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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, 2005

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

Yes þ No o

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

Yes þ No o

At June 30, 2005, 174,159,338 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.

Definitions


Coke and Coke Battery		Raw coal is heated to high temperatures in ovens to drive off impurities, leaving a carbon residue called coke. Coke is combined with iron ore to create a high metallic iron that is used to produce steel. A series of coke ovens configured in a module is referred to as a battery.

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, MichCon and numerous non-utility subsidiaries

FERC		Federal Energy Regulatory Commission

GCR		A gas cost recovery mechanism authorized by the MPSC, permitting MichCon to pass the cost of natural gas to its customers.

ITC		International Transmission Company (until February 28, 2003, a direct 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

Non-utility subsidiary		A subsidiary that is not a public utility. Its conditions of service, prices of goods and services and other operating related matters are not regulated by the MPSC or the FERC.

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 expenses. The clause was suspended under 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 as authorized under Section 29 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources. The amount of a Section 29 tax credit can vary each year as determined by the Internal Revenue Service.

SFAS		Statement of Financial Accounting Standards

Stranded costs		Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval would not otherwise expect to be recoverable if customers switch to alternative energy suppliers.

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 higher price of oil and its impact on the value of Section 29 tax credits, and the ability to utilize and/or sell interests in facilities producing such credits;

•		implementation of electric and gas Customer Choice programs;

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

•		employee relations and the impact of collective bargaining agreements;

•		unplanned outages;

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

•		the timing and extent of changes in interest rates;

•		the level of borrowings;

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

•		effects of competition;

•		impact of regulation by FERC, MPSC, NRC and other applicable governmental proceedings and regulations;

•		contributions to earnings by non-utility subsidiaries;

•		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 2004 and approximately $21 billion in assets at December 31, 2004. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales and distribution services throughout southeastern Michigan. Additionally, we have numerous non-utility subsidiaries involved in energy-related businesses predominantly in the Midwest and eastern U.S.

Earnings in the second quarter of 2005 were $29 million, or $.17 per diluted share, compared to earnings in the 2004 second quarter of $35 million, or $.20 per diluted share. For the 2005 six-month period, our earnings were $151 million, or $.87 per diluted share, compared to earnings of $225 million, or $1.31 per diluted share, for the same 2004 period. Lower earnings were due to the deferral of a portion of the gains received from the sale of our synfuel facilities and losses at our Gas Utility segment, partially offset by higher earnings at our Electric Utility segment due to rate increases and warmer weather.

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

•

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

•

Gas Cost Recovery and gas final rate orders; and

•

Electric final rate order, effects of weather and Customer Choice program.

Synthetic fuel operations

We operate nine synthetic fuel production plants at eight locations. Since 2002, we have sold interests in eight of the nine plants, representing approximately 88% of our total production capacity as of June 30, 2005. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (IRS) rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuel produced from coal. Synfuel-related tax credits expire in December 2007.

Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. In order to recognize Section 29 tax credits, a taxpayer must have sufficient taxable income in the year the tax credit is generated. Once earned, the tax credits are utilized subject to certain limitations but can be carried forward indefinitely. We have not had sufficient taxable income to fully utilize tax credits earned in prior periods. As of December 2004, we had $483 million in tax credit carry-forwards. To optimize income and cash flow from our synfuel operations, we have sold interests in eight of our nine facilities as of June 30, 2005. In July 2005, we sold a 49% interest in the ninth facility. We intend to sell additional interests in our two majority-owned plants during 2005, representing 99% of our production capacity. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

The value of a Section 29 tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS in April of the following year. Additionally, the value of the tax credit in a given year is reduced if the “Reference Price” of oil within the year exceeds a threshold price and is eliminated entirely

if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which recently has been $4 — $8 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2004 and 2005 are as follows:


			Beginning Phase-Out		Ending Phase-Out
	Reference Price		Price		Price
2004 (actual)	$	36.75	$	51.35	$	64.46
2005 (estimated)	Not Available		$	52	$	66

Numerous recent events have significantly increased domestic crude oil prices, including terrorism, storm-related supply disruptions and strong worldwide demand. Through June 30, 2005, the NYMEX closing price of a barrel of oil for 2005 has averaged approximately $52, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to an approximate $44 to $48 Reference Price (assuming that such price were to continue for the entire year). For 2005 and later years, if the Reference Price falls within or exceeds the phase-out range, the availability of synfuel tax credits in that year would be reduced or eliminated, respectively.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized when earned and collectibility is assured. The variable component is based on an estimate of tax credits allocated to our partners, is subject to refund based on the annual oil price phase-out, and is recognized as a gain only when probability of refund is considered remote and collectibility is assured. Additionally, based on estimates of tax credits allocated, our partners reimburse us (through the project entity) for the operating losses of the synfuel facilities. In the event that the tax credit is phased out, we are contractually obligated to refund to our partners an amount equal to the operating losses funded by our partners. To assess the probability of refund, we use valuation and analysis models that calculate the probability of surpassing the estimated lower band of the phase-out range for the Reference Price of oil for the year. Due to the rise in oil prices, there is a possibility that the Reference Price of oil could reach the threshold at which Section 29 tax credits begin to phase out. While we believe the possibility of phase-out is unlikely in 2005, we have not met the strict accounting gain recognition criteria that would allow us to recognize the gains on the variable component. We deferred $69 million pretax in the second quarter of 2005 and $110 million pretax in the six months ended June 30, 2005 of the variable component of synfuel-related gains for the potential phase-out of synfuel tax credits. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria are met. It is possible that additional gains will be deferred in the 2005 third quarter until there is persuasive evidence that no tax credit phase-out will occur. This will result in shifting earnings from earlier quarters to later quarters.

As discussed in Note 9, we have entered into derivative and other contracts to economically hedge a portion of our 2005 and 2006 synfuel cash flow exposure related to the risk of an increase in oil prices. The derivative contracts are accounted for under the mark to market method with changes in their fair value recorded as an adjustment to synfuel gains. We recorded a mark to market loss of $11 million pre-tax during the 2005 second quarter. For the six months ended June 30, 2005, we have recorded mark to market gains of $43 million pre-tax. As part of our synfuel-related risk management strategy, we continue to evaluate alternatives available to mitigate unhedged exposure to oil price volatility.

Assuming no synfuel tax credit phase out in future years and sufficient taxable income, we expect cash flow from our synfuel business to total approximately $1.6 billion from 2005 to 2008. The source of synfuel cash flow includes cash from operations, asset sales, and the utilization of Section 29 tax credits carried forward from synfuel production. Tax credit utilization in part could be extended past 2008, if taxable income is reduced from current forecasts.

Gas operations

Gas cost recovery order — In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per thousand cubic feet (Mcf) for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order allowed MichCon to recognize a regulatory asset representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. MichCon’s 2002 GCR reconciliation case was filed with the MPSC in February 2003. On April 28, 2005, the MPSC issued an order in the 2002 GCR reconciliation case that disallowed $26 million plus accrued interest of $3 million. We recorded the impact of the disallowance in the first quarter of 2005.

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

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

The MPSC order reduces MichCon’s depreciation rates and the related revenue requirement associated with depreciation expense by $14.5 million and is designed to have no impact on net income.

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

The MPSC order also resulted in the disallowance of computer system and equipment costs and adjustments to environmental regulatory assets and liabilities. The MPSC disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. As a result of the order, MichCon recognized an impairment of this asset of approximately $42 million in the first quarter of 2005. This impairment had a minimal impact on DTE Energy since a valuation allowance was established for this asset at the time of the MCN acquisition in 2001. The MPSC disallowed approximately $6 million of certain computer equipment and related depreciation and the recovery of certain internal labor and legal costs related to remediation of manufactured gas plants of approximately $6 million. The MPSC order resulted in an additional $5 million charge due to a change in the allocation of historical manufactured gas plant insurance proceeds.

Electric operations

In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and eliminated transition credits and implemented transition charges for electric Customer Choice customers. The increases were applicable to all customers not subject to a rate cap. The MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs. For the 2005 second quarter and the 2005 six-month period our margins were higher by $38 million and $64 million, respectively, due to increased rates. Earnings in our electric operations are seasonal and sensitive to weather. During 2005, we have experienced warmer weather which has increased sales demand and resulted in higher margins of $26 million for the second quarter and $34 million in the six-month period of 2005.

Since 2002, our customers have had the option of participating in the electric Customer Choice program. This program is designed to give all customers added choices and the opportunity to benefit from lower power costs resulting from competition. The financial impact of electric Customer Choice was mitigated by the issuance of the electric rate orders in 2004 that increased base rates, including the recovery of lost margins and transition charges. The electric Customer Choice volumes in the second quarter of 2005 were 1,996 gWh as compared to 2,480 gWh in the second quarter of 2004. Year to date electric Customer Choice volumes for 2005 were 3,910 gWh compared to 4,622 gWh for the comparable period in 2004. These lower volumes were offset by an increase in higher margin commercial customer participation in the Customer Choice program resulting in an immaterial effect on margins. With current regulation continuing to hinder our ability to retain certain customers, we continue working with the MPSC to address issues associated with the electric Customer Choice program including a revenue-neutral rate restructuring proposal which we filed in February 2005 designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, Detroit Edison’s commercial and industrial rates would be lowered in 2006, but residential rates would increase over a five-year period beginning in 2007. The number and mix of customers participating in the electric Customer Choice program could be impacted under the rate restructuring.

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

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

RESULTS OF OPERATIONS

Our earnings in the 2005 second quarter were $29 million, or $.17 per diluted share, compared to earnings of $35 million, or $.20 per diluted share, in the 2004 second quarter. For the 2005 six-month period, our earnings were $151 million, or $.87 per diluted share, compared to earnings of $225 million, or $1.31 per diluted share, for the same 2004 period. The following sections provide a detailed discussion of our segments’ operating performance and future outlook.

Segments realigned — Prior to the second quarter of 2005, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. In the second quarter of 2005, we realigned our business units to strengthen the Company’s focus on customer relationships and growth within our non-utility businesses. Based on this structure, we set strategic goals, allocate resources and evaluate performance. Our segment information is based on the following alignment:

	•		Electric Utility, consisting of Detroit Edison;

	•		Gas Utility, primarily consisting of MichCon;

	•		Non-utility Operations

	•		Power and Industrial Projects, primarily consisting of synfuel projects, on-site energy services, steel-related projects, power generation with services and waste coal recovery operations;

	•		Unconventional Gas Production, primarily consisting of unconventional gas project development and production;

	•		Fuel Transportation and Marketing, primarily consisting of coal transportation and marketing, gas pipelines and storage, and energy marketing and trading operations; and

•

Corporate & Other, primarily consisting of corporate support functions and certain energy technology investments.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions, except per share data)	2005			2004			2005			2004
Net Income (Loss)
Electric Utility	$	43		$	8		$	98		$	52
Gas Utility		(51	)		(38	)		(38	)		33
Non-utility Operations:
Power and Industrial Projects		31			54			99			89
Unconventional Gas Production		—			2			1			3
Fuel Transportation and Marketing		—			(1	)		(10	)		60
Corporate & Other		7			10			2			(5	)

Income from Continuing Operations
Utility		(8	)		(30	)		60			85
Non-utility		31			55			90			152
Corporate & Other		7			10			2			(5	)

		30			35			152			232
Discontinued Operations		(1	)		—			(1	)		(7	)

Net Income	$	29		$	35		$	151		$	225


Diluted Earnings (Loss) Per Share
Total Utility	$	(.05	)	$	(.17	)	$	.34		$	.49
Non-utility Operations		.18			.32			.52			.88
Corporate & Other		.04			.05			.01			(.02	)

Income from Continuing Operations		.17			.20			.87			1.35
Discontinued Operations		—			—			—			(.04	)

Net Income	$	.17		$	.20		$	.87		$	1.31

The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in DTE Energy’s assets and liabilities as a whole.

ELECTRIC UTILITY

Our Electric Utility segment consists of Detroit Edison which is engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeastern Michigan.

Factors impacting income: Electric Utility earnings increased $35 million during the 2005 second quarter and $46 million in the 2005 six-month period. As subsequently discussed, these results primarily reflect higher rates due to the November 2004 MPSC final rate order, warmer weather and lower operations and maintenance expenses, partially offset by increased depreciation and amortization expenses.


	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
(in Millions)
Operating Revenues	$	1,035		$	835		$	2,025		$	1,721
Fuel and Purchased Power		343			200			644			416

Gross Margin		692			635			1,381			1,305
Operation and Maintenance Fuel and purchased power		330			360			651			703
Depreciation and Amortization		160			122			310			236
Taxes Other Than Income		63			62			132			130
Asset (Gains) and Losses, Net		—			(1	)		—			(1	)

Operating Income		139			92			288			237
Other (Income) and Deductions		75			79			144			158
Income Tax Provision		21			5			46			27

Net Income	$	43		$	8		$	98		$	52


Operating Income as a Percent of Operating Revenues		13	%		11	%		14	%		14	%

Gross margins increased $57 million during the 2005 second quarter and $76 million in the 2005 six-month period. Operating revenues increased $200 million in the second quarter of 2005 and increased $304 million for the six months ended 2005. The quarterly and year to date improvements were primarily as a result of the MPSC final rate order issued in November 2004 and higher demand due to the warmer weather in 2005 resulting in increased margins from retail customers of $26 million in the 2005 second quarter and $34 million in the 2005 six-month period. The current year periods experienced the return of customers who in the comparable 2004 period participated in the electric Customer Choice program. Detroit Edison lost 15% of retail sales in the first half of 2005, compared to 18% of such sales during the same 2004 period as a result of Customer Choice penetration.

Operating revenues and fuel and purchased power costs increased in the 2005 periods reflecting a $7.01 per megawatt hour (MWh) (47%) increase in fuel and purchased power costs during the current quarter and a $5.22 per MWh (35%) increase during the six-month period. Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR mechanism, except for residential customers whose rate caps expire in January 2006. The increase in power supply costs is driven by higher purchased power rates, higher coal prices and increased power purchases due to the outage at our Fermi 2 nuclear facility, which was offline for 14 days in the first quarter of 2005 and for 6 days in the second quarter of 2005. Pursuant to the MPSC final rate order, transmission expense previously recorded in operation and maintenance expenses are now reflected in purchased power expenses. The PSCR mechanism provides related revenues for the transmission expense.


	Three Months Ended						Six Months Ended
	June 30						June 30
Power Generated and Purchased	2005			2004			2005			2004
(in Thousands of MWh)
Power Plant Generation
Fossil		9,546			8,507			19,310			18,291
Nuclear		2,272			2,409			4,325			4,817

		11,818			10,916			23,635			23,108
Purchased Power		1,331			1,226			2,809			2,424

System Output		13,149			12,142			26,444			25,532
Less Line Loss and Internal Use		(752	)		(1,130	)		(1,349	)		(1,911	)

Net System Output		12,397			11,012			25,095			23,621


Average Unit Cost ($/MWh)
Generation (1)	$	14.66		$	12.68		$	14.53		$	12.78

Purchased Power (2)	$	85.66		$	34.04		$	66.51		$	34.29

Overall Average Unit Cost	$	21.85		$	14.84		$	20.05		$	14.83


(1)		Represents fuel costs associated with power plants.

(2)		The average purchased power amounts include hedging activities.

Three Months Ended

Six Months Ended

June 30

Electric Sales

2005

2004

2005

2004

(in Thousands of MWh)

Residential

3,766

3,472

7,817

7,541

Commercial

3,820

3,049

7,184

6,540

Industrial

3,024

2,810

5,920

5,564

Wholesale

557

552

1,120

1,109

Other

103

193

212

11,255

9,986

22,234

20,966

Interconnections sales (1)

1,142

1,026

2,861

2,655

Total Electric Sales

12,397

11,012

25,095

23,621

Electric Deliveries

(in Thousands of MWh)

Retail and Wholesale

11,255

9,986

22,234

20,966

Electric Choice

1,996

2,480

3,910

4,622

Electric Choice — Self Generators (2)

174

185

366

352

Total Electric Sales and Deliveries

13,425

12,651

26,510

25,940


(1)		Represents power that is not distributed by Detroit Edison.

(2)		Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.

Operation and maintenance expense decreased $30 million in the second quarter of 2005 and $52 million in the 2005 six-month period and included transmission expenses of $25 million in the 2004 second quarter and $39 million in the 2004 six-month period. Pursuant to the MPSC final rate order, transmission expenses in 2005 are included in purchased power expense with related revenues through the PSCR mechanism. In addition, pursuant to the MPSC final rate order, merger interest is no longer allocated to Detroit Edison. The 2005 periods also experienced lower uncollectible accounts receivable expense, partially offset by increased power plant outage expenses, higher costs for the funding of the low-income customer assistance fund and system reliability expenses.

Depreciation and amortization expense increased $38 million in the second quarter of 2005 and $74 million in the 2005 six-month period. Depreciation expense reflects the income effects of recording

regulatory assets. The interim and final electric rate orders in 2004 recover PA 141 costs previously deferred as regulatory assets. As a result, the regulatory asset deferrals totaled $8 million in the second quarter of 2005 and $21 million in the 2005 six month period as compared to $22 million in the second quarter of 2004 and $57 million in the six month period ending June 30, 2004.

Other income and deductions expense decreased $4 million in the 2005 second quarter and $14 million in the 2005 six-month period, primarily due to lower interest expense as a result of adjustments due to settlements related to tax audits.

Outlook — Future operating results are expected to vary as a result of factors such as regulatory proceedings, new legislation, changes in market prices of power, coal and natural gas, plant performance, cost containment efforts and process improvements, changes in economic conditions, weather, the levels of customer participation in the electric Customer Choice program and the severity and frequency of storms.

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

In conjunction with DTE Energy’s sale of International Transmission Company (ITC) in February 2003, the Federal Energy Regulatory Commission (FERC) froze ITC’s transmission rates through December 2004. Annual rate adjustments pursuant to a formulistic pricing mechanism will result in an estimated increase in Detroit Edison’s transmission expense of $50 million annually, beginning in January 2005. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission revenues lost as a result of a FERC order modifying the pricing of transmission service in the Midwest. During the first half of 2005, Detroit Edison recorded an estimated $7 million of additional expense. Detroit Edison anticipates additional expenses of approximately $1 million per month through March 2006. Detroit Edison is expected to incur an additional $15 million in 2005 for charges related to the implementation of Midwest Independent Transmission System Operator’s open market. Detroit Edison received rate orders in 2004 that allow for the recovery of increased transmission expenses through the PSCR mechanism.

See Note 5 — Regulatory Matters.

GAS UTILITY

Gas Utility operations include gas distribution services primarily provided by MichCon that purchases, stores, distributes and sells natural gas to 1.2 million residential, commercial and industrial customers located throughout Michigan.

Factors impacting income: Gas Utility’s earnings decreased $13 million in the 2005 second quarter and declined $71 million in the 2005 six-month period. As subsequently discussed, results primarily reflect the impact of effective tax rate adjustments and the impact of the MPSC’s April 2005 gas cost recovery and final rate orders.

The MPSC final gas rate order disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. MichCon impaired this asset by approximately $42 million in the first quarter of 2005. This impairment was not reflected at DTE Energy since this disallowance was previously reserved at the time of the MCN acquisition in 2001.


	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
(in Millions)
Operating Revenues	$	267		$	276		$	1,119		$	1,005
Cost of Gas		137			163			781			662

Gross Margin		130			113			338			343
Operation and Maintenance		98			112			221			212
Depreciation and Amortization		24			25			50			51
Taxes other than Income		14			13			27			25
Asset (Gains) and Losses, Net		—			—			4			(2	)

Operating Income (Loss)		(6	)		(37	)		36			57
Other (Income) and Deductions		9			11			23			24
Income Tax Provision (Benefit)		36			(10	)		51			—

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


Operating Income (Loss) as a Percent of Operating Revenues		(2	)%		(13	)%		3	%		6	%

Gross margins increased $17 million in the 2005 second quarter and decreased $5 million in the 2005 six-month period. Gross margins in the 2005 second quarter were favorably affected by higher base rates as a result of the interim and final gas rate orders. In April 2005, the MPSC issued an order in the 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at December 2001. We recorded the impact of the disallowance during the first quarter of 2005. Operating revenues and cost of gas increased in the 2005 six month period reflecting higher gas prices which are recoverable from customers through the gas cost recovery (GCR) mechanism.


	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Gas Markets (in Millions)
Gas sales	$	206	$	220	$	979	$	875
End user transportation		28		25		73		67

		234		245		1,052		942
Intermediate transportation		12		12		28		27
Other		21		19		39		36

	$	267	$	276	$	1,119	$	1,005


Gas Markets (in Bcf)
Gas sales		22		22		106		107
End user transportation		33		29		83		79

		55		51		189		186
Intermediate transportation		84		129		218		303

		139		180		407		489

Operation and maintenance expense decreased $14 million in the 2005 second quarter and increased $9 million in the 2005 six-month period. The decrease in the second quarter was due to DTE Energy no longer allocating merger-related interest to MichCon effective in April 2005 as a result of the disallowance of those costs in the MPSC’s final rate order. The decrease for the second quarter was also due to a decline in injuries and damages accruals. For the six months ended, the increase is primarily due to the impact of the MPSC final rate order which disallowed certain environmental expenses that had been recorded as a regulatory asset and its requirement to defer negative pension expense as a regulatory liability. Uncollectible accounts receivables expense increased in the six-month period reflecting higher past due amounts attributable to an increase in gas prices, continued weak economic conditions and inadequate government-sponsored assistance for low-income customers.

Asset gains and losses, net increased $6 million in the 2005 six-month period as a result of a write-off of certain computer equipment and related depreciation resulting from the April 2005 final rate order.

Income taxes increased $46 million in the 2005 second quarter and $51 million in the 2005 six-month period. Income taxes were negatively affected by increases in effective tax rate adjustments of $35 million in the 2005 second quarter and $59 million in the 2005 six-month period. The adjustments were required in 2005 to be consistent with the estimated annual effective tax rate. The 2005 effective income tax rate is unusually low due to the relationship of annual tax adjustments to the level of pre-tax income which has been impacted by rate order considerations. The effective rate adjustments are substantially offset by corresponding adjustments in the Corporate & Other segment, with minor impact on DTE Energy consolidated results.

Outlook — Operating results are expected to vary as a result of factors such as regulatory proceedings, weather and changes in economic conditions, and cost containment efforts and process improvements. 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. In the April 2005 final gas rate order, the MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC.

See Note 5 — Regulatory Matters.

NON-UTILITY OPERATIONS

Power and Industrial Projects

Power and Industrial Projects is comprised of a portfolio of asset intensive businesses that supply energy inputs to and manage energy assets for large industrial users. The businesses are Coal-Based Fuels, On-Site Energy Projects, non-utility Power Generation, Biomass and PepTec. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. The production of synthetic fuel from all of our synfuel plants and the production of coke from one of our coke batteries generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Non-utility 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, non-utility Power Generation develops, operates and acquires coal and gas-fired generation. Biomass develops, owns and operates landfill recovery systems throughout the United States. PepTec uses proprietary technology to produce high quality coal products from fine coal slurries typically discarded from coal mining operations.

Factors impacting income: Power and Industrial Projects earnings decreased $23 million during the 2005 second quarter and increased $10 million in the 2005 six-month period. The earnings variances are primarily due to the synfuel operations and the comparability of results is affected by the gains recognized from selling interests in our synfuel plants and gains or losses on synfuel hedges.


	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
(in Millions)
Operating Revenues	$	348		$	269		$	659		$	524
Operation and Maintenance		378			292			698			561
Depreciation and Amortization		27			24			52			45
Taxes other than Income		8			5			15			7
Asset (Gains) and Losses, Net		(19	)		(58	)		(101	)		(106	)

Operating Income (Loss)		(46	)		6			(5	)		17
Other (Income) and Deductions		(6	)		(6	)		(10	)		(6	)
Minority Interest		(68	)		(51	)		(121	)		(81	)
Income Taxes
Provision		10			21			47			35
Section 29 Tax Credits		(13	)		(12	)		(20	)		(20	)

		(3	)		9			27			15

Net Income	$	31		$	54		$	99		$	89

Operating revenues increased $79 million in the 2005 second quarter and $135 million in the 2005 six-month period primarily reflecting higher synfuel sales, along with higher market prices for our coke production. The improvement in synfuel revenues results from increased production due to sales of project interests in prior periods, reflecting our strategy to produce synfuel primarily from plants in which we had sold interests in order to optimize income and cash flow. As previously discussed, operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold.

Operation and maintenance expense increased $86 million in the 2005 second quarter and $137 million in the 2005 six-month period reflecting costs associated with the increased levels of synfuel production.

Asset (gains) and losses, net decreased $39 million in the 2005 second quarter and decreased $5 million in the 2005 six-month period. The gains consist primarily of sales of interests in our synfuel projects. The decline is due to the deferral of the variable component of gains resulting from the increase in crude oil prices. We also recorded mark to market losses on derivatives used to economically hedge our cash flow exposure related to the risk of an increase in oil prices. Partially offsetting this decline is additional sales of interests in our synfuel projects resulting in fixed payment-related gains. During the first six months of 2005, we recorded a $100 million pre-tax gain on synfuel sales, as compared to $106 million pre-tax gain in 2004. The following table displays the various components that comprise the determination of gains recorded in the 2005 periods related to our synfuel projects.


(in Millions)	Three Months Ended					Six Months Ended
	June 30					June 30
Components of Synfuel Gains	2005			2004		2005			2004
Gains associated with fixed payments	$	29		$	23	$	57		$	39
Gains associated with variable payments		69			35		110			67
Deferred gains reserved on variable payments		(69	)		—		(110	)		—
Unrealized hedge gains (losses) (mark-to-market)
Hedges for 2005 exposure		(27	)		—		23			—
Hedges for 2006 exposure		16			—		20			—

Net synfuel gains	$	18		$	58	$	100		$	106



After Tax synfuel gains	$	12		$	38	$	65		$	69

Minority interest increased $17 million in the second quarter of 2005 and $40 million in the six-month period of 2005. The amounts reflect our partners’ share of operating losses associated with synfuel operations. The sale of interests in our synfuel facilities during prior periods resulted in allocating a larger percentage of such losses to our partners.

Income taxes declined $12 million in the 2005 second quarter and increased $12 million in the 2005 six-month period reflecting changes in pre-tax income.

Outlook — We plan to complete the sale of additional interests in our two majority-owned synfuel plants during 2005 and take actions to protect our expected synfuel cash flows of approximately $1.6 billion through 2008. Synfuel-related tax credits expire in December 2007. We will continue leveraging our extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. As a result of executing long-term utility services contracts in 2004, we expect solid earnings from our on-site energy business in 2005. We expect to continue to grow our Biomass and PepTec businesses. Biomass, in conjunction with the Coal Services business, has entered the coal mine methane business. We purchased coal mine methane assets in Illinois at the end of 2004, and completed the reconfiguration of equipment and restarted operations during the second quarter of 2005. We believe a substantial market could exist for the use of PepTec’s technology. We continue to modify and test this technology.

Unconventional Gas Production

Unconventional Gas Production is engaged in natural gas project development and production. Our Unconventional Gas Production business primarily produces gas from proven reserves in northern Michigan and sells the gas to the Fuel Transportation and Marketing segment.

Factors impacting income: Earnings decreased $2 million in the second quarter of 2005 and declined $2 million in the six months ended June 30, 2005. Both the quarter and year to date decline in earnings are due to lower production volumes and increased operating expenses.


	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
(in Millions)
Operating Revenues	$	17	$	18	$	33	$	35
Operation and Maintenance		8		6		14		13
Depreciation and Amortization		5		5		9		9
Taxes Other Than Income		2		2		4		4

Operating Income		2		5		6		9
Other (Income) and Deductions		2		3		4		5
Income Tax Provision		—		—		1		1

Net Income	$	—	$	2	$	1	$	3

Outlook — We expect to continue developing our gas production properties in northern Michigan and leverage our experience in this area by pursuing investment opportunities in unconventional gas production outside of Michigan. During 2004, we acquired approximately 50,000 leasehold acres in the Barnett shale in Texas, an area of increasing production. We began drilling wells in proven areas in December 2004 and are continuing to drill a number of test wells in 2005. Initial results from the test wells are expected in the second half of 2005. If the results are successful, we could commit a significant level of capital over the next several years to develop these properties.

Fuel Transportation and Marketing

Fuel Transportation and Marketing consists of the electric and gas marketing and gas trading operations of DTE Energy Trading and CoEnergy, Coal Services and the Pipelines, Processing & Gas Storage business. 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 their contracted natural gas pipelines and gas storage capacity positions. 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. Coal Services provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. Pipelines, Processing & Gas Storage 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: Fuel Transportation and Marketing earnings increased $1 million during the 2005 second quarter and decreased $70 million in the six-month period. The comparability of results is impacted by the $74 million one-time pre-tax gain from a contract modification/termination recorded in 2004 and 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage.


	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
(in Millions)
Operating Revenues	$	431		$	261		$	747		$	566
Fuel, Purchased Power and Gas.		275			96			448			230
Operation and Maintenance		153			165			310			240
Depreciation and Amortization		2			1			3			3
Taxes Other Than Income		2			1			3			2

Operating Income (Loss)		(1	)		(2	)		(17	)		91
Other (Income) and Deductions		—			(3	)		(1	)		(4	)
Income Tax Provision (Benefit)		(1	)		2			(6	)		35

Net Income (Loss)	$	—		$	(1	)	$	(10	)	$	60

Operating revenues increased $170 million in second quarter of 2005 and increased $181 million in the six months ended June 2005. During the first six months of 2005, our trading operations and Coal Services experienced increased revenues due to increased business volume. In 2004, our trading operations recorded an adjustment that increased revenue by $86 million related to the modification of a future purchase commitment under a transportation agreement with an interstate pipeline company (Note 4).

Fuel, purchased power and gas increased $179 million in the second quarter of 2005 and $218 million in the six month period of 2005 reflecting increased trading activity and increased mark to market losses in our trading business. During the first quarter of 2005, we were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for natural gas and an increase in the forward price for natural gas. We anticipate the financial impact of this timing difference will reverse when the gas is withdrawn from storage in the next storage cycle. In 2004, our trading operations recorded a gas inventory adjustment that increased expense by $12 million related to the termination of a 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.

Operations and maintenance expenses decreased $12 million in the 2005 second quarter and increased $70 million in the 2005 six-month period. During the second quarter Coal Services experienced a decline in volume, however for the year to date period, Coal Services had increased coal purchases due to increased sales.

Income tax provision decreased $3 million in 2005 second quarter and $41 million in 2005 six-month period reflecting decreased pre-tax income.

Outlook – We expect to continue to grow our Coal Services business by acquiring strategic physical assets across the coal value chain. The electric and gas marketing and trading business has experienced recent changes including expansion into the gas business and impacts on electric margins due to the MISO procedures and entry of new financial participants. We will seek to manage the businesses 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 electric and gas marketing and trading portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as owned and contracted natural gas pipelines and storage assets. The financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not considered derivatives for accounting purposes. As a result, this segment will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which runs annually from April of one year to March of the next year. Our strategy is to economically hedge a majority of the price risk of all gas purchases for storage with sales in the over-the-counter (forwards) and futures markets. Current accounting rules require the marking to market of forward sales and futures, but do not allow for the marking to market of

the related gas inventory. This results in gains and losses that are recognized in different interim and annual accounting periods. We anticipate the financial impact of this timing difference will typically reverse by the end of each storage cycle. See “Fair Value of Contracts” section that follows.

We are seeking regulatory approval for a capacity expansion at one of our Michigan storage facilities which will allow an additional 14 Bcf of long-term sales starting in April 2006. In addition, Vector Pipeline is in advanced negotiation with prospective customers to support an expansion project for an in-service date of November 2007. We are also seeking to secure markets for our 10.5% interest in the proposed Millennium Pipeline and are considering increasing our equity position.

CORPORATE & OTHER

Corporate & Other includes various corporate support functions such as accounting, legal and information technology. As these functions essentially support the entire Company, their costs 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-utility debt and investments, including assets held for sale and in emerging energy technologies. These investments include DTE Energy Technologies (Dtech), which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations.

Factors impacting income: Corporate & Other’s results declined $3 million in the 2005 second quarter and increased $7 million in the 2005 six-month period. Results reflect adjustments in both years to normalize the effective income tax rate. 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, as well as lower Michigan Single Business Taxes resulting from tax saving initiatives.

Outlook — In July 2005, management approved the restructuring of Dtech in which certain assets and liabilities are planned to be sold, certain businesses are planned to be terminated and certain businesses are planned to be merged with Detroit Edison or one of its affiliates. We expect to recognize a net of tax impairment loss of approximately $25 million to $30 million in the 2005 third and fourth quarters representing the write-down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill. See Note 12.

DISCONTINUED OPERATIONS

Southern Missouri Gas Company — We owned 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” and we have reported its operating results as a discontinued operation. We 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. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and the sale closed in May 2005. During the second quarter of 2005 we recognized a net of tax gain of $2 million.

International Transmission Company — In February 2003, we sold International Transmission Company (ITC), our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Through December 31, 2004, we recorded a net of tax gain of $58 million. During the second quarter of 2005, the net of tax gain was adjusted to $56 million.

CAPITAL RESOURCES AND LIQUIDITY


	Six Months Ended
	June 30
(in Millions)	2005			2004
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	151		$	225
Depreciation, depletion and amortization		424			346
Deferred income taxes		65			112
Gain on sale of synfuel and other assets, net		(97	)		(130	)
Working capital and other		136			(34	)

		679			519

Investing activities:
Plant and equipment expenditures — utility		(372	)		(363	)
Plant and equipment expenditures — non-utility		(58	)		(33	)
Proceeds from sale of synfuel and other assets, net of cash divested		163			147
Restricted cash and other investments		(37	)		(64	)

		(304	)		(313	)

Financing activities:
Issuance of long-term debt and common stock		395			439
Redemption of long-term debt		(639	)		(565	)
Short-term borrowings, net		91			120
Repurchase of common stock		(11	)		—
Dividends on common stock and other		(181	)		(179	)

		(345	)		(185	)

Net Increase in Cash and Cash Equivalents	$	30		$	21

Operating Activities

We use cash derived from operating activities to maintain and expand our electric and gas utilities and to grow our non-utility businesses. In addition, we use cash from operations to retire long-term debt and pay dividends. A majority of the Company’s operating cash flow is provided by the two regulated utilities, which are significantly influenced by factors such as power supply cost and gas cost recovery proceedings, weather, electric Customer Choice sales loss, regulatory deferrals, regulatory outcomes, economic conditions and operating costs. Our non-utility businesses also provide sources of cash flow to the enterprise and reflect a range of operating profiles. These profiles vary from our synthetic fuel business, which we believe will provide substantial cash flow through 2008, to new start-ups, new investments and expansion of existing businesses. These new start-ups include our unconventional gas and waste coal recovery businesses, which we are growing and, if successful, could require significant investment.

Although DTE Energy’s overall earnings were down $74 million or 33% in the 2005 six-month period, cash from operations totaling $679 million, was up $160 million or 31% from the comparable 2004 period. The operating cash flow comparison reflects a decrease of $170 million in working capital and other requirements, partially offset by a decrease of $10 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains). Working capital requirements during the 2004 period were higher due primarily to income tax payments made as a result of certain 2003 transactions, including the divestiture of ITC.

Outlook — We expect cash flow from operations to increase over the long-term, including a rise of $100 million to $150 million for the full year 2005 over 2004. Cash flow improvements from utility rate increases and the sale of interests in our synfuel projects, will be partially offset by higher cash requirements on environmental and other utility capital as well as growth investments in our non-utility portfolio. We are continuing our efforts to identify opportunities to improve cash flow through working capital improvement initiatives.

Assuming no synfuel tax credit phase out or reduction in taxable income in this year or future years, we expect cash flow from our synfuel business to total approximately $1.6 billion between 2005 and 2008 of which $420 million is expected in 2005. Synfuel cash flow consists of variable and fixed payments from partners, proceeds from option and other contracts used to protect us from risk of loss from a tax credit phase-out and the use of prior years’ tax credit carry-forwards. We believe our expected 2005 synfuel cash flow is 100% protected from risk of loss, our estimated 2006 cash flow of $500 million is approximately 75% protected and our 2007 cash flow of $500 million is approximately 20% protected. These amounts are based on current forecasts of tax credit utilization and taxable income. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use this cash to reduce parent company debt, to continue to pursue growth investments that meet our strict risk-return and value creation criteria and to potentially repurchase common stock if adequate investment opportunities are not available. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit ratings and outlook, and to replace the value of synfuel operations currently inherent in our share price.

Investing Activities

Cash inflows associated with investing activities are partially generated from the sale of assets and are utilized to invest in our utility and non-utility businesses. In any given year, we will attempt 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-utility businesses is for ongoing maintenance, expansion and growth. Growth spending is managed very carefully. We seek investments that meet strict criteria in terms of strategy, management skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis.

Net cash outflows for investing activities decreased $9 million in the 2005 six-month period as compared to the same 2004 period primarily due to higher synfuel proceeds and lower other investments, partially offset by higher capital expenditures.

Capital expenditures during the 2005 six-month period were $430 million. This represents a $34 million increase from the comparable 2004 period and was driven by spending on DTE2, our Company-wide initiative to improve existing processes and implement new core information systems.

Outlook — Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2005 of up to $1.1 billion. The approximately $200 million increase over 2004 is primarily due to environmental spending requirements and our DTE2 investment, mitigated by lower base spending within our non-utility businesses. As previously mentioned, our strategy is to re-deploy cash generated through the sale of our synfuel assets. As opportunities become available, we may make additional growth investments beyond our base level of capital expenditures.

We believe that we will have sufficient capital resources, both internal and external, to fund anticipated capital requirements.

Financing Activities

We rely on both short-term borrowings and longer- term financings as a source of funding for our capital requirements not satisfied by the Company’s operations. Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturities. We continually evaluate our leverage target, which is currently 50% or lower, to ensure it is consistent with our objective to have a strong investment grade debt rating.

Net cash used for financing activities increased $160 million during the 2005 six-month period, compared to the same 2004 period, due mostly to redemption of long-term debt and a reduction in short-term and long-term debt issuances.

In February 2005, Detroit Edison issued senior notes totaling $400 million. Proceeds from this issuance were primarily used to call $385 million quarterly income debt securities (QUIDS), which will save approximately $9 million annually in interest expense.

In February 2005, Detroit Edison redeemed $76 million of 7.5% Senior Notes and $100 million of 7.0% remarketed secured notes, which matured in February 2005.

In July 2005, Detroit Edison entered into a Note Purchase Agreement pursuant to which it agreed to issue and sell to a group of institutional investors in a private placement transaction $100 million aggregate principal amount of its 2005 Series C, 5.19% Senior Notes due October 1, 2023. The sale of the notes pursuant to the agreement is expected to close on or about September 29, 2005. The proceeds will be used to redeem Detroit Edison senior notes due in October 2005.

In August 2005, DTE expects to remarket the senior notes comprising part of its Equity Security Units issued in June 2002. The senior notes will mature in August 2007. Additionally, in August 2005, DTE expects to settle the stock purchase contract component of its Equity Security Units by issuing common stock to holders of units. The issue price will be determined by the average closing price per share of our common stock during a 20 trading-day period ending August 11, 2005. Based on this price, the number of shares expected to be issued will be between 3.3 million and 4 million. The total equity to be issued in connection with these security units is $172.5 million.

Outlook — Our goal is to maintain a healthy balance sheet. We will continually evaluate our debt portfolio and take advantage of favorable refinancing opportunities .

MichCon currently has an $81.25 million, three-year unsecured credit agreement entered into in October 2003, and a $243.75 million, five-year unsecured revolving credit facility entered into in October 2004. These credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for our commercial paper program. These credit facilities make possible short-term borrowings primarily for seasonal needs to buy gas in the summer for use in the winter heating season. In the last twelve months, the peak borrowing for these facilities was $324.8 million. Borrowings under the facilities are available at prevailing short-term interest rates. Among other things, the agreements require MichCon to maintain an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1 for each twelve-month period ending on the last day of March, June, September and December of each year.

As a result of the non-recurring accounting adjustments that were required due to the MPSC gas rate orders issued on April 28, 2005, MichCon did not meet the EBITDA to interest ratio at March 31, 2005. The credit facilities were amended on May 9, 2005 to exclude the EBITDA to interest ratio for the first quarter of 2005, and subsequently amended on June 10, 2005 to exclude non-recurring items in the EBITDA calculation through the maturity of the agreement. If lenders had not amended the credit facilities, MichCon’s access to the commercial paper markets would have been limited. At June 30, 2005, MichCon did not have any indebtedness under the credit facilities or any commercial paper outstanding. If MichCon experiences diminished ability to access the short-term and/or long-term capital markets, it will have to seek additional sources of liquidity. This may have a material negative impact on MichCon’s financial position and significantly harm the operation of that business. We believe that MichCon will have sufficient internal and external capital resources to manage liquidity and to fund anticipated capital requirements .

CRITICAL ACCOUNTING POLICIES

Goodwill

Certain of our business units have goodwill resulting from purchase business combinations. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we must determine the reporting unit’s fair value using valuation techniques, which use estimates of discounted future cash flows to be generated by the reporting unit. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance.

As of June 30, 2005, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units, with approximately $769 million allocated to the Gas Utility reporting unit. The value of the utility reporting units may be significantly impacted by rate orders and the regulatory environment. The Gas Utility reporting unit is comprised primarily of MichCon. We made certain cash flow assumptions for MichCon that were dependent upon the outcome of the gas rate case (Note 5). We received the MPSC final order in the gas rate case in late April 2005. We evaluated the impact of the order on our valuation assumptions and the carrying value of the related goodwill for our Gas Utility reporting unit. We have determined that the fair value of the Gas Utility reporting unit exceeds the carrying value and no impairment of goodwill exists.

We continue to monitor our estimates and assumptions regarding future cash flows. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

ENVIRONMENTAL MATTERS

The United States Environmental Protection Agency (EPA) ozone transport and acid rain regulations and final new air quality standards relating to ozone and particulate air pollution continue to impact us. In March 2005, the EPA issued interstate air and mercury rules. The interstate air rule requires a 70 percent reduction in annual emissions of nitrogen oxide and sulfur dioxide by 2015. The mercury rule represents the first national regulation of power plant mercury emissions and expects to achieve a 70 percent reduction when fully implemented in 2018. Detroit Edison estimates that it will spend up to $100 million in 2005 and up to an additional $1.8 billion of future capital expenditures through 2018 to satisfy both existing and new control requirements. Under PA 141 and the MPSC’s November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

DTE2

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems including, finance, human resources, supply chain and work management. As part of this initiative, we are implementing Enterprise Business Systems software including, among others, products developed by SAP AG and MRO Software, Inc. The first phase of implementation commenced in July 2005 and will continue at minimum through 2007. The conversion of data and the implementation and operation of SAP will be continuously monitored and reviewed and should ultimately strengthen our internal control structure.

MIDWEST INDEPENDENT TRANSMISSION SYSTEM OPERATOR (MISO)

The MISO was formed in 1996 by its member transmission owners and in December 2001 received FERC approval as a Regional Transmission Organization (RTO) authorized to provide regional transmission services as prescribed by FERC in its Order 2000. Order 2000 requires an RTO to perform eight functions

including, tariff administration, transmission system congestion management, provision of ancillary services to support transmission operations, market monitoring, interregional coordination and the coordination of system planning and expansion. MISO’s independence from ownership of either generation or transmission facilities is intended to enable it to ensure fair access to the transmission grid, and through its congestion management role, MISO is also charged with ensuring grid reliability. MISO’s initial provision of transmission services in December 2001 was known as Day 1 operations.

In keeping with Order 2000, which permits RTOs to provide real-time energy imbalance services and a market-based mechanism for congestion management, MISO, on April 1, 2005, launched its Midwest Energy Market, or Day 2 operations, and began regional wholesale electric market operations and transmission service throughout its area. A key feature of the Midwest Energy Market is the establishment of Locational Marginal Prices (LMPs) which provide price transparency for the sale and purchase of wholesale electricity at different locations in the market territory. The LMPs establish the price of the most efficient generation offered for dispatch adjusted to reflect the cost of locational congestion on the transmission system. Detroit Edison participates in the Energy Market by offering its generation on a day-ahead and real time basis and by bidding for power in the market to serve its load. The cost of power procured from the market net of any gain realized from generation sold into the market is included and recovered through the PSCR mechanism. The Midwest Market is expected to yield financial benefits to consumers as a result of generator price competition arising from the price transparency provided by the market. In addition, LMPs are expected to encourage new generation to locate where the power produced is of most value to the load and is expected to identify where new transmission facilities are needed to relieve grid congestion.

MISO is compensated for assuring grid reliability and for supporting the energy market through FERC-approved rates charged to load. Detroit Edison became a non-transmission owning member of MISO in compliance with section 10w (1) of Act 141. The MPSC has ordered that MISO costs charged to Detroit Edison should be recovered through the PSCR mechanism.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 — New Accounting Pronouncements for discussion of new pronouncements.

FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and we believe provide enhanced transparency of the derivative activities and position of our Energy Trading and CoEnergy businesses and our other businesses.

We use the criteria in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments. The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can sometimes be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as Assets or Liabilities from Risk Management and Trading Activity, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the fair value of the contract, a practice known as mark to market (MTM) accounting.

Fair value represents the amount at which willing parties would transact an arms-length transaction. To determine the fair value of contracts that are accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward prices, volatility, interest rates, and exercise periods.

Contracts we typically classify as derivative instruments are power, gas and oil forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as derivatives

(and which are therefore excluded from the following tables) include gas inventory, gas storage and transportation arrangements, full-requirements power contracts and gas and oil reserves. As subsequently discussed, we have fully reserved the value of derivative contracts beyond the liquid trading timeframe and which therefore do not impact income.

The subsequent tables contain the following four categories represented by their operating characteristics and key risks.

•		“Proprietary Trading” represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

•		“Structured Contracts” represents derivative activity transacted with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting transaction can be executed.

•		“Economic Hedges” represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility as discussed in more detail in the preceding Results of Operations section.

•		“Other Non-Trading Activities” primarily represent derivative activity associated with our Michigan gas reserves. Oil-related derivative contracts have been executed to economically hedge cash flow risks related to underlying, non-derivative synfuel related positions through 2006. A substantial portion of the price risk associated with the Michigan gas reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Assets or Liabilities from Risk Management and Trading with an offset in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and synfuel proceeds including changes therein.

Roll-Forward of Mark to Market Energy Contract Net Assets

The following tables provide details on changes in our MTM net asset or (liability) position during 2005:


													Other
	Energy Trading & CoEnergy												Non-
	Proprietary			Structured			Economic						Trading
(in Millions)	Trading			Contracts			Hedges			Total			Activities			Total
MTM at December 31, 2004	$	3		$	23		$	(98	)	$	(72	)	$	(100	)	$	(172	)

Reclassed to realized upon settlement		(4	)		(1	)		38			33			26			59
Changes in fair value recorded to income		10			(14	)		(59	)		(63	)		41			(22	)
Amortization of option premiums		—			—			(2	)		(2	)		—			(2	)

Amounts recorded to unrealized income		6			(15	)		(23	)		(32	)		67			35
Amounts recorded in OCI		—			(24	)		—			(24	)		(105	)		(129	)
Option premiums paid and other		5			—			—			5			40			45

MTM at June 30, 2005	$	14		$	(16	)	$	(121	)	$	(123	)	$	(98	)	$	(221	)

The following table provides a current and noncurrent analysis of Assets and Liabilities from Risk Management and Trading Activities as reflected in the Consolidated Statement of Financial Position as of June 30, 2005. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.


																Other
	Energy Trading & CoEnergy															Non-			Total
	Proprietary			Structured			Economic									Trading			Assets
(in Millions)	Trading			Contracts			Hedges			Eliminations			Totals			Activities			(Liabilities)
Current assets	$	144		$	131		$	139		$	(93	)	$	321		$	40		$	361
Noncurrent assets		25			67			145			(36	)		201			127			328

Total MTM assets		169			198			284			(129	)		522			167			689


Current liabilities		(133	)		(132	)		(203	)		93			(375	)		(85	)		(460	)
Noncurrent liabilities		(22	)		(82	)		(202	)		36			(270	)		(180	)		(450	)

Total MTM liabilities.		(155	)		(214	)		(405	)		129			(645	)		(265	)		(910	)

Total MTM net assets (liabilities)	$	14		$	(16	)	$	(121	)	$	—		$	(123	)	$	(98	)	$	(221	)

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 timeframe. Our intent is to recognize MTM activity only when pricing data is obtained from active quotes and published indexes. Actively quoted and published indexes include exchange traded (i.e., NYMEX) and over-the-counter (OTC) positions for which broker quotes are available. The NYMEX has currently quoted prices for the next 72 months. Although broker quotes for gas and power are generally available for 18 and 24 months into the future, respectively, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe and which therefore do not impact income.

The table below shows the maturity of our MTM positions:


(in Millions)													Total
										2008 and			Fair
Source of Fair Value	2005			2006			2007			Beyond			Value
Proprietary Trading	$	16		$	(7	)	$	4		$	1		$	14
Structured Contracts		6			(10	)		(13	)		1			(16	)
Economic Hedges		(6	)		(41	)		(67	)		(7	)		(121	)

Total Energy Trading & CoEnergy		16			(58	)		(76	)		(5	)		(123	)
Other Non-Trading Activities		(1	)		(24	)		(57	)		(16	)		(98	)

Total	$	15		$	(82	)	$	(133	)	$	(21	)	$	(221	)

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 coal 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. Commodity price risk associated with our electric and gas utilities is limited due to the PSCR and GCR mechanisms.

Our Energy Services and Biomass businesses are also subject to crude oil price risk. As previously discussed, the Section 29 tax credits generated by DTE Energy’s synfuel, coke battery and biomass operations are subject to phase out if domestic crude oil prices reach certain levels. We have entered into a series of derivative contracts for 2005 and 2006 to economically hedge the impact of oil prices on our synfuel cash flow.

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered at risk of probable 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.

Other

We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.

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, 2005, the Company had a floating rate debt to total debt ratio of approximately 12% (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.

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, 2005 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 10%			Assuming a 10%
Activity	increase in rates			decrease in rates			Change in the fair value of
Gas Contracts	$	(23	)	$	23		Commodity contracts
Power Contracts	$	(26	)	$	26		Commodity contracts
Oil Contracts	$	69		$	(49	)	Commodity options
Interest Rate Risk	$	(299	)	$	313		Long-term debt
Foreign Currency Risk	$	—		$	—		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 design and operation 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, 2005, 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 effective in ensuring that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Due to the inherent limitations in the effectiveness of any disclosure controls and procedures, management cannot provide absolute assurance that the objectives of its disclosure controls and procedures will be met.

(b) Changes in internal control over financial reporting

On April 1, 2005, the Midwest Independent System Operator (MISO) Day 2 market became effective which impacted DTE Energy’s regulated electric generation, purchased power and non-utility power marketing and trading. In connection with the implementation of MISO Day 2, DTE Energy has implemented new processes and modified existing processes to facilitate participation in and settlement within the MISO market. The impact of the MISO Day 2 market may be considered a material change in internal control over financial reporting. With the exception of this change, there has been no other change in the Company’s internal control over financial reporting during the quarter ended June 30, 2005 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)	2005			2004			2005			2004
Operating Revenues	$	1,945		$	1,501		$	4,260		$	3,594


Operating Expenses
Fuel, purchased power and gas		638			377			1,607			1,118
Operation and maintenance		936			851			1,840			1,633
Depreciation, depletion and amortization		216			179			424			346
Taxes other than income		89			60			180			145
Asset (gains) and losses, net		(19	)		(61	)		(95	)		(111	)

		1,860			1,406			3,956			3,131


Operating Income		85			95			304			463


Other (Income) and Deductions
Interest expense		129			129			257			260
Interest income		(13	)		(17	)		(27	)		(27	)
Other income		(11	)		(33	)		(23	)		(43	)
Other expenses		15			14			26			29

		120			93			233			219

Income (Loss) Before Income Taxes and Minority Interest		(35	)		2			71			244

Income Tax Provision		3			18			40			93

Minority Interest		(68	)		(51	)		(121	)		(81	)


Income from Continuing Operations		30			35			152			232

Loss from Discontinued Operations, net of tax (Note 3)		(1	)		—			(1	)		(7	)


Net Income	$	29		$	35		$	151		$	225


Basic Earnings per Common Share (Note 6)
Income from continuing operations	$	.17		$	.20		$	.87		$	1.35
Discontinued operations		—			—			—			(.04	)

Total	$	.17		$	.20		$	.87		$	1.31


Diluted Earnings per Common Share (Note 6)
Income from continuing operations	$	.17		$	.20		$	.87		$	1.35
Discontinued operations		—			—			—			(.04	)

Total	$	.17		$	.20		$	.87		$	1.31


Average Common Shares
Basic		174			173			174			172
Diluted		175			174			175			172

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)	2005			2004
ASSETS
Current Assets
Cash and cash equivalents	$	86		$	56
Restricted cash		107			126
Accounts receivable
Customer (less allowance for doubtful accounts of $138 and $129, respectively)		1,103			880
Accrued unbilled revenues		232			378
Other		470			383
Inventories
Fuel and gas		517			509
Materials and supplies		153			159
Assets from risk management and trading activities		361			296
Other		318			209

		3,347			2,996


Investments
Nuclear decommissioning trust funds		613			590
Other		563			558

		1,176			1,148


Property
Property, plant and equipment		18,118			18,011
Less accumulated depreciation and depletion		(7,619	)		(7,520	)

		10,499			10,491


Other Assets
Goodwill		2,064			2,067
Regulatory assets		2,132			2,119
Securitized regulatory assets		1,391			1,438
Notes receivable		488			529
Assets from risk management and trading activities		328			125
Prepaid pension assets		185			184
Other		212			200

		6,800			6,662


Total Assets	$	21,822		$	21,297

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Financial Position


	(Unaudited)
	June 30			December 31
(in Millions, Except Shares)	2005			2004
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	979		$	892
Accrued interest		117			111
Dividends payable		90			90
Accrued payroll		24			33
Income taxes		—			16
Short-term borrowings		494			403
Gas inventory equalization (Note 1)		116			—
Current portion of long-term debt, including capital leases		885			514
Liabilities from risk management and trading activities		460			369
Other		833			581

		3,998			3,009


Other Liabilities
Deferred income taxes		1,250			1,124
Regulatory liabilities		831			817
Asset retirement obligations (Note 1)		943			916
Unamortized investment tax credit		137			143
Liabilities from risk management and trading activities		450			224
Liabilities from transportation and storage contracts		368			387
Accrued pension liability		313			265
Deferred gains from asset sales		235			414
Minority interest		120			132
Nuclear decommissioning		80			77
Other		664			635

		5,391			5,134


Long-Term Debt (net of current portion) (Note 7)
Mortgage bonds, notes and other		5,122			5,673
Securitization bonds		1,345			1,400
Equity-linked securities		172			178
Trust preferred-linked securities		289			289
Capital lease obligations		61			66

		6,989			7,606


Commitments and Contingencies (Notes 5, 9 and 10)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 174,159,338 and 174,209,034 shares issued and outstanding, respectively		3,307			3,323
Retained earnings		2,355			2,383
Accumulated other comprehensive loss		(218	)		(158	)

		5,444			5,548


Total Liabilities and Shareholders’ Equity	$	21,822		$	21,297

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Cash Flows (Unaudited)


	Six Months Ended
	June 30
(in Millions)	2005			2004
Operating Activities
Net Income	$	151		$	225
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		424			346
Deferred income taxes		65			112
Gain on sale of interests in synfuel projects		(100	)		(106	)
Loss (gain) on sale of assets, net		3			(24	)
Partners’ share of synfuel project losses		(149	)		(87	)
Contributions from synfuel partners		113			36
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		172			17

Net cash from operating activities		679			519


Investing Activities
Plant and equipment expenditures – utility		(372	)		(363	)
Plant and equipment expenditures – non-utility		(58	)		(33	)
Proceeds from sale of interests in synfuel projects		145			88
Proceeds from sale of other assets, net of cash divested		18			59
Restricted cash for debt redemptions		19			10
Other investments		(56	)		(74	)

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


Financing Activities
Issuance of long-term debt		395			418
Redemption of long-term debt		(639	)		(565	)
Short-term borrowings, net		91			120
Issuance of common stock		—			21
Repurchase of common stock		(11	)		—
Dividends on common stock		(179	)		(176	)
Other		(2	)		(3	)

Net cash used for financing activities		(345	)		(185	)


Net Increase in Cash and Cash Equivalents		30			21
Cash and Cash Equivalents at Beginning of the Period		56			54

Cash and Cash Equivalents at End of the Period	$	86		$	75

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

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


										Accumulated
	Common Stock						Retained			Other Comprehensive
(Dollars in Millions, Shares in Thousands)	Shares			Amount			Earnings			Loss			Total
Balance, December 31, 2004		174,209		$	3,323		$	2,383		$	(158	)	$	5,548

Net income		—			—			151			—			151
Dividends declared on common stock		—			—			(179	)		—			(179	)
Repurchase of common stock, net		(240	)		(10	)		—			—			(10	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(65	)		(65	)
Net change in unrealized gain on investments, net of tax		—			—			—			5			5
Unearned stock compensation and other		190			(6	)		—			—			(6	)

Balance, June 30, 2005		174,159		$	3,307		$	2,355		$	(218	)	$	5,444

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


(in Millions)	2005			2004
Net income	$	151		$	225

Other comprehensive income (loss), net of tax:
Net unrealized income (losses) on derivatives:
Losses arising during the period, net of taxes of $(46) and $(12), respectively		(85	)		(23	)
Amounts reclassified to earnings, net of taxes of $11 and $(2), respectively		20			(3	)

		(65	)		(26	)
Net change in unrealized gain on investments, net of taxes of $3 and $(6)		5			(11	)

		(60	)		(37	)

Comprehensive income	$	91		$	188

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 2004 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.

Prior to December 2004, DTE Energy did not eliminate amounts, principally within Other Income and Other Deductions, resulting from certain intercompany transactions. The amounts of the transactions are immaterial and had no effect on net income. Previously reported prior period amounts have been adjusted to eliminate those intercompany transactions and are now consistent with the current year’s presentation. We reclassified certain other prior year balances to match the current year’s financial statement presentation.

	•		Electric Utility, consisting of Detroit Edison;

	•		Gas Utility, primarily consisting of MichCon;

	•		Non-utility Operations

	•		Power and Industrial Projects, primarily consisting of synfuel projects, on-site energy services, steel-related projects, power generation with services and waste coal recovery operations;

	•		Unconventional Gas Production, primarily consisting of unconventional gas project development and production;

	•		Fuel Transportation and Marketing, primarily consisting of coal transportation and marketing, gas pipelines and storage, and energy marketing and trading operations; and

•

Corporate & Other, primarily consisting of corporate support functions and certain energy technology investments.

References in this report to “we,” “us,” “our” or “Company” are to DTE Energy and its subsidiaries, collectively.

Gains from Sale of Interests in Synthetic Fuel Facilities

Through June 30, 2005, we have sold interests in eight of our nine synthetic fuel production plants, representing approximately 88% of our total production capacity. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 9 for further discussion. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. We recorded pre-tax gains of $18 million in the second quarter of 2005 and $100 million for the six months ended June 30, 2005 from the sale of interests in synthetic fuel facilities compared to pre-tax gains of $58 million and $106 million for the comparative periods in 2004.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectibility is assured. The variable component includes an estimate of tax credits allocated to our partners, is subject to refund based on the annual oil price phase out, and is recognized as a gain only when probability of refund is considered remote and collectibility is assured. In the event that the tax credit is phased-out, we are contractually obligated to refund to our partners an amount equal to the operating losses funded by our partners. To assess the probability of refund, we use valuation and analyst models that calculate the probability of surpassing the estimated lower band of the phase-out range for the Reference Price of oil for the year. Due to the rise in oil prices, there is a possibility that the Reference Price of oil could reach the threshold at which Section 29 tax credits begin to phase out. While we believe the possibility of phase out is unlikely in 2005, we have not met the strict accounting gain recognition criteria that would allow us to recognize the gains on the variable component. We deferred $69 million pretax in the second quarter of 2005 and $110 million pretax in the six months ended June 30, 2005 of the variable component of synfuel-related gains for the potential phase-out of synfuel tax credits. All or a portion of the deferred gains will be recognized when and if the gain recognition criteria are met. It is possible that additional gains will be deferred in the third quarter until there is persuasive evidence that no tax credit phase out will occur. This will result in shifting earnings from earlier quarters to later quarters.

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 under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,”and follows the nominal vesting period approach for awards with retirement eligible provisions. No compensation cost related to stock options is reflected in earnings, 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 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)	2005			2004			2005			2004
Net Income As Reported	$	29		$	35		$	151		$	225
Less: Total stock-based expense (1)		(1	)		(2	)		(3	)		(4	)

Pro Forma Net Income	$	28		$	33		$	148		$	221


Earnings Per Share
Basic — as reported	$	.17		$	.20		$	.87		$	1.31

Basic — pro forma	$	.16		$	.19		$	.85		$	1.29


Diluted — as reported	$	.17		$	.20		$	.87		$	1.31

Diluted — pro forma	$	.16		$	.19		$	.85		$	1.29


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

Consolidated Statement of Cash Flows

A detailed analysis of the changes in assets and liabilities that are reported in the consolidated statement of cash flows follows:


	Six Months Ended
	June 30
(in Millions)	2005			2004
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(232	)	$	53
Accrued unbilled receivable		146			104
Accrued GCR revenue		17			(70	)
Inventories		(2	)		78
Accrued/Prepaid pensions		46			40
Accounts payable		87			76
Accrued PSCR refund		(29	)		45
Exchange gas payable		(34	)		(74	)
Income taxes payable		(49	)		(207	)
General taxes		10			(20	)
Risk management and trading activities		93			35
Gas inventory equalization		116			93
Other		3			(136	)

	$	172		$	17

Supplementary cash and non-cash information follows:


	Six Months Ended
	June 30
(in Millions)	2005		2004
Cash Paid for
Interest (excluding interest capitalized)	$	251	$	264
Income taxes	$	22	$	191
Noncash Investing and Financing Activities
Notes received from sale of synfuel projects	$	—	$	155
Sale of assets
Note receivable	$	47		—
Other assets	$	32		—
Common stock contribution to pension plan	$	—	$	170

Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations,” 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.”

A reconciliation of the asset retirement obligation for the 2005 six-month period follows:


(in Millions)
Asset retirement obligations at January 1, 2005	$	916
Accretion		30
Liabilities settled		(3	)

Asset retirement obligations at June 30, 2005	$	943

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.

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
(in Millions)	Pension Benefits						Benefits
	2005			2004			2005			2004
Three Months Ended June 30
Service Cost	$	17		$	14		$	14		$	10
Interest Cost		43			43			26			23
Expected Return on Plan Assets		(55	)		(56	)		(18	)		(14	)
Amortization of
Net loss		17			15			15			11
Prior service cost		2			2			—			(1	)
Net transition liability		—			—			2			2

Net Periodic Benefit Cost	$	24		$	18		$	39		$	31


Six Months Ended June 30

Service Cost	$	33		$	30		$	28		$	21
Interest Cost		86			86			52			46
Expected Return on Plan Assets		(109	)		(108	)		(35	)		(28	)
Amortization of
Net loss		34			31			30			21
Prior service cost		4			4			(1	)		(2	)
Net transition liability		—			—			4			4

Net Periodic Benefit Cost	$	48		$	43		$	78		$	62

Gas in Inventory

Gas inventory at MichCon is priced on a last-in, first-out (LIFO) basis. In anticipation that interim inventory reductions will be replaced prior to year end, the cost of gas of net withdrawals from inventory is recorded at the estimated average purchase rate for the calendar year. The excess of these charges over the LIFO cost is credited to the gas inventory equalization account. During interim periods when there are net injections to inventory, the equalization account is reversed.

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Stock Based Payments

In December 2004, the FASB issued SFAS No. 123-R, “Stock Based Payments,” which established the accounting for transactions in which an entity exchanges equity instruments for goods or services. SFAS No. 123-R was effective for interim or annual periods beginning after June 15, 2005 with earlier adoption encouraged. In April 2005, the U.S. Securities and Exchange Commission delayed the effective date by requiring implementation beginning in the next fiscal year that begins after June 15, 2005. We have completed a preliminary review and based on historical levels of stock based payments we estimate that the new standard will reduce reported earnings by approximately $5 million to $10 million per year.

Accounting for Conditional Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” FIN 47 seeks to clarify the requirement to record liabilities stemming from a legal obligation to perform asset retirement activities on fixed assets when that retirement is conditioned on a future event. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company is currently assessing the effects of this interpretation, and has not yet determined the impact on the consolidated financial statements.

NOTE 3 — DISCONTINUED OPERATIONS

Southern Missouri Gas Company

We owned 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” and we have reported its operating results as a discontinued operation. We 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. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and the sale was closed in May 2005. During the second quarter of 2005 we recognized a net of tax gain of $2 million.

International Transmission Company

In February 2003, we sold International Transmission Company (ITC), our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Through December 31, 2004, we recorded a net of tax gain of $58 million. During 2005, the net of tax gain was adjusted to $56 million.

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

In December 2004, Detroit Edison and other parties filed petitions for rehearing related to the MPSC’s November 2004 final rate order. Among other items, Detroit Edison’s petition requested a correction of the capital structure used in the determination of the final order and recovery of certain disallowed costs. On June 30, 2005, the MPSC issued a series of orders denying Detroit Edison’s and other parties petitions for rehearing.

Electric Rate Restructuring Proposal

On February 4, 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies that are part of its current pricing structure. The proposal would adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, commercial and industrial rates would be lowered, but residential rates would increase over a five-year period beginning in 2007. The MPSC indicated in the November 2004 final rate order that this proceeding is expected to be completed in time to have new rates in effect no later than January 1, 2006.

Other Postretirement Benefits Costs Tracker

On February 10, 2005, Detroit Edison filed an application, pursuant to the MPSC’s November 2004 final rate order, requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. This mechanism would recognize differences between cost levels collected in rates and the actual costs under current accounting rules as regulatory assets or regulatory liabilities with an annual reconciliation proceeding before the MPSC.

2004 PSCR Reconciliation and 2004 Net Stranded Cost Case

In accordance with the MPSC’s direction in Detroit Edison’s November 2004 final rate order, on March 31, 2005, Detroit Edison filed a joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. The combined proceeding will provide a comprehensive true-up of the 2004 PSCR and production fixed cost stranded cost calculations, including treatment of Detroit Edison’s third party wholesale sales revenues. Under the MPSC’s preferred methodology, Detroit Edison incurred approximately $112 million in stranded costs in 2004. Detroit Edison also received approximately $218 million in third party wholesale sales.

In the filing, Detroit Edison recommended the following distribution of the $218 million of third party wholesale sale revenues: $91 million to offset PSCR fuel expense and $74 million to offset 2004 production operation and maintenance expense. The remaining $53 million would be allocated between bundled customers and electric Customer Choice customers. This allocation would result in a refund of approximately $8 million to bundled customers and a net stranded cost amount to be collected from electric Customer Choice customers of approximately $99 million.

Included with the application was the filing of a motion for a temporary interim order requesting the continuation of the existing electric Customer Choice transition charges until a final order is issued. An order is expected in the first quarter of 2006.

Power Supply Recovery Proceedings

2005 Plan Year — In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates. In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order. The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor are power supply costs, transmission expenses and nitrogen oxide emission allowance costs. Detroit Edison self-implemented a factor of a negative 2.00 mills per kWh on January 1, 2005. Effective June 1, 2005, Detroit Edison began billing the maximum allowable factor of 0.48 mills per kWh due to increased power supply costs. At June 30, 2005, Detroit Edison has recorded an under-recovery of approximately $38 million related to the 2005 plan year. The Michigan Attorney General filed a motion for summary disposition of this proceeding based on arguments that the PSCR statute requires a fixed 48-month PSCR factor. The MPSC denied the Attorney General’s motion and affirmed Detroit Edison’s ability to make annual filings for PSCR plan approval.

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 requested an overall increase in base rates of $194 million per year 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 final rate request was subsequently revised to $159 million.

MPSC Final Rate Order — On April 28, 2005, the MPSC issued an order for final rate relief. The MPSC determined that the base rate increase granted to MichCon should be $61 million annually effective April 29, 2005. This amount is an increase of $26 million over the $35 million in interim rate relief approved in

September 2004. The rate increase was based on a 50% debt and 50% equity capital structure and an 11% rate of return on common equity.

The MPSC order reduces MichCon’s depreciation rates, and the related revenue requirement associated with depreciation expense by $14.5 million and is designed to have no impact on net income.

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

The MPSC order also resulted in the disallowance of computer system and equipment costs and adjustments to environmental regulatory assets and liabilities. The MPSC disallowed recovery of 90% of the costs of a computer billing system that was in place prior to DTE Energy’s acquisition of MCN Energy in 2001. As a result of the order, MichCon recognized an impairment of this asset of approximately $42 million in the first quarter of 2005. This impairment had a minimal impact on DTE Energy since a valuation allowance was established for this asset at the time of the MCN acquisition in 2001. The MPSC disallowed approximately $6 million of certain computer equipment and related depreciation and the recovery of certain internal labor and legal costs related to remediation of manufactured gas plants of approximately $6 million. The MPSC ordered an additional $5 million charge due to a change in the allocation of historical manufactured gas plant insurance proceeds.

Rehearing Request — In May 2005, MichCon filed for rehearing of various aspects of the MPSC final rate order. On July 19, 2005, the MPSC denied MichCon’s petition for rehearing.

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 thousand cubic feet (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 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 was 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. We recorded a $26.5 million reserve in 2003 to reflect the impact of this order.

MichCon’s 2002 GCR reconciliation case was filed with the MPSC in February 2003. The Staff and various intervening parties in this proceeding sought to have the MPSC disallow an additional $26 million, representing unbilled revenues at December 2001. One party also proposed the disallowance of half of an $8 million payment made to settle Enron bankruptcy issues. The other parties to the case recommended that the Enron bankruptcy settlement be addressed in the 2003 GCR reconciliation case. In April 2005, the MPSC issued an order in the 2002 GCR reconciliation case affirming the order in the 2002 GCR plan case disallowing $26.5 million related to the use of storage gas in 2001. The April 2005 order also disallowed the additional $26 million representing unbilled revenues at December 2001. We recorded the impact of the

disallowance in the first quarter of 2005. The MPSC agreed that the $8 million related to the Enron issue be addressed in the 2003 GCR reconciliation case.

2003 Plan Year — MichCon’s 2003 GCR reconciliation case was filed with the MPSC in February 2004. In May 2005, the MPSC issued an order in the 2003 GCR reconciliation case approving recovery of the $8 million related to the Enron bankruptcy settlement.

2005-2006 Plan Year — In December 2004, MichCon filed its 2005-2006 GCR plan case proposing a maximum GCR factor of $7.99 per Mcf. The plan includes quarterly contingent GCR factors. These contingent factors allow MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery. In April 2005, the MPSC issued an order recognizing that Michigan law allows MichCon to self-implement its quarterly contingent factors. Approval of the contingent factors will be determined in the MPSC’s final order in this case. In July 2005, MichCon self-implemented a quarterly contingent GCR factor of $8.54 per Mcf.

Other

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

NOTE 6 — COMMON STOCK AND 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 assume the exercise of stock options, vesting of non-vested stock awards, and the issuance of performance share awards. A reconciliation of both calculations is presented in the following table:


	Three Months Ended				Six Months Ended
	June 30				June 30
(Millions, except per share amounts)	2005		2004		2005		2004
Basic Earnings Per Share
Income from continuing operations	$	30.0	$	34.9	$	151.9	$	231.8
Average number of common shares outstanding		173.6		173.2		173.7		171.6

Income per share of common stock based on weighted average number of shares outstanding	$	.17	$	.20	$	.87	$	1.35


Diluted Earnings Per Share
Income from continuing operations	$	30.0	$	34.9	$	151.9	$	231.8

Average number of common shares outstanding		173.6		173.2		173.7		171.6
Incremental shares from stock based awards		1.2		.6		1.0		.5

Average number of dilutive shares outstanding		174.8		173.8		174.7		172.1


Income per share of common stock
assuming issuance of incremental shares	$	.17	$	.20	$	.87	$	1.35

Options to purchase approximately 90,000 shares of common stock in 2005, and five million shares of common stock in 2004, were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive.

NOTE 7 — LONG -TERM DEBT

In February 2005, Detroit Edison issued $400 million of senior notes in two series, $200 million of 4.8% series due 2015 and $200 million of 5.45% series due 2035. The proceeds were used to redeem the $385 million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

In February 2005, Detroit Edison redeemed $76 million of 7.5% senior notes and $100 million of 7.0% remarketed secured notes, which matured February 2005.

In August 2005, DTE Energy expects to remarket the senior notes comprising part of its Equity Security Units that were issued in June 2002. The senior notes will mature in August 2007. Additionally, in August 2005, DTE Energy expects to settle the stock purchase contract component of its Equity Security Units by issuing common stock to holders of these units. The issue price will be determined by the average closing price per share of our common stock during a 20 trading-day period ending August 11, 2005. Based on this price, the number of shares expected to be issued will be between 3.3 million and 4 million. The total equity to be issued in connection with these security units is $172.5 million.

NOTE 8 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

but primarily are intended to provide liquidity support for MichCon’s commercial paper program. Borrowings under the facilities are available at prevailing short-term interest rates. Among other things, the agreements require MichCon to maintain an “earnings before interest, taxes, depreciation and amortization” (EBITDA) to interest ratio of no less than 2 to 1 for each twelve-month period ending on the last day of March, June, September and December of each year.

NOTE 9 — DERIVATIVE INSTRUMENTS

Commodity Price Risk

Our Energy Services and Biomass businesses generate Section 29 tax credits. Through June 2005, Energy Services has sold interests in eight of its nine synthetic fuel production plants. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 10 for further discussion.

To manage our exposure in 2005 and 2006 to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full years 2005 and 2006 average New York Mercantile Exchange (NYMEX) trading prices for light, sweet crude oil in relation to the strike prices of each option. If the average NYMEX prices of oil in 2005 and 2006 are less than approximately $56 per barrel, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $56 per barrel, the derivatives will yield a payment equal to the excess of the average NYMEX price over $56 per barrel, multiplied by the number of barrels covered, up to a maximum price of approximately $73 per barrel. The agreements do not qualify for hedge accounting and, as a result, changes in the fair value of the options are recorded currently in earnings. We recorded a mark to market loss of $11 million pre-tax during the 2005 second quarter. For the six months ended June 30, 2005, we have recorded mark to market gains of $43 million pre-tax. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and therefore included in the “Asset gains and losses, net” line item in the consolidated statement of operations.

NOTE 10 — COMMITMENTS AND CONTINGENCIES

Synthetic Fuel Operations

We partially or wholly own nine synthetic fuel production facilities. 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 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.

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 tax credit in a given year is reduced if 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. Due to recent increased volatility, the Reference Price per barrel of oil has been $4-$8 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation. For 2005, we estimate that the threshold price at which the tax credit would begin to be reduced is $52 per barrel and would be completely phased out if the Reference Price reached $66. Through June 30, 2005, the NYMEX closing price of a barrel of oil has averaged $52, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to a $44 to $48 Reference Price (assuming that such price were to continue for the entire year and the difference between wellhead and NYMEX ranges from $4 — $8 per barrel). We cannot predict with any accuracy the future price of a barrel of oil.

Numerous recent events have increased domestic crude oil prices, including terrorism, storm-related supply disruptions and worldwide demand. If the credit is reduced or eliminated in future years, our financial statements may be negatively impacted. We continue to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy. To manage our exposure to oil prices in 2005 and 2006, we entered into oil-related derivative contracts. See Note 9 for further discussion.

Environmental

Air — Detroit Edison is subject to United States Environmental Protection Agency (EPA) ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. In March 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze and mercury air pollution. The new rules will lead to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide and mercury emissions. To comply with these requirements, Detroit Edison has spent approximately $580 million through 2004, and estimates that it will spend up to $100 million in 2005 and incur up to $1.8 billion of additional future capital expenditures through 2018 to satisfy both the existing and proposed new control requirements. Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure could be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end on December 31, 2005 upon MPSC authorization. Under PA 141 and the MPSC’s November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

Water — Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the intakes. It is estimated that we will incur up to $50 million over the next five to seven years in additional capital expenditures for Detroit Edison.

Contaminated Sites — Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufactured locally 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. The existence of these sites and the results of the environmental investigations have been reported to the Michigan Department of Environmental Quality (MDEQ).

Enterprises is remediating eight of the former MGP sites and conducting more extensive investigations at five other former MGP sites. Enterprises received MDEQ closure of one site, and a determination that it is not a responsible party for three other sites. Enterprises received closure from the EPA in 2002 for one site.

In 1984, Enterprises established a $12 million reserve for costs associated with environmental investigation and remediation activities. During 1993, MichCon received MPSC approval of a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites in excess of this reserve. 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. As a result of these studies, Enterprises accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. In early December 2004, Enterprises retained multiple environmental consultants to estimate the projected cost to remediate each MGP facility. The results of the evaluation indicated that the MGP reserve should be set at $24 million.

During 2004, Enterprises spent approximately $2 million investigating and remediating these former MGP sites. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and, therefore, have an effect on the Company’s financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Detroit Edison conducted remedial investigations at contaminated sites, including two 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 cost to remediate 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.

Guarantees

In certain circumstances we enter into contractual guarantees. We may guarantee another entity’s obligation in the event it fails to perform. We may provide guarantees in certain indemnification agreements. Finally, we may provide indirect guarantees of the indebtedness of others. Below are the details of specific material guarantees we currently provide. Our other guarantees are not individually material and total approximately $38 million at June 30, 2005.

Sale of Interests in Synfuel Facilities

We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities. The guarantees cover general commercial, environmental and tax-related exposure and will survive until 90 days after expiration of all applicable statute of limitations, or indefinitely, depending on the nature of the guarantee. We estimate that our maximum liability under these guarantees at June 30, 2005 totals $1.4 billion.

Parent Company Guarantee of Subsidiary Obligations

We have issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy’s credit rating is downgraded below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $380 million at June 30, 2005. This estimated amount fluctuates based upon the provisions and maturities of the underlying agreements.

Personal Property Taxes

Prior to 1999, Detroit Edison, MichCon and other Michigan utilities asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000

and are currently used to calculate property tax expense. However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002, issued its decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. Detroit Edison and MichCon have filed motions and the MTT agreed to place their cases in abeyance pending the conclusion of settlement negotiations being conducted by State of Michigan Treasury officials. On February 14, 2005, MTT issued a scheduling order that lifts the prior abeyances in a significant number of Detroit Edison and MichCon appeals. The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison and MichCon continue to record property tax expense based on the new tables. Detroit Edison and MichCon will continue through settlement or litigation to seek to apply the new tables retroactively and to ultimately resolve the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. To the extent that settlements cannot be achieved with the jurisdictions, litigation regarding the valuation of utility property will delay any recoveries by Detroit Edison and MichCon.

Other Commitments

Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. In 1996, a special charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through 2008. During the first six months of 2005, we purchased $18 million of steam and electricity. For the full year 2004, we purchased $42 million of steam and electricity. We estimate steam and electric purchase commitments through 2024 will not exceed $472 million. In January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

In 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. 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 2004 earnings by $48 million, net of taxes.

At December 31, 2004, we have entered into numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments and energy trading contracts. We estimate that these commitments will be approximately $6.5 billion through 2027. We also estimate that 2005 base level capital expenditures will be $1.1 billion. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies

We purchase and sell electricity, gas, coal and coke from and to numerous companies operating in the steel, automotive, energy and retail industries. Several customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of loss. We believe our previously 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.

Other

We are involved in certain legal, regulatory, administrative and environmental 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 operations or financial statements in the period they are resolved.

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

NOTE 11 — SEGMENT INFORMATION

Beginning in the second quarter of 2005, we operate our businesses through five strategic business units (Electric Utility, Gas Utility, Power and Industrial Projects, Unconventional Gas Production and Fuel Transportation and Marketing). The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. Inter-segment revenues primarily consist of power sales, gas sales and coal transportation services between our Electric Utility and other Non-utility Operations segments.


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2005			2004			2005			2004
Operating Revenues
Electric Utility	$	1,035		$	835		$	2,025		$	1,721
Gas Utility		267			276			1,119			1,005
Non-utility Operations:
Power and Industrial Projects		348			269			659			524
Unconventional Gas Production		17			18			33			35
Fuel Transportation and Marketing		431			261			747			566

		796			548			1,439			1,125


Corporate & Other		6			13			16			27
Reconciliation & Eliminations		(159	)		(171	)		(339	)		(284	)

Total	$	1,945		$	1,501		$	4,260		$	3,594


	Three Months Ended						Six Months Ended
	June 30						June 30
(in Millions)	2005			2004			2005			2004
Net Income (Loss)
Electric Utility	$	43		$	8		$	98		$	52
Gas Utility		(51	)		(38	)		(38	)		33
Non-utility Operations:
Power and Industrial Projects		31			54			99			89
Unconventional Gas Production		—			2			1			3
Fuel Transportation and Marketing		—			(1	)		(10	)		60

Corporate & Other		7			10			2			(5	)

Income from Continuing Operations
Utility		(8	)		(30	)		60			85
Non-utility		31			55			90			152
Corporate & Other		7			10			2			(5	)

		30			35			152			232
Discontinued Operations		(1	)		—			(1	)		(7	)

Net Income	$	29		$	35		$	151		$	225

NOTE 12 — SUBSEQUENT EVENTS

DTE Energy is the indirect parent company of DTE Energy Technologies (Dtech), which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations. On July 26, 2005, management approved the restructuring of this business in which certain assets and liabilities are planned to be sold, certain businesses are planned to be terminated and certain businesses are planned to be merged with Detroit Edison or one of its affiliates.

As of June 30, 2005, the restructuring plan had not met the SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” criteria to classify the assets as “held for sale,” and accordingly no impairment loss was recorded in the 2005 second quarter. We expect to recognize a net of tax impairment loss of approximately $25 million to $30 million in the 2005 third and fourth quarters representing the write-down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill. As required under SFAS No. 144, we expect to report Dtech’s operating results as a discontinued operation beginning with the 2005 third quarter.

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, 2005, and the related condensed consolidated statement of operations for the three-month and six-month periods ended June 30, 2005 and 2004, and the condensed consolidated statement of cash flows for the six-month periods ended June 30, 2005 and 2004, and condensed consolidated statements of changes in shareholders’ equity and comprehensive income for the six-month period ended June 30, 2005 and the six-month periods ended June 30, 2005 and 2004, respectively. These interim financial statements are the responsibility of DTE Energy Company’s management.

We conducted our reviews in accordance with the 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 the 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.

We have previously audited, in accordance with the 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, 2004, 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 15, 2005 (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 and goodwill and energy trading contracts in 2002), 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, 2004 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 4, 2005

Other Information

Legal Proceedings

We are involved in certain legal, regulatory, administrative and environmental 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.

See Note 5 for a discussion of contingencies related to Regulatory Matters and Note 10 for a discussion of specific non-regulatory matters.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about Company purchases of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act during the six months ended June 30, 2005:


	Total				Total Number of		Maximum Dollar
	Number				Shares Purchased		Value that May Yet
	of Shares		Average		as Part of Publicly		Be Purchased Under
	Purchased		Price Paid		Announced Plans		the Plans or
Period	(1)		Per Share		or Programs		Programs
01/01/05 — 01/31/05		—		—		—	$	700,000,000
02/01/05 — 02/28/05		205,940	$	43.75		—	$	700,000,000
03/01/05 — 03/31/05		1,000	$	45.26		—	$	700,000,000
04/01/05 — 04/30/05		15,500	$	45.67		—	$	700,000,000
05/01/05 — 05/31/05		16,400	$	46.07		—	$	700,000,000
06/01/05 — 06/30/05		1,320	$	47.55		—	$	700,000,000

Total		240,160	$	44.06		—


(1)		Represents shares of common stock purchased on the open market to provide shares to participants under various employee compensation and incentive programs. These purchases were not made pursuant to a publicly announced plan or program.

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 28, 2005. 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 eight directors listed below continue until the annual meeting dates shown after each name:


Alfred R. Glancy III		April 2006
John E. Lobbia		April 2006
Eugene A. Miller		April 2006
Charles W. Pryor, Jr.		April 2006
Anthony F. Earley, Jr.		April 2007
Allan D. Gilmour		April 2007
Frank M. Hennessey		April 2007
Gail J. McGovern		April 2007

(c)

At the annual meeting of the holders of Common Stock of the Company held on April 28, 2005, three directors were elected to serve until the annual meeting in the Year 2008 with the votes shown:


			Total Vote
	Total Vote		Withheld
	For Each		from Each
	Director		Director
Lillian Bauder		134,511,400		2,562,499
Josue Robles, Jr.		134,890,354		2,183,545
Howard F. Sims		134,681,398		2,392,501

Shareholders ratified the appointment of Deloitte & Touche LLP as the Company’s independent registered accounting firm for the year 2005 with the votes shown:


For	Against		Abstain
134,444,928		1,050,001		1,578,970

		There were no Shareholder proposals.

(d)		Not applicable.

Exhibits


Exhibit
Number		Description
Filed:
	12-35	Computation of Ratio of Earnings to Fixed Charges
	15-17	Awareness Letter of Deloitte & Touche LLP
	31-17	Chief Executive Officer Section 302 Certification
	31-18	Chief Financial Officer Section 302 Certification


Furnished:
	32-17	Chief Executive Officer Section 906 Certification
	32-18	Chief Financial Officer Section 906 Certification


		DTE ENERGY COMPANY

Date: August 4, 2005		/s/ DANIEL G. BRUDZYNSKI

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


	Page
Definitions		1

Forward-Looking Statements		3

Part I – Financial Information

Item 1. Financial Statements

Consolidated Statement of Operations		28

Consolidated Statement of Financial Position		29

Consolidated Statement of Cash Flows		31

Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income		32

Notes to Consolidated Financial Statements		33

Report of Independent Registered Public Accounting Firm		49

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		4

Item 3. Quantitative and Qualitative Disclosures About Market Risk		25

Item 4. Controls and Procedures		27

Part II – Other Information

Item 1. Legal Proceedings		50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50

Item 4. Submission of Matters to a Vote of Security Holders		50

Item 6. Exhibits		51

Signature		53
Computation of Ratio of Earnings to Fixed Charges
Awareness Letter of Deloitte & Touche LLP
Chief Executive Officer Section 302 Certification
Chief Financial Officer Section 302 Certification
Chief Executive Officer Section 906 Certification
Chief Financial Officer Section 906 Certification


Bcf		Billion cubic feet of gas

gWh		Gigawatthour of electricity

kWh		Kilowatthour of electricity

Mcf		Thousand cubic feet of gas

MW		Megawatt of electricity

MWh		Megawatthour of electricity