1	)		68			—			82
			(158	)		35			242			278			397
Income Before Income Taxes			285			21			166			(277	)		195
Income Tax Expense (Benefit)			56			22			(134	)		—			(56	)
Income (Loss) from Continuing Operations			229			(1	)		300			(277	)		251
Discontinued Operations
	Income from operations		—			—			5			—			5
	Gain on sale		63			—			—			—			63
			63			—			5			—			68
Cumulative Effect of Accounting Changes
	Asset retirement obligations		—			(2	)		(9	)		—			(11	)
	Energy trading activities		—			(13	)		(3	)		—			(16	)
			—			(15	)		(12	)		—			(27	)
Net Income (Loss)		$	292		$	(16	)	$	293		$	(277	)	$	292

40

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

		Nine Months Ended September 30, 2002
		DTE									Eliminations
		Energy			DTE			Other			and			Consolidated
		Company			Enterprises			Subsidiaries			Reclasses			Total
		(In millions)
Operating Revenues		$	—		$	1,364		$	3,682		$	(21	)	$	5,025
Operating Expenses
	Fuel, purchased power and gas		—			859			842			(62	)		1,639
	Operation and maintenance		(76	)		256			1,556			45			1,781
	Depreciation, depletion and amortization		—			92			481			—			573
	Taxes other than income		—			44			217			—			261
			(76	)		1,251			3,096			(17	)		4,254
Operating Income			76			113			586			(4	)		771
Other (Income) and Deductions
	Interest expense		127			69			247			(36	)		407
	Preferred stock dividends of subsidiaries		—			9			10			—			19
	Interest income		(25	)		(11	)		(20	)		36			(20	)
	Other income		(441	)		(16	)		(6	)		441			(22	)
	Other expense		—			(3	)		34			—			31
			(339	)		48			265			441			415
Income Before Income Taxes			415			65			321			(445	)		356
Income Tax Expense (Benefit)			(14	)		24			(46	)		—			(36	)
Income from Continuing Operations			429			41			367			(445	)		392
Discontinued Operations			—			—			37			—			37
Net Income		$	429		$	41		$	404		$	(445	)	$	429

41

CONSOLIDATING STATEMENTS OF FINANCIAL POSITION (Unaudited)

				September 30, 2003
				DTE									Eliminations
				Energy			DTE			Other			and			Consolidated
				Company			Enterprises			Subsidiaries			Reclasses			Total
				(In millions, except shares)
ASSETS
Current Assets
	Cash and cash equivalents			$	54		$	4		$	32		$	—		$	90
	Restricted cash				—			—			100			—			100
	Accounts receivable
		Customer, less allowance for doubtful accounts			—			243			582			—			825
		Accrued unbilled revenues			—			30			157			—			187
		Other			1,171			267			573			(1,682	)		329
	Inventories
		Fuel and gas			—			430			166			—			596
		Materials and supplies			—			23			147			—			170
	Assets from risk management and trading activities				1			188			75			(3	)		261
	Other				95			124			56			(76	)		199
					1,321			1,309			1,888			(1,761	)		2,757
Investments
	Nuclear decommissioning trust funds				—			—			484						484
	Other				6,536			444			269			(6,781	)		468
					6,536			444			753			(6,781	)		952
Property
	Property, plant and equipment				—			3,749			13,885			(3	)		17,631
	Less accumulated depreciation and depletion				—			(2,116	)		(5,845	)		—			(7,961	)
					—			1,633			8,040			(3	)		9,670
Other Assets
	Goodwill				—			2,045			39			—			2,084
	Regulatory assets				—			63			2,025			—			2,088
	Securitized regulatory assets				—			—			1,550			—			1,550
	Assets from risk management and trading activities				—			121			21			(1	)		141
	Prepaid pension assets				—			179			—			—			179
	Other				21			192			302			—			515
					21			2,600			3,937			(1	)		6,557
			Total Assets	$	7,878		$	5,986		$	14,618		$	(8,546	)	$	19,936
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
	Accounts payable			$	118		$	402		$	553		$	(423	)	$	650
	Accrued interest				60			8			54			(2	)		120
	Dividends payable				87			1			77			(74	)		91
	Accrued payroll				—			6			27			—			33
	Short-term borrowings				167			675			745			(1,118	)		469
	Current portion of long-term debt, including capital leases				550			63			139			—			752
	Liabilities from risk management and trading activities				—			222			59			(2	)		279
	Other				253			141			239			—			633
					1,235			1,518			1,893			(1,619	)		3,027
Other Liabilities
	Deferred income taxes				(462	)		(220	)		1,798			(1	)		1,115
	Regulatory liabilities				—			134			27			—			161
	Asset retirement obligations				—			22			832			—			854
	Unamortized investment tax credit				—			21			138			—			159
	Liabilities from risk management and trading activities				—			200			14			(2	)		212
	Liabilities from transportation and storage contracts				—			486			—			—			486
	Accrued pension liability				—			26			378			—			404
	Nuclear decommissioning				—			—			61			—			61
	Other				(36	)		156			777			(214	)		683
					(498	)		825			4,025			(217	)		4,135
Long-Term Debt
	Mortgage bonds, notes and other				1,881			775			3,190			(186	)		5,660
	Securitization bonds				—			—			1,496			—			1,496
Obligated Mandatorily Redeemable Preferred Securities of
	Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises				—			100			180			—			280
	Equity-linked securities				186			—			—			—			186
	Capital lease obligations				—			1			77			—			78
					2,067			876			4,943			(186	)		7,700
Shareholders’ Equity
	Common stock, without par value, 400,000,000 shares authorized, 168,301,400 shares issued and outstanding				3,091			3,195			2,556			(5,751	)		3,091
	Retained earnings				2,168			(186	)		1,202			(1,016	)		2,168
	Accumulated other comprehensive loss				(185	)		(242	)		(1	)		243			(185	)
					5,074			2,767			3,757			(6,524	)		5,074
			Total Liabilities and Shareholders’ Equity	$	7,878		$	5,986		$	14,618		$	(8,546	)	$	19,936

42

CONSOLIDATING STATEMENTS OF FINANCIAL POSITION

			December 31, 2002
			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
			Company			Enterprises			Subsidiaries			Reclasses			Total
			(In millions, except shares)
ASSETS
Current Assets
	Cash and cash equivalents		$	21		$	12		$	100		$	—		$	133
	Restricted cash			—			—			237			—			237
	Accounts receivable
		Customer, less allowance for doubtful accounts		—			301			601			—			902
		Accrued unbilled revenues		—			119			177			—			296
		Other		778			150			436			(1,127	)		237
	Inventories
		Fuel and gas		—			219			194			—			413
		Materials and supplies		—			19			144			—			163
	Assets from risk management and trading activities			—			78			146			—			224
	Other			22			118			21			(2	)		159
				821			1,016			2,056			(1,129	)		2,764
Investments
	Nuclear decommissioning trust funds			—			—			417			—			417
	Other			6,313			436			577			(6,839	)		487
				6,313			436			994			(6,839	)		904
Property
	Property, plant and equipment			—			3,679			14,186			(3	)		17,862
	Less accumulated depreciation and depletion			—			(2,051	)		(5,998	)		—			(8,049	)
				—			1,628			8,188			(3	)		9,813
Other Assets
	Goodwill			—			2,080			39			—			2,119
	Regulatory assets			—			45			1,152			—			1,197
	Securitized regulatory assets			—			—			1,613			—			1,613
	Assets from risk management and trading activities			—			133			19			—			152
	Prepaid pension assets			—			172			—			—			172
	Other			11			189			306			(2	)		504
				11			2,619			3,129			(2	)		5,757
Total Assets			$	7,145		$	5,699		$	14,367		$	(7,973	)	$	19,238
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
	Accounts payable		$	73		$	307		$	551		$	(284	)	$	647
	Accrued interest			17			18			83			(3	)		115
	Dividends payable			86			1			76			(73	)		90
	Accrued payroll			—			9			40			—			49
	Short-term borrowings			440			450			274			(750	)		414
	Current portion of long-term debt, including capital leases			400			259			359			—			1,018
	Liabilities from risk management and trading activities			—			159			126			(1	)		284
	Other			83			104			409			—			596
				1,099			1,307			1,918			(1,111	)		3,213
Other Liabilities
	Deferred income taxes			(339	)		(305	)		1,561			(1	)		916
	Regulatory liabilities			—			142			37			—			179
	Unamortized investment tax credit			—			22			146			—			168
	Liabilities from risk management and trading activities			—			199			9			—			208
	Liabilities from transportation and storage contracts			—			523			—			—			523
	Accrued pension liability			—			21			561			—			582
	Nuclear decommissioning			—			—			416			—			416
	Other			(104	)		146			1,032			(391	)		683
				(443	)		748			3,762			(392	)		3,675
Long-Term Debt
	Mortgage bonds, notes and other			1,733			738			3,371			(186	)		5,656
	Securitization bonds			—			—			1,585			—			1,585
	Equity-linked securities			191			—			—						191
	Capital lease obligations			—			2			80			—			82
				1,924			740			5,036			(186	)		7,514
Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises				—			97			174			—			271
Shareholders’ Equity
	Common stock, without par value, 400,000,000 shares authorized, 167,462,430 shares issued and outstanding			3,052			3,191			2,711			(5,902	)		3,052
	Retained earnings			2,132			(131	)		1,185			(1,054	)		2,132
	Accumulated other comprehensive loss			(619	)		(253	)		(419	)		672			(619	)
				4,565			2,807			3,477			(6,284	)		4,565
Total Liabilities and Shareholders’ Equity			$	7,145		$	5,699		$	14,367		$	(7,973	)	$	19,238

43

CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)

			Nine Months Ended September 30, 2003
			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
			Company			Enterprises			Subsidiaries			Reclasses			Total
			(In millions)
Net Cash From (Used For) Operating Activities			$	282		$	54		$	252		$	(346	)	$	242
Investing Activities
	Plant and equipment expenditures regulated			—			(67	)		(437	)		—			(504	)
	Plant and equipment expenditures non-regulated			—			(23	)		(35	)		—			(58	)
	Proceeds from sale of interests in synfuel projects			—			—			67			—			67
	Proceeds from sale of ITC and other assets (Note 3)			610			33			—			—			643
	Restricted cash for debt redemptions			—			—			137			—			137
	Capital contribution to subsidiary			(170	)		—			—			170			—
	Other investments			(366	)		(38	)		(19	)		357			(66	)
		Net cash from (used for) investing activities		74			(95	)		(287	)		527			219
Financing Activities
	Issuance of long-term debt			281			199			49			—			529
	Redemption of long-term debt			(105	)		(254	)		(538	)		—			(897	)
	Short-term borrowings, net			(272	)		125			472			(270	)		55
	Capital contribution by parent company			—			—			170			(170	)		—
	Issuance of common stock			33			—			—			—			33
	Dividends on common stock			(259	)		(37	)		(222	)		259			(259	)
	Contributions from synfuel partners			—			—			44			—			44
	Other			(1	)		—			(8	)		—			(9	)
		Net cash from financing activities		(323	)		33			(33	)		(181	)		(504	)
Net Increase (Decrease) in Cash and Cash Equivalents				33			(8	)		(68	)		—			(43	)
Cash and Cash Equivalents, Beginning of Period				21			12			100			—			133
Cash and Cash Equivalents, End of Period			$	54		$	4		$	32		$	—		$	90

44

CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)

			Nine Months Ended September 30, 2002
			DTE									Eliminations
			Energy			DTE			Other			and			Consolidated
			Company			Enterprises			Subsidiaries			Reclasses			Total
			(In millions)
Net Cash From (Used For) Operating Activities			$	210		$	226		$	839		$	(759	)	$	516
Investing Activities
	Plant and equipment expenditures — regulated			—			(54	)		(446	)		—			(500	)
	Plant and equipment expenditures — non-regulated			—			(18	)		(132	)		—			(150	)
	Proceed from sale of interests in synfuel projects			—			—			11			—			11
	Proceeds from sale of other assets			—			8			—			—			8
	Restricted cash for debt redemptions			—			—			34			—			34
	Other investments			(519	)		19			(386	)		827			(59	)
		Net cash from (used for) investing activities		(519	)		(45	)		(919	)		827			(656	)
Financing Activities
	Issuance of long-term debt			367			—			21			—			388
	Redemption of long-term debt			(1	)		(212	)		(299	)		—			(512	)
	Issuance of preferred securities			—			—			180			—			180
	Redemption of preferred securities			—			(180	)		—			—			(180	)
	Short-term borrowings, net			(54	)		226			225			(290	)		107
	Issuance of common stock			265			—			—			—			265
	Dividends on common stock			(252	)		—			(222	)		222			(252	)
	Contributions from synfuel partners			—			—			10			—			10
	Other			(4	)					(18	)					(22	)
		Net cash from (used for) financing activities		321			(166	)		(103	)		(68	)		(16	)
Net Increase (Decrease) in Cash and Cash Equivalents				12			15			(183	)		—			(156	)
Cash and Cash Equivalents, Beginning of Period				8			9			251			—			268
Cash and Cash Equivalents, End of Period			$	20		$	24		$	68		$	—		$	112

45

INDEPENDENT ACCOUNTANTS’ REPORT

To the Board of Directors and Shareholders of

DTE Energy Company

      We have reviewed the accompanying condensed consolidated statement of financial position of DTE Energy Company and subsidiaries as of September 30, 2003, the related condensed consolidated statements of operations for the three-month and nine-month periods ended September 30, 2003 and 2002, the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2003 and 2002, and the condensed consolidated statement of changes in shareholders’ equity and comprehensive income for the nine-month period ended September 30, 2003 and nine-month periods ended September 30, 2003 and 2002, respectively. These interim financial statements are the responsibility of DTE Energy Company’s management.

      We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

      Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

      We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated statement of financial position of DTE Energy Company and subsidiaries as of December 31, 2002, and the related consolidated statements of operations, cash flows and changes in shareholders’ equity and comprehensive income for the year then ended (not presented herein); and in our report dated February 11, 2003 (March 12, 2003 as to Note 21 and July 10, 2003 as to Note 2 — Asset Retirement Obligations and Note 4 — Disposition of International Transmission Company — Discontinued Operation), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated statement of financial position as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated statement of financial position from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan

November 7, 2003

46

OTHER INFORMATION

Legal Proceedings

      We are involved in certain legal (including commercial matters), administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include contract disputes, environmental reviews and investigations, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our financial statements in the period they are resolved. For additional discussion on legal matters, see the Notes to the Consolidated Financial Statements.

Exhibits and Reports on Form 8-K

      (a) Exhibits

Exhibit
Number		Description
	Filed:
	15-12	Awareness Letter of Deloitte & Touche LLP
	31-3	Chief Executive Officer Section 302 Form 10-Q Certification
	31-4	Chief Financial Officer Section 302 Form 10-Q Certification
	99-13	364-Day Credit Agreement dated as of October 24, 2003 among DTE Energy Company, The Banks, Financial Institutions and Other Institutional Lenders, and Citibank, N.A., and Banc One Capital Markets, Inc., and Barclays Bank PLC
	99-14	Three-Year Credit Agreement dated as of October 24, 2003 among DTE Energy Company, The Banks, Financial Institutions and Other Institutional Lenders, and Citibank, N.A., and Banc One Capital Markets, Inc., and Barclays Bank PLC
	Furnished:
	32-3	Chief Executive Officer Section 906 Certification of Periodic Report
	32-4	Chief Financial Officer Section 906 Certification of Periodic Report

      (b) Reports on Form 8-K

      During the quarterly period ended September 30, 2003, we filed Current Reports on Form 8-K covering matters, as follows:

Item 5.	Other Events filed July 15, 2003 and dated July 14, 2003;
Item 7.	Exhibits and Item 9. Information Provided Under Item 12 (Results of Operations and Financial Condition) filed and dated July 28, 2003;
Item 5.	Other Events and Item 7. Exhibits and Item 9. Information Provided Under Item 12. (Results of Operations and Financial Condition) filed and dated August 1, 2003;
Item 7.	Exhibits and Item 12. (Results of Operations and Financial Conditions) filed and dated August 14, 2003; and
Item 5.	Other Events and Item 7. Exhibits filed and dated August 27, 2003.

47

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

/S/ DANIEL G. BRUDZYNSKI

_______________________________________

DANIEL G. BRUDZYNSKI

Chief Accounting Officer,

Vice President and Controller

Date: November 7, 2003

48

EXHIBIT INDEX

Exhibit
Number		Description
	Filed:
	15-12	Awareness Letter of Deloitte & Touche LLP
	31-3	Chief Executive Officer Section 302 Form 10-Q Certification
	31-4	Chief Financial Officer Section 302 Form 10-Q Certification
	99-13	364-Day Credit Agreement dated as of October 24, 2003 among DTE Energy Company, The Banks, Financial Institutions and Other Institutional Lenders, and Citibank, N.A., and Banc One Capital Markets, Inc., and Barclays Bank PLC
	99-14	Three-Year Credit Agreement dated as of October 24, 2003 among DTE Energy Company, The Banks, Financial Institutions and Other Institutional Lenders, and Citibank, N.A., and Banc One Capital Markets, Inc., and Barclays Bank PLC
	Furnished:
	32-3	Chief Executive Officer Section 906 Certification of Periodic Report
	32-4	Chief Financial Officer Section 906 Certification of Periodic Report