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

3

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.

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.

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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.

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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

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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.

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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.

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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.

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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.

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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.

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

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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.

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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.

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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

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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.

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CAPITAL RESOURCES AND LIQUIDITY

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

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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.

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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.

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•

“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.

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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.

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.

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.

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