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 March 31, 2005

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 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ  No o

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

Yes þ  No o

At March 31, 2005, 174,175,040 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 March 31, 2005

TABLE OF CONTENTS

Definitions

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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:

•	the effects of weather and other natural phenomena on operations and sales to customers, and purchases from suppliers;
•	economic climate and growth or decline in the geographic areas where we do business;
•	environmental issues, laws and regulations, and the cost of remediation and compliance associated therewith;
•	nuclear regulations and operations associated with nuclear facilities;
•	the higher price of oil and its impact on the value of Section 29 tax credits, and the ability to utilize and/or sell interests in facilities producing such credits;
•	implementation of electric and gas Customer Choice programs;
•	impact of electric and gas utility restructuring in Michigan, including legislative amendments;
•	employee relations and the impact of collective bargaining agreements;
•	unplanned outages;
•	access to capital markets and capital market conditions and the results of other financing efforts which can be affected by credit agency ratings;
•	the timing and extent of changes in interest rates;
•	the level of borrowings;
•	changes in the cost and availability of coal and other raw materials, purchased power and natural gas;
•	effects of competition;
•	impact of regulation by FERC, MPSC, NRC and other applicable governmental proceedings and regulations;
•	contributions to earnings by non-utility businesses;
•	changes in federal, state and local tax laws and their interpretations, including the Internal Revenue Code, regulations, rulings, court proceedings and audits;
•	the ability to recover costs through rate increases;
•	the availability, cost, coverage and terms of insurance;
•	the cost of protecting assets against or damage due to terrorism;
•	changes in accounting standards and financial reporting regulations;
•	changes in federal or state laws and their interpretation with respect to regulation, energy policy and other business issues; and
•	changes in the economic and financial viability of our suppliers, customers and trading counterparties, and the continued ability of such parties to perform their obligations to the Company.

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

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DTE ENERGY COMPANY
Management’s Discussion and Analysis
of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with approximately $7 billion in revenues in 2004 and approximately $21 billion in assets at December 31, 2004. 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-utility subsidiaries involved in energy-related businesses predominantly in the Midwest and eastern U.S.

A significant portion of our earnings is derived from our utility operations, synthetic fuel business, and energy marketing and trading operations. Earnings in first quarter of 2005 were $122 million, or $.70 per diluted share, compared to earnings in the 2004 first quarter of $190 million, or $1.11 per diluted share. In June 2004, we adopted Financial Accounting Standards Board Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” retroactive to January 1, 2004 and as a result earnings for the first quarter of 2004 have been restated. As a result of the restatement, earnings for the period ending March 31, 2004 increased by $4 million or $.02 per diluted share.

The items discussed below influenced our first quarter 2005 financial performance and/or may affect future results are:

•	Synfuel-related earnings and the impact of higher oil prices;
•	Gas Cost Recovery and gas final rate orders; and
•	Electric Customer Choice program.

Synthetic fuel operations

We operate nine synthetic fuel production plants at eight locations. Since 2002, we have sold interests in eight of the nine plants, representing approximately 88% of our total production capacity. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (IRS) rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuel produced from coal. Synfuel-related tax credits expire in December 2007.

Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. In order to recognize Section 29 tax credits, a taxpayer must have sufficient taxable income in the year the tax credit is generated. Once earned, the tax credits are utilized subject to certain limitations but can be carried forward indefinitely. We have not had sufficient taxable income to fully utilize tax credits earned in prior periods. As of December 2004, we had $483 million in tax credit carry-forwards. In order to optimize income and cash flow from our synfuel operations, we have sold interests in eight of our nine facilities and intend to sell interests in the remaining plant during 2005, representing 99% of our production capacity. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Gain recognition is dependent on the synfuel production qualifying for Section 29 tax credits and the value of such credits as subsequently discussed. In substance, we are receiving synfuel 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.

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The value of a Section 29 tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS in April of the following year. Additionally, the value 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 recently has been $4 — $7 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2004 and 2005 are as follows:

Numerous recent events have significantly increased domestic crude oil prices, including terrorism, storm-related supply disruptions and strong worldwide demand. Through March 31, 2005, the NYMEX closing price of a barrel of oil has averaged $50, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to a $43 to $46 Reference Price (assuming that such price was to continue for the entire year.) For 2005 and later years, if the Reference Price falls within or exceeds the phase-out range, the availability of synfuel tax credits in that year would be reduced or eliminated, respectively.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectability is assured. The variable component includes an estimate of tax credits allocated to our partners, is subject to refund based on the annual oil price phase out, and is recognized as a gain only when probability of refund is considered remote and collectability is assured. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities. This amount is subject to refund based on the annual oil price phase out. To assess the probability of refund, we use valuation and analyst models that calculate the probability of surpassing the estimated lower band of the phase-out range for the Reference Price of oil for the year. Due to the rise in oil prices, there is a possibility that the Reference Price of oil could reach the threshold at which Section 29 tax credits phase out. While we believe the possibility of phase out is unlikely, we have not met the strict accounting gain recognition criteria that would allow us to recognize the gains on the variable component. During the first quarter of 2005, we deferred $41 million pretax of the variable component of synfuel-related gains until there is greater certainty of recognition. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria is met. It is possible that additional gains will be deferred in the second and/or third quarters until there is persuasive evidence that no tax credit phase out will occur. This will result in shifting earnings from earlier quarters to later quarters.

As discussed in Note 8, we have entered into derivative and other contracts to economically hedge our 2005 and 2006 synfuel cash flow exposure related to the risk of an increase in oil prices. The derivative contracts are accounted for under the mark to market method with changes in their fair value recorded as an adjustment to synfuel gains. We recorded a mark to market gain during the 2005 first quarter that increased 2005 synfuel gains by $54 million pre-tax. As part of our synfuel-related risk management strategy, we continue to evaluate alternatives available to mitigate unhedged exposure to oil price volatility.

Assuming no synfuel tax credit phase out in future years, we expect cash flow from our synfuel business to total approximately $1.6 billion between 2005 and 2008. The source of synfuel cash flow includes cash from operations, asset sales, and the utilization of Section 29 tax credits carried forward from synfuel production prior to 2004.

Gas operations

Gas cost recovery order - In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per thousand cubic feet (Mcf) for January 2002 billings and up to

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$4.38 per Mcf for the remainder of 2002. Consistent with the prior order, MichCon recognized a regulatory asset representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. MichCon’s 2002 GCR reconciliation case was filed with the MPSC in February 2003. The Staff and various intervening parties in this proceeding sought to have the MPSC disallow $26 million representing unbilled revenues at December 2001. On April 28, 2005, the MPSC issued an order in the 2002 GCR reconciliation case that disallowed $26 million plus accrued interest of $3 million. We recorded the impact of the disallowance in the first quarter of 2005.

Gas final rate order - On April 28, 2005, the MPSC issued an order for final rate relief. The MPSC granted a base rate increase to MichCon of $61 million annually, effective April 29, 2005. This amount is an increase of $26 million over the $35 million in interim rate relief approved in September 2004. The rate increase was based on a 50% debt and 50% equity capital structure and an 11% rate of return on common equity.

The MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC. The MPSC also approved the deferral of the non-capitalized portion of the negative pension expense. MichCon will record a regulatory liability in its financial statements for any negative pension costs as determined under generally accepted accounting principles. In addition, the MPSC approved a one-way tracker which provided for $25 million which is refundable in the event that the funds are not expended for safety and training operation and maintenance expenses.

The MPSC order reduces MichCon’s depreciation rates, and the related revenue requirement associated with depreciation expense by $14.5 million with no impact on net income for the quarter ended March 31, 2005.

The MPSC did not allow the recovery of approximately $25 million of costs allocated to MichCon that were incurred by DTE Energy as a result of the acquisition of MCN Energy.

The MPSC order also resulted in the disallowance of computer system and equipment costs and adjustments to environmental regulatory assets and liabilities. The MPSC disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. MichCon impaired this asset by approximately $42 million in the first quarter of 2005. This impairment is not reflected at DTE Energy since this disallowance was previously reserved at the time of the MCN acquisition in 2001. The MPSC disallowed approximately $6 million of certain computer equipment and related depreciation. The MPSC order also disallowed recovery of certain environmental costs related to remediation of manufactured gas plants of approximately $6 million.

Electric Customer Choice Program

Since 2002, Michigan residents and businesses have had the option of participating in the electric Customer Choice program. This program is designed to give all customers added choices and the opportunity to benefit from lower power costs resulting from competition. However, Detroit Edison’s rates are regulated by the 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 rates relative to their cost of service, primarily commercial and industrial businesses. As a result, our margins continue to be affected. To address this issue, we filed a revenue neutral rate restructuring proposal in February 2005 designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, Detroit Edison’s commercial and industrial rates would be lowered in 2006, but residential rates would increase over a five-year period beginning in 2007. The number and mix of customers participating in the electric Customer Choice program could be impacted under the rate restructuring.

The financial impact of electric Customer Choice was mitigated by the issuance of electric interim and final rate orders in 2004 that increased base rates, including the recovery of lost margins and transition charges. The final rate order lost margin recovery was based on a 2004 electric Customer Choice volume

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estimate of 9,245 gWh. The electric Customer Choice volumes in the first quarter of 2005 were 1,722 gWh as compared to 1,975 gWh in the first quarter of 2004. These lower volumes were offset by an increase in higher margin commercial customer participation in the Choice program resulting in an immaterial effect on margins. With current regulation continuing to hinder our ability to retain certain customers, we will continue working with the MPSC to address issues associated with the electric Customer Choice program including the rate restructuring proposal discussed above.

Outlook - In 2005, we will focus on maintaining a strong utility base, pursuing a growth strategy focused on value creation in targeted energy markets, maintaining a strong balance sheet and paying an attractive dividend. The impact of the electric and gas rate orders is expected to increase utility earnings in 2005 and 2006 as rate caps expire.

Our financial performance will be dependent on successfully redeploying an expected $1.6 billion of cash flow through 2008, primarily associated with proceeds from the sale of interests in synfuel facilities. Our objective for cash redeployment is to strengthen the balance sheet and coverage ratios, as well as replace the value of synfuels that is currently inherent in our share price. We expect to use this cash to reduce parent Company debt. Secondly, we will continue to pursue growth investments that meet our strict risk-return and value creation criteria. Share repurchases will be used to build share value if adequate investment opportunities are not available.

RESULTS OF OPERATIONS

Our earnings for the 2005 first quarter were $122 million, or $.70 per diluted share, compared to earnings of $190 million, or $1.11 per diluted share in the 2004 first quarter. As subsequently discussed, the comparability of earnings was impacted by our discontinued business, Southern Missouri Gas Company. Excluding discontinued operations, our earnings from continuing operations for the 2005 first quarter were $122 million, or $.70 per diluted share, compared to earnings of $197 million, or $1.15 per diluted share in the first quarter 2004. 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 utility and non-utility operations. The balance of our business consisted of Corporate & Other. This resulted in the following reportable segments. In the second quarter of 2005, we expect to realign our business units as discussed in Note 1.

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ENERGY RESOURCES

Utility - Power Generation

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

Factors impacting income: Power Generation earnings decreased $4 million during the 2005 first quarter. As subsequently discussed, these results primarily reflect increased depreciation and amortization expenses, partially offset by higher rates due to the November 2004 MPSC final rate order and lower operations and maintenance expense.

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Gross margins increased $22 million primarily due to rate increases as a result of the MPSC final rate order issued in November 2004. Additionally, the first quarter of 2005 has seen the return of customers who formerly participated in the Customer Choice program. Detroit Edison lost 13 % of retail sales in the 2005 first quarter and 15% of such sales in the 2004 first quarter as a result of Customer Choice penetration. Operating revenues and fuel and purchased power costs increased in the 2005 first quarter compared to the 2004 first quarter reflecting a $3.46 per megawatt hour (MWh) (23%) increase in power cost which is a pass-through with the reinstatement of the PSCR. The increase in power supply cost is driven by higher purchase power rates, higher coal prices and increased power purchases due to the outage at our nuclear facility, Fermi 2, which was offline for 14 days during the 2005 first quarter. Pursuant to the MPSC final rate order, transmission expenses previously recorded in Energy Distribution Utility – Power Distribution operation and maintenance expenses are now reflected in Energy Resources Utility – Power Generation’s purchased power expenses. The PSCR mechanism provides related revenues for the transmission expense.

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

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Operation and maintenance expense decreased $9 million in the first quarter of 2005. Pursuant to the MPSC final rate order, merger interest is no longer allocated to Detroit Edison. The 2005 period also experienced lower benefit costs, partially offset by increased power plant outage expense.

Depreciation and amortization expense increased $39 million in the first quarter of 2005. The increase reflects the income effect of recording regulatory assets, which lowers depreciation and amortization expenses. The interim and final electric rate orders in 2004 recover PA 141 costs previously deferred as regulatory assets. As a result, the regulatory asset deferrals totaled $13 million in the first quarter of 2005 compared to $42 million in the first quarter of 2004.

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 natural gas, plant performance, changes in economic conditions, weather and the levels of customer participation in the electric Customer Choice program.

As previously discussed, we expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are resolved. We have addressed certain issues of the electric Customer Choice program in our revenue neutral February 2005 rate restructuring proposal. We cannot predict the outcome of these matters.

In conjunction with the sale of the transmission assets of International Transmission Company (ITC) in February 2003, the Federal Energy Regulatory Commission (FERC) froze ITC’s transmission rates through December 2004. Annual rate adjustments pursuant to a formulistic pricing mechanism will result in an estimated increase in Detroit Edison’s transmission expense of $50 million annually, beginning in January 2005. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission revenues lost as a result of a FERC order modifying the pricing of transmission service in the Midwest. During the first quarter of 2005 Detroit Edison recorded an estimated $9 million of additional expense. Detroit Edison anticipates additional expenses $1 million per month from April 2005 through March 2006. Detroit Edison is expected to incur an additional $15 million in 2005 for charges related to the implementation of Midwest Independent Transmission System Operator’s open market. Detroit Edison received rate orders in 2004 that allow for the recovery of increased transmission expenses through the PSCR mechanism.

See Note 5 – Regulatory Matters.

Energy Services

Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and Non-utility Power Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. 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 acquires coal and gas-fired generation.

Factors impacting income: Energy Services earnings increased $34 million during the 2005 first quarter. As subsequently discussed, the comparability of results is affected by the gains recognized from selling interests in our synfuel plants and gains on synfuel hedges.

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Operating revenues increased $57 million in the first quarter of 2005, reflecting higher synfuel and coke sales, along with higher market prices for our coke production.

The improvement in synfuel revenues results from increased production due to sales of project interests in prior periods, reflecting our strategy to produce synfuel primarily from plants in which we had sold interests in order to optimize income and cash flow. As previously discussed, 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. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold.

Operation and maintenance expense increased $52 million primarily reflecting costs associated with the increased levels of synfuel production.

Asset Gains and Losses, net increased $34 million in the first quarter of 2005. The improvements are due to mark to market gains on derivatives used to economically hedge our cash flow exposure related to the risk of an increase in oil prices. The improvement is also due to additional sales of interests in our synfuel projects resulting in fixed payment-related gains, partially offset by the deferral of variable payment-related gains, as previously discussed. During the first quarter of 2005, we recorded an $82 million pre-tax gain on synfuel sales. The following table displays the various components that comprise the determination of gains recorded in the first quarter of 2005 related to synfuels.