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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period ended June 30, 2004

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


Michigan (State or other jurisdiction of incorporation or organization)		38-3217752 (I.R.S. Employer Identification No.)

2000 2nd Avenue, Detroit, Michigan (Address of principal executive offices)		48226-1279 (Zip Code)

313-235-4000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X No __

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

Yes X No __

At June 30, 2004, 173,728,563 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.

DEFINITIONS


Company		DTE Energy Company and subsidiary companies

Customer Choice		Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas.

Detroit Edison		The Detroit Edison Company (a direct wholly owned subsidiary of DTE Energy Company) and subsidiary companies

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

FERC		Federal Energy Regulatory Commission

GCR		A gas cost recovery mechanism authorized by the MPSC that was reinstated by MichCon in January 2002, permitting MichCon to pass the cost of natural gas to its customers.

ITC		International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)

MichCon		Michigan Consolidated Gas Company (an indirect wholly owned subsidiary of DTE Energy) and subsidiary companies

MPSC		Michigan Public Service Commission

NRC		Nuclear Regulatory Commission

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

Section 29 Tax Credits		Tax credits authorized under Section 29 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources.

SFAS		Statement of Financial Accounting Standards

Stranded Costs		Costs incurred by utilities in order to serve customers in a regulated environment that are not expected to be recoverable if customers switch to alternative suppliers of electricity and gas.

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

Forward-Looking Statements

Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those contemplated, projected, estimated or budgeted in such forward-looking statements. There are many factors that may impact forward-looking statements including, but not limited to, the following:

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

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

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

• nuclear regulations and operations associated with nuclear facilities;

• the 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.

DTE Energy Company

Management’s Discussion and Analysis
of Financial Condition and Results of Operations

OVERVIEW

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

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

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

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.


	Quarter			Six Months
	Ended			Ended
	June 30			June 30
Effect of Interim Rate Order (in Millions)	2004			2004
Base Rate Increase and Transition Charges - effective February 21, 2004	$	45		$	58
PSCR Reduction — effective January 1, 2004.		(29	)		(59	)

Revenue Increase (Decrease)	$	16		$	(1	)

Net Income Increase (Decrease)	$	10		$	(1	)

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

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

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.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
Net Income (Loss)
Energy Resources
Regulated – Power Generation	$	1		$	46		$	17		$	71

Non-regulated
Energy Services		56			76			94			127
Energy Marketing & Trading		(7	)		(15	)		50			29
Other		—			1			(2	)		1

Total Non-regulated		49			62			142			157

		50			108			159			228

Energy Distribution
Regulated – Power Distribution		7			(16	)		35			(20	)
Non-regulated		(8	)		(5	)		(11	)		(9	)

		(1	)		(21	)		24			(29	)

Energy Gas
Regulated – Gas Distribution		(38	)		(8	)		33			51
Non-regulated		5			6			9			14

		(33	)		(2	)		42			65

Corporate & Other		19			(122	)		7			(193	)

Income (Loss) from Continuing Operations
Regulated		(30	)		22			85			102
Non-regulated (1)		65			(59	)		147			(31	)

		35			(37	)		232			71

Discontinued Operations		—			(2	)		(7	)		72
Cumulative Effect of Accounting Changes		—			—			—			(27	)

Net Income (Loss)	$	35		$	(39	)	$	225		$	116

Diluted Earnings (Loss) per Share
Regulated	$	(.17	)	$	.13		$	.49		$	.61
Non-regulated (1)		.37			(.35	)		.86			(.19	)

Income from Continuing Operations		.20			(.22	)		1.35			.42
Discontinued Operations		—			(.01	)		(.04	)		.43
Cumulative Effect of Accounting Changes		—			—			—			(.16	)

Net Income (Loss)	$	.20		$	(.23	)	$	1.31		$	.69

(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.

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.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
Operating Revenues	$	508		$	589		$	1,059		$	1,206
Fuel and Purchased Power		199			224			409			465

Gross Margin		309			365			650			741
Operation and Maintenance		165			158			347			341
Depreciation and Amortization		61			61			111			134
Taxes other than Income		37			38			76			81

Operating Income		46			108			116			185
Other (Income) and Deductions		45			37			91			77
Income Tax Provision		—			25			8			37

Net Income	$	1		$	46		$	17		$	71

Operating Income as a Percent of Operating Revenues		9	%		18	%		11	%		15	%

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.


	Three Months Ended				Six Months Ended
	June 30				June 30
	2004		2003		2004		2003
Electric Sales (in Thousands of MWh)
Retail		9,434		10,427		19,857		21,602
Wholesale and Other		1,578		1,170		3,764		2,446

		11,012		11,597		23,621		24,048

Power Generated and Purchased (in Thousands of MWh)
Power Plant Generation
Fossil		8,507		9,207		18,291		18,341
Nuclear		2,409		1,301		4,817		3,549

		10,916		10,508		23,108		21,890
Purchased Power		1,226		1,843		2,424		3,731

System Output		12,142		12,351		25,532		25,621

Average Unit Cost ($/MWh)
Generation (1)	$	12.68	$	13.56	$	12.78	$	13.42

Purchased Power (2)	$	34.04	$	35.26	$	34.29	$	34.48

Overall Average Unit Cost	$	14.83	$	16.80	$	14.84	$	17.00

(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.

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.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
Operating Revenues
Coal-Based Fuels	$	234		$	230		$	463		$	426
On-Site Energy Projects		27			15			49			37
Power Generation-Non-Regulated		4			3			5			4

		265			248			517			467
Operation and Maintenance		283			287			542			551
Gains on Sale of Interests in Synfuel Projects		(58	)		(23	)		(106	)		(33	)
Depreciation and Amortization		22			23			41			53
Taxes Other Than Income		4			5			6			10

Operating Income (Loss)		14			(44	)		34			(114	)
Other (Income) and Deductions		(56	)		(32	)		(86	)		(47	)
Income Taxes
Provision (Benefit)		25			(4	)		42			(23	)
Section 29 Tax Credits		(11	)		(84	)		(16	)		(171	)

		14			(88	)		26			(194	)

Net Income	$	56		$	76		$	94		$	127

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

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

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.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
DTE Energy Trading
Margins – Gains (Losses)
Realized (1)	$	17		$	15		$	31		$	48
Unrealized (2)		(8	)		(6	)		(8	)		—

		9			9			23			48
Operating and Other Costs		7			9			14			16
Income Tax Provision		1			—			3			11

Net Income	$	1		$	—		$	6		$	21

CoEnergy
Margins – Gains (Losses) (3)
Realized (1)	$	(15	)	$	(7	)	$	(18	)	$	29
Unrealized (2)		6			(13	)		17			(10	)

		(9	)		(20	)		(1	)		19
Gain From Contract Modification / Termination		—			—			74			—
Operating and Other Costs		3			3			5			6
Income Tax Provision (Benefit)		(4	)		(8	)		24			5

Net Income (Loss)	$	(8	)	$	(15	)	$	44		$	8

Total Energy Marketing & Trading Net Income	$	(7	)	$	(15	)	$	50		$	29

(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.

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.


	Three Months Ended						Six Months Ended
	June 30						June 30
	2004			2003			2004			2003
(in Millions)
Operating Revenues	$	327		$	281		$	662		$	601
Fuel and Purchased Power		—			2			6			9
Operation and Maintenance		195			186			356			368
Depreciation and Amortization		61			62			125			125
Taxes other than Income		24			27			53			56

Operating Income		47			4			122			43
Other (Income) and Deductions		35			29			68			73
Income Tax Provision (Benefit)		5			(9	)		19			(10	)

Net Income (Loss)	$	7		$	(16	)	$	35		$	(20	)

Operating Income as a Percent of Operating Revenues		14	%		1	%		18	%		7	%

Three Months Ended

Six Months Ended

June 30

Electric Deliveries
(in Thousands of MWh)

2004

2003

2004

2003

Residential

3,472

3,243

7,541

7,098

Commercial

3,049

3,962

6,540

8,088

Industrial

2,810

3,134

5,564

6,219

Wholesale

553

550

1,109

1,126

Other

103

212

196

9,987

10,978

20,966

22,727

Electric Choice

2,480

1,844

4,622

3,051

Total Electric Sales and Deliveries

12,467

12,822

25,588

25,778

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.

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.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
Operating Revenues	$	276		$	289		$	1,005		$	928
Cost of Gas		163			163			662			593

Gross Margin		113			126			343			335
Operation and Maintenance		112			86			210			167
Depreciation and Amortization		25			26			51			50
Taxes other than Income		13			14			25			31

Operating Income (Loss)		(37	)		—			57			87
Other (Income) and Deductions		11			11			24			22
Income Tax Provision (Benefit)		(10	)		(3	)		—			14

Net Income (Loss)	$	(38	)	$	(8	)	$	33		$	51

Operating Income (Loss) as a Percent of Operating Revenues		(13	)%		—	%		6	%		9	%

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

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

& 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.

CAPITAL RESOURCES AND LIQUIDITY


	Six Months Ended
	June 30
(in Millions)	2004			2003
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	225		$	116
Depreciation, depletion and amortization		346			381
Deferred income taxes		112			61
Gain on sale ITC, synfuel and other assets, net		(130	)		(151	)
Working capital and other		(34	)		(79	)

		519			328

Investing activities:
Plant and equipment expenditures – regulated		(363	)		(356	)
Plant and equipment expenditures – non-regulated		(33	)		(44	)
Investment in joint ventures		(36	)		(4	)
Proceeds from sale of ITC, synfuel and other assets		147			647
Restricted cash and other investments		(28	)		61

		(313	)		304

Financing activities:
Issuance of long-term debt and common stock		439			501
Redemption of long-term debt		(565	)		(800	)
Short-term borrowings, net		120			(184	)
Dividends on common stock and other		(179	)		(179	)

		(185	)		(662	)

Net Increase (Decrease) in Cash and Cash Equivalents	$	21		$	(30	)

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

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).

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.


	Energy Marketing & Trading

	Proprietary			Structured			Owned						Gas
(in Millions)	Trading (1)			Contracts (2)			Assets (3)			Total			Production			Total
MTM at December 31, 2003	$	10		$	17		$	(171	)	$	(144	)	$	(80	)	$	(224	)

Reclassed to realized upon settlement		(9	)		(7	)		52			36			(23	)		13
Changes in fair value		1			2			(29	)		(26	)		—			(26	)
Amortization of option premiums		(1	)		—			—			(1	)		—			(1	)

Amounts impacting unrealized income		(9	)		(5	)		23			9			(23	)		(14	)
Effective portion of change in fair value		—			—			—			—			(25	)		(25	)

MTM at June 30, 2004	$	1		$	12		$	(148	)	$	(135	)	$	(128	)	$	(263	)

(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.


	Energy Marketing & Trading
																			Total
	Proprietary			Structured			Owned									Gas			Assets
(in Millions)	Trading			Contracts			Assets			Eliminations			Total			Production			(Liabilities)
Current assets	$	72		$	136		$	68		$	(41	)	$	235		$	—		$	235
Noncurrent assets		18			112			103			(37	)		196			—			196

Total MTM assets		90			248			171			(78	)		431			—			431

Current liabilities		(70	)		(133	)		(170	)		42			(331	)		(57	)		(388	)
Noncurrent liabilities		(19	)		(103	)		(149	)		36			(235	)		(71	)		(306	)

Total MTM liabilities		(89	)		(236	)		(319	)		78			(566	)		(128	)		(694	)

Total MTM net assets (liabilities)	$	1		$	12		$	(148	)	$	—		$	(135	)	$	(128	)	$	(263	)

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.


										2007			Total
										And			Fair
(in Millions)	2004			2005			2006			Beyond			Value
Source of Fair Value
Proprietary Trading	$	7		$	(6	)	$	(1	)	$	1		$	1
Structured Contracts		—			10			2			—			12
Owned Assets		(88	)		(37	)		(15	)		(8	)		(148	)

Energy Marketing & Trading		(81	)		(33	)		(14	)		(7	)		(135	)
Gas Production		(29	)		(53	)		(39	)		(7	)		(128	)

Total	$	(110	)	$	(86	)	$	(53	)	$	(14	)	$	(263	)

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.

The results of the sensitivity analysis calculations follow:

(in Millions)


	Assuming a			Assuming a
	10%			10%
	increase			decrease			Change in the
Activity	in rates			in rates			fair value of
Gas contracts	$	(17	)	$	17		Commodity contracts
Power contracts	$	(2	)	$	1		Commodity contracts
Interest rate risk	$	(290	)	$	308		Long-term debt
Foreign currency risk	$	.2		$	(.2	)	Forward contracts

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.

DTE Energy Company

Consolidated Statement of Operations (unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions, Except per Share Amounts)	2004			2003			2004			2003
Operating Revenues	$	1,501		$	1,600		$	3,594		$	3,695

Operating Expenses
Fuel, purchased power and gas		377			493			1,118			1,306
Operation and maintenance		851			792			1,633			1,556
Depreciation, depletion and amortization		179			180			346			377
Taxes other than income		60			87			145			184
Gains on sale of assets, net		(61	)		(23	)		(111	)		(16	)

		1,406			1,529			3,131			3,407

Operating Income		95			71			463			288

Other (Income) and Deductions
Interest expense		129			138			260			277
Interest income		(17	)		(7	)		(27	)		(15	)
Minority interest		(51	)		(36	)		(81	)		(52	)
Other income		(42	)		(18	)		(59	)		(31	)
Other expenses		23			18			45			51

		42			95			138			230

Income (Loss) Before Income Taxes		53			(24	)		325			58
Income Tax Provision (Benefit)		18			13			93			(13	)

Income (Loss) from Continuing Operations		35			(37	)		232			71

Income (Loss) from Discontinued Operations, net of tax (Note 3)		—			(2	)		(7	)		72
Cumulative Effect of Accounting Changes, net of tax (Note 2)		—			—			—			(27	)

Net Income (Loss)	$	35		$	(39	)	$	225		$	116

Basic Earnings (Loss) per Common Share (Note 6)
Income (Loss) from continuing operations	$	.20		$	(.22	)	$	1.35		$	.43
Discontinued operations		—			(.01	)		(.04	)		.43
Cumulative effect of accounting changes		—			—			—			(.17	)

Total	$	.20		$	(.23	)	$	1.31		$	.69

Diluted Earnings (Loss) per Common Share (Note 6)
Income (Loss) from continuing operations	$	.20		$	(.22	)	$	1.35		$	.42
Discontinued operations		—			(.01	)		(.04	)		.43
Cumulative effect of accounting changes		—			—			—			(.16	)

Total	$	.20		$	(.23	)	$	1.31		$	.69

Average Common Shares
Basic		173			168			172			167
Diluted		174			168			172			168
Dividends Declared per Common Share	$	.515		$	.515		$	1.03		$	1.03

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Financial Position


	(Unaudited)
	June 30			December 31
(in Millions)	2004			2003
ASSETS
Current Assets
Cash and cash equivalents	$	75		$	54
Restricted cash		121			131
Accounts receivable
Customer (less allowance for doubtful accounts of $129 and $99, respectively)		859			877
Accrued unbilled revenues		212			316
Other		464			338
Inventories
Fuel and gas		390			467
Materials and supplies		161			162
Assets from risk management and trading activities		238			186
Other		207			181

		2,727			2,712

Investments
Nuclear decommissioning trust funds		544			518
Other		574			601

		1,118			1,119

Property
Property, plant and equipment		17,966			17,679
Less accumulated depreciation and depletion		(7,590	)		(7,355	)

		10,376			10,324

Other Assets
Goodwill		2,063			2,067
Regulatory assets		2,109			2,063
Securitized regulatory assets		1,484			1,527
Notes receivable		552			469
Assets from risk management and trading activities		196			88
Prepaid pension assets		182			181
Other		204			203

		6,790			6,598

Total Assets	$	21,011		$	20,753

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company
Consolidated Statement of Financial Position


	(Unaudited)
	June 30			December 31
(in Millions, Except Shares)	2004			2003
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	701		$	625
Accrued interest		106			110
Dividends payable		90			87
Accrued payroll		43			51
Income taxes		—			185
Short-term borrowings		490			370
Current portion of long-term debt, including capital leases		340			477
Liabilities from risk management and trading activities		387			326
Other		610			593

		2,767			2,824

Other Liabilities
Deferred income taxes		1,093			988
Regulatory liabilities		816			817
Asset retirement obligations (Note 2)		892			866
Unamortized investment tax credit		150			156
Liabilities from risk management and trading activities		306			173
Liabilities from transportation and storage contracts		407			495
Accrued pension liability		216			345
Deferred gains from asset sales		412			311
Minority interest		145			156
Nuclear decommissioning		70			67
Other		589			599

		5,096			4,973

Long-Term Debt (net of current portion)
Mortgage bonds, notes and other		5,672			5,624
Securitization bonds		1,446			1,496
Equity-linked securities		181			185
Trust preferred-linked securities		289			289
Capital lease obligations		71			75

		7,659			7,669

Contingencies (Notes 5 and 9)
Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 173,728,563 and 168,606,522 shares issued and outstanding, respectively		3,300			3,109
Retained earnings		2,356			2,308
Accumulated other comprehensive loss		(167	)		(130	)

		5,489			5,287

Total Liabilities and Shareholders’ Equity	$	21,011		$	20,753

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Cash Flows (Unaudited)


	Six Months Ended
	June 30
(in Millions)	2004			2003
Operating Activities
Net Income	$	225		$	116
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		346			381
Deferred income taxes		112			61
Gain on sale of interests in synfuel projects		(106	)		(33	)
Gain on sale of ITC and other assets, net		(24	)		(118	)
Partners’ share of synfuel project losses		(87	)		(38	)
Contributions from synfuel partners		36			29
Cumulative effect of accounting changes		—			27
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		17			(97	)

Net cash from operating activities		519			328

Investing Activities
Plant and equipment expenditures – regulated		(363	)		(356	)
Plant and equipment expenditures – non-regulated		(33	)		(44	)
Investment in joint ventures		(36	)		(4	)
Proceeds from sale of interests in synfuel projects		88			43
Proceeds from sale of ITC and other assets		59			604
Restricted cash for debt redemptions		10			110
Other investments		(38	)		(49	)

Net cash from (used for) investing activities		(313	)		304

Financing Activities
Issuance of long-term debt		418			480
Redemption of long-term debt		(565	)		(800	)
Short-term borrowings, net		120			(184	)
Issuance of common stock		21			21
Dividends on common stock		(176	)		(173	)
Other		(3	)		(6	)

Net cash used for financing activities		(185	)		(662	)

Net Increase (Decrease) in Cash and Cash Equivalents		21			(30	)
Cash and Cash Equivalents at Beginning of the Period		54			133

Cash and Cash Equivalents at End of the Period	$	75		$	103

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity
and Comprehensive Income (Unaudited)


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

Net income		—			—			225			—			225
Issuance of new shares (Note 6)		5,158			202			—			—			202
Dividends declared on common stock		—			—			(177	)		—			(177	)
Repurchase and retirement of common stock		(36	)		(2	)		—			—			(2	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(26	)		(26	)
Net change in unrealized gain on investments, net of tax		—			—			—			(11	)		(11	)
Unearned stock compensation and other		—			(9	)		—			—			(9	)

Balance, June 30, 2004		173,729		$	3,300		$	2,356		$	(167	)	$	5,489

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


(in Millions)	2004			2003
Net income	$	225		$	116

Other comprehensive income (loss), net of tax:
Net unrealized losses on derivatives:
Losses arising during the period, net of taxes of $(12) and $(9), respectively		(23	)		(17	)
Amounts reclassified to earnings, net of taxes of $(2) and $(1), respectively		(3	)		(2	)

		(26	)		(19	)
Net change in unrealized gain on investments, net of taxes of $(6) and $-		(11	)		—
Pension obligations, net of taxes of $- and $224, respectively		—			417

		(37	)		398

Comprehensive income	$	188		$	514

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Notes to Consolidated Financial Statements (unaudited)

NOTE 1 — GENERAL

These consolidated financial statements should be read in conjunction with the notes to consolidated financial statements included in the 2003 Annual Report on Form 10-K.

The accompanying consolidated financial statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

The consolidated financial statements are unaudited, but in our opinion include all adjustments necessary for a fair statement of the results for the interim periods. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year.

We reclassified certain prior year balances to match the current year’s presentation.

Stock-Based Compensation

We have a stock-based employee compensation plan. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan using the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation cost related to stock options is reflected in net income, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. The recognition provisions under Statement of Financial Accounting Standards (SFAS) No. 123,“Accounting for Stock-Based Compensation,” require the recording of compensation expense for stock options equal to their fair value at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and earnings per share if we had recorded compensation expense for options granted under the fair value recognition provisions of SFAS No. 123.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions, except per share amounts)	2004			2003			2004			2003
Net Income (Loss) As Reported	$	35		$	(39	)	$	225		$	116
Less: Total stock-based expense (1)		(2	)		(1	)		(4	)		(3	)

Pro Forma Net Income (Loss)	$	33		$	(40	)	$	221		$	113

Income (Loss) Per Share
Basic – as reported	$	.20		$	(.23	)	$	1.31		$	.69

Basic – pro forma	$	.19		$	(.24	)	$	1.29		$	.67

Diluted – as reported	$	.20		$	(.23	)	$	1.31		$	.69

Diluted – pro forma	$	.19		$	(.24	)	$	1.29		$	.67

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

Investment in Plug Power

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

Restricted Cash

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

Consolidated Statement of Cash Flows

The components of changes in assets and liabilities follow:


	Six Months Ended
	June 30
(in Millions)	2004			2003
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	53		$	(127	)
Accrued unbilled receivables		104			105
Accrued gas cost recovery revenue		(70	)		(33	)
Inventories		78			43
Accrued/Prepaid pensions		40			(147	)
Accounts payable		76			206
Exchange gas payable		(74	)		21
Income taxes payable		(207	)		(50	)
General taxes		(20	)		(14	)
Risk management and trading activities		35			37
Gas inventory equalization		93			75
Other		(91	)		(213	)

	$	17		$	(97	)

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


	Six Months Ended
	June 30
(in Millions)	2004		2003
Supplementary Cash Flow Information
Interest paid (excluding interest capitalized)	$	264	$	267
Income taxes paid	$	191	$	27
Notes received from sale of synfuel projects	$	155	$	—
Common stock contribution to pension plan	$	170	$	—

Retirement Benefits and Trusteed Assets

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


							Other Postretirement
	Pension Benefits						Benefits
(in Millions)	2004			2003			2004			2003
Three Months Ended June 30
Service Cost	$	14		$	13		$	10		$	11
Interest Cost		43			41			23			22
Expected Return on Plan Assets		(56	)		(53	)		(14	)		(12	)
Amortization of Net loss		15			9			11			7
Prior service cost		2			3			(1	)		(1	)
Net transition liability		—			—			2			2

Net Periodic Benefit Cost	$	18		$	13		$	31		$	29

Six Months Ended June 30
Service Cost	$	30		$	26		$	21		$	22
Interest Cost		86			83			46			45
Expected Return on Plan Assets		(108	)		(106	)		(28	)		(24	)
Amortization of Net loss		31			19			21			14
Prior service cost		4			5			(2	)		(2	)
Net transition liability		—			—			4			4

Net Periodic Benefit Cost	$	43		$	27		$	62		$	59

In June 2004, we retroactively adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) No. 106-2. This FSP provides guidance on the accounting for the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act). As a result of the retroactive adoption, our other postretirement benefit costs were reduced by $4 million and $8 million for the three and six months ended June 30, 2004. See Note 2.

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

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Consolidation of Variable Interest Entities

In January 2003, FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51,” was issued and requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses.

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

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

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and Fermi 2 nuclear plants. To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to regulated operations, we believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and will be deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $306 million with offsetting accumulated depreciation of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to regulated operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million (net of taxes of $7 million) for 2003.

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


(in Millions)
Asset retirement obligations at January 1, 2004	$	866
Accretion		29
Liabilities settled		(3	)

Asset retirement obligations at June 30, 2004	$	892

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

Energy Trading Activities

Under Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” companies were required to use mark-to-market accounting for contracts utilized in energy trading activities. EITF Issue No. 98-10 was rescinded in October 2002, and energy trading contracts must now be reviewed to determine if they meet the definition of a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities measured at their fair value and sets forth conditions in which a derivative instrument may be designated and recognized as a hedge. SFAS No. 133 also requires that changes in the fair value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts.

Additionally, inventory utilized in energy trading activities accounted for under the fair value method of accounting as prescribed by ARB No. 43 is no longer permitted. Our Energy Marketing & Trading segment uses gas inventory in its trading operations and switched to the average cost inventory accounting method in January 2003.

Effective January 1, 2003, DTE Energy no longer applied EITF Issue No. 98-10 to energy contracts and ARB No. 43 to gas inventory. As a result of discontinuing the application of these accounting principles, we recorded a cumulative effect of accounting change that reduced net income for the first quarter of 2003 by $16 million (net of taxes of $9 million).

Medicare Act Accounting

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

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

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


	Three		Three Months		Six
	Months		Ended		Months
	Ended		June 30,		Ended
(in Millions)	March 31, 2004		2004		June 30, 2004
Reduction in service cost	$	—	$	1	$	1
Reduction in interest cost		2		1		3
Amortization of actuarial gain		2		2		4

Decrease in postretirement benefit cost	$	4	$	4	$	8

We have elected to apply the provisions of FSP No. 106-2 retroactive to January 1, 2004, and as a result earnings for the first quarter of 2004 have been restated. A reconciliation of previously reported first quarter 2004 net income and earnings per share to the amounts adjusted for the decrease in costs due to the Medicare Act follows:


	Quarter Ended March 31, 2004
			Basic		Diluted
	Net		Earnings		Earnings
(In Millions, except per share amounts)	Income		Per Share		Per Share
As reported	$	186	$	1.10	$	1.09
Add: Decrease in costs due to Medicare Act		4		.02		.02

As adjusted	$	190	$	1.12	$	1.11

NOTE 3 – DISCONTINUED OPERATIONS

Impairment of Southern Missouri Gas Company

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

Disposition of International Transmission Company

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

NOTE 4 – CONTRACT MODIFICATION/TERMINATION

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

NOTE 5 – REGULATORY MATTERS

Electric Rate Case

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

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

In addition, Detroit Edison has updated its request for recovery of regulatory assets from $109 million to $93 million annually over a 5-year period, which includes recovery of deferred return on and of Clean Air Act costs and capital expenditures in excess of base depreciation amounts, transmission costs and electric Customer Choice implementation costs as allowed by Public Act (PA) 141.

Detroit Edison is also requesting recovery of $187 million of historical stranded costs, through the date of the final order in this case, to be collected pursuant to PA 141.

A summary of the rate requests follows:


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

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

Total	$	536		$	550

Phase in By Year
2004	$	299
2005		57
2006		180

Total	$	536

(1) Does not include recovery of $187 million of historical stranded costs

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

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

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

Although the base rate increase and transition charges total $278 million, the interim order is only designed to result in an increase in 2004 revenues of $51 million. This lower amount is a result of the rate caps, the February 21, 2004 effective date of the interim base rate increase and the PSCR reduction effective January 1, 2004. Amounts collected are subject to a potential refund pending a final order in this rate case.

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

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

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

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

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs - PA 141 provides Detroit Edison with the right to recover net stranded costs. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding. During each quarter, Detroit Edison records a regulatory asset representing an estimate of the cumulative stranded costs as of that period. Our revised and ongoing calculations concluded that the $68 million of net stranded costs recorded as of December 31, 2003 is appropriate. During the 2004 six-month period, we recorded $43 million of additional stranded costs as a regulatory asset.

An April 1, 2004 Michigan Court of Appeals order found that the MPSC should not defer recovery of Detroit Edison’s electric Customer Choice implementation costs indefinitely. On June 29, 2004, the MPSC issued an order authorizing Detroit Edison to recover $20 million in implementation costs incurred during 2002. Detroit Edison elected to collect these costs as well as implementation costs incurred in 2000 and 2001 as part of the $93 million regulatory asset recovery previously discussed.

Gas Rate Case

Rate Request - In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. MichCon requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004. The interim request was based on a projected revenue deficiency for the test year 2004.

MPSC Staff Report on Interim Rate Relief - The Staff report on MichCon’s interim rate request was filed on May 3, 2004. After adjusting for several items that it will address in its final rate relief recommendation, the Staff recommended a $25 million interim rate increase. This compares with MichCon’s requested total interim base rate relief of $154 million. In addition, the Staff proposed a 50% debt and 50% equity capital structure utilizing MichCon’s current allowed rate of return of 11.5%. The Staff has subsequently revised its position and is now recommending a $29 million interim rate increase. An interim order is expected in the third quarter of 2004 and a final order in the first quarter of 2005.

MPSC Staff Recommendation on Final Rate Relief - The Staff report on MichCon’s final rate relief request was filed on July 26, 2004. The Staff recommended a $70 million increase in base rates compared to MichCon’s requested base rate relief of $194 million. In addition, the Staff proposed a 50% debt and 50% equity capital structure utilizing a reduced rate of return of 11%.

Gas Cost Recovery Proceedings

2002 Plan Year - In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per Mcf for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset of approximately $14 million representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset is subject to the 2002 GCR reconciliation process. In March 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year.

Although we recorded a $26.5 million reserve in the first quarter of 2003 to reflect the impact of this order, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment will be decided in MichCon’s 2002 GCR reconciliation case that was filed with the MPSC in

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

2003 Plan Year - In July 2003, the MPSC approved an increase in MichCon’s 2003 GCR rate to a maximum of $5.75 per Mcf for the billing months of August 2003 through December 2003. As of December 31, 2003, MichCon has accrued a $19 million regulatory asset representing the under-recovery of actual gas costs incurred in 2003 and the 2002 GCR under-recovery.

2004 Plan Year - In September 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf. MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR Plan Case. The operational GCR year would run from April to March of the following year. To accomplish the switch, the 2004 GCR Plan Case reflects a 15-month transitional period, January 2004 through March 2005. Under the transition proposal, MichCon would file two reconciliations pertaining to the transition period; one addressing the January 2004 to March 2004 period, the other addressing the remaining April 2004 to March 2005 period. The plan also proposes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby minimizing the possibility of a GCR under recovery. Due to sustained increase in market prices for natural gas, in June 2004, the MPSC approved an increase in the maximum GCR factor and a contingent factor which resulted in a new maximum factor of $6.62 per Mcf, effective July 1, 2004.

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

NOTE 6 - COMMON STOCK AND EARNINGS PER SHARE

Common Stock

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

Earnings per Share

We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average number of common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assumes the exercise of stock options, vesting of non-vested stock awards and the issuance of performance share awards. A reconciliation of both calculations for the 2004 and 2003 three-month and six-month periods is presented in the following table:


	Three Months Ended					Six Months Ended
	June 30					June 30
(Millions, except per share amounts)	2004		2003			2004		2003
Basic Earnings Per Share
Income (Loss) from continuing operations	$	34.9	$	(36.7	)	$	231.8	$	71.8
Average number of common shares outstanding		173.2		167.5			171.6		167.4

Income (Loss) per share of common stock based on weighted average number of shares outstanding	$	.20	$	(.22	)	$	1.35	$	.43

Diluted Earnings Per Share
Income (Loss) from continuing operations	$	34.9	$	(36.7	)	$	231.8	$	71.8

Average number of common shares outstanding		173.2		167.5			171.6		167.4
Incremental shares from stock - based awards		.6		.4			.5		.5

Average number of dilutive shares outstanding		173.8		167.9			172.1		167.9

Income (Loss) per share of common stock assuming issuance of incremental shares	$	.20	$	(.22	)	$	1.35	$	.42

NOTE 7 – LONG -TERM DEBT AND PREFERRED SECURITIES

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

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

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

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

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

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

NOTE 8 – SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In May 2004, we entered into a $375 million two-year unsecured revolving credit facility with a group of banks to be utilized for general corporate borrowings. This agreement requires the company to maintain a debt to total capitalization ratio of no more than .65 to l and an earnings before interest, taxes, depreciation and amortization to interest ratio of no less than 2 to 1. DTE Energy is currently in compliance with these financial covenants.

NOTE 9 – CONTINGENCIES

Environmental

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

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

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

Synthetic Fuel Operations

We operate nine synthetic fuel production facilities, two of which are wholly owned. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (IRS) rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 tax credits.

During July 2004, several unaffiliated companies announced that they have been notified that the IRS intends to challenge the placed in service dates for some of their synfuel facilities. If the IRS ultimately prevails, Section 29 credits claimed by these companies would be disallowed. The placed in service issue

is fact-driven and specific to each facility. The in-service dates for eight of our nine synfuel plants have been reviewed by the IRS in conjunction with issuing determination letters and/or recently completed field audits. We believe all nine of our synthetic fuel plants meet the required in-service condition.

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

To reduce U.S. dependence on imported oil, the Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive is not deemed necessary if the price of oil increases and provides a natural market for these fuels. As such, the credit in a given year is reduced as the “reference price” of oil within that year exceeds a threshold price. The reference price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil over the entire year. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. The threshold price was $50.14 in 2003. Based on the monthly average wellhead price per barrel of oil in 2004 to date, the average price of oil would have to exceed approximately $70 per barrel for the remaining months in 2004 to reduce credits and the price of oil would have to exceed approximately $100 per barrel to eliminate them. In the unlikely event the credit is reduced, our financial statements could be negatively impacted.

Other

We are involved in certain legal, regulatory and administrative proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our financial statements in the period they are resolved.

See Note 5 for a discussion of contingencies related to Regulatory Matters.

NOTE 10 – SEGMENT INFORMATION

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


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
Operating Revenues
Energy Resources
Regulated - Power Generation	$	508		$	589		$	1,059		$	1,206

Non-regulated
Energy Services		265			248			517			467
Energy Marketing & Trading		98			157			334			464
Other		78			70			147			132

Total Non-regulated		441			475			998			1,063

		949			1,064			2,057			2,269

Energy Distribution
Regulated - Power Distribution		327			281			662			601
Non-regulated		12			9			24			14

		339			290			686			615

Energy Gas
Regulated – Gas Distribution		276			289			1,005			928
Non-regulated		29			23			54			44

		305			312			1,059			972

Corporate & Other		8			3			9			6
Reconciliations and eliminations		(100	)		(69	)		(217	)		(167	)

Total
Regulated		1,111			1,159			2,726			2,735
Non-regulated (1)		390			441			868			960

	$	1,501		$	1,600		$	3,594		$	3,695

(1) Includes Corporate & Other.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2004			2003			2004			2003
Net Income (Loss)
Energy Resources
Regulated – Power Generation	$	1		$	46		$	17		$	71

Non-regulated
Energy Services		56			76			94			127
Energy Marketing & Trading		(7	)		(15	)		50			29
Other		—			1			(2	)		1

Total Non-regulated		49			62			142			157

		50			108			159			228

Energy Distribution
Regulated – Power Distribution		7			(16	)		35			(20	)
Non-regulated		(8	)		(5	)		(11	)		(9	)

		(1	)		(21	)		24			(29	)

Energy Gas
Regulated – Gas Distribution		(38	)		(8	)		33			51
Non-regulated		5			6			9			14

		(33	)		(2	)		42			65

Corporate & Other		19			(122	)		7			(193	)

Income (Loss) from Continuing Operations
Regulated		(30	)		22			85			102
Non-regulated (1)		65			(59	)		147			(31	)

		35			(37	)		232			71

Discontinued Operations		—			(2	)		(7	)		72
Cumulative Effect of Accounting Changes		—			—			—			(27	)

Net Income (Loss)	$	35		$	(39	)	$	225		$	116

Diluted Earnings (Loss) per Share
Regulated	$	(.17	)	$	.13		$	.49		$	.61
Non-regulated (1)		.37			(.35	)		.86			(.19	)

Income from Continuing Operations		.20			(.22	)		1.35			.42
Discontinued Operations		—			(.01	)		(.04	)		.43
Cumulative Effect of Accounting Changes		—			—			—			(.16	)

Net Income (Loss)	$	.20		$	(.23	)	$	1.31		$	.69

(1) Includes Corporate & Other.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

DTE Energy Company

We have reviewed the accompanying condensed consolidated statement of financial position of DTE Energy Company and subsidiaries as of June 30, 2004, and the related condensed consolidated statement of operations for the three-month and six-month periods ended June 30, 2004 and 2003, the condensed consolidated statement of cash flows for the six-month periods ended June 30, 2004 and 2003, and the condensed consolidated statements of changes in shareholders’ equity and comprehensive income for the six-month period ended June 30, 2004 and the six-month periods ended June 30, 2004 and 2003, respectively. These interim financial statements are the responsibility of DTE Energy Company’s management.

We conducted our reviews in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the condensed consolidated interim financial statements, DTE Energy Company applied the provisions of Financial Accounting Standards Board Staff Position No. 106-2, which relates to accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, retroactive to January 1, 2004.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated statement of financial position of DTE Energy Company and subsidiaries as of December 31, 2003, and the related consolidated statements of operations, cash flows and changes in shareholders’ equity and comprehensive income for the year then ended (not presented herein); and in our report dated March 1, 2004 (which report includes an explanatory paragraph relating to the change in the methods of accounting for asset retirement obligations, energy trading contracts and gas inventories in 2003, goodwill and energy trading contracts in 2002 and derivative instruments and hedging activities in 2001), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated statement of financial position as of December 31, 2003 is fairly stated, in all material respects, in relation to the consolidated statement of financial position from which it has been derived.

/S/ DELOITTE & TOUCHE LLP

Detroit, Michigan
August 3, 2004

Other Information

Legal Proceedings

We are involved in certain legal, regulatory and administrative proceedings before various courts, arbitration panels and governmental agencies concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, audits, inquiries from various regulators, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or financial statements in the period they are resolved.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

On March 3, 2004, we contributed 4,344,492 shares of DTE Energy common stock (valued at $170 million) to the DTE Energy Company Affiliates Employee Benefit Plans Master Trust, which is maintained in conjunction with the DTE Energy Company Retirement Plan. We made the contribution as a private placement in satisfaction of a funding obligation and the re-offering of these shares has since been registered with the Securities and Exchange Commission.

Submission of Matters to a Vote of Security Holders

(a) The annual meeting of the holders of Common Stock of the Company was held on April 29, 2004. Proxies for the meeting were solicited pursuant to Regulation 14(a).

(b) There was no solicitation in opposition to the Board of Directors’ nominees, as listed in the proxy statement, for directors to be elected at the meeting and all such nominees were elected.

The terms of the previously elected seven directors listed below continue until the annual meeting dates shown after each name:


Lillian Bauder		April 2005
David Bing		April 2005
Howard F. Sims		April 2005
Alfred R. Glancy III		April 2006
John E. Lobbia		April 2006
Eugene A. Miller		April 2006
Charles W. Pryor, Jr.		April 2006

(c) At the annual meeting of the holders of common stock of the company held on April 29, 2004, the following directors were elected to serve until the annual meeting in 2007 with the votes shown, with the exception of Josue Robles, Jr. who was elected to serve until the annual meeting in 2005:


			Total Vote
	Total Vote		Withheld
	For Each		From Each
	Director		Director
Anthony F. Earley, Jr.		132,555,666		2,798,977
Allan D. Gilmour		125,739,511		9,615,132
Frank M. Hennessey		132,379,660		2,974,983
Gail J. McGovern		119,383,861		15,970,782
Josue Robles, Jr.		132,382,675		2,971,968

Shareholders ratified the appointment of Deloitte & Touche LLP as the company’s independent auditors for the year 2004 with the votes shown:


For	Against		Abstain
130,840,188		2,899,359		1,615,096

There were no Shareholder proposals.

(d) Not applicable.

Exhibits and Reports on Form 8-K

(a) Exhibits


Exhibit
Number		Description
Filed:

3(f)		Bylaws of DTE Energy Company, as amended through April 29, 2004

4(p)		Supplemental Indenture dated as of June 1, 2004, supplementing the Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and BNY Midwest Trust Company (successor to The Bank of New York), relating to the 2004 Series C Floating Rate Notes due 2007

4(q)		Amended and Restated Trust Agreement of DTE Energy Trust II dated as of June 1, 2004

4(r)		Supplemental Indenture dated as of June 1, 2004, supplementing the Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and BNY Midwest Trust Company (successor to The Bank of New York), relating to the 7.50% Junior Subordinated Debentures due 2044

4(s)		Two-Year Credit Agreement dated as of May 7, 2004 among DTE Energy Company, the Initial Lenders named therein, Barclays Bank PLC, as Administrative Agent and Co-Syndication Agent, Citigroup Global Markets Inc., as Co-Syndication Agent and BNP PARIBAS, Keybank National Association, and The Bank of Nova Scotia, as Co-Documentation Agents

15-14		Awareness Letter of Deloitte & Touche LLP

31-9		Chief Executive Officer Section 302 Form 10-Q Certification

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

Furnished:


32-9		Chief Executive Officer Section 906 Certification of Periodic Report

32-10		Chief Financial Officer Section 906 Certification of Periodic Report

(b) Reports on Form 8-K.

During the quarterly period ended June 30, 2004, we filed or furnished Current Reports on Form 8-K covering matters, as follows:

Item 7. Exhibits and Item 12. Results of Operations and Financial Condition furnished on April 29, 2004 and dated April 28, 2004;

Item 7. Exhibits and Item 12. Results of Operations and Financial Condition furnished and dated April 29, 2004; and

Item 5. Other Events and Item 7. Exhibits filed and dated June 24, 2004.

Exhibit Index


Exhibit
Number		Description
Filed:

3(f)		Bylaws of DTE Energy Company, as amended through April 29, 2004

4(p)		Supplemental Indenture dated as of June 1, 2004, supplementing the Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and BNY Midwest Trust Company (successor to The Bank of New York), relating to the 2004 Series C Floating Rate Notes due 2007

4(q)		Amended and Restated Trust Agreement of DTE Energy Trust II dated as of June 1, 2004

4(r)		Supplemental Indenture dated as of June 1, 2004, supplementing the Amended and Restated Indenture, dated as of April 9, 2001, between DTE Energy Company and BNY Midwest Trust Company (successor to The Bank of New York), relating to the 7.50% Junior Subordinated Debentures due 2044

4(s)		Two-Year Credit Agreement dated as of May 7, 2004 among DTE Energy Company, the Initial Lenders named therein, Barclays Bank PLC, as Administrative Agent and Co-Syndication Agent, Citigroup Global Markets Inc., as Co-Syndication Agent and BNP PARIBAS, Keybank National Association, and The Bank of Nova Scotia, as Co-Documentation Agents

15-14		Awareness Letter of Deloitte & Touche LLP

31-9		Chief Executive Officer Section 302 Form 10-Q Certification

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

32-9		Chief Executive Officer Section 906 Certification of Periodic Report

32-10		Chief Financial Officer Section 906 Certification of Periodic Report


Bcf		Billion cubic feet of gas

Bcfe.		Conversion metric of natural gas, the ratio as defined by the Securities and Exchange Commission of 6 Mcf of gas to 1 barrel of oil.

gWh		Gigawatthour of electricity

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MMcf		Million cubic feet of gas

MW		Megawatt of electricity

MWh		Megawatthour of electricity


		DTE ENERGY COMPANY

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

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


	Page
Definitions		3
Forward-Looking Statements		5
Part I – Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations		29
Consolidated Statement of Financial Position		30
Consolidated Statement of Cash Flows		32
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		33
Notes to Consolidated Financial Statements		34
Report of Independent Registered Public Accounting Firm		49
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		6
Item 3. Quantitative and Qualitative Disclosures About Market Risk		27
Item 4. Controls and Procedures		28
Part II – Other Information
Item 1. Legal Proceedings		50
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities		50
Item 4. Submission of Matters to a Vote of Security Holders		50
Item 6. Exhibits and Reports on Form 8-K		51
Signature		53
Bylaws of DTE Energy Company As Amended Through April 29, 2004
Supplemental Indenture Dated As Of June 1, 2004
Amended & Restated Trust Agmt. of DTE Energy Trust II Dated as of June 1, 2004
Supplemental Indenture Dated as of June 1, 2004
Two-Year Credit Agreement Dated as of May 7, 2004
Awareness Letter of Deloitte & Touche LLP
Chief Executive Officer Section 302 Form 10-Q Certification
Chief Financial Officer Section 302 Form 10-Q Certification
Chief Executive Officer Section 906 Certification of Periodic Report
Chief Financial Officer Section 906 Certification of Periodic Report

•		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.

•		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.

•		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.

(a)		The annual meeting of the holders of Common Stock of the Company was held on April 29, 2004. Proxies for the meeting were solicited pursuant to Regulation 14(a).

(b)		There was no solicitation in opposition to the Board of Directors’ nominees, as listed in the proxy statement, for directors to be elected at the meeting and all such nominees were elected.

		The terms of the previously elected seven directors listed below continue until the annual meeting dates shown after each name: