e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period ended September 30, 2004

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 [X] No [ ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes [X] No [ ]

At September 30, 2004, 173,958,093 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.

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 direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies

DTE Energy		DTE Energy Company, directly or indirectly the parent of Detroit Edison and MichCon

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 (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies

MPSC		Michigan Public Service Commission

NRC		Nuclear Regulatory Commission

PSCR		A power supply cost recovery mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power electric expenses. The clause was suspended pursuant to Michigan’s restructuring legislation signed into law June 5, 2000, which lowered and froze electric customer rates. The clause was reinstated by the MPSC effective January 1, 2004.

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. The amount of a Section 29 tax credit can vary each year as determined by the Internal Revenue Service (Note 9).

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		The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production generates Section 29 tax credits.

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, and purchases from suppliers;

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

• environmental issues, laws and regulations, and the cost of remediation and compliance associated therewith;

• nuclear regulations and operations associated with nuclear facilities;

• the higher price of oil and its impact on the amount of Section 29 tax credits, and the ability to utilize and/or sell interests in facilities producing such credits;

• implementation of electric and gas Customer Choice programs;

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

• employee relations and the impact of collective bargaining agreements;

• unplanned outages;

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

• the timing and extent of changes in interest rates;

• the level of borrowings;

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

• effects of competition;

• impacts of regulations by FERC, MPSC, NRC and other applicable governmental proceedings and regulations;

• contributions to earnings by non-regulated businesses;

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

• the ability to recover costs through rate increases;

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

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

• changes in accounting standards and financial reporting regulations;

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

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

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

DTE Energy Company

Management’s Discussion and Analysis

of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with approximately $7 billion in revenues in 2003, and approximately $21 billion in assets at December 31, 2003. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales and distribution services throughout southeastern Michigan. Additionally, we have numerous non-regulated subsidiaries involved in energy-related businesses predominantly in the Midwest and Eastern U.S.

A significant portion of our earnings is derived from utility operations and our synthetic fuel business, which qualifies for Section 29 tax credits. Earnings in the 2004 third quarter were $93 million, or $0.54 per diluted share, compared to earnings in the 2003 third quarter of $176 million, or $1.04 per diluted share. For the 2004 nine-month period, our earnings were $318 million, or $1.84 per diluted share, compared to earnings of $292 million, or $1.73 per diluted share for the same 2003 period.

As discussed in the “RESULTS OF OPERATIONS” section that follows, the comparability of earnings in the nine-month period was significantly impacted by discontinued businesses and the adoption of new accounting rules. Excluding discontinued operations and the cumulative effect of accounting changes, earnings from continuing operations in the 2004 nine-month period were $325 million, or $1.88 per diluted share, compared to earnings of $251 million, or $1.49 per diluted share for the same 2003 period. Income for both periods reflects reduced contributions from our regulated businesses and varying contributions from our non-regulated businesses and Corporate & Other. Significant items that influenced our 2004 financial performance and/or may affect future results are:

• Lost revenues from electric Customer Choice penetration;

• Proposed Michigan legislation to address electric Customer Choice issues;

• Interim electric and gas rate orders;

• Increased uncollectable utility accounts receivables;

• Synfuel-related earnings and the risk of higher oil prices;

• Gains and losses; and

• Effective tax rate adjustments.

Electric Customer Choice Program - Detroit Edison’s rates are regulated by the Michigan Public Service Commission (MPSC), while alternative suppliers can charge market-based rates. This regulation has hindered Detroit Edison’s ability to retain customers. In addition, the MPSC has maintained regulated rates for certain groups of customers that exceed the cost of service to those customers. This has resulted in high levels of participation in the electric Customer Choice program by those customers that have the highest price relative to their cost of service. As a result, we continue to lose margins. To address this issue, we expect to file a rate case in 2005 designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers.

Lost margins and electricity volumes associated with electric Customer Choice were approximately $63 million and 2,655 gigawatthours (gWh) in the 2004 third quarter and approximately $172 million and 7,277 gWh in the 2004 nine-month period. This compares with lost electric Customer Choice margins and volumes of approximately $35 million and 2,141 gWh in the 2003 third quarter and $80 million and 5,192 gWh in the 2003 nine-month period. The financial impact of electric Customer Choice was also affected by the issuance of the electric interim rate order that increased base rates, authorized transition charges and reaffirmed the resumption of the power supply cost recovery (PSCR) mechanism, as subsequently discussed. Partially offsetting the impact of lost margins on income, we recorded regulatory assets of approximately $24 million and $67 million in the 2004 third quarter and nine-month period, respectively, and $8 million and $20 million in the 2003 third quarter and nine-month

period. The regulatory assets represent an estimate of stranded costs that we believe are recoverable under existing Michigan legislation and MPSC orders. There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix, wholesale electric prices and transition charges. As a result, our estimate of stranded costs could increase or decrease. The actual amount of stranded costs to be recovered and the timing of recovery will ultimately be determined by the MPSC.

In February 2004, the MPSC authorized an interim electric rate increase that recognized a revenue deficiency for a portion of the lost electric Customer Choice revenues, and eliminated transition credits and implemented a transition charge for electric Customer Choice customers. Although the interim order, along with changes in wholesale market prices, has stabilized electric Customer Choice sales volumes, current regulation continues to hinder our ability to retain customers. In Detroit Edison’s June 2003 electric rate filing, we addressed numerous issues with the electric Customer Choice program, including stranded costs. The continued delay in addressing the structural problems of the electric Customer Choice program and the timely and full recovery of stranded costs, unfavorably impacts earnings and cash flow. See Note 5 for a further discussion of the electric Customer Choice program and the MPSC interim rate order.

Proposed Michigan Legislation - We are pursuing a legislative solution in addressing the structural issues associated with the electric Customer Choice program. On July 1, 2004, a package of six bills was introduced in the Michigan Senate to address unintended consequences of Public Act (PA) 141, Michigan legislation enacted in 2000 that began the restructuring of the electric utility industry in Michigan. We believe that this legislation would address a number of the most important issues in the Michigan electric sector. The proposed legislation:

• protects against rate shock by requiring electric utility rates to reflect a full cost of service for all electric customer classes over a 10-year period;

• allows current electric Customer Choice customers to return to utility service at regulated rates until December 31, 2005 and at market rates thereafter;

• requires mandatory reliability standards and sets a minimum annual 15 percent power reserve margin for all utilities and alternative energy suppliers;

• establishes a transition charge formula;

• establishes a low-income energy assistance surcharge to all customers receiving distribution service from an electric or gas utility;

• establishes a lower special rate for public and private K-12 schools;

• clarifies that environmental compliance costs can be securitized; and

• authorizes an environmental recovery surcharge applicable to all electric customers to recover the costs of government-mandated pollution control measures.

The Michigan Senate Technology and Energy Committee held hearings that began in August 2004 in an effort to build consensus among Michigan’s electric utilities, alternative energy suppliers, and customer groups. The committee is expected to convene in November 2004 and commence discussions regarding moving the legislative package to the Michigan Senate floor.

Electric Interim Rate Order - Under PA 141, electric rates for all residential, commercial and industrial customers were frozen through 2003. The legislation also capped rates for residential customers through 2005, and for small commercial and industrial customers through 2004. The rate freeze and caps apply to base rates and rates designed to recover fuel and purchased power costs. Historically, fuel and purchased power costs have been a pass-through under the PSCR mechanism.

In June 2003, Detroit Edison filed an application with the MPSC for: 1) an increase in retail electric rates of $427 million annually, 2) the resumption of the PSCR mechanism, and 3) the recovery of net stranded and other costs as permitted under Michigan legislation. Detroit Edison received an interim order in this rate case authorizing an increase in base rates of $248 million annually, effective February 21, 2004,

which is applicable to all customers not subject to the rate cap. The order also terminated certain transition credits and authorized transition charges to Choice customers designed to result in $30 million in additional revenues. Additionally, the interim order reaffirmed the resumption of the PSCR mechanism for both capped and uncapped customers, effective January 1, 2004, which is expected to reduce PSCR revenues by $126 million in 2004. However, the interim order allowed Detroit Edison to increase base rates for customers still subject to the cap in an equal and offsetting amount with the change in the PSCR factor to maintain the total capped rate levels in effect for these customers.

Although the base rate increase and transition charges total $278 million, the effects of the interim order are estimated to have increased income by $5 million, net of taxes, in the 2004 third quarter, and decreased income by $3 million, net of taxes, in the 2004 nine-month period. This lower amount is a result of the rate caps, the February 21, 2004 effective date of the interim base rate increase and the PSCR reduction effective January 1, 2004. Revenues from the interim rate order increased income $11 million, net of taxes, in the 2004 third quarter, and increased income $10 million, net of taxes, in the 2004 nine-month period. Revenues from the interim rate order also relate to items that were previously deferred as regulatory assets. The reduction in regulatory asset deferrals related to previously capped customers decreased income by $6 million, net of taxes, in the 2004 third quarter, and decreased income by $13 million, net of taxes, in the 2004 nine-month period. Amounts collected are subject to a potential refund pending a final order in this proceeding. A final order from the MPSC is expected in November 2004. See Note 5.

Gas Interim Rate Order - In September 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 requested an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. In September 2004, MichCon received an interim order in this rate case authorizing an increase in base rates of $35 million annually, effective September 22, 2004. The interim rate order increased revenues by approximately $0.2 million in the 2004 third quarter and nine-month period and is expected to increase revenues by approximately $10 million in the 2004 fourth quarter. MichCon expects a final order from the MPSC in the first quarter of 2005.

Uncollectable Utility Accounts Receivables - Both utilities continue to experience high levels of past due receivables, especially within our Energy Gas operations. The increase is attributable to economic conditions, high natural gas prices and the lack of adequate levels of assistance for low-income customers. As a result of these factors, our allowance for doubtful accounts expense for the two utilities increased to $83 million in the 2004 nine-month period compared to $47 million for the corresponding 2003 period. We are taking aggressive actions to reduce the level of past due receivables, including customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers. However, failure to make continued progress in collecting our past due receivables would unfavorably affect operating results.

In MichCon’s September 2003 gas rate filing, we addressed numerous operating cost issues, including uncollectable accounts receivables expense. The MPSC Staff supports a provision, proposed by MichCon, that would allow MichCon to recover or refund 90% of uncollectable accounts receivables expense above or below the amount that is reflected in base rates. We support the MPSC Staff’s recommendation and believe the provision would significantly reduce our risk of high uncollectable gas accounts receivables.

Synthetic Fuel Operations - We operate nine synthetic fuel production plants at eight locations. Since 2002, we have sold majority interests in seven of the nine plants, representing approximately 82 percent of the plants’ production capacity that we owned. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (IRS) rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuel produced from coal. Synfuel-related tax credits expire in December 2007.

Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. In order to recognize Section 29 tax credits, a taxpayer must have sufficient taxable income in the year the tax credit is generated. Once earned, the tax credits are utilized subject to certain limitations but can be carried forward indefinitely. We have not had sufficient taxable income to fully utilize tax credits earned in prior periods.

As of December 2003, we had nearly $500 million in tax credit carry-forwards. In order to optimize income and cash flow from our synfuel operations, we intend to sell majority interests in all of our remaining synfuel plants by the end of the first quarter of 2005, representing 99 percent of the plants’ production capacity that we owned. When we sell an interest in a synfuel project, we recognize the gain from such sale under the installment method of accounting. Gain recognition is dependent on the synfuel production qualifying for Section 29 tax credits and the amount of such credits as subsequently discussed. In substance, we are receiving installment gains and reduced operating losses in exchange for tax credits associated with the projects sold. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

The amount of a Section 29 tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS. Additionally, the amount of the tax credit in a given year is reduced if the “Reference Price” of oil within the year exceeds a threshold price and is eliminated entirely if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which in recent years has been $3-$4 lower than the New York Mercantile Exchange (NYMEX) price. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2003, 2004 and 2005 are as follows:


			Beginning Phase-Out		Ending Phase-Out
	Reference Price		Price			Price
2003 (actual)	$	27.56	$	50.14		$	62.94
2004 (estimated)	$	35.60	$	51.14		$	64.20
	(through 9/30/04)
2005 (estimated)	Not Available		$	52.17		$	65.48

Based on the estimated monthly average wellhead price per barrel of oil through September 2004, the average price of oil would have to exceed approximately $102 per barrel during the 2004 fourth quarter before 2004 credits begin to phase-out and the price of oil would have to exceed approximately $158 per barrel for such period to eliminate the credits. We cannot predict with any accuracy the future price of a barrel of oil, but believe it is highly unlikely that Section 29 tax credits for synthetic fuels produced in 2004 will be reduced.

Numerous recent events have increased domestic crude oil prices to record levels, including terrorism and storm-related supply disruptions. As of November 1, 2004, the NYMEX closing price of a barrel of oil to be delivered in December 2004 was $50.13, which is comparable to a $46.48 Reference Price (assuming that such price was to continue for an entire year). For 2005 and later years, if the Reference Price falls within or exceeds the phase-out range, the availability of tax credits in that year would be reduced or eliminated, respectively. We are continuing to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy. Assuming no synfuel tax credit phase out in future years, we expect cash from previously completed synfuel sales, coupled with completing remaining sales by the end of the first quarter of 2005, to produce approximately $300 million to $500 million of annual cash flow through 2008. See Note 9 for further discussion.

Earnings from our synfuel operations totaled $54 million and $150 million in the 2004 third quarter and nine-month period, respectively, compared to earnings of $26 million and $150 million in the same 2003 periods. Earnings were affected by increased gains in 2004 from selling interests in synfuel plants, as well as different synfuel production patterns in 2004 compared to the same period in 2003 as discussed in the “Energy Services” section that follows.

Gains and Losses — During the 2004 nine-month period, we recorded gains and losses associated with the following transactions.

• Transportation and gas exchange (storage) agreements — During the 2004 first quarter, we modified our future purchase commitments under a transportation agreement and terminated a related long-term gas exchange (storage) agreement with an interstate pipeline company. The agreements were at rates that were not reflective of current market conditions and had been fair-valued under U.S.

generally accepted accounting principles. The fair value net liability totaling approximately $75 million as of December 31, 2003, was being amortized to income through 2016, the life of the related agreements. As a result of the contract modification and termination, we recorded an adjustment to the net liability, increasing earnings in the 2004 first quarter by $48 million, net of taxes.

• Energy technology investments - As part of our energy technology strategy, we invest in a portfolio of energy technology companies that facilitate the creation of new businesses and expand growth opportunities for existing DTE Energy businesses. Since 1997 we have held an investment in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. During May 2004, we sold 3.5 million shares of the 14.1 million shares of Plug Power stock owned as part of our renewed focus on cost management and cash generation. The sale generated $27 million in cash and increased earnings in the 2004 second quarter by $14 million, net of taxes.

We also assessed the fair value of other technology investments in our portfolio. The assessment concluded there were “other than temporary” declines in fair value of the investments based on loan defaults and other factors. As a result of the assessment, we recorded an impairment expense in the 2004 second quarter that reduced earnings by $8 million, net of taxes.

• On-site energy project - Our Energy Services segment owns and/or operates numerous on-site facilities, including those that deliver utility services to industrial, commercial and institutional customers. During May 2004, we formed a utility services company that acquired utility-related assets from a large automotive company and entered into a long-term agreement to provide utility and energy conservation services to the company. In the 2004 second quarter, our income was increased by the recording of a $6 million after tax fee that was generated in conjunction with developing the energy project and selling a 50% interest in the project to an unaffiliated partner.

Effective Tax Rate Adjustments - Under U.S. generally accepted accounting principles, we are required to adjust our effective tax rate each quarter to be consistent with the estimated annual effective tax rate. The quarterly adjustment at the DTE Energy corporate segment had the effect of decreasing income tax expense by $24 million and $14 million in the 2004 third quarter and nine-month period, respectively. This compares with the 2003 quarterly adjustments which decreased income tax expense by $82 million in the 2003 third quarter and increased income tax expense by $70 million in the 2003 nine-month period. Fluctuations in estimated annual earnings and Section 29 tax credits were the primary variables that resulted in the year-over-year variations. Annual results are not affected by the quarterly effective tax rate adjustments.

Outlook - We are facing many challenges to achieve earnings and cash flow objectives while protecting a strong balance sheet. Our financial performance will be dependent on preserving healthy electric and gas utilities, minimizing our risk to high oil prices on synfuel earnings and cash flows, selling majority interests in the remaining synfuel projects and continuing to grow our non-regulated businesses in a prudent manner.

Remedying the structural issues of the electric Customer Choice program in Michigan is a key priority for the Company. These issues must be corrected to prevent the further migration of customers to the electric Customer Choice program based on false market signals. The potential implications of the electric Customer Choice program to remaining customers over the longer term could be significantly higher electricity rates.

The timing and ultimate amount of final rate relief granted in the current electric and gas rate cases will affect our financial performance and customer service levels. Cash flow and earnings from our utilities will remain under pressure until adequate rate relief is granted. In the interim, we remain focused on good cash management and a healthy balance sheet.

We are pursuing the sale of majority interests in all of our remaining synthetic fuel projects in 2004 and early 2005. Assuming no synfuel tax credit phase out, these sales, in addition to previously completed sales, are expected to provide approximately $300 million to $500 million of annual cash flow through 2008. In addition, we are continuing development activities intended to grow our non-regulated businesses in areas such as waste coal recovery, on-site energy project development, unconventional gas recovery and gas midstream projects. Due to the regulatory uncertainties over the short term, we remain disciplined and conservative in our pursuit of incremental growth investments.

RESULTS OF OPERATIONS

Our earnings in the 2004 third quarter were $93 million, or $0.54 per diluted share, compared to earnings in the 2003 third quarter of $176 million, or $1.04 per diluted share. For the 2004 nine-month period, our earnings were $318 million, or $1.84 per diluted share, compared to earnings of $292 million, or $1.73 per diluted share, for the same 2003 period. As subsequently discussed, the comparability of earnings was impacted by our two discontinued businesses, International Transmission Company and Southern Missouri Gas Company, and the adoption of two new accounting rules in the 2003 first quarter. Excluding discontinued operations and the cumulative effect of accounting changes, our earnings from continuing operations in the 2004 third quarter were $93 million, or $0.54 per diluted share, compared to income in the 2003 third quarter of $180 million, or $1.06 per diluted share. For the 2004 nine-month period, our earnings from continuing operations were $325 million, or $1.88 per diluted share, compared to earnings of $251 million, or $1.49 per diluted share, for the same 2003 period. Earnings were also affected by lost margins under the Customer Choice program, interim electric and gas rate orders, increased uncollectable accounts receivables, varying synfuel production, gains and losses, and effective tax rate adjustments. The following sections provide a detailed discussion of our segments, operating performance and future outlook.

Segment Performance & Outlook - We operate our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit has regulated and non-regulated operations. The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. This results in the following reportable segments.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Net Income (Loss)
Energy Resources
Regulated — Power Generation	$	34		$	61		$	51		$	132

Non-regulated
Energy Services		51			23			145			151
Energy Marketing & Trading		12			23			62			52
Other		1			(1	)		(1	)		(1	)

Total Non-regulated		64			45			206			202

		98			106			257			334

Energy Distribution
Regulated — Power Distribution		28			35			63			15
Non-regulated		(4	)		(3	)		(15	)		(12	)

		24			32			48			3

Energy Gas
Regulated — Gas Distribution		(55	)		(45	)		(22	)		5
Non-regulated		5			12			14			26

		(50	)		(33	)		(8	)		31

Corporate & Other		21			75			28			(117	)

Income (Loss) from Continuing Operations
Regulated		7			51			92			152
Non-regulated		65			54			205			216
Corporate & Other		21			75			28			(117	)

		93			180			325			251

Discontinued Operations		—			(4	)		(7	)		68
Cumulative Effect of Accounting Changes		—			—			—			(27	)

Net Income	$	93		$	176		$	318		$	292

Diluted Earnings (Loss) per Share
Regulated	$	.04		$	.30		$	.53		$	.91
Non-regulated		.37			.32			1.18			1.28
Corporate & Other		.13			.44			.17			(.70	)

Income from Continuing Operations		.54			1.06			1.88			1.49
Discontinued Operations		—			(.02	)		(.04	)		.40
Cumulative Effect of Accounting Changes		—			—			—			(.16	)

Net Income	$	.54		$	1.04		$	1.84		$	1.73

ENERGY RESOURCES

Power Generation - Regulated

The power generation plants of Detroit Edison comprise our regulated power generation business. Detroit Edison’s numerous fossil plants, its hydroelectric pumped storage plant and its nuclear plant generate

electricity. The generated electricity, supplemented with purchased power, is sold principally throughout Michigan and the Midwest to residential, commercial, industrial and wholesale customers.

Factors impacting income: Power Generation earnings declined $27 million during the 2004 third quarter and $81 million in the 2004 nine-month period. As subsequently discussed, these results primarily reflect reduced gross margins, partially offset by the recording of higher regulatory assets, which affected depreciation and amortization expenses. Increased operation and maintenance expenses and costs associated with the August 2003 blackout also affected the comparison (Note 5).


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Operating Revenues	$	587		$	669		$	1,646		$	1,874
Fuel and Purchased Power		234			284			643			749

Gross Margin		353			385			1,003			1,125
Operation and Maintenance		159			147			506			487
Depreciation and Amortization		66			65			177			199
Taxes Other Than Income		38			40			114			121

Operating Income		90			133			206			318
Other (Income) and Deductions		38			39			129			115
Income Tax Provision		18			33			26			71

Net Income	$	34		$	61		$	51		$	132

Operating Income as a Percent of Operating Revenues		15	%		20	%		13	%		17	%

Gross margins declined $32 million during the 2004 third quarter and $122 million in the 2004 nine-month period due primarily to lost margins from retail customers choosing to purchase power from alternative suppliers under the electric Customer Choice program. As a result of electric Customer Choice penetration, Detroit Edison lost 18% of retail sales in the first nine months of 2004, compared to 13% of such sales during the same 2003 period. The decline in margins in the current nine-month period is also due to a revision of estimate in the level of sales lost to electric Customer Choice in the 2004 second quarter. Sales lost under the electric Customer Choice program are estimated each month and are finalized in subsequent months when actual data is available. Variances between estimated and actual lost electric Customer Choice sales directly impact the accrual of unbilled sales to full service customers. Electric Customer Choice sales adjustments in the 2004 second quarter had the effect of increasing Customer Choice-related lost sales, thereby reducing unbilled sales by $19 million. The adjustment also reduced sales within Energy Distribution’s Power Distribution — Regulated segment.

The loss of retail sales under the electric Customer Choice program also resulted in lower purchase power requirements, as well as excess power capacity that was sold in the wholesale market. Under the interim order previously discussed, revenues from selling excess power reduce the level of recoverable fuel and purchased power costs and therefore do not impact margins. The interim rate order also lowered PSCR revenues which were more than offset by increased base rate and transition charge revenues, resulting in an increase in margins in the 2004 third quarter and nine-month period (Note 5). Weather during 2004 was milder than in 2003, resulting in decreased margins from retail customers. Operating revenues and fuel and purchased power costs decreased in 2004 compared to 2003 reflecting a $2.79 per megawatt hour (MWh) (15%) decline in fuel and purchased power costs during the current quarter and a $2.41 per MWh (14%) decline during the nine-month period. Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR, and therefore do not affect margins or earnings. The decrease in fuel and purchased power costs is attributable to lower priced purchases and the use of a more favorable power supply mix. The favorable mix is due to lower purchases, driven by lost sales under the electric Customer Choice program. The 2003 third quarter and nine-month period includes higher costs associated with

substitute power purchased to meet customer demand during the August 2003 blackout. We were required to purchase additional power during the 36-day period it took for our generation fleet to return to pre-blackout capacity.


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2004		2003		2004		2003
Electric Sales
(in Thousands of MWh)
Retail		10,623		11,762		30,480		33,364
Wholesale and Other		1,974		1,603		5,738		4,049

		12,597		13,365		36,218		37,413

Power Generated and Purchased
(in Thousands of MWh)
Power Plant Generation
Fossil		10,407		10,308		28,698		28,649
Nuclear		2,043		2,096		6,860		5,645

		12,450		12,404		35,558		34,294
Purchased Power		1,209		1,868		3,633		5,599

System Output		13,659		14,272		39,191		39,893

Average Unit Cost ($/MWh)
Generation (1)	$	13.33	$	13.21	$	12.98	$	13.34

Purchased Power (2)	$	42.77	$	55.38	$	37.12	$	43.79

Overall Average Unit Cost	$	15.94	$	18.73	$	15.21	$	17.62

(1)		Represents fuel costs associated with power plants.

(2)		The average purchased power amounts include hedging activities.

Operation and maintenance expense increased $12 million in the 2004 third quarter and $19 million in the 2004 nine-month period. The increases reflect costs associated with maintaining our generation fleet and higher allocations for corporate support services. Additionally, the increases are due to costs associated with our DTE2 implementation project, a company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management.

Depreciation and amortization expense increased $1 million and decreased $22 million in the 2004 third quarter and nine-month period, respectively. Depreciation and amortization expense was affected by increased charges resulting from generation-related capital expenditures. Depreciation and amortization expense was reduced by the income effect of recording regulatory assets totaling $29 million and $86 million in the 2004 third quarter and nine-month period, respectively, compared to $27 million and $67 million in the same 2003 periods. The regulatory assets represent the deferral of net stranded costs and other costs we believe are recoverable under Public Act 141.

Other income and deductions expense increased $14 million in the 2004 nine-month period, primarily due to lower income associated with recording a return on regulatory assets, as well as costs associated with addressing the structural issues of Public Act 141.

Outlook - Future operating results are expected to vary as a result of external factors such as regulatory proceedings, new legislation, changes in market prices of power, coal and gas, plant performance, changes in economic conditions, weather and the levels of customer participation in the electric Customer Choice program.

As previously discussed, we expect cash flows and operating performance will continue to be adversely affected by the electric Customer Choice program until the inequities associated with this program are addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We have addressed the issue of stranded costs in our June 2003 electric rate filing and are also supporting the proposed legislative solution. Additionally, we requested an increase in retail electric rates to recover higher operating costs. The actual timing and level of recovering stranded and operating costs will ultimately be determined by the MPSC or legislation. We cannot predict the outcome of these matters. See Note 5 — Regulatory Matters.

Energy Services

Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and non-regulated Power Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke batteries. The production of synthetic fuel from all of our synfuel plants and the production of coke from one of our coke batteries generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Power Generation owns and operates four gas-fired peaking electric generating plants, and manages and operates two additional gas-fired power plants under contract. Additionally, Power Generation develops, operates and potentially acquires coal and gas-fired generation.

Factors impacting income: Energy Services earnings increased $28 million in the 2004 third quarter and decreased $6 million during the 2004 nine-month period. Earnings in both periods include higher gains recognized from selling majority interests in our synfuel plants as previously discussed. The earnings decline in the 2004 nine-month period was due to a $19 million after tax gain in the 2003 second quarter from terminating a tolling agreement at one of our non-regulated power generation facilities. Partially offsetting the nine-month period decline was a $6 million after tax fee recorded in the 2004 second quarter. The fee was generated in conjunction with developing an energy project and selling a 50% interest in the project to an unaffiliated partner. Synfuel earnings in both 2004 periods have also been affected by our decision to reduce production levels as a result of our strategy of producing synfuel primarily from plants in which we have sold interests.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Operating Revenues
Coal-Based Fuels	$	254		$	212		$	719		$	639
On-Site Energy Projects		23			14			71			51
Power Generation-Non-Regulated		6			3			10			6

		283			229			800			696
Operation and Maintenance		304			242			846			792
Gains on Sale of Interests in Synfuel Projects		(58	)		(18	)		(164	)		(51	)
Depreciation and Amortization		27			11			68			64
Taxes Other Than Income		6			1			12			12

Operating Income (Loss)		4			(7	)		38			(121	)
Other (Income) and Deductions		(72	)		(21	)		(158	)		(69	)
Income Taxes
Provision (Benefit)		32			5			74			(19	)
Section 29 Tax Credits		(7	)		(14	)		(23	)		(184	)

		25			(9	)		51			(203	)

Net Income	$	51		$	23		$	145		$	151

Operating revenues increased $54 million in the 2004 third quarter and $104 million in the 2004 nine-month period primarily reflecting higher synfuel, coal and coke sales, as well as increased revenues from our on-site energy projects.

The improvement in synfuel revenues in 2004 results from increased production due to additional sales of project interests. The synfuel revenues in 2003 reflect our strategy to produce only at sold projects. As discussed in our 2003 Annual Report on Form 10-K, our sales were delayed in May 2003 when the IRS announced it had reason to question the scientific validity of test procedures and results that had been presented in the industry as evidence that synfuel projects had met chemical change requirements, which are the basis for earning Section 29 tax credits. In October 2003, the IRS announced it had concluded its assessment and determined that test procedures and results used by taxpayers are scientifically valid if the procedures are applied in a consistent and unbiased manner. We believe our synfuel facilities meet these IRS requirements.

Synfuel and coal revenues in both 2004 periods have also been affected by our strategy to produce synfuel primarily from plants in which we have sold interests in order to optimize earnings and cash flow. This strategy has resulted in the curtailment of synfuel production levels. We were contractually obligated to supply coal to customers at certain sites that did not produce synfuel as a result of our current production strategy. To meet our obligations to provide coal under long-term contracts with customers, we acquired coal that was resold to customers. The coal was sold at prices higher than the prices at which synfuel would have been sold to these customers.

Revenues from coke sales were higher in both 2004 periods due to higher coke sales volumes combined with higher market prices due to limited supplies of coke in the U.S.

Revenues from on-site energy projects increased in both 2004 periods reflecting the completion in the 2004 second quarter of new long-term utility services contracts with a large automotive company and a large manufacturer of paper products. As previously discussed, revenues in the 2004 nine-month period

also includes a $9 million pre-tax fee generated in conjunction with the development of a related energy project, 50% of which was sold to an unaffiliated partner.

Operation and maintenance expense increased $62 million in the 2004 third quarter and $54 million in the 2004 nine-month period reflecting costs associated with synfuel production and coal operations. Partially offsetting the higher synfuel operating costs was the recording of insurance proceeds associated with a December 2001 accident at one of our coke batteries. Operation and maintenance expense in the 2003 nine-month period was affected by a $30 million pre-tax gain from the termination of a tolling agreement at one of our generation facilities, substantially offset by the establishment of a $28 million pre-tax reserve for receivables associated with a large customer that filed for bankruptcy.

Gains on sale of interests in synfuel projects increased $40 million in the 2004 third quarter and $113 million in the 2004 nine-month period. The improvements are due to the sale of interests in our synfuel projects. We recognize the gain from such sales under the installment method of accounting as qualifying synfuel is produced and sold.

Other income and deductions increased $51 million in the 2004 third quarter and $89 million in the 2004 nine-month period reflecting our minority partners’ share of operating losses associated with synfuel operations. Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. The sale of interests in our synfuel facilities during 2003 and 2004 resulted in allocating a larger percentage of such losses to our minority partners.

Income taxes increased $34 million in the 2004 third quarter and $254 million in the 2004 nine-month period, reflecting higher taxable earnings and a decline in the level of Section 29 tax credits. Tax credits from our synfuel operations decreased due to the sale of interests in synfuel facilities. The level of tax credits has been adjusted at Corporate & Other in order that the DTE Energy consolidated income tax expense during each quarter reflects the estimated calendar year effective rate.

Outlook - A significant portion of Energy Services’ earnings is derived from gains on sales of interests in synfuel projects and Section 29 tax credits. Synfuel-related tax credits expire in December 2007. We are selling interests in all of our synfuel plants and have sold majority interests in seven of our nine synfuel plants, representing approximately 82 percent of the plants’ production capacity that we owned. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

The sale of further interests in our synfuel projects continues to progress and interest remains high. However, two recent events within the industry may slow future sales and/or impact earnings. The first event relates to announcements by several unaffiliated companies that the IRS was challenging the in-service dates of some of their synthetic fuel facilities. Synfuel facilities must have been placed in service before July 1, 1998 to qualify for Section 29 tax credits. The in-service dates of our facilities have not been challenged, and we believe all nine of our synfuel plants meet the required in-service date. The second event is associated with the increase in domestic crude oil prices to record levels. As previously discussed, the amount of a Section 29 tax credit in a given year is reduced if the Reference Price of oil within the year exceeds a threshold price. See Note 9 for further discussion.

Energy Services will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We continue to explore growth opportunities that will not require significant initial capital investment. We expect an increase in income from our on-site energy business in 2005 as a result of executing long-term utility services contracts in 2004.

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 the optimization of DTE Energy’s owned and contracted natural gas pipelines and gas storage capacity. To this end, both companies enter into derivative financial instruments as part of their marketing and hedging strategies, including forwards, futures, swaps and option contracts. Most of the derivative financial instruments are accounted for under the mark-to-market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives.

Factors impacting income: Energy Marketing & Trading’s earnings decreased $11 million in the 2004 third quarter, consisting of a $12 million improvement at DTE Energy Trading and a $23 million decline at CoEnergy. Earnings in the 2004 nine-month period increased $10 million, consisting of a $3 million reduction at DTE Energy Trading and a $13 million improvement at CoEnergy.

DTE Energy Trading’s earnings in the 2004 third quarter and nine-month period varied from the comparable 2003 periods primarily due to realized and unrealized margins associated with short-term physical trading and origination activities.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
DTE Energy Trading
Margins — Gains (Losses)
Realized (1)	$	32		$	24		$	62		$	72

Unrealized (2):
Proprietary Trading (3)		(1	)		(5	)		(4	)		(10	)
Structured Contracts (4)		4			—			(1	)		3
Economic Hedges (5)		3			(2	)		4			—

Total Unrealized Margins		6			(7	)		(1	)		(7	)

Total Margins		38			17			61			65

Operating and Other Costs		8			5			22			21
Income Tax Provision		11			5			14			16

Net Income	$	19		$	7		$	25		$	28

CoEnergy
Margins — Gains (Losses) (6)
Realized (1)	$	8		$	4		$	(9	)	$	33

Unrealized (2):
Proprietary Trading (3)		4			2			(1	)		3
Structured Contracts (4)		14			2			14			(4	)
Economic Hedges (5)		(36	)		20			(14	)		15

Total Unrealized Margins		(18	)		24			(1	)		14

Total Margins		(10	)		28			(10	)		47

Gain From Contract Modification / Termination		—			—			74			—
Operating and Other Costs		1			4			7			10
Income Tax Provision (Benefit)		(4	)		8			20			13

Net Income (Loss)	$	(7	)	$	16		$	37		$	24

Total Energy Marketing & Trading Net Income	$	12		$	23		$	62		$	52

(1)		Realized margins include the settlement of all derivative and non-derivative contracts, as well as the amortization of deferred assets and liabilities.

(2)		Unrealized margins include mark-to-market gains and losses on derivative contracts, net of gains and losses reclassified to realized. See “Fair Value of Contracts” section that follows.

(3)		“Proprietary Trading” represents the net unrealized effect of actively traded positions entered into to take advantage of market price movements.

(4)		“Structured Contracts” represent the net unrealized effect of derivative transactions entered into with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and alternative energy suppliers.

(5)		“Economic Hedges” represent the net unrealized effect of derivative activity associated with assets owned or contracted for by DTE Energy, including forward sales of gas production and trades associated with transportation and storage capacity.

(6)		Excludes the impact on margins from the modification of a transportation agreement with an interstate pipeline company (Note 4).

CoEnergy’s earnings in the 2004 third quarter and nine-month period were affected by higher unrealized losses on economic hedge contracts related to storage assets. As subsequently discussed in the “Outlook” section, the unrealized losses of economic hedge contracts are required to be recognized under mark-to-market accounting, while the offsetting unrealized gains on the underlying asset positions are not recognized.

CoEnergy’s earnings in the 2004 nine-month period reflect a one-time gain from modifying a future purchase commitment under a transportation agreement and terminating a related long-term gas exchange (storage) agreement with an interstate pipeline company (Note 4). Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season.

The realized and unrealized margins comparison for both DTE Energy Trading and CoEnergy was affected by our decision in late 2003 to monetize certain in-the-money derivative contracts while simultaneously entering into replacement at-the-market contracts. The monetizations were completed in conjunction with implementing a series of initiatives to improve cash flow and fully utilize Section 29 tax credits. Although the monetizations did not impact earnings, they had the effect of decreasing realized margins and increasing unrealized margins on economic hedges in the third quarter and nine-month period comparisons.

Outlook - Energy Marketing & Trading will seek to manage 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 add value.

Significant portions of the Energy Marketing & Trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as owned and contracted natural gas pipelines and storage assets. The 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. The majority of such earnings volatility is associated with the natural gas storage cycle, which runs annually from April of one year to March of the next year. Our strategy is to economically hedge the price risk of all gas purchases for storage with sales in the over-the-counter (forwards) and futures markets. Current accounting rules require the marking to market of forward sales and futures, but do not allow for the marking to market of the related gas inventory. This results in gains and losses that are recognized in different interim accounting periods. We anticipate the financial impact of this timing difference will reverse by the end of each storage cycle. See “Fair Value of Contracts” section that follows.

Non-regulated — Other

Our other non-regulated businesses include the Coal Services and Biomass units. Coal Services provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. Coal Services has formed a subsidiary, DTE PepTec Inc., which uses proprietary technology to produce high quality coal products from fine coal slurries typically discarded from coal mining operations. Biomass develops, owns and operates landfill recovery systems in the U.S. Gas produced from many of these landfill sites qualifies for Section 29 tax credits.

Factors impacting income: Earnings increased $2 million in the 2004 third quarter reflecting higher sales from coal and emissions credits, partially offset by increased costs associated with our waste coal operations.

Outlook - We expect to continue to grow our Coal Services and Biomass units. We believe a substantial market exists for the use of DTE PepTec Inc. technology and continue to work to modify and prove out this technology.

The Section 29 tax credits generated by Biomass are subject to the same phase out risk if domestic crude oil prices reach certain levels as detailed in the synthetic fuel operations discussion. See Note 9.

ENERGY DISTRIBUTION

Power Distribution — Regulated

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

Factors impacting income: Power Distribution earnings decreased $7 million in the 2004 third quarter and increased $48 million in the 2004 nine-month period. As subsequently discussed, these results primarily reflect an increase in operating revenues, a non-recurring loss recorded in the 2003 first quarter and higher operation and maintenance expenses.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Operating Revenues	$	371		$	348		$	1,033		$	950
Fuel and Purchased Power		4			4			10			13
Operation and Maintenance		202			169			558			538
Depreciation and Amortization		62			62			187			187
Taxes Other Than Income		25			27			78			83

Operating Income		78			86			200			129
Other (Income) and Deductions		36			33			104			107
Income Tax Provision (Benefit)		14			18			33			7

Net Income (Loss)	$	28		$	35		$	63		$	15

Operating Income as a Percent of Operating Revenues		21	%		25	%		19	%		14	%

Three Months Ended

Nine Months Ended

September 30

2004

2003

2004

2003

Electric Deliveries

(in Thousands of MWh)

Residential

4,114

4,457

11,655

11,555

Commercial

3,557

4,162

10,097

12,251

Industrial

2,854

3,044

8,418

9,264

Wholesale

531

556

1,640

1,682

Other

310

294

11,154

12,316

32,120

35,046

Electric Choice

2,655

2,141

7,277

5,192

Total Electric Sales and Deliveries

13,809

14,457

39,397

40,238

Operating revenues increased $23 million in the 2004 third quarter and $83 million in the 2004 nine-month period primarily due to the increase in base rates resulting from the interim order and residential sales growth, partially offset by the effects of milder weather. Additionally, the nine-month period comparison was affected by a revision of estimated unbilled sales in the 2004 second quarter, which reduced revenues by $6 million. As previously discussed, the revision also reduced sales within Energy Resources’ Power Generation - Regulated segment.

Operation and maintenance expense increased $33 million in the 2004 third quarter and $20 million in the 2004 nine-month period. Both 2004 periods were affected by higher reserves for uncollectable

accounts receivables, reflecting higher past due amounts attributable to economic conditions. Additionally, the increases are due to higher transmission expenses, resulting from a refund in the 2003 third quarter, as well as costs associated with our DTE2 implementation project. The comparison for the nine-month period was also affected by a $22 million loss ($14 million net of tax) on the sale of our steam heating business in the 2003 first quarter.

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. As previously mentioned, Detroit Edison filed a rate case in June 2003 to address higher operating costs and other issues. Detroit Edison received an interim order in this rate case in February 2004. See Note 5 - Regulatory Matters.

In conjunction with the sale of transmission assets to International Transmission Company (ITC) in February 2003, the Federal Energy Regulatory Commission froze ITC’s transmission rates through December 2004. It is expected that annual rate adjustments pursuant to a formulistic pricing mechanism beginning in January 2005 will result in an estimated increase in Detroit Edison’s annual transmission expense of $40 million. Additionally, several Midwest utilities seek to recover lost transmission revenues associated with the creation of multiple regional transmission organizations in the Midwest. This Federal Energy Regulatory Commission proceeding could require that Detroit Edison and its customers be responsible for increased transmission costs of up to $30 million annually. Included in the electric rate case filing and 2005 PSCR plan case, Detroit Edison has proposed transmission expenses, above the level established in base rates, be recoverable through the PSCR mechanism. See Note 5.

Non-regulated

Non-regulated Energy Distribution operations include DTE Energy Technologies, which markets and distributes distributed generation products, provides application engineering, and monitors and manages generation system operations.

Factors impacting income: Non-regulated results declined $1 million in the 2004 third quarter and $3 million in the 2004 nine-month period. The nine-month period includes an impairment charge for an “other than temporary” decline in the fair value of a technology investment, as previously discussed.

Outlook - DTE Energy Technologies has tightened its focus on sales of proprietary pre-engineered and packaged continuous generation products in key applications. This will likely result in near-term revenue decline, but we anticipate gross profit margins will improve. Combined with continuing cost reductions and resumption of sales growth, we believe these actions will lead to improved profit performance in 2005.

ENERGY GAS

Gas Distribution — Regulated

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

Factors impacting income: Gas Distribution’s earnings declined $10 million in the 2004 third quarter and $27 million in the 2004 nine-month period. Due to the seasonal nature of the gas distribution business, it is not unusual to experience losses in the third quarter of each year. As subsequently discussed, results primarily reflect improved gross margins, varying operation and maintenance expenses, a non-recurring loss recorded in the 2003 first quarter, and unfavorable effective tax rate adjustments.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Operating Revenues	$	160		$	146		$	1,165		$	1,074
Cost of Gas		68			58			730			651

Gross Margin		92			88			435			423
Operation and Maintenance		94			98			304			265
Depreciation and Amortization		26			26			77			76
Taxes Other Than Income		13			11			38			42

Operating Income (Loss)		(41	)		(47	)		16			40
Other (Income) and Deductions		13			10			37			33
Income Tax Provision (Benefit)		1			(12	)		1			2

Net Income (Loss)	$	(55	)	$	(45	)	$	(22	)	$	5

Operating Income (Loss) as a Percent of Operating Revenues		(26	)%		(32	)%		1	%		4	%

Gross margins increased $4 million in the 2004 third quarter and $12 million in the 2004 nine-month period. The gross margins improvement in the 2004 third quarter reflects increased revenues from providing appliance maintenance services and other energy-related services. The gross margins comparison for the nine-month period was affected by a $26.5 million pre-tax reserve recorded in the 2003 first quarter for the potential disallowance in gas costs pursuant to an MPSC order in MichCon’s 2002 gas cost recovery (GCR) plan case (Note 5). Both 2004 periods also reflect lower sales due to milder weather. Operating revenues and cost of gas in both 2004 periods increased significantly compared to the same 2003 period reflecting higher gas prices, which are recoverable from customers through the GCR mechanism.

Operation and maintenance expense decreased $4 million in the 2004 third quarter and increased $39 million in the 2004 nine-month period. The third quarter comparison reflects higher costs in the 2003 periods associated with customer service process improvements, as well as an impairment loss on the sale of MichCon’s former headquarters. Partially offsetting the 2004 third quarter decrease, and driving the 2004 nine-month period increase, were higher reserves for uncollectable accounts receivable, increased pension and postretirement costs and higher injuries and damages accruals. The increase in uncollectable accounts expense reflects higher past due amounts attributable to an increase in gas prices, continued weak economic conditions and a lack of adequate assistance for low-income customers.

Income taxes in both 2004 periods were unfavorably affected by a lower effective tax rate in 2004 as compared to 2003, which was driven by lower estimated annual earnings.

Outlook - Operating results are expected to vary as a result of external factors such as regulatory proceedings, weather and changes in economic conditions. Higher gas prices and economic conditions 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 past due receivables would unfavorably affect operating results. Energy assistance programs funded by the federal government and the State of Michigan remain critical to MichCon’s ability to control uncollectable accounts receivable expenses. We are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory.

As a result of the continued increase in operating costs, MichCon filed a rate case in September 2003 to increase rates by $194 million annually to address future operating costs and other issues. MichCon received an interim order in this rate case in September 2004. See Note 5 — Regulatory Matters.

Non-regulated

Non-regulated operations include the Gas Production business and the Gas Storage, Pipelines & Processing business. Our Gas Production business produces gas from proven reserves in northern Michigan and sells the gas to the Energy Marketing & Trading segment. Gas Storage, 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 lease rights to another natural gas storage field. The assets of these businesses are integrated with other DTE Energy entities.

Factors impacting income: Earnings decreased $7 million in the 2004 third quarter and $12 million in the 2004 nine-month period. The decline in both periods is due to gains recorded in the 2003 periods from selling our 16% pipeline interest in the Portland Natural Gas Transmission System, as well as from selling certain gas properties. Partially offsetting the declines were increased earnings from our interest in Vector Pipeline, as a result of an additional 15% ownership acquired in late 2003, as well as increased storage sales.

Outlook - We expect to continue developing our gas production properties in northern Michigan and our pipelines and storage assets to further enhance other DTE Energy businesses. Additionally, we expect to leverage our experience in these areas by continuing to invest in opportunities in unconventional gas production outside of Michigan.

CORPORATE & OTHER

Corporate & Other includes the administrative and general expenses of various corporate support functions such as accounting, legal and information technology. As these functions essentially support the entire company, they are fully allocated to the various segments based on services utilized, and therefore the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-regulated debt and investments, including assets held for sale and in emerging energy technologies.

Factors impacting income: Corporate & Other’s results decreased $54 million in the 2004 third quarter and improved $145 million in the 2004 nine-month period. Results reflect adjustments in both years to normalize the effective income tax rate. There were favorable adjustments of $24 million and $14 million in the 2004 third quarter and nine-month period, respectively, compared to a favorable adjustment of $82 million and an unfavorable adjustment of $70 million in the corresponding 2003 periods. The income tax provisions of the segments are determined on a stand-alone basis. Corporate & Other records necessary adjustments in order that the consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. The 2004 nine-month period was also affected by a $14 million net of tax gain from the sale of 3.5 million shares of Plug Power stock (Note 1), as previously discussed, as well as lower Michigan Single Business Taxes resulting from tax saving initiatives. The 2003 nine-month period earnings include a $15 million cash contribution to the DTE Energy Foundation, funded with proceeds received from the sale of ITC (Note 3). Corporate & Other also benefited from lower financing costs in both 2004 periods.

DISCONTINUED OPERATIONS

Southern Missouri Gas Company (SMGC) - We own SMGC, a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. Under U.S. generally accepted accounting principles, we classified SMGC as a discontinued operation in the 2004 first quarter and recognized a net of tax

impairment loss of approximately $7 million representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill.

International Transmission Company - In February 2003, we sold ITC, our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Accordingly, we classified ITC as a discontinued operation. The sale generated a preliminary net of tax gain in the 2003 first quarter of $69 million. The gain was adjusted during the 2003 second quarter to $67 million, and further adjusted to $63 million in the 2003 third quarter, net of transaction costs and the portion of the gain that was refundable to customers. We had income from discontinued operations of $5 million in the first quarter of 2003.

See Note 3 for further discussion.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

As required by U.S. generally accepted accounting principles, on January 1, 2003, we adopted new accounting rules for asset retirement obligations and energy trading activities. The cumulative effect of adopting these new accounting rules reduced 2003 first quarter earnings by $27 million. See Note 2 for further discussion.

CAPITAL RESOURCES AND LIQUIDITY


	Nine Months Ended
	September 30
	2004			2003
(in Millions)
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	318		$	292
Depreciation, depletion and amortization		536			551
Deferred income taxes		104			(55	)
Gain on sale of ITC, synfuel and other assets, net.		(193	)		(187	)
Working capital and other		(175	)		(315	)

		590			286

Investing activities:
Plant and equipment expenditures — regulated		(555	)		(504	)
Plant and equipment expenditures — non-regulated		(52	)		(58	)
Investment in joint ventures		(36	)		(5	)
Proceeds from sale of ITC, synfuel and other assets		213			710
Restricted cash and other investments		(4	)		76

		(434	)		219

Financing activities:
Issuance of long-term debt and common stock		648			562
Redemption of long-term debt		(620	)		(897	)
Short-term borrowings, net		106			55
Dividends on common stock and other		(270	)		(268	)

		(136	)		(548	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	20		$	(43	)

Operating Activities

We use cash derived from operating activities to maintain and expand our electric and gas utilities and to grow our non-regulated businesses. In addition, we use cash from operations to retire long-term debt and pay dividends. Currently, a majority of the company’s operating cash flow is provided by the two regulated utilities, which are significantly influenced by factors such as weather, electric Customer Choice sales loss, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. Our non-regulated businesses also provide sources of cash flow to the enterprise and reflect a range of operating profiles. The profiles vary from our synthetic fuel business, which we believe will provide substantial cash flow through 2008 to new start-ups. These new start-ups include our unconventional gas or waste coal recovery businesses, which are growing and will require modest investments beyond their cash generation capabilities.

Although DTE Energy’s overall earnings were up $26 million in the 2004 nine-month period, cash from operations totaling $590 million was up $304 million from the comparable 2003 period. The operating cash flow comparison reflects an increase of $164 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), and a $140 million improvement in working capital and other requirements. A portion of this improvement is attributable to the change in our strategy to primarily produce synfuel from plants in which we have sold interests. As previously discussed, synfuel projects generate operating losses, which have been more than offset by tax credits that we have been unable to fully utilize, thereby negatively affecting operating cash flow. Cash from working capital reflects improvements in accounts receivables and accounts payables. The working capital comparison was also affected by a $222 million cash contribution to our pension plan in the 2003 first

quarter. Partially offsetting these improvements were higher income tax payments of $175 million in 2004, reflecting a different payment pattern of taxes in 2004 compared to 2003.

Outlook - We expect cash flow from operations to increase over the long-term, but to remain relatively the same for the full year 2004 as 2003. Cash flow improvements from partial year utility rate increases and the sale of interests in our synfuel projects will be partially offset by higher cash requirements, primarily within our gas storage business. We are continuing our efforts that began in 2003 to identify opportunities to improve cash flow through a cash improvement initiative.

Investing Activities

Cash inflows associated with investing activities are primarily generated from the sale of assets. In any given year, we will look to harvest cash from under-performing or non-strategic assets. Capital spending within the utility business is primarily to maintain our generation and distribution infrastructure and comply with environmental regulations. Capital spending within our non-regulated businesses is for ongoing maintenance and expansion.

Net cash relating to investing activities declined $653 million in the 2004 nine-month period, compared to the same 2003 period, primarily due to the sale of ITC in February 2003 and cash contractually designated for debt service.

Outlook - Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2004 of approximately $1 billion. Our utilities plan to spend higher amounts of capital compared to 2003, but actual spending levels will be matched to available cash flows.

Capital spending for general corporate purposes will increase in 2004 primarily as a result of DTE2. We expect non-regulated capital spending to approximate $150 million in 2004. Capital spending for growth of existing or new businesses will be constrained in 2004 due to the pending rate cases, electric Customer Choice issues and a focus on maintaining balance sheet health.

We believe that we will have sufficient internal and external capital resources to fund anticipated capital requirements.

Financing Activities

Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturity. We continually evaluate our leverage targets to ensure they are consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet. The extension of the average maturity was accomplished at interest rates that lowered our debt costs.

Net cash used for financing activities decreased $412 million during the 2004 nine-month period, compared to the same 2003 period, primarily due to higher issuances of new long- and short-term debt, and fewer repurchases of long-term debt. See Note 7.

We also contributed $170 million of DTE Energy common stock to our pension plan in the first quarter of 2004.

Outlook - Our goal is to maintain a healthy balance sheet. We intend to maintain an investment grade credit rating and maintaining leverage at approximately 50% or lower (excluding certain debt, principally securitization debt).

We expect to continue issuing new DTE Energy shares for our dividend reinvestment plan, generating approximately $50 million annually. We believe this is a cost-effective means of raising new equity.

Debt maturing in the last quarter of 2004 totals approximately $30 million. We are issuing commercial paper as needed to meet our cash requirements and in May 2004 obtained an additional credit facility of $375 million with a two-year maturity. This new facility complements our existing $1.3 billion revolving credit facilities that were renewed and modified in October 2004, and that support our use of letters of credit and the issuance of commercial paper (Note 8).

NEW ACCOUNTING PRONOUNCEMENTS

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

ENVIRONMENTAL MATTERS

See Note 9 — Contingencies for discussion of environmental matters.

REPRESENTED EMPLOYEES

There are several bargaining units for our represented employees. Approximately 4,700, or approximately 85% of our represented employees were under contracts that expired in June 2004 for electric employees and in October 2004 for gas employees. Electric and gas employees have both ratified new three-year contracts.

FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and we believe provide enhanced transparency of the derivative activities and position of our Energy Trading & Marketing segment and our gas production business.

We use the criteria in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as Assets or Liabilities from Risk Management and Trading Activity, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting.

Fair value represents the amount at which willing parties would transact an arms-length transaction. To determine the fair value of contracts that are accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates, and exercise periods.

Contracts we typically classify as derivative instruments are power and gas forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as derivatives (and which are therefore excluded from the following tables) include gas inventory, gas storage and transportation arrangements, full-requirements power contracts and gas and oil reserves. As subsequently discussed, we have fully reserved the value of derivative contracts beyond the liquid trading timeframe and which therefore do not impact income.

The subsequent tables contain the following four categories represented by their operating characteristics and key risks.

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

• “Structured Contracts” represents derivative activity transacted with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting transaction can be executed.

• “Economic Hedges” represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility as discussed in more detail in the preceding Results of Operations section.

• “Gas Production” represents derivative activity associated with our Michigan gas reserves. A substantial portion of the price risk associated with these reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Liabilities from Risk Management and Trading with an offset in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and the changes therein.

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

The following tables provide details on changes in our MTM net asset or (liability) position during 2004.


	Energy Marketing & Trading
	Proprietary			Structured			Economic						Gas
	Trading			Contracts			Hedges			Total			Production			Total
(in Millions)
MTM at December 31, 2003	$	10		$	17		$	(171	)	$	(144	)	$	(80	)	$	(224	)

Reclassed to realized upon settlement		(8	)		(6	)		58			44			(32	)		12
Changes in fair value recorded to income		3			19			(68	)		(46	)		—			(46	)
Amortization of option premiums		(2	)		—			—			(2	)		—			(2	)

Amounts impacting unrealized income		(7	)		13			(10	)		(4	)		(32	)		(36	)
Changes in fair value recorded to Other Comprehensive Income		—			(9	)		—			(9	)		(32	)		(41	)

MTM at September 30, 2004	$	3		$	21		$	(181	)	$	(157	)	$	(144	)	$	(301	)

The following table provides a current and noncurrent analysis of Assets and Liabilities from Risk Management and Trading Activities as reflected in the Consolidated Statement of Financial Position as of September 30, 2004. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.


	Energy Marketing & Trading																		Total
	Proprietary			Structured			Economic									Gas			Assets
	Trading			Contracts			Hedges			Eliminations			Total			Production			(Liabilities)
(in Millions)
Current assets	$	81		$	157		$	121		$	(39	)	$	320		$	—		$	320
Noncurrent assets		28			91			115			(29	)		205			—			205

Total MTM assets		109			248			236			(68	)		525			—			525

Current liabilities		(78	)		(151	)		(211	)		38			(402	)		(68	)		(470	)
Noncurrent liabilities		(28	)		(76	)		(206	)		30			(280	)		(76	)		(356	)

Total MTM liabilities		(106	)		(227	)		(417	)		68			(682	)		(144	)		(826	)

Total MTM net assets (liabilities)	$	3		$	21		$	(181	)	$	—		$	(157	)	$	(144	)	$	(301	)

Maturity of Fair Value of MTM Energy Contract Net Assets

As previously discussed, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe. Our intent is to recognize MTM activity only when pricing data is obtained from active quotes and published indexes. Actively quoted and published indexes includes exchange traded (i.e., NYMEX) and over-the-counter (OTC) positions for which broker quotes are available. The NYMEX has currently quoted prices for the next 72 months. Although broker quotes for gas and power are generally available for 18 and 24 months into the future, respectively, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe and which therefore do not impact income.

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


										2007			Total
										And			Fair
	2004			2005			2006			Beyond			Value
(in Millions)
Source of Fair Value
Energy Marketing & Trading
Proprietary Trading	$	8		$	(5	)	$	(2	)	$	2		$	3
Structured Contracts		5			6			9			1			21
Economic Hedges		(99	)		(48	)		(20	)		(14	)		(181	)

Total Energy Marketing & Trading		(86	)		(47	)		(13	)		(11	)		(157	)

Gas Production		(16	)		(67	)		(51	)		(10	)		(144	)

Total	$	(102	)	$	(114	)	$	(64	)	$	(21	)	$	(301	)

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 sale 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.

Our Energy Services and Biomass businesses are also subject to crude oil price risk. As previously discussed, the Section 29 tax credits generated by DTE Energy’s synfuel and biomass operations are subject to phase out if domestic crude oil prices reach certain levels. See Note 9 for further discussion.

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal and coke from and to numerous companies operating in the steel, automotive, energy, retail and other industries. Several customers and suppliers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We closely monitor these bankruptcies, regularly review contingent matters relating to these bankruptcies 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.

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). As of September 30, 2004, the company has a floating rate debt to total debt ratio of approximately 11% (excluding securitized debt).

Foreign Currency Risk

DTE Energy has foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts. These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through 2008.

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the Company carried out an evaluation, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, of 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, 2004, which is the end of the period covered by this report. Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effectively designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and timely reported in accordance with Commission’s rules and forms.

(b) Changes in internal control over financial reporting

The Company has established a formal assessment process and related procedures to evaluate the effectiveness of internal control over financial reporting using criteria specified by Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. The assessment process is comprehensive in scope, utilizes internal and external resources and involves many individuals at various levels of the Company in the design, testing and evaluation of internal control.

As part of the evaluation and assessment process, the Company has been improving the design and operating effectiveness of many entity-level and process-level controls. Control testing and remediation activities provide reasonable, but not absolute, assurance that a material weakness in internal control over financial reporting will be avoided. The inherent limitations of our current internal controls, a portion of which are manual by their nature, contribute to the potential for control deficiencies. Although management has not yet completed its assessment and continues to implement control improvements, management does not believe any areas requiring further improvement will constitute a material weakness in internal control over financial reporting as of December 31, 2004.

There has been no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

DTE Energy Company

Consolidated Statement of Operations (unaudited)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions, Except per Share Amounts)
Operating Revenues	$	1,594		$	1,654		$	5,188		$	5,349

Operating Expenses
Fuel, purchased power and gas		316			452			1,434			1,758
Operation and maintenance		884			742			2,517			2,298
Depreciation, depletion and amortization		190			170			536			547
Taxes other than income		86			71			231			255
Gains on sale of assets, net		(55	)		(13	)		(166	)		(29	)

		1,421			1,422			4,552			4,829

Operating Income		173			232			636			520

Other (Income) and Deductions
Interest expense		131			135			391			412
Interest income		(14	)		(7	)		(41	)		(22	)
Minority interest		(66	)		(20	)		(147	)		(72	)
Other income		(27	)		(44	)		(86	)		(75	)
Other expenses		20			31			65			82

		44			95			182			325

Income Before Income Taxes		129			137			454			195
Income Tax Provision (Benefit)		36			(43	)		129			(56	)

Income from Continuing Operations		93			180			325			251

Income (Loss) from Discontinued Operations, net of tax (Note 3)		—			(4	)		(7	)		68
Cumulative Effect of Accounting Changes, net of tax (Note 2)		—			—			—			(27	)

Net Income	$	93		$	176		$	318		$	292

Basic Earnings per Common Share (Note 6)
Income from continuing operations	$	.54		$	1.07		$	1.89		$	1.49
Discontinued operations		—			(.02	)		(.04	)		.41
Cumulative effect of accounting changes		—			—			—			(.16	)

Total	$	.54		$	1.05		$	1.85		$	1.74

Diluted Earnings per Common Share (Note 6)
Income from continuing operations	$	.54		$	1.06		$	1.88		$	1.49
Discontinued operations		—			(.02	)		(.04	)		.40
Cumulative effect of accounting changes		—			—			—			(.16	)

Total	$	.54		$	1.04		$	1.84		$	1.73

Average Common Shares
Basic		173			168			172			168
Diluted		174			168			173			168
Dividends Declared per Common Share	$	.515		$	.515		$	1.545		$	1.545

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Financial Position


	(Unaudited)
	September 30			December 31
	2004			2003
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	74		$	54
Restricted cash (Note 1)		76			131
Accounts receivable
Customer (less allowance for doubtful accounts of $130 and $99, respectively)		868			877
Accrued unbilled revenues		174			316
Other		431			338
Inventories
Fuel and gas		568			467
Materials and supplies		159			162
Assets from risk management and trading activities		307			186
Other		247			181

		2,904			2,712

Investments
Nuclear decommissioning trust funds		557			518
Other		565			601

		1,122			1,119

Property
Property, plant and equipment		18,101			17,679
Less accumulated depreciation and depletion		(7,699	)		(7,355	)

		10,402			10,324

Other Assets
Goodwill		2,064			2,067
Regulatory assets		2,132			2,063
Securitized regulatory assets		1,462			1,527
Notes receivable		527			469
Assets from risk management and trading activities		205			88
Prepaid pension assets		183			181
Other		193			203

		6,766			6,598

Total Assets	$	21,194		$	20,753

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Financial Position


	(Unaudited)
	September 30			December 31
	2004			2003
(in Millions, Except Shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	691		$	625
Accrued interest		111			110
Dividends payable		90			87
Accrued payroll		40			51
Income taxes		11			185
Short-term borrowings		476			370
Current portion of long-term debt, including capital leases		516			477
Liabilities from risk management and trading activities		454			326
Other		584			593

		2,973			2,824

Other Liabilities
Deferred income taxes		1,071			988
Regulatory liabilities		812			817
Asset retirement obligations (Note 2)		903			866
Unamortized investment tax credit		147			156
Liabilities from risk management and trading activities		357			173
Liabilities from transportation and storage contracts		397			495
Accrued pension liability		237			345
Deferred gains from asset sales		398			311
Minority interest		115			156
Nuclear decommissioning		72			67
Other		605			599

		5,114			4,973

Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		5,689			5,624
Securitization bonds		1,400			1,496
Equity-linked securities		179			185
Trust preferred-linked securities		289			289
Capital lease obligations		70			75

		7,627			7,669

Contingencies (Notes 5 and 9)
Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 173,958,093 and 168,606,522 shares issued and outstanding, respectively		3,312			3,109
Retained earnings		2,360			2,308
Accumulated other comprehensive loss		(192	)		(130	)

		5,480			5,287

Total Liabilities and Shareholders’ Equity	$	21,194		$	20,753

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Cash Flows (Unaudited)


	Nine Months Ended
	September 30
	2004			2003
(in Millions)
Operating Activities
Net Income	$	318		$	292
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		536			551
Deferred income taxes		104			(55	)
Gain on sale of interests in synfuel projects		(166	)		(57	)
Gain on sale of ITC and other assets, net		(27	)		(130	)
Partners’ share of synfuel project losses		(158	)		(58	)
Contributions from synfuel partners		71			44
Cumulative effect of accounting changes		—			27
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(88	)		(328	)

Net cash from operating activities		590			286

Investing Activities
Plant and equipment expenditures — regulated		(555	)		(504	)
Plant and equipment expenditures — non-regulated		(52	)		(58	)
Investment in joint ventures		(36	)		(5	)
Proceeds from sale of interests in synfuel projects		151			67
Proceeds from sale of ITC and other assets		62			643
Restricted cash for debt redemptions		55			137
Other investments		(59	)		(61	)

Net cash from (used for) investing activities		(434	)		219

Financing Activities
Issuance of long-term debt		617			529
Redemption of long-term debt		(620	)		(897	)
Short-term borrowings, net		106			55
Issuance of common stock		31			33
Dividends on common stock		(265	)		(259	)
Other		(5	)		(9	)

Net cash used for financing activities		(136	)		(548	)

Net Increase (Decrease) in Cash and Cash Equivalents		20			(43	)
Cash and Cash Equivalents at Beginning of the Period		54			133

Cash and Cash Equivalents at End of the Period	$	74		$	90

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity

and Comprehensive Income (unaudited)


										Accumulated
	Common Stock						Retained			Other Comprehensive
	Shares			Amount			Earnings			Loss			Total
(Dollars in Millions, Shares in Thousands)
Balance, January 1, 2004		168,607		$	3,109		$	2,308		$	(130	)	$	5,287

Net income		—			—			318			—			318
Issuance of new shares (Note 6)		5,413			211			—			—			211
Dividends declared on common stock		—			—			(267	)		—			(267	)
Repurchase and retirement of common stock		(62	)		(2	)		—			—			(2	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(43	)		(43	)
Net change in unrealized gain on investments, net of tax		—			—			—			(19	)		(19	)
Unearned stock compensation and other		—			(6	)		1			—			(5	)

Balance, September 30, 2004		173,958		$	3,312		$	2,360		$	(192	)	$	5,480

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


	2004			2003
(in Millions)
Net income	$	318		$	292

Other comprehensive income (loss), net of tax:
Net unrealized losses on derivatives:
Losses arising during the period, net of taxes of $(21) and $10, respectively		(38	)		19
Amounts reclassified to earnings, net of taxes of $(3) and $(1), respectively		(5	)		(2	)

		(43	)		17
Net change in unrealized gain on investments, net of taxes of $(10) and $-		(19	)		—
Pension obligations, net of taxes of $- and $224, respectively		—			417

		(62	)		434

Comprehensive income	$	256		$	726

See Notes to Consolidated Financial Statements (Unaudited)

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 2003 Annual Report on Form 10-K.

The accompanying consolidated financial statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require 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 certain 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 Statement of Financial Accounting Standards (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 Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions, except per share amounts)
Net Income As Reported	$	93		$	176		$	318		$	292
Less: Total stock-based expense (1)		(2	)		(2	)		(6	)		(6	)

Pro Forma Net Income	$	91		$	174		$	312		$	286

Income Per Share
Basic — as reported	$	0.54		$	1.05		$	1.85		$	1.74

Basic — pro forma	$	0.53		$	1.04		$	1.81		$	1.71

Diluted — as reported	$	0.54		$	1.04		$	1.84		$	1.73

Diluted — pro forma	$	0.52		$	1.03		$	1.81		$	1.70

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

Investment in Plug Power

We have an investment in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. At December 31, 2003, we owned 14.1 million shares, or approximately 19% of Plug Power’s common stock. We apply the cost method of accounting for our investment in Plug Power. In May 2004, we sold 3.5 million shares of Plug Power stock and recorded a gain of approximately $14 million, net of taxes. The sale reduced our ownership interest in Plug Power to 10.6 million shares, or approximately 14%.

Restricted Cash

Restricted cash consists of funds held to satisfy requirements of certain debt and partnership operating agreements.

Consolidated Statement of Cash Flows

The components of changes in assets and liabilities follow:


	Nine Months Ended
	September 30
	2004			2003
(in Millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	39		$	(2	)
Accrued unbilled receivables		142			109
Accrued gas cost recovery revenue		(52	)		(15	)
Inventories		(98	)		(198	)
Accrued/Prepaid pensions		60			(134	)
Accounts payable		66			3
Accrued power supply cost recovery revenue		62			—
Exchange gas payable		(42	)		91
Income taxes payable		(175	)		22
General taxes		(19	)		(29	)
Risk management and trading activities		75			(28	)
Other		(146	)		(147	)

	$	(88	)	$	(328	)

Other cash and non-cash investing and financing activities follow:


	Nine Months Ended
	September 30
	2004		2003
(in Millions)
Supplementary Cash Flow Information
Interest paid (excluding interest capitalized)	$	390	$	391
Income taxes paid	$	202	$	27
Notes received from sale of synfuel projects	$	162	$	—
Common stock contribution to pension plan	$	170	$	—
Exchange of debt	$	—	$	100

Retirement Benefits and Trusteed Assets

The components of net periodic benefit costs for qualified and non-qualified pension benefits and other postretirement benefits follow:


							Other Postretirement
	Pension Benefits						Benefits
	2004			2003			2004			2003
(in Millions)
Three Months Ended September 30
Service Cost	$	14		$	11		$	10		$	6
Interest Cost		43			43			23			20
Expected Return on Plan Assets		(54	)		(52	)		(14	)		(11	)
Amortization of:
Net loss		16			10			12			8
Prior service cost		3			2			(1	)		—
Net transition liability		—			1			2			6

Net Periodic Benefit Cost	$	22		$	15		$	32		$	29

Nine Months Ended September 30
Service Cost	$	44		$	37		$	31		$	28
Interest Cost		129			126			69			65
Expected Return on Plan Assets		(162	)		(158	)		(42	)		(35	)
Amortization of:
Net loss		47			29			33			22
Prior service cost		7			7			(3	)		(2	)
Net transition liability		—			1			6			10

Net Periodic Benefit Cost	$	65		$	42		$	94		$	88

In June 2004, we retroactively adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) No. 106-2. This FSP provides guidance on the accounting for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). As a result of the retroactive adoption, our other postretirement benefit costs were reduced by $4 million and $12 million for the three and nine months ended September 30, 2004, respectively. See Note 2.

In March 2004, we contributed shares of DTE Energy common stock, valued at $170 million, to a defined benefit retirement plan. In January 2004, we made a $40 million cash contribution to our postretirement health care and life insurance plans. We do not expect to make any additional contributions during 2004.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Consolidation of Variable Interest Entities

In January 2003, FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51,” was issued and 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.

In October 2003 and December 2003, the FASB issued Staff Position No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, which clarified FIN 46 and provided for the deferral of the effective date of FIN 46 for certain variable interest entities.

We have evaluated all of our equity and non-equity interests and have adopted all current provisions of FIN 46-R. The adoption of FIN 46-R did not have a material effect on our financial statements. We expect additional implementation guidance to be issued regarding FIN 46-R and are unable to determine what effect, if any, this additional guidance might have on our financial statements.

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. We 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 (net of taxes of $7 million) for 2003.

A reconciliation of the asset retirement obligation for the 2004 nine-month period follows:


(in Millions)
Asset retirement obligations at January 1, 2004	$	866
Accretion		43
Liabilities settled		(4	)
Revisions in estimated cash flows		(2	)

Asset retirement obligations at September 30, 2004	$	903

A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

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 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 ARB No. 43 is no longer permitted. Our 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 applied 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).

Medicare Act Accounting

In December 2003, the Medicare Act was signed into law. This Act provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans providing a benefit that is at least “actuarially equivalent” to the benefit established by law. We elected at that time to defer the provisions of the Medicare Act, and its impact on our accumulated postretirement benefit obligation and net periodic postretirement benefit cost pending the issuance of specific authoritative accounting guidance by the FASB.

In May 2004, FSP No. 106-2 was issued on accounting for the effects of the Medicare Act. The FSP is effective for the first interim period beginning after June 15, 2004, with earlier application encouraged. The guidance in this FSP is applicable to sponsors of single-employer defined benefit postretirement health care plans for which (a) the employer has concluded the prescription drug benefits available under the plan to some or all participants are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy under the Medicare Act and (b) the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. We believe we qualify for the subsidy under the Medicare Act and the expected subsidy will partially offset our share of the cost of the postretirement prescription drug coverage.

The reduction in the accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service is approximately $95 million and is accounted for as an actuarial gain as required under the FSP. The effects of the subsidy on the measurement of net periodic postretirement benefit costs is expected to reduce cost by $16 million in 2004. The impact of the Medicare Act on the components of other postretirement benefit costs is as follows:


	Three Months		Nine Months
	Ended		Ended
	Sept. 30, 2004		Sept. 30, 2004
(in Millions)
Reduction in service cost	$	—	$	1
Reduction in interest cost		2		5
Amortization of actuarial gain		2		6

Decrease in postretirement benefit cost	$	4	$	12

NOTE 3 — DISCONTINUED OPERATIONS

Impairment of Southern Missouri Gas Company

We own Southern Missouri Gas Company (SMGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31, 2004, SMGC met the SFAS No. 144 criteria of an asset “held for sale.” Therefore, we recognized a net of tax impairment loss of approximately $7 million in the 2004 first quarter representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill.

Disposition of International Transmission Company

We have reported the operations of the International Transmission Company (ITC) as a discontinued operation. In February 2003, we sold ITC to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. The sale generated a preliminary net of tax gain in the 2003 first quarter of $69 million. The gain was adjusted during the 2003 second quarter to $67 million, and further adjusted to $63 million in the 2003 third quarter, net of transaction costs and the portion of the gain that was refundable to customers. We had income from discontinued operations of $5 million in the first quarter of 2003.

NOTE 4 — CONTRACT MODIFICATION/TERMINATION

In February 2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and terminated a related long-term gas exchange (storage) agreement, effective March 31, 2004. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season. The agreements were at rates that were not reflective of current market conditions and had been fair valued under accounting principles generally accepted in the U.S. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately $75 million as of December 31, 2003. As a result of the contract modification and termination, we recorded an adjustment to the net liability increasing earnings in the 2004 first quarter by $48 million, net of taxes.

NOTE 5 — REGULATORY MATTERS

Electric Rate Case

Rate Request - In June 2003, Detroit Edison filed an application with the MPSC requesting a change in retail electric rates, resumption of the power supply cost recovery (PSCR) mechanism, and recovery of net stranded costs. The application requested a base rate increase for both full-service and electric Customer Choice customers totaling $416 million annually (approximately 12% increase) in 2006, with a three-year phase-in starting in 2004 as the caps on customer rates expire. Detroit Edison proposed that the $416 million increase be allocated between full-service customers ($265 million) and electric Customer Choice customers ($151 million). In November 2003, Detroit Edison increased its original rate request by $11 million to $427 million.

During the second quarter of 2004, based upon the MPSC Staff’s (Staff) filing for final rate relief, as subsequently discussed, and more current information regarding the level of electric Customer Choice sales penetration, Detroit Edison revised its base rate increase request from $427 million to $457 million.

In addition, Detroit Edison has updated its request for recovery of regulatory assets from $109 million to $93 million annually over a 5-year period, which includes recovery of deferred return on and of Clean Air Act costs and capital expenditures in excess of base depreciation amounts, transmission costs and electric

Customer Choice implementation costs as allowed by Public Act (PA) 141. Detroit Edison is also requesting recovery of $107 million of historical stranded costs, through the date of the interim order.

A summary of the rate requests follows:


	Initial			Revised
	Final			Final
	Rate			Rate
	Request			Request
(in Millions)
Base Rate Revenue Deficiency	$	553		$	583
PSCR Savings/Choice Mitigation		(126	)		(126	)

Base Rate Increase		427			457
Regulatory Asset Recovery Surcharge		109			93	(1)

Total	$	536		$	550

Phase in By Year
2004	$	299
2005		57
2006		180

Total	$	536

(1)

Does not include recovery of $107 million of historical stranded costs.

The revised rate request did not allocate the phase in amounts by year, but the amounts would be allocated to the customer classes as the rate caps expire.

MPSC Interim Rate Order - On February 20, 2004, the MPSC issued an order for interim rate relief. The order authorized an interim increase in base rates, a transition charge for customers participating in the electric Customer Choice program and a new PSCR factor.

The interim base rate increase totaled $248 million annually, effective February 21, 2004, and is applicable to all customers not subject to the rate cap. The increase has been allocated to both full-service customers ($240 million) and electric Customer Choice customers ($8 million). However, because of the rate caps under PA 141, not all of the increase will be realized in 2004. The interim order also terminated certain transition credits and authorized transition charges to electric Customer Choice customers designed to result in $30 million in additional revenues. Additionally, the MPSC authorized a PSCR factor for all customers, a credit of 1.05 mills per kilowatthour (kWh) compared to the 2.04 mills per kWh charge previously in effect. However, the MPSC order allows Detroit Edison to increase base rates for customers still subject to the cap in an equal and offsetting amount with the required reduction in the PSCR factor to maintain the total capped rate levels currently in effect for these customers.

Although the base rate increase and transition charges total $278 million, the effects of the interim order are estimated to have increased income by $5 million, net of taxes, in the 2004 third quarter, and decreased income by $3 million, net of taxes, in the 2004 nine-month period. This lower amount is a result of the rate caps, the February 21, 2004 effective date of the interim base rate increase and the PSCR reduction effective January 1, 2004. Revenues from the interim rate order increased income $11 million, net of taxes, in the 2004 third quarter, and increased income $10 million, net of taxes, in the 2004 nine-month period. Revenues from the interim rate order also relate to items that were previously deferred as regulatory assets. The reduction in regulatory asset deferrals related to previously capped customers decreased income by $6 million, net of taxes, in the 2004 third quarter, and decreased income by $13 million, net of taxes, in the 2004 nine-month period. Amounts collected are subject to a potential refund pending a final order in this proceeding.

The MPSC deferred addressing other items in the rate request, including a surcharge to recover regulatory assets, until a final rate order is issued, which is expected in November 2004. We cannot predict the amount of final rate relief that will be granted by the MPSC.

MPSC Staff Recommendation on Final Rate Relief - On March 5, 2004, the Staff filed testimony regarding final rate relief requested by Detroit Edison. The Staff recommended a base rate increase of $275 million. The recommended amount was subsequently adjusted to $254 million, a $6 million increase over the $248 million interim order. The Staff’s proposed $254 million base rate increase excluded an estimated $93 million of stranded costs from sales lost to electric Customer Choice. The Staff’s proposal would provide Detroit Edison the opportunity to mitigate this loss with third-party wholesale sales by modifying the PSCR mechanism to remove the revenue credit from these sales. The revenue credit from third-party wholesale sales currently included in the PSCR mechanism flows this benefit to full-service customers. The Staff recommends that any future Customer Choice margin loss be recovered using two basic provisions; (1) allowing Detroit Edison to retain 90% of the net third-party revenue earned from wholesale sales up to 110% of each year’s electric Customer Choice sales, and (2) that non-cost Choice margin loss (impact of inter-class rate subsidization) be recovered through future rate increases from full-service customers.

The Staff recommended that accrued regulatory assets be recovered through three mechanisms. The first mechanism would recover electric Customer Choice implementation costs through a charge to both full- service and electric Customer Choice customers of approximately $25 million per year, effective in 2006 when all current rate caps expire. The second mechanism recovers accrued regulatory assets, including deferred costs under the Clean Air Act through a five-year surcharge that would only be collected from full-service customers as their rate caps expire for an average of approximately $38 million per year. The third mechanism would recover prior period stranded costs determined pursuant to the MPSC’s existing production fixed cost revenue deficiency methodology. The Staff estimated that Detroit Edison’s stranded costs for 2002, 2003 and 2004 through the date of the interim rate order of February 20, 2004 are approximately $44 million. These stranded costs would be recovered from electric Customer Choice customers utilizing the transition charge approved in the interim rate order.

The Staff recommended a capital structure of 54% debt and 46% equity and proposed an 11% return on equity.

ALJ’s Recommendation on Final Rate Relief - On August 26, 2004, an MPSC Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) regarding final rate relief requested by Detroit Edison. The ALJ agreed with the Staff and recommended a $254 million base rate increase which excluded $93 million of stranded costs. The recommended base rate increase is predicated upon Detroit Edison being allowed to retain third-party wholesale sales due to electric Customer Choice to recover the $93 million of stranded costs. The ALJ also endorsed the Staff’s position on regulatory assets and historical stranded costs.

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs - PA 141 provides Detroit Edison with the right to recover net stranded costs. 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. During each quarter, Detroit Edison records a regulatory asset representing an estimate of the cumulative stranded costs as of that period. Our revised and ongoing calculations concluded that the $68 million of net stranded costs recorded as of December 31, 2003 is appropriate. During the 2004 nine-month period, Detroit Edison recorded $67 million of additional stranded costs as a regulatory asset.

An April 1, 2004 Michigan Court of Appeals order found that the MPSC should not defer recovery of Detroit Edison’s electric Customer Choice implementation costs indefinitely. On June 29, 2004, the MPSC

issued an order authorizing Detroit Edison to recover $20 million in implementation costs incurred during 2002. Detroit Edison elected to collect these costs as well as implementation costs incurred in 2000 and 2001 as part of the $93 million regulatory asset recovery previously discussed.

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 2003 related to the blackout, excluding lost margins, were approximately $25 million ($16 million net of tax). In October 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. On September 21, 2004, the MPSC denied Detroit Edison’s application to defer and recover these blackout related expenses.

DTE2 Accounting Application

In 2003, we began the implementation of DTE2, a company-wide initiative to improve existing processes and to implement new core information systems including, finance, human resources, supply chain and work management. The new information systems are replacing systems that are approaching the end of their useful lives. We expect the benefits of DTE2 to include lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize DTE2 costs, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. Through September 30, 2004, we have expensed approximately $22 million of training, maintenance and overhead costs pending MPSC action on our application. Detroit Edison is proposing a 15-year amortization period for the costs, exclusive of the computer equipment costs.

Power Supply Cost Recovery Proceedings

2005 Plan Year - In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills/kWh above the amount included in base rates to be established in the electric rate case final order. Included in the factor are power supply costs, transmission expenses and emission credit costs. In accordance with the Staff’s recommendation in the electric rate case, the filing includes Detroit Edison’s retention of 90% of the net third-party revenues earned from wholesale sales. Detroit Edison may self-implement the proposed factor on January 1, 2005 if an MPSC order is not received prior to that time.

Transmission Proceedings

Several Midwest utilities seek to recover lost transmission revenues associated with the creation of multiple regional transmission organizations in the Midwest. Positions advocated by several parties in a Federal Energy Regulatory Commission (FERC) proceeding could require that Detroit Edison and its customers be responsible for increased transmission costs. Detroit Edison continues to actively participate in this proceeding and estimates that increased transmission expenses of up to $30 million annually may arise as a result of this proceeding. A FERC decision in this proceeding is expected in November 2004.

Gas Rate Case

Rate Request - In September 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. MichCon requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004. The interim request was based on a projected revenue deficiency for the test year 2004.

MPSC Interim Rate Order - In September 2004, the MPSC issued an order granting interim rate relief to MichCon in the amount of $35 million. The interim rate order was based on a 50% debt and 50% equity capital structure, and an 11.5% rate of return. Amounts collected are subject to a potential refund pending a final order in this rate case.

MPSC Staff Recommendation on Final Rate Relief - The Staff has recommended a $76 million increase in base rates compared to MichCon’s requested base rate relief of $194 million. The Staff also supports a provision, proposed by MichCon, that would allow MichCon to recover or refund 90% of uncollectable accounts receivables expense above or below the amount that is reflected in base rates. In addition, the Staff proposed a 50% debt and 50% equity capital structure utilizing a reduced rate of return of 11%. MichCon’s current allowed rate of return is 11.5%. MichCon expects a final order in the first quarter of 2005.

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 is subject to the 2002 GCR reconciliation process. In March 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 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 that was filed with the MPSC in February 2003. The Staff and various intervening parties in this proceeding are seeking to have the MPSC disallow an additional $26 million, representing unbilled revenues at December 2001. One party has proposed that half of the $8 million related to the settlement of the Enron bankruptcy also be disallowed. The other parties to the case have recommended that the Enron bankruptcy settlement be addressed in the 2003 GCR reconciliation case. An MPSC Administrative Law Judge has recommended disallowances of $26.5 million related to the use of storage gas in 2001 and $26 million related to the December 2001 unbilled issue, and recommended that the $8 million related to the Enron issue be addressed in the 2003 GCR reconciliation case. We have included this item in our testimony in the 2003 GCR reconciliation filed in February 2004. The Staff has recommended that MichCon be allowed to recover the entire $8 million related to the Enron issue. A final order in this proceeding is expected in 2004. In addition, we filed an appeal of the March 2003 MPSC order with the Michigan Court of Appeals.

2003 Plan Year - In July 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 December 31, 2003, MichCon has accrued a $19 million regulatory asset representing the under-recovery of actual gas costs incurred in 2003 and the 2002 GCR under-recovery.

2004 Plan Year - In September 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 the 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 reducing the possibility of a GCR under recovery. Due to sustained increase in market prices for natural gas, in June 2004, the MPSC approved a temporary increase in the maximum GCR factor and a contingent factor which resulted in a new temporary maximum factor of $6.62 per Mcf, effective from July 1, 2004 until the MPSC issues its final order in this case.

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

NOTE 6 — COMMON STOCK AND EARNINGS PER SHARE

Common Stock

In March 2004, we issued 4,344,492 shares of DTE Energy common stock, valued at $170 million. The common stock was contributed to a defined benefit retirement plan.

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 stock awards and the issuance of performance share awards. A reconciliation of both calculations for the 2004 and 2003 three-month and nine-month periods is presented in the following table:


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2004		2003		2004		2003
(Millions, except per share amounts)
Basic Earnings Per Share
Income from continuing operations	$	93.3	$	179.7	$	325.1	$	250.5
Average number of common shares outstanding		173.5		167.8		172.2		167.5

Income per share of common stock based on weighted average number of shares outstanding	$	0.54	$	1.07	$	1.89	$	1.49

Diluted Earnings Per Share
Income from continuing operations	$	93.3	$	179.7	$	325.1	$	250.5

Average number of common shares outstanding		173.5		167.8		172.2		167.5
Incremental shares from stock — based awards		.7		.6		.6		.6

Average number of dilutive shares outstanding		174.2		168.4		172.8		168.1

Income per share of common stock assuming issuance of incremental shares	$	0.54	$	1.06	$	1.88	$	1.49

NOTE 7 — LONG -TERM DEBT AND PREFERRED SECURITIES

In January 2004, $100 million of 8.625% trust preferred-linked securities due 2038 were redeemed. Accordingly, the underlying DTE Energy debt security was also simultaneously redeemed.

In January 2004, $60 million of 7.12% medium term notes matured.

In April 2004, Detroit Edison issued $36 million of 4-7/8% tax-exempt bonds due 2029, the proceeds of which were used to redeem $36 million of 6.55% tax-exempt bonds due 2024. In April 2004, Detroit Edison also issued $32 million of 4.65% tax-exempt bonds due in 2028, the proceeds of which were used to redeem the following tax-exempt issues: $11.5 million of 6.05% bonds due 2023, $7.5 million of 5.875% bonds due 2024, and $13 million of 6.45% bonds due 2024.

In May and June 2004, DTE Energy Trust II, an unconsolidated affiliate, issued an aggregate of $100 million of 7.50% Trust Originated Preferred Securities. The proceeds from the issuance were loaned to DTE Energy in exchange for debt securities with essentially the same terms as the related preferred securities.

In June 2004, DTE Energy issued $250 million of floating rate notes due in 2007. The proceeds were used to repay short-term borrowings incurred in connection with the June 2004 redemption of $250 million of DTE Energy 6.0% senior notes.

In July 2004, Detroit Edison issued $200 million of 5.40% senior notes due in 2014. The proceeds were used to repay short-term borrowings and for general corporate purposes.

In October 2004, MichCon issued $120 million of 5.0% senior notes due in 2019. The proceeds will be principally used to redeem the following two issues: $52 million of 6.85% senior notes due 2038 and $55 million of 6.85% senior notes due 2039. These securities are expected to be called for redemption in

November 2004 at a price of 100 percent of the principal amount plus accrued and unpaid interest from September 1, 2004.

NOTE 8 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In May 2004, we entered into a $375 million two-year unsecured revolving credit facility with a group of banks to be utilized for general corporate borrowings. This agreement requires the company to maintain a debt to total capitalization ratio of no more than .65 to l and an “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.

On October 15 2004, DTE Energy entered into a $525 million, five-year unsecured revolving credit facility and lowered its existing three-year revolving credit facility from $350 million to $175 million. DTE Energy’s wholly-owned subsidiaries, Detroit Edison and MichCon, also entered into similar revolving credit facilities. Detroit Edison entered into a $206.25 million, five-year facility and lowered its three-year facility from $137.5 million to $68.75 million. MichCon entered into a $243.75 million, five-year facility and lowered its three-year facility from $162.5 million to $81.25 million. The five-year facilities replace the October 2003 364-day facilities, which expired. The three-year revolving credit facilities expire in October 2006. The five- and three-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for each of the Companies’ commercial paper programs. Borrowings under the facilities will be available at prevailing short-term interest rates. The agreements require each of the Companies to maintain a debt to total capitalization ratio of no more than .65 to l and an EBITDA to interest ratio of no less than 2 to 1. The Companies are currently in compliance with these financial covenants. 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.

NOTE 9 — CONTINGENCIES

Environmental

Prior to the construction of major natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. DTE Enterprises Inc. (MichCon and Citizens) owns, or previously owned, 18 such former manufactured gas plant (MGP) sites. During the mid-1980’s, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. Enterprises employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies. The findings of these investigations indicated that the estimated total expenditures for investigation and remediation activities for these sites could range from $30 million to $170 million based on undiscounted 1995 costs. As a result of these studies, Enterprises accrued a liability and a corresponding regulatory asset of $35 million during 1995. At December 31, 2003, the reserve balance was $23 million of which $5 million was classified as current. Our current estimates indicate that the previously accrued amounts are adequate to cover the costs of required remedial actions, and therefore no additional accrual will be required.

Detroit Edison conducted remedial investigations at contaminated sites, including 2 former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated total costs to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

In July 2004, the Environmental Protection Agency (EPA) published final regulations establishing requirements and a permitting process for existing power plant cooling water intake structures. These regulations require individual facility studies, and permitting and intake modifications that will be determined and implemented over the next 5 to 7 years and which could require up to $50 million in additional capital expenditures for Detroit Edison.

Synthetic Fuel Operations

We partially or wholly own nine synthetic fuel production facilities. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (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 tax credits.

In-Service Date - During July 2004, several unaffiliated companies announced that they have been notified that the IRS intends to challenge the placed in service dates for some of their synfuel facilities. If the IRS ultimately prevails, Section 29 credits claimed by these companies would be disallowed. The placed in service issue is fact-driven and specific to each facility. The in-service dates for eight of our nine synfuel plants have been reviewed by the IRS in conjunction with issuing determination letters and/or recently completed audits. We believe all nine of our synthetic fuel plants meet the required in-service condition.

Through December 31, 2003, we have generated approximately $484 million in synfuel tax credits.

Oil Prices - To reduce U.S. dependence on imported oil, the Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides a natural market for these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which in recent years has been $3-$4 lower than the New York Mercantile Exchange (NYMEX) price. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2003, the threshold price at which the tax credit would have begun to be reduced was $50.14 and would have been completely phased out if the Reference Price reached $62.94. The actual Reference Price of oil was $27.56 for 2003 and is estimated to be $35.60 through September 30, 2004. Based on the estimated monthly average wellhead price per barrel of oil through September 2004, the average price of oil would have to exceed approximately $102 per barrel for the remaining months in 2004 before credits begin to phase out and the price of oil would have to exceed approximately $158 per barrel to eliminate the credits. We cannot predict with any accuracy the future price of a barrel of oil, but believe it is highly unlikely that Section 29 tax credits for synthetic fuels produced in 2004 will be reduced.

Numerous recent events that have increased domestic crude oil prices to record levels, including terrorism and storm-related supply disruptions. If the credit is reduced or eliminated in 2004 or future years, our financial statements would be negatively impacted. We are continuing to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy.

Other

We are involved in certain legal, regulatory and administrative 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,

NOTE 10 — SEGMENT INFORMATION

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


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Operating Revenues
Energy Resources
Regulated — Power Generation	$	587		$	669		$	1,646		$	1,874

Non-regulated
Energy Services		283			229			800			696
Energy Marketing & Trading		147			230			481			713
Other		111			77			258			209

Total Non-regulated		541			536			1,539			1,618

		1,128			1,205			3,185			3,492

Energy Distribution
Regulated — Power Distribution		371			348			1,033			950
Non-regulated		8			11			32			25

		379			359			1,065			975

Energy Gas
Regulated — Gas Distribution		160			146			1,165			1,074
Non-regulated		30			26			84			70

		190			172			1,249			1,144

Corporate & Other		5			4			14			10
Reconciliations and eliminations		(108	)		(86	)		(325	)		(272	)

Total
Regulated		1,118			1,163			3,844			3,898
Non-regulated		579			573			1,655			1,713
Corporate & Other including reconciliations and eliminations		(103	)		(82	)		(311	)		(262	)

	$	1,594		$	1,654		$	5,188		$	5,349


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2004			2003			2004			2003
(in Millions)
Net Income (Loss)
Energy Resources
Regulated — Power Generation	$	34		$	61		$	51		$	132

Non-regulated
Energy Services		51			23			145			151
Energy Marketing & Trading		12			23			62			52
Other		1			(1	)		(1	)		(1	)

Total Non-regulated		64			45			206			202

		98			106			257			334

Energy Distribution
Regulated — Power Distribution		28			35			63			15
Non-regulated		(4	)		(3	)		(15	)		(12	)

		24			32			48			3

Energy Gas
Regulated — Gas Distribution		(55	)		(45	)		(22	)		5
Non-regulated		5			12			14			26

		(50	)		(33	)		(8	)		31

Corporate & Other		21			75			28			(117	)

Income (Loss) from Continuing Operations
Regulated		7			51			92			152
Non-regulated		65			54			205			216
Corporate & Other		21			75			28			(117	)

		93			180			325			251

Discontinued Operations		—			(4	)		(7	)		68
Cumulative Effect of Accounting Changes.		—			—			—			(27	)

Net Income	$	93		$	176		$	318		$	292

Diluted Earnings (Loss) per Share
Regulated	$	.04		$	.30		$	.53		$	.91
Non-regulated		.37			.32			1.18			1.28
Corporate & Other		.13			.44			.17			(.70	)

Income from Continuing Operations		.54			1.06			1.88			1.49
Discontinued Operations		—			(.02	)		(.04	)		.40
Cumulative Effect of Accounting Changes.		—			—			—			(.16	)

Net Income	$	.54		$	1.04		$	1.84		$	1.73

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004, and the related condensed consolidated statement of operations for the three-month and nine-month periods ended September 30, 2004 and 2003, the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2004 and 2003, and the condensed consolidated statements of changes in shareholders’ equity and comprehensive income for the nine-month period ended September 30, 2004 and the nine-month periods ended September 30, 2004 and 2003, respectively. These interim financial statements are the responsibility of DTE Energy Company’s management.

We conducted our reviews in accordance with standards of the Public Company Accounting Oversight Board (United States). 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 standards of the Public Company Accounting Oversight Board (United States), 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 standards of the Public Company Accounting Oversight Board (United States), the consolidated statement of financial position of DTE Energy Company and subsidiaries as of December 31, 2003, 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 March 1, 2004 (which report includes an explanatory paragraph relating to the change in the methods of accounting for asset retirement obligations, energy trading contracts and gas inventories in 2003, goodwill and energy trading contracts in 2002 and derivative instruments and hedging activities in 2001), 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, 2003 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 4, 2004

Other Information

Legal Proceedings

We are involved in certain legal, regulatory and administrative proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. 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 operations or financial statements in the period they are resolved.

Amendment of Benefit Plans

On September 22, 2004, the Organization and Compensation Committee of the Company’s Board of Directors amended the DTE Energy Company Executive Supplemental Retirement Plan, the DTE Energy Company Supplemental Retirement Plan, the DTE Energy Company Supplemental Savings Plan and the DTE Energy Company Executive Deferred Compensation Plan to permit certain participants and former participants in such plans to make unscheduled withdrawals from plan accounts. The amendments provide that the unscheduled withdrawals will be paid in a single lump sum. A 10% penalty will be deducted prior to any such unscheduled withdrawal.

Exhibits


Exhibit
Number		Description
Filed:

10-51		DTE Energy Company Executive Supplemental Retirement Plan

10-52		Amendment to the DTE Energy Company Executive Supplemental Retirement Plan

10-53		Amendment to the DTE Energy Company Supplemental Retirement Plan

10-54		Amendment to the DTE Energy Company Supplemental Savings Plan

10-55		Amendment to the DTE Energy Company Executive Deferred Compensation Plan

15-15		Awareness Letter of Deloitte & Touche LLP

31-11		Chief Executive Officer Section 302 Form 10-Q Certification

31-12		Chief Financial Officer Section 302 Form 10-Q Certification

Furnished:

32-11		Chief Executive Officer Section 906 Certification of Periodic Report

32-12		Chief Financial Officer Section 906 Certification of Periodic Report


	Assuming a			Assuming a
	10%			10%
(in Millions)	increase			decrease		Change in the
Activity	in rates			in rates		fair value of
Gas contracts	$	(24	)	$	24	Commodity contracts
Power contracts	$	1		$	—	Commodity contracts
Interest rate risk	$	(308	)	$	322	Long-term debt
Foreign currency risk	$	—		$	—	Forward contracts


		DTE ENERGY COMPANY

Date: November 4, 2004		/s/ DANIEL G. BRUDZYNSKI

		Daniel G. Brudzynski
		Chief Accounting Officer,
		Vice President and Controller


	Page
Definitions		3
Forward-Looking Statements		5
Part I — Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations		34
Consolidated Statement of Financial Position		35
Consolidated Statement of Cash Flows		37
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		38
Notes to Consolidated Financial Statements		39
Report of Independent Registered Public Accounting Firm		56
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		6
Item 3. Quantitative and Qualitative Disclosures About Market Risk		31
Item 4. Controls and Procedures		33
Part II — Other Information
Item 1. Legal Proceedings		57
Item 5. Other Information		57
Item 6. Exhibits		57
Signature		58
Exhibit Index		59
Executive Supplemental Retirement Plan
Amendment to the Executive Supplemental Retirement Plan
Amendment to the Supplemental Retirement Plan
Amendment to the Supplemental Savings Plan
Amendment to the Executive Deffered Compensation Plan
Awareness Letter 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


gWh		Gigawatthour of electricity

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MWh		Megawatthour of electricity

•		protects against rate shock by requiring electric utility rates to reflect a full cost of service for all electric customer classes over a 10-year period;

•		allows current electric Customer Choice customers to return to utility service at regulated rates until December 31, 2005 and at market rates thereafter;

•		requires mandatory reliability standards and sets a minimum annual 15 percent power reserve margin for all utilities and alternative energy suppliers;

•		establishes a transition charge formula;

•		establishes a low-income energy assistance surcharge to all customers receiving distribution service from an electric or gas utility;

•		establishes a lower special rate for public and private K-12 schools;

•		clarifies that environmental compliance costs can be securitized; and

•		authorizes an environmental recovery surcharge applicable to all electric customers to recover the costs of government-mandated pollution control measures.

		generally accepted accounting principles. The fair value net liability totaling approximately $75 million as of December 31, 2003, was being amortized to income through 2016, the life of the related agreements. As a result of the contract modification and termination, we recorded an adjustment to the net liability, increasing earnings in the 2004 first quarter by $48 million, net of taxes.

•		Energy technology investments - As part of our energy technology strategy, we invest in a portfolio of energy technology companies that facilitate the creation of new businesses and expand growth opportunities for existing DTE Energy businesses. Since 1997 we have held an investment in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. During May 2004, we sold 3.5 million shares of the 14.1 million shares of Plug Power stock owned as part of our renewed focus on cost management and cash generation. The sale generated $27 million in cash and increased earnings in the 2004 second quarter by $14 million, net of taxes.

		We also assessed the fair value of other technology investments in our portfolio. The assessment concluded there were “other than temporary” declines in fair value of the investments based on loan defaults and other factors. As a result of the assessment, we recorded an impairment expense in the 2004 second quarter that reduced earnings by $8 million, net of taxes.

•		On-site energy project - Our Energy Services segment owns and/or operates numerous on-site facilities, including those that deliver utility services to industrial, commercial and institutional customers. During May 2004, we formed a utility services company that acquired utility-related assets from a large automotive company and entered into a long-term agreement to provide utility and energy conservation services to the company. In the 2004 second quarter, our income was increased by the recording of a $6 million after tax fee that was generated in conjunction with developing the energy project and selling a 50% interest in the project to an unaffiliated partner.

		The revised rate request did not allocate the phase in amounts by year, but the amounts would be allocated to the customer classes as the rate caps expire.

		MPSC Interim Rate Order - On February 20, 2004, the MPSC issued an order for interim rate relief. The order authorized an interim increase in base rates, a transition charge for customers participating in the electric Customer Choice program and a new PSCR factor.

		The interim base rate increase totaled $248 million annually, effective February 21, 2004, and is applicable to all customers not subject to the rate cap. The increase has been allocated to both full-service customers ($240 million) and electric Customer Choice customers ($8 million). However, because of the rate caps under PA 141, not all of the increase will be realized in 2004. The interim order also terminated certain transition credits and authorized transition charges to electric Customer Choice customers designed to result in $30 million in additional revenues. Additionally, the MPSC authorized a PSCR factor for all customers, a credit of 1.05 mills per kilowatthour (kWh) compared to the 2.04 mills per kWh charge previously in effect. However, the MPSC order allows Detroit Edison to increase base rates for customers still subject to the cap in an equal and offsetting amount with the required reduction in the PSCR factor to maintain the total capped rate levels currently in effect for these customers.

		Although the base rate increase and transition charges total $278 million, the effects of the interim order are estimated to have increased income by $5 million, net of taxes, in the 2004 third quarter, and decreased income by $3 million, net of taxes, in the 2004 nine-month period. This lower amount is a result of the rate caps, the February 21, 2004 effective date of the interim base rate increase and the PSCR reduction effective January 1, 2004. Revenues from the interim rate order increased income $11 million, net of taxes, in the 2004 third quarter, and increased income $10 million, net of taxes, in the 2004 nine-month period. Revenues from the interim rate order also relate to items that were previously deferred as regulatory assets. The reduction in regulatory asset deferrals related to previously capped customers decreased income by $6 million, net of taxes, in the 2004 third quarter, and decreased income by $13 million, net of taxes, in the 2004 nine-month period. Amounts collected are subject to a potential refund pending a final order in this proceeding.