UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

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

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.

DTE Energy Company

Quarterly Report on Form 10-Q
Quarter Ended September 30, 2004

Table of Contents

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DEFINITIONS

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Units of Measurement

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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:

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

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

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

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nuclear regulations and operations associated with nuclear facilities;

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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;

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implementation of electric and gas Customer Choice programs;

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

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employee relations and the impact of collective bargaining agreements;

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unplanned outages;

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

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the timing and extent of changes in interest rates;

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the level of borrowings;

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

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effects of competition;

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

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contributions to earnings by non-regulated businesses;

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

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the ability to recover costs through rate increases;

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the availability, cost, coverage and terms of insurance;

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

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changes in accounting standards and financial reporting regulations;

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

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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.

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DTE Energy Company

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:

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Lost revenues from electric Customer Choice penetration;

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Proposed Michigan legislation to address electric Customer Choice issues;

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Interim electric and gas rate orders;

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Increased uncollectable utility accounts receivables;

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

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Gains and losses; and

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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

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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,

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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.

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.

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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:

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.

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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.

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		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.

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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.

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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

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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).

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

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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.