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 June 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 June 30, 2004, 173,728,563 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 June 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:

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

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

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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.

The majority of our earnings is derived from utility operations and our synthetic fuel business, which qualifies for Section 29 tax credits. Earnings in the 2004 second quarter were $35 million, or $.20 per diluted share, compared to losses in the 2003 second quarter of $39 million, or $.23 per diluted share. For the 2004 six-month period, our earnings were $225 million, or $1.31 per diluted share, compared to earnings of $116 million, or $.69 per diluted share, for the same 2003 period.

As discussed in the “RESULTS OF OPERATIONS” section that follows, the comparability of earnings in the six-month period was significantly impacted by discontinued businesses in 2003 and the adoption of new accounting rules. Excluding discontinued operations and the cumulative effect of accounting changes, earnings from continuing operations in the 2004 six-month period were $232 million, or $1.35 per diluted share, compared to earnings of $71 million, or $.42 per diluted share, for the same 2003 period. The significant improvement in income for both periods reflects increased contributions from our non-regulated businesses. Reduced contributions from our regulated businesses have affected the comparison. Significant items that influenced our 2004 financial performance and/or may affect future results are:

•

Lost revenues from electric Customer Choice penetration;

•

Proposed Michigan legislation to address electric Customer Choice issues;

•

An interim electric rate order increasing earnings;

•

Increased uncollectable utility accounts receivables;

•

Lower synfuel-related earnings;

•

Gains and losses; and

•

Effective tax rate adjustments.

Electric Customer Choice Program - Detroit Edison’s rates are regulated by the Michigan Public Service Commission (MPSC), while alternative suppliers can charge market-based rates. This regulation has hindered Detroit Edison’s ability to retain customers. In addition, the MPSC has maintained regulated rates for certain groups of customers that exceed the cost of service to those customers. This has resulted in high levels of participation in the electric Customer Choice program by those customers that have the highest price relative to their cost of service. As a result, we have continued to lose sales. Lost margins and electricity volumes associated with electric Customer Choice were approximately $59 million and 2,480 gigawatthours (gWh) in the 2004 second quarter and approximately $109 million and 4,622 gWh in the 2004 six-month period. This compares with lost electric Customer Choice margins and volumes of approximately $25 million and 1,844 gWh in the 2003 second quarter and $45 million and 3,051 gWh in the 2003 six-month period. Partially offsetting the impact of lost margins on income, we recorded regulatory assets of approximately $18 million and $43 million in the 2004 second quarter and six-month period, respectively, and $6 million and $12 million in the 2003 second quarter and six-month period. The regulatory assets represent an estimate of stranded costs that we believe are recoverable under existing Michigan legislation and MPSC orders. There are a number of variables and estimates that

6

impact the level of recoverable stranded costs, including weather, sales mix and wholesale electric prices. 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 lost electric Customer Choice revenues, and eliminated transition credits and implemented a transition charge for electric Customer Choice customers. Although the interim order 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:

•		requires mandatory reliability standards and sets a minimum annual 15 percent power reserve margin for all utilities and alternative energy suppliers;
•		requires financial adequacy standards for all alternative energy suppliers;
•		protects against rate shock by requiring a move to 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;
•		separates generation, transmission and distribution charges on electric customers’ bills;
•		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 is scheduled to hold hearings beginning in August 2004 in an effort to build consensus among Michigan’s electric utilities, alternative energy suppliers, and customer groups.

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 as well as rates designed to recover fuel and purchased power costs. Historically, fuel and purchased power costs have been a pass-through under the power supply cost recovery (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, and 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

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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 annually. 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.

As a result of rate caps, the different effective dates of the interim base rate increase, transition charges and the PSCR mechanism, and other factors, the interim rate order increased revenues in the 2004 second quarter by $16 million and decreased revenues in the 2004 six-month period by $1 million. Additionally, because of these factors, the interim order was only designed to increase revenues by $51 million in 2004 (Note 5). A final order from the MPSC is expected in September 2004.

Uncollectable Utility Accounts Receivables – Both our 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 $61 million in the 2004 six-month period compared to $32 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.

Synthetic Fuel Operations - We operate nine synthetic fuel production plants at eight locations. Majority interests in seven of the nine plants, representing 81 percent of the plants’ production capacity, have been sold since 2002. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service 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 are more than offset by the resulting Section 29 tax credits. In order to utilize qualifying Section 29 tax credits, a taxpayer must have sufficient taxable income, or the tax credits are carried forward to future years. We have not had sufficient taxable income to fully utilize tax credits earned in prior periods. As of December 2003, we had nearly $500 million in tax credit carry-forwards. In order to optimize income and cash flow from our synfuel operations, we intend to sell majority interests in all of our remaining synfuel plants during 2004. When we sell an interest in a synfuel facility, 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. In substance, we are receiving installment gains and

8

reduced operating losses in exchange for tax credits. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

Earnings from our synfuel operations totaled $56 million and $96 million in the 2004 second quarter and six-month period, respectively, compared to earnings of $70 million and $123 million in the same 2003 periods. The decline in earnings is due to lower synfuel production reflecting our strategy of producing synfuel primarily from plants in which we have sold interests.

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

•		Transportation and gas exchange (storage) agreements - During the 2004 first quarter, we modified our future purchase commitments under a transportation agreement and terminated a related long-term gas exchange (storage) agreement with an interstate pipeline company. The agreements were at rates that were not reflective of current market conditions and had been fair valued under U.S. generally accepted accounting principles. The fair value net liability totaling approximately $75 million as of December 31, 2003, was being amortized to income through 2016, the life of the related agreements. As a result of the contract modification and termination, we recorded an adjustment to the net liability, increasing earnings in the 2004 first quarter by $48 million, net of taxes.
•		Energy technology investments - As part of our energy technology strategy, we invest in a portfolio of energy technology companies that facilitate the creation of new businesses and expand growth opportunities for existing DTE Energy businesses. Since 1997 we have held an investment in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems. During May 2004, we sold 3.5 million shares of the 14.1 million shares of Plug Power stock owned as part of our renewed focus on cost management and cash generation. The sale generated $27 million in cash and increased earnings in the 2004 second quarter by $14 million, net of taxes.
		We also assessed the fair value of other technology investments in our portfolio. The assessment concluded there were “other than temporary” declines in fair value of the investments based on loan defaults and other factors. As a result of the assessment, we recorded an impairment expense in the 2004 second quarter that reduced earnings by $8 million, net of taxes.
•		On-site energy project - Our Energy Services segment owns and/or operates numerous on-site facilities, including those that deliver utility services to industrial, commercial and institutional customers. During May 2004, we formed a utility services company that acquired utility-related assets from a large automotive company and entered into a long-term agreement to provide utility and energy conservation services to the company. In the 2004 second quarter, we recorded 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 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 increasing income tax expense by $4 million and $10 million in the 2004 second quarter and six-month period, respectively, and increasing income tax expense by $107 million and $152 million in the comparable 2003 periods. Fluctuations in estimated annual earnings and Section 29 tax credits were the primary variables that resulted in the larger adjustments. Annual results are not affected by the quarterly effective tax rate adjustments.

Outlook - We are facing many challenges in 2004 to achieve earnings and cash flow objectives while protecting a strong balance sheet. Our financial performance over the short term will be dependent on

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preserving healthy electric and gas utilities, selling majority interests in the remaining synthetic fuel 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 continued migration of customers to the electric Customer Choice program based on false market signals. The potential implications of the electric Customer Choice program to remaining customers over the longer term could be significantly higher electricity rates.

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

We are aggressively pursuing the sales of majority interests in all of our remaining synthetic fuel projects in 2004. These sales, in addition to previously completed sales, are expected to provide over a $300 million boost to our cash flow in 2004. The availability of qualified buyers and the timing of these sales will impact this financial outcome. 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, and unconventional gas recovery. 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 second quarter were $35 million, or $.20 per diluted share, compared to losses in the 2003 second quarter of $39 million, or $.23 per diluted share. For the 2004 six-month period, our earnings were $225 million, or $1.31 per diluted share, compared to earnings of $116 million, or $.69 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 second quarter were $35 million, or $.20 per diluted share, compared to losses in the 2003 second quarter of $37 million, or $.22 per diluted share. For the 2004 six-month period, our earnings from continuing operations were $232 million, or $1.35 per diluted share, compared to earnings of $71 million, or $.42 per diluted share, for the same 2003 period. As subsequently discussed, earnings were affected by lost margins under the Customer Choice program, an electric interim rate order, increased uncollectable accounts receivables, lower 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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(1)

Includes Corporate & Other.

ENERGY RESOURCES

Power Generation — Regulated

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

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Factors impacting income: Power Generation earnings declined $45 million during the 2004 second quarter and $54 million in the 2004 six-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.

Gross margins declined $56 million during the 2004 second quarter and $91 million in the 2004 six-month period due primarily to lost margins from retail customers choosing to purchase power from alternative suppliers under the electric Customer Choice program. Detroit Edison lost 18% of retail sales in the first half of 2004, compared to 12% of such sales during the same 2003 period as a result of Customer Choice penetration. The decline in margins is also due to a revision of estimate in the 2004 second quarter in the level of sales lost to electric Customer Choice. 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 results in lower purchase power requirements, as well as excess power capacity that is 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 second quarter. However, as a result of rate caps and the different effective dates of rate adjustments previously discussed, the interim order resulted in a decrease in margins in the 2004 six-month period. Weather during 2004 was warmer than in 2003, resulting in increased margins from retail customers of $11 million in the 2004 second quarter and $3 million in the 2004 six-month period. Operating revenues and fuel and purchased power costs decreased in 2004 compared to 2003 reflecting a $1.97 per megawatt hour (MWh) (12%) decline in fuel and purchased power costs during the current quarter and a $2.16 per MWh (13%) decline during the six-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 using a more favorable power supply mix. The favorable mix is due to lower purchases, driven by lost sales under the electric Customer Choice program.

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(1)

Represents fuel costs associated with power plants.

(2)

The average purchased power amounts include hedging activities.

Depreciation and amortization expense was unchanged in the 2004 second quarter and decreased $23 million in the 2004 six-month period. Depreciation and amortization expense was affected by increased charges resulting from generation-related capital expenditures. These expenses were also affected by the income effect of recording regulatory assets totaling $22 million and $57 million in the 2004 second quarter and six-month period, respectively, compared to $21 million and $40 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 $8 million in the 2004 second quarter and $14 million in the 2004 six-month period, reflecting expenses associated with addressing the structural issues of PA 141. The increase also reflects costs of performing other non-operating activities.

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

As previously discussed, we expect cash flows and operating performance will continue to be adversely affected by the electric Customer Choice program until the inequities associated with this program are addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs 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 of $427 million annually 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.

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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 gas and coal-fired generation.

Factors impacting income: Energy Services earnings decreased $20 million in the 2004 second quarter and $33 million during the 2004 six-month period. The decline in earnings in both periods is due to lower synfuel production and a higher level of capacity sold. The comparison was also affected by 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 declines 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.

Operating revenues increased $17 million in the 2004 second quarter and $50 million in the 2004 six-month period primarily reflecting higher coal and coke sales as well as a $9 million pre-tax fee generated in conjunction with the development of an energy project. Partially offsetting the improvements were lower synfuel sales. Synfuel revenues primarily reflect our decision to only produce synfuel from seven of our nine plants. As previously discussed, our strategy is to produce synfuel primarily from plants in which we have sold interests in order to optimize earnings and cash flow. 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 significantly higher than synfuel prices. Reduced synfuel production through April 2004 is also due to lower production at one facility due to a fire in the coal mine that caused a temporary shutdown of the mine and curtailed coal

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feedstock to the facility. The mine reopened in the 2004 second quarter, and the related synfuel facility resumed normal operations. Revenues from coke sales were higher in both 2004 periods reflecting higher coke sales volumes combined with higher market prices due to limited supplies of coke in the U.S.

Operation and maintenance expense decreased $4 million in the 2004 second quarter and $9 million in the 2004 six-month period reflecting costs associated with the lower levels of synfuel production. Operation and maintenance expense in both 2003 periods 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 $35 million in the 2004 second quarter and $73 million in the 2004 six-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 $24 million in the 2004 second quarter and $39 million in the 2004 six-month period due to 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 are 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 $102 million in the 2004 second quarter and $220 million in the 2004 six-month period, reflecting higher taxable earnings and a decline in the level of Section 29 tax credits from the production and sale of synfuel. Tax credits from our synfuel operations decreased due to the sale of interests in synfuel facilities and lower synfuel production. 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 aggressively selling interests in all of our synfuel plants and have sold majority interests in seven of our nine synfuel plants, representing 81 percent of the plants’ production capacity. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base. Recently, several unaffiliated companies announced that the Internal Revenue Service (IRS) was challenging the in-service dates of some of their synthetic fuel facilities. A synfuel facility must have been placed in service prior to July 1, 1998 to generate tax credits. The in-service dates of our facilities have not been challenged. The sale of further interests in our synfuel projects continues to progress and interest remains high. However, future sales may be slowed by this recent IRS challenge. The in-service dates for eight of our nine synfuel plants have been reviewed by the IRS in conjunction with issuing determination letters and/or recently completed field audits. We believe all nine of our synthetic fuel plants meet the required in-service condition. See Note 9 for further discussion.

Although earnings from our synfuel projects were down $14 million or 20% in the 2004 second quarter and $27 million or 22% in the 2004 six-month period due to the mine fire and our decision to only produce synfuel from plants in which we have sold interests, we expect a significant increase in synfuel earnings over the balance of the year. The increase in earnings will be driven by the sale of interests in our remaining synfuel projects and the resumed production at the synfuel location that was affected by the mine fire.

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

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from our on-site energy business in the 2004 third quarter and future periods as a result of our recently executed long-term utility services’ contract with a major automotive manufacturer in the Midwest and a large manufacturer of paper products.

Power prices over the past few years have been low due, in part, to the current excess capacity in the generation industry. Additionally, a generation tolling agreement that was settled in 2003 was at above market rates. As a result of these factors, we expect lower revenues and earnings from our power generation business in 2004. We expect this reduction to be offset by increased coke sales due to higher market prices for coke.

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 increased $8 million in the 2004 second quarter, consisting of a $7 million improvement at CoEnergy and a $1 million improvement at DTE Energy Trading. Earnings in the 2004 six-month period increased $21 million, consisting of a $36 million improvement at CoEnergy, partially offset by a $15 million reduction at DTE Energy Trading.

DTE Energy Trading’s earnings in the 2004 six-month period declined primarily due to margins associated with short-term physical trading and origination activities. Margins in the 2003 six-month period were favorably impacted by increased realized gains due to greater pricing variability and reduced liquidity.

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(1)

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

(2)

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

(3)

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

During 2003, we monetized 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 as well as our ability to fully utilize Section 29 tax credits. Although the monetizations did not impact earnings, they did impact the comparability of realized and unrealized margins. The monetizations had the effect of decreasing realized margins and increasing unrealized margins in the 2004 second quarter and six-month periods.

CoEnergy’s earnings in the 2004 second quarter were affected by an improvement in realized margins from storage activities compared to the 2003 second quarter due to a lower average cost of inventory. This increase was partially offset by higher unrealized losses in 2004 on contracts that are required to be marked-to-market while underlying asset positions are not, as subsequently discussed.

CoEnergy’s earnings in the 2004 six-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.

Additionally, CoEnergy’s earnings in the 2004 six-month period were affected by a reduction in realized margins from storage activities compared to the same 2003 period which benefited from significantly higher gas prices. The decline in earnings also reflects lower unrealized gains in 2004 on contracts that are required to be marked-to-market.

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

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 power production 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 these landfill sites qualifies for Section 29 tax credits.

Factors impacting income: Earnings decreased $1 million in the 2004 second quarter and $3 million in the 2004 six-month period reflecting losses in the current quarter from discontinuing one of our Biomass sites and increased operating costs associated with ramping up the DTE PepTec Inc. business. Our first waste coal facility in Ohio became operational in late 2003.

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.

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 increased $23 million in the 2004 second quarter and $55 million in the 2004 six-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 varying operation and maintenance expenses.

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Operating revenues increased $46 million in the 2004 second quarter and $61 million in the 2004 six-month period primarily due to residential sales growth and the effects of warmer weather. The increase in the 2004 second quarter was also due to the increase in base rates resulting from the interim order. Partially offsetting these improvements was the impact of 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 $9 million in the 2004 second quarter and decreased $12 million in the 2004 six-month period. Both 2004 periods were affected by higher reserves for uncollectable accounts receivables and increased pension and health care costs. The increase in uncollectable accounts expense reflects higher past due amounts attributable to economic conditions. Partially offsetting these increased costs were benefits from our company-wide cost savings initiative as well as lower transmission expenses in the 2004 six-month period. The decrease in the current six-month period is due primarily to 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 future operating costs and other issues. Detroit Edison received an interim order in this rate case in February 2004. See Note 5 – Regulatory Matters.

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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 $3 million in the 2004 second quarter and $2 million in the 2004 six-month period, reflecting an impairment charge for an “other than temporary” decline in the fair value of a technology investment, as previously discussed. Absent this charge, results for both periods were up, reflecting growing revenue and continuing expense control.

Outlook – DTE Energy Technologies continues to take actions to reduce expenses and streamline operations. In addition, a new leader has been selected to head up our continued participation in the emerging distributed generation market. We will tightened our focus on sales of our proprietary pre-engineered and packaged continuous generation products in key applications.

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 $30 million in the 2004 second quarter and $18 million in the 2004 six-month period. As subsequently discussed, results primarily reflect varying gross margin contributions, increased operation and maintenance expenses and a non-recurring loss recorded in the 2003 first quarter.

Gross margins decreased $13 million in the 2004 second quarter and increased $8 million in the 2004 six-month period. Gross margins in the 2004 second quarter were affected by lower sales due to the economy and warmer weather in 2004 compared to the prior year, as well as higher levels of lost gas. The impact of these items on the 2004 six-month period was more than offset by the effects of a $26.5 million pre-tax reserve recorded in the 2003 first quarter for the potential disallowance in gas costs pursuant to an MPSC

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order in MichCon’s 2002 gas cost recovery (GCR) plan case (Note 5). Operating revenues and cost of gas in the 2004 six-month period 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 increased $26 million in the 2004 second quarter and $43 million in the 2004 six-month period primarily due to higher reserves for uncollectable accounts receivables, 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. Partially offsetting these increases were benefits from company-wide cost savings initiatives.

Income taxes in both 2004 periods were favorably 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 our past due receivables would unfavorably affect operating results. Energy assistance programs funded by the federal government and the State of Michigan remain critical to MichCon’s ability to control uncollectable accounts receivable expenses. We are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory.

As a result of the continued increase in operating costs, MichCon filed a rate case in September 2003 to increase rates by $194 million annually to address future operating costs and other issues. 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 well integrated with other DTE Energy entities.

Factors impacting income: Earnings decreased $1 million in the 2004 second quarter and $5 million in the 2004 six-month period resulting from gains recorded in the 2003 first and second quarters from selling certain gas properties. The declines are partially offset by increased earnings from DTE’s interest in an interstate transmission pipeline as a result of an additional 15% ownership acquired in late 2003, as well as increased storage sales.

Outlook – We expect to further develop our gas production properties in northern Michigan and our pipelines and storage assets to support other DTE Energy businesses. Additionally, we expect to continue to invest in opportunities in unconventional gas production to leverage our experience in those areas.

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

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& 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 improved $141 million in the 2004 second quarter and $200 million in the 2004 six-month period. Results reflect adjustments in both years to normalize the effective income tax rate. There were unfavorable adjustments of $4 million and $10 million in the 2004 second quarter and six-month period, respectively, compared to unfavorable adjustments of $107 million and $152 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 periods were 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 six-month period earnings include a $15 million cash contribution to the DTE Energy Foundation, funded with proceeds received from the sale of International Transmission Company (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 generally accepted accounting principles, we classified SMGC as a discontinued operation in the 2004 first quarter and recognized a net of tax impairment loss of approximately $7 million representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill.

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

See Note 3 for further discussion.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

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

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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, such as 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 $109 million in the 2004 six-month period, cash from operations totaling $519 million was up $191 million from the comparable 2003 period. The operating cash flow comparison reflects an increase of $146 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), and a $45 million improvement in working capital and other requirements. A portion of this improvement is attributable to the change in our strategy to only produce synfuel from plants in which we have sold interests. As previously discussed, synfuel projects generate operating losses, which are more than offset by tax credits that we have been unable to fully utilize, and therefore negatively affect operating cash flow. Cash from working capital reflects improvements in inventories, 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 $164 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 $617 million in the 2004 six-month period as 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, ranging from $750 million to $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. Until our two rate cases are resolved, we intend to hold utility capital spending at 2003 levels.

Capital spending for general corporate purposes will increase in 2004 primarily as a result of DTE2, our company-wide initiative to improve existing processes and to implement new core information systems, that replace existing systems for finance, human resources, supply chain and work management that are reaching the end of useful lives. 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 $477 million during the 2004 six-month period, compared to the same 2003 period, due to lower issuances of new long-term debt, and fewer repurchases of long- and short-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 on maintaining an investment grade credit rating and maintaining leverage at approximately 50% or lower (excluding certain debt, principally securitization debt).

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

Debt maturing in the latter half of 2004 totals approximately $83 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 support our use of letters of credit and the issuance of commercial paper.

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 the company’s 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 have been developed through efforts of the Committee of Chief Risk Officers (CCRO), a committee of chief risk officers from companies active in both physical and financial energy trading and marketing. We believe the disclosures provide enhanced transparency of the activities and position of our Energy Trading & Marketing segment.

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

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

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(1)

“Proprietary Trading” represents derivative activity transacted with the intent of capturing profits on forward price movements.

(2)

“Structured Contracts” represent derivative activity transacted with the intent to capture profits by originating substantially 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.

(3)

“Owned Assets” represent derivative activity associated with assets owned by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Derivatives are generally executed with the intent of locking in and optimizing profits without creating additional risk.

Maturity of Fair Value of MTM Energy Contract Net Assets

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

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

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Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). As of June 30, 2004, the company has a floating rate debt to total debt ratio of approximately 11% (excluding securitized debt).

Foreign Currency Risk

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

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal and coke from and to numerous companies operating in the steel, automotive, energy, retail and other industries. A number of customers and suppliers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We closely monitor these bankruptcies, regularly review contingent matters relating to these bankruptcies and record provisions for amounts considered probable of loss. We believe our accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

Summary of Sensitivity Analysis

We performed a sensitivity analysis to calculate the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at June 30, 2004 by a hypothetical 10% and calculating the resulting change in the fair values of the commodity, debt and foreign currency agreements.

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The results of the sensitivity analysis calculations follow:

(in Millions)

CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures

Management of the company carried out an evaluation, under the supervision and with the participation of the company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2004, which is the end of the period covered by this report. Based on this evaluation, the company’s Chief Executive Officer and Chief Financial Officer have concluded that such controls and procedures are effectively designed to ensure that required information disclosed by the company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and timely reported in accordance with Commission’s rules and forms.

(b) Changes in internal control over financial reporting

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

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DTE Energy Company