e10vq

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 September 30, 2005

Commission file number 1-11607

DTE ENERGY COMPANY

(Exact name of registrant as specified in its charter)


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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

At September 30, 2005, 177,825,796 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 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 the chemical modification and binding of 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. Many factors 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 population 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;

•		changes in the 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 borrowing;

•		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 or regulations;

•		contributions to earnings by non-utility subsidiaries;

•		changes in federal, state and local tax laws or 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 damage due to terrorism;

•		changes in accounting standards and financial reporting regulations;

•		changes in federal or state laws or their interpretation with respect to regulation, energy policy and other business issues;

•		uncollectible accounts receivable; 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 throughout southeastern Michigan. Additionally, we have numerous energy-related non-utility subsidiaries located throughout the U.S.

Earnings in the third quarter of 2005 were $4 million, or $.02 per diluted share, compared to earnings in the 2004 third quarter of $93 million, or $.54 per diluted share. For the 2005 nine-month period, our earnings were $155 million, or $.89 per diluted share, compared to earnings of $318 million, or $1.84 per diluted share, for the same 2004 period. Lower earnings were due to the deferral of a substantial portion of the gains from the sale of interests in our synfuel facilities, the impact of mark-to-market losses in our Fuel Transportation and Marketing segment and losses from discontinued operations, 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;

•		Mark to market losses in Fuel Transportation and Marketing business;

•		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. 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 all nine of our facilities, representing 91% of our total production capacity as of September 30, 2005. We intend to sell additional interests in our two remaining majority-owned plants. Upon the completion of the sale of such interests, we will have sold approximately 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. For the first eight months of 2005, the monthly average wellhead prices have been approximately $6 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 through 2007 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
2006 (estimated)	Not Available		$	53	$	67
2007 (estimated)	Not Available		$	54	$	68

Numerous recent events have significantly increased domestic crude oil prices, including terrorism, storm-related supply disruptions and strong worldwide demand. Through September 30, 2005, the NYMEX daily closing price of a barrel of oil for 2005 has averaged approximately $55.61, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to an approximate $49.61 Reference Price (assuming that such price were to continue for the entire year and the difference between the wellhead price and NYMEX price is approximately $6 per barrel). For 2005 and later years, if the Reference Price falls within or exceeds the phase-out range, the availability of synfuel tax credits in that year would be reduced or eliminated, respectively.

The gain from the sale of synfuel facilities is comprised of fixed and variable components. The fixed component represents note payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and 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 all or a portion of 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 $57 million pretax in the third quarter of 2005 and $167 million pretax in the nine months ended September 30, 2005 of the variable component of synfuel-related gains for the potential phase-out of synfuel tax credits. We anticipate that all or a portion of the deferred gains will be recognized in the fourth quarter of 2005 if the gain recognition criteria are met.

As discussed in Note 9, we have entered into derivative and other contracts to economically hedge a portion of our 2005, 2006 and 2007 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 fair value recorded as an adjustment to synfuel gains. We recorded a mark to market gain of $46 million pretax during the 2005 third quarter. For the nine months ended September 30, 2005, we recorded mark to market gains of $89 million pretax. 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 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.

Fuel transportation and marketing operations

Fuel Transportation and Marketing earnings decreased $147 million during the 2005 third quarter and decreased $217 million in the nine-month period. The comparability of results is impacted by a $74 million one-time pretax gain from a contract modification/termination recorded in the first quarter of 2004 and significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts.

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. Most 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 experiences earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. This results in gains and losses that are recognized in different interim and annual accounting periods.

During 2005, our earnings have been negatively impacted by the economically favorable decision in early 2005 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 current storage cycle and is sold at prices significantly in excess of the cost of gas in storage. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. Some of these underlying contracts are not derivatives, while the related economic hedge is, and therefore marked to market. As a result the transaction produces the accounting/economic misalignment as described above. We expect the timing difference on the forward power contracts will not be fully realized until 2007.

Gas operations

Gas Utility’s earnings increased $216 million in the 2005 third quarter and $145 million in the 2005 nine-month period. Income taxes decreased $196 million in the 2005 third quarter and $145 million in the 2005 nine-month period. The decrease in income taxes is due primarily to lower annual forecasted pretax income. The adjustments were required in 2005 to be consistent with the estimated annual effective tax rate. The 2005 effective income tax rate is unusually high due to the relationship of annual tax adjustments to the level of decreased pretax income that 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.

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. 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 because 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 plant sites 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

Electric rate orders — 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 third quarter and the 2005 nine-month period our pretax margins were higher by $27 million and $122 million, respectively, due to increased rates.

Weather — 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 pretax margins of $109 million for the third quarter and $159 million in the nine-month period of 2005.

Electric customer choice — Since 2002, our customers have had the option of participating in the electric Customer Choice program. This program is designed to give all customers the ability to select an alternative electric supplier. 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 third quarter of 2005 were 1,635 gWh as compared to 2,555 gWh in the third quarter of 2004. Year to date electric Customer Choice volumes for 2005 were 5,178 gWH compared to 6,824 gWh for the comparable period in 2004. The return of electric Choice Customers resulted in higher gross

margins for both the 2005 third quarter and year to date periods. 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 proposed rate restructuring.

The positive impacts of higher rates, weather and return of electric Customer Choice customers were partially offset by unrecovered power supply costs as a result of residential rate caps (which are due to expire January 1, 2006).

Outlook — We are focusing 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.

Looking forward, we will continue to focus on several points to improve future performance:

	•		enhance our cost structure across all business segments;

	•		improve our regulatory environment; and

	•		invest in businesses that leverage our skills, assets and expertise.

Our financial performance will be dependent on successfully redeploying an expected $1.6 billion of cash flow through 2008, primarily associated with our synfuel business. Our objective for cash redeployment is to strengthen the balance sheet and coverage ratios, and to replace the value of synfuel operations currently inherent in our share price. We expect to use this cash to reduce DTE Energy’s parent company debt, and pursue growth investments that have attractive competitive dynamics and provide meaningful scale and scope while maintaining a manageable risk profile. If adequate investment opportunities are not available, share repurchases may be used to build share value.

RESULTS OF OPERATIONS

Our earnings in the 2005 third quarter were $4 million, or $.02 per diluted share, compared to earnings of $93 million, or $.54 per diluted share, in the 2004 third quarter. For the 2005 nine-month period, our earnings were $155 million, or $.89 per diluted share, compared to earnings of $318 million, or $1.84 per diluted share, for the same 2004 period. The following sections provide a detailed discussion of our business segments’ operating performance and future outlook.

Segment performance— 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. 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						Nine Months Ended
	September 30						September 30
(in Millions, except per share data)	2005			2004			2005			2004
Net Income (Loss)
Electric Utility	$	114		$	62		$	212		$	114
Gas Utility		161			(55	)		123			(22	)
Non-utility Operations:
Power and Industrial Projects		68			49			167			138
Unconventional Gas Production		2			1			3			4
Fuel Transportation and Marketing		(129	)		18			(139	)		78
Corporate & Other		(187	)		22			(178	)		28

Income from Continuing Operations
Utility		275			7			335			92
Non-utility		(59	)		68			31			220
Corporate & Other		(187	)		22			(178	)		28

		29			97			188			340
Discontinued Operations		(25	)		(4	)		(33	)		(22	)

Net Income	$	4		$	93		$	155		$	318


Diluted Earnings (Loss) Per Share
Total Utility	$	1.57		$	.04		$	1.91		$	.53
Non-utility Operations		(.33	)		.40			.18			1.27
Corporate & Other		(1.07	)		.12			(1.02	)		.16

Income from Continuing Operations		.17			.56			1.07			1.96
Discontinued Operations		(.15	)		(.02	)		(.18	)		(.12	)

Net Income	$	.02		$	.54		$	.89		$	1.84

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 or indirect 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 electricity to 2.1 million customers in southeastern Michigan.

Factors impacting income: Electric Utility earnings increased $52 million during the 2005 third quarter and $98 million in the 2005 nine-month period. As discussed, these results primarily reflect higher rates due to the November 2004 MPSC final rate order, return of customers from the electric Customer Choice program, warmer weather and lower operations and maintenance expenses, partially offset by a portion of higher fuel and purchased power costs, which are unrecoverable as a result of residential rate caps (which are due to expire January 1, 2006) and increased depreciation and amortization expenses.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2005			2004			2005			2004
(in Millions)
Operating Revenues	$	1,409		$	958		$	3,434		$	2,679
Fuel and Purchased Power		604			238			1,248			654

Gross Margin		805			720			2,186			2,025
Operation and Maintenance		325			361			976			1,064
Depreciation and Amortization		174			128			484			364
Taxes Other Than Income		68			62			200			192
Asset (Gains) and Losses, Net		(26	)		—			(26	)		(1	)

Operating Income		264			169			552			406
Other (Income) and Deductions		70			75			214			233
Income Tax Provision		80			32			126			59

Net Income	$	114		$	62		$	212		$	114


Operating Income as a Percent of Operating Revenues		19	%		18	%		16	%		15	%

Gross margins increased $85 million during the 2005 third quarter and $161 million in the 2005 nine-month period. The quarterly and year to date improvements were primarily a result of higher demand due to warmer weather in 2005 and the increased rates due to the November 2004 MPSC final rate order, partially offset by unrecovered power supply costs as a result of residential rate caps (which are due to expire January 1, 2006) and a stagnant Michigan economy. The following table displays changes in various gross margin components relative to the comparable 2004 periods:


Increase (Decrease) in Gross Margin Components Compared to Prior Year	Three			Nine
(in Millions)	Months			Months
Weather related margin improvements	$	109		$	159
MPSC 2004 rate orders		27			122
Unrecovered power supply costs — residential customers		(63	)		(75	)
Transmission charges (1)		(36	)		(81	)
Return of customers from electric Customer Choice		25			45
Service territory economic performance		24			(9	)
Other, net		(1	)		—

Increase in gross margin performance	$	85		$	161


(1)		Transmission expenses were recorded in operation and maintenance expense in 2004.

As a result of Customer Choice penetration, Detroit Edison lost 12% of retail sales in the nine months of 2005, compared to 17% of such sales during the same 2004 period. In 2004, the MPSC eliminated transition credits and implemented transition charges for electric Customer Choice customers.

Operating revenues and fuel and purchased power costs increased in the 2005 periods reflecting a $17.35 per megawatt hour (MWh) (109%) increase in fuel and purchased power costs during the current quarter and a $9.81 per MWh (64%) increase during the nine-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 weather and outages at our Fermi 2 nuclear facility, which was offline

for 14 days in the first quarter of 2005 and for 20 days in the second and third quarters of 2005. Increased fossil plant generation offset the decline in nuclear generation. Pursuant to the MPSC final rate order, transmission expense previously recorded in operation and maintenance expenses in 2004 is now reflected in purchased power expenses. The PSCR mechanism provides related revenues for the transmission expense.


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2005			2004			2005			2004
Power Generated and Purchased (in Thousands of MWh)
Power Plant Generation
Fossil		11,578			10,407			30,887			28,698
Nuclear		1,979			2,043			6,304			6,860

		13,557			12,450			37,191			35,558
Purchased Power		2,347			1,209			5,156			3,633

System Output		15,904			13,659			42,347			39,191
Less Line Loss and Internal Use		(888	)		(1,062	)		(2,237	)		(2,973	)

Net System Output		15,016			12,597			40,110			36,218


Average Unit Cost ($/MWh)
Generation (1)	$	17.69		$	13.33		$	15.68		$	12.98

Purchased Power (2)	$	123.36		$	42.77		$	92.39		$	37.12

Overall Average Unit Cost	$	33.29		$	15.94		$	25.02		$	15.21


(1)		Represents fuel costs associated with power plants.

(2)		The average purchased power amounts do not include hedging activities.


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2005		2004		2005		2004
Electric Sales (in Thousands of MWh)
Residential		5,554		4,114		13,371		11,655
Commercial		4,462		3,557		11,646		10,097
Industrial		3,197		2,854		9,118		8,418
Wholesale		599		531		1,719		1,640
Other		93		98		285		310

		13,905		11,154		36,139		32,120
Interconnection sales (1)		1,111		1,443		3,971		4,098

Total Electric Sales		15,016		12,597		40,110		36,218


Electric Deliveries (in Thousands of MWh)
Retail and Wholesale		13,905		11,154		36,139		32,120
Electric Choice		1,635		2,555		5,178		6,824
Electric Choice — Self Generators (2)		62		100		429		453

Total Electric Sales and Deliveries		15,602		13,809		41,746		39,397


(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 $36 million in the third quarter of 2005 and $88 million in the 2005 nine-month period and included transmission expenses of $36 million in the 2004 third quarter and $81 million in the 2004 nine-month period. Pursuant to the MPSC final rate order, transmission expenses in 2005 are included in purchased power expense with related revenues recorded through the PSCR mechanism. In addition, pursuant to the MPSC final rate order, merger interest is no longer allocated from the DTE Energy parent company to Detroit Edison. Partially offsetting the lack of merger

interest expense and the transmission expense accounting reclassification were higher 2005 storm expenses of $24 million for the nine months ended 2005.

Depreciation and amortization expense increased $46 million in the third quarter of 2005 and $120 million in the 2005 nine-month period. Depreciation expense reflects the income effects of recording regulatory assets. PA 141 costs previously deferred as regulatory assets were recovered via the interim and final electric rate orders in 2004. Consequently, regulatory asset deferrals totaled $5 million in the third quarter of 2005 and $34 million in the 2005 nine-month period compared to $32 million in the third quarter of 2004 and $93 million in the nine-month period ending September 30, 2004. Additionally, higher sales volumes relative to the prior year have resulted in greater amortization of securitization assets.

Asset gains and losses, net increased $26 million in the third quarter of 2005 and $25 million in the 2005 nine-month period as a result of our sale of land near our headquarters in Detroit, Michigan.

Other income and deductions expense decreased $5 million in the 2005 third quarter and $19 million in the 2005 nine-month period, primarily due to lower interest expense as a result of adjustments due to tax audit settlements.

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 level 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 nine months of 2005, Detroit Edison recorded an estimated $8 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 transmission expenses through the PSCR mechanism.

See Note 5 — Regulatory Matters.

GAS UTILITY

Gas Utility operations include gas distribution services primarily provided by MichCon which 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 increased $216 million in the 2005 third quarter and $145 million in the 2005 nine-month period. As subsequently discussed, results primarily reflect income tax effective 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						Nine Months Ended
	September 30						September 30
(in Millions)	2005			2004			2005			2004
Operating Revenues	$	210		$	160		$	1,329		$	1,165
Cost of Gas		102			68			883			730

Gross Margin		108			92			446			435
Operation and Maintenance		97			94			318			306
Depreciation and Amortization		22			26			72			77
Taxes other than Income		11			13			38			38
Asset (Gains) and Losses, Net		—			—			4			(2	)

Operating Income (Loss)		(22	)		(41	)		14			16
Other (Income) and Deductions		12			13			35			37
Income Tax Provision (Benefit)		(195	)		1			(144	)		1

Net Income (Loss)	$	161		$	(55	)	$	123		$	(22	)


Operating Income (Loss) as a Percent of Operating Revenues		(10	)%		(26	)%		1	%		1	%

Gross margins increased $16 million in the 2005 third quarter and $11 million in the 2005 nine-month period. Gross margins in the 2005 third 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 2005 reflecting higher gas prices which are recoverable from customers through the gas cost recovery (GCR) mechanism.


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2005		2004		2005		2004
Gas Markets (in Millions)
Gas sales	$	151	$	110	$	1,130	$	985
End user transportation		24		22		97		89

		175		132		1,227		1,074
Intermediate transportation		14		11		42		38
Other		21		17		60		53

	$	210	$	160	$	1,329	$	1,165


Gas Markets (in Bcf)
Gas sales		10		13		116		120
End user transportation		34		28		117		107

		44		41		233		227
Intermediate transportation		95		128		313		431

		139		169		546		658

Operation and maintenance expense increased $3 million in the 2005 third quarter and $12 million in the 2005 nine-month period. The increase is primarily due to the impact of the MPSC final rate order that 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 third quarter and nine-month period of 2005 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. The increase in operation and maintenance expense was partially offset by the DTE Energy parent company 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 increase was also partially offset by a decline in accruals for injuries and damages for the third quarter and nine-month period of 2005.

Asset gains and losses, net increased $6 million in the 2005 nine-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 decreased $196 million in the 2005 third quarter and $145 million in the 2005 nine-month period. Results reflect adjustments in both years to reflect the projected annual effective income tax rate. There were favorable adjustments of $181 million and $130 million in the 2005 third quarter and nine-month periods, respectively, compared to unfavorable adjustments of $23 million and $15 million in the corresponding 2004 periods. The adjustments were required to be consistent with the estimated annual effective tax rate. The 2005 effective income tax rate is unusually high due to the relationship of annual tax adjustments to the expected low level of annual pretax income that has been impacted by rate order considerations. The effective rate adjustments are expected to reverse in the fourth quarter and 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. We expect a loss in the 2005 fourth quarter due to the reversal of the favorable income tax effective rate adjustments recorded through the current nine-month period. 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 to customers 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 an additional gas-fired power plant 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 increased $19 million during the 2005 third quarter and increased $29 million in the 2005 nine-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 marked to market gains and/or losses on oil hedges.


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2005			2004			2005			2004
Operating Revenues	$	349		$	285		$	1,008		$	809
Operation and Maintenance		402			308			1,100			869
Depreciation and Amortization		33			28			85			73
Taxes other than Income		10			6			25			13
Asset (Gains) and Losses, Net		(79	)		(55	)		(180	)		(161	)

Operating Income (Loss)		(17	)		(2	)		(22	)		15
Other (Income) and Deductions		(12	)		(4	)		(22	)		(10	)
Minority Interest		(87	)		(66	)		(208	)		(147	)
Income Taxes
Provision		31			27			78			62
Section 29 Tax Credits		(17	)		(8	)		(37	)		(28	)

		14			19			41			34

Net Income	$	68		$	49		$	167		$	138

Operating revenues increased $64 million in the 2005 third quarter and $199 million in the 2005 nine-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 $94 million in the 2005 third quarter and $231 million in the 2005 nine-month period reflecting costs associated with the increased levels of synfuel production.

Asset (gains) and losses, net increased $24 million in the 2005 third quarter and $19 million in the 2005 nine-month period. The increases are due to additional sales of interests in our synfuel projects resulting in fixed payment-related gains, partially offset by the deferral of the variable component of gains resulting from the increase in crude oil prices. We also recorded mark to market gains on derivatives used to economically hedge our cash flow exposure related to the risk of an increase in oil prices. During the first nine months of 2005, we recorded a $180 million pretax gain on synfuel sales, as compared to $164 million pretax 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					Nine Months Ended
	September 30					September 30
Components of Synfuel Gains	2005			2004		2005			2004
Gains associated with fixed payments	$	34		$	24	$	91		$	63
Gains associated with variable payments		57			34		167			101
Deferred gains reserved on variable payments		(57	)		—		(167	)		—
Unrealized hedge gains (losses) (mark-to-market)
Hedges for 2005 exposure		14			—		37			—
Hedges for 2006 exposure		32			—		52			—

Net synfuel gains	$	80		$	58	$	180		$	164

After tax synfuel gains	$	52		$	38	$	117		$	107

Minority interest increased $21 million in the third quarter of 2005 and $61 million in the nine-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 $5 million in the 2005 third quarter and increased $7 million in the 2005 nine-month period reflecting changes in pretax income and Section 29 tax credits.

Outlook — We plan to complete the sale of additional interests in our two majority-owned synfuel plants 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. In the third quarter of 2005, we executed an agreement to purchase six on-site energy projects. The purchase of three of the projects closed, with the purchases of two of the remaining projects scheduled to close over the next few months. The agreement to purchase the sixth project has been terminated by mutual agreement.

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 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 increased $1 million in the third quarter of 2005 and declined $1 million in the nine-months ended September 30, 2005.


	Three Months Ended				Nine Months Ended
	September 30				September 30
(in Millions)	2005		2004		2005		2004
Operating Revenues	$	20	$	18	$	53	$	53
Operation and Maintenance		7		7		21		20
Depreciation and Amortization		5		5		14		14
Taxes Other Than Income		3		1		7		5

Operating Income		5		5		11		14
Other (Income) and Deductions		2		2		6		7
Income Tax Provision		1		2		2		3

Net Income	$	2	$	1	$	3	$	4

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 and early 2005, we acquired approximately 58,000 leasehold acres in the Barnett shale in Texas, an area of increasing production. We began drilling wells in proven areas in December 2004 and continue to drill a number of test wells in 2005. Initial results from the test wells are expected in the first half of 2006. In August 2005, we acquired additional leasehold mineral rights and 44 producing natural gas wells on approximately 18,000 acres in the Barnett shale formation. We expect to 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, Coal Services and the Pipelines, Processing & Gas Storage businesses. Effective August 1, 2005, DTE Energy Trading and CoEnergy merged under the DTE Energy Trading name. DTE Energy Trading focuses on physical power and gas marketing and structured transactions, as well as the enhancement of returns from DTE Energy’s power plants and the optimization of contracted natural gas pipelines and gas storage capacity positions. DTE Energy Trading enters into derivative financial instruments as part of its 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 synergistic with other DTE Energy entities.

Factors impacting income: Fuel Transportation and Marketing earnings decreased $147 million during the 2005 third quarter and decreased $217 million in the nine-month period. The comparability of results is impacted by a $74 million one-time pretax gain from a contract modification/termination recorded in the first quarter of 2004 and significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts.


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2005			2004			2005			2004
Operating Revenues	$	277		$	309		$	1,024		$	875
Fuel, Purchased Power and Gas		279			115			727			345
Operation and Maintenance		201			163			511			403
Depreciation and Amortization		2			2			5			5
Taxes Other Than Income		—			1			3			3

Operating Income (Loss)		(205	)		28			(222	)		119
Other (Income) and Deductions		(5	)		(1	)		(6	)		(5	)
Income Tax Provision (Benefit)		(71	)		11			(77	)		46

Net Income (Loss)	$	(129	)	$	18		$	(139	)	$	78

Operating revenues decreased $32 million in third quarter of 2005 and increased $149 million in the nine months ended September 2005. The third quarter decline in revenue is a result of mark-to-market adjustments recorded at DTE Energy Trading, partially offset by increased volumes and prices at Coal Services. During the first nine-months of 2005, our trading operations and Coal Services experienced increased revenues due to increased sales volumes and higher prices. In the first quarter of 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 $164 million in the third quarter of 2005 and $382 million in the nine month period of 2005 reflecting increased trading activity and increased commodity prices at DTE Energy Trading. During 2005, our earnings have been negatively impacted by the economically favorable decision in early 2005 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 current storage cycle and is sold at prices significantly in excess of the cost of gas in storage. In addition, we entered into forward power contracts to economically hedge certain physical and capacity power contracts. We expect the timing difference on the forward power contracts will not be fully realized until 2007. In the first quarter of 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 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.

Operation and maintenance expenses increased $38 million in the 2005 third quarter and increased $108 million in the 2005 nine-month period. Our Coal Services business has experienced higher throughput volumes and increased prices for coal.

Income tax provision decreased $82 million in the 2005 third quarter and $123 million in the 2005 nine-month period reflecting decreased pretax income.

Outlook —The electric and gas marketing and trading business has experienced recent changes including expansion of 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. DTE Energy Trading will continue to acquire gas storage and transportation capacity that enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. Significant portions of the electric and gas marketing and trading portfolio are economically hedged. We will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. See “Fair Value of Contracts” section that follows.

We expect to continue to grow our Coal Services business by acquiring strategic physical assets across the coal value chain.

We expect to continue to grow our Pipeline, Processing and Storage business by expanding existing assets and developing new assets. Pipelines, Processing & Gas Storage received MPSC approval in September 2005 and executed long-term contracts for a capacity expansion at one of our Michigan storage fields that will facilitate an additional 14 Bcf of storage service sales starting in April 2006. Vector Pipeline has secured long-term market commitments to support an expansion project, for approximately 200,000 Dth/d, with a projected in-service date of November 2007. Vector Pipeline will file an application with the FERC in the fourth quarter of 2005. The Millennium Pipeline filed an application for FERC approval on August 1, 2005. In addition, Pipeline, Processing and Gas Storage owns a 10.5% interest in the Millennium Pipeline and is currently negotiating to increase its equity interest.

CORPORATE & OTHER

Corporate & Other includes various corporate support functions such as accounting, legal and information technology. Because these functions essentially support the entire Company, their costs are fully allocated to the various segments based on services utilized. 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.

Factors impacting income: Corporate & Other’s results declined $209 million in the 2005 third quarter and $206 million in the 2005 nine-month period. Corporate & Other records necessary adjustments in order that the consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. Results reflect adjustments in both years to normalize the effective income tax rate. There were unfavorable adjustments of $194 million and $154 million in the 2005 third quarter and nine-month period, respectively, compared to favorable adjustments of $24 million and $14 million in the corresponding 2004 periods. The income tax provisions of the segments are determined on a stand-alone basis. Pursuant to the final MPSC electric and gas rate orders, beginning in 2005, merger interest is retained at the DTE Energy parent company and is no longer allocated to the electric and gas utilities. Results were favorably impacted in both years by Michigan Single Business Tax adjustments. The 2004 nine-month period was also affected by a $14 million net of tax gain from the sale of 3.5 million shares of Plug Power stock.

DISCONTINUED OPERATIONS

DTE Energy Technologies (Dtech) - We own 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. In July 2005, management approved the restructuring of this business resulting in the identification of certain assets and liabilities to be sold or abandoned, primarily associated with standby and continuous duty operations. The systems monitoring business and certain other operations are planned to be retained. We recognized a net of tax restructuring loss of $23 million during the third quarter representing the write down to fair value of the assets of Dtech, less costs to sell, and the write-off of goodwill. As we execute the restructuring plan, there may be adjustments to amounts recorded related to the impairment and exit costs. We anticipate completing the restructuring plan by mid-2006. See Note 3.

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


	Nine Months Ended
	September 30
(in Millions)	2005			2004
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	155		$	318
Depreciation, depletion and amortization		663			536
Deferred income taxes		121			104
Gain on sale of synfuel and other assets, net		(211	)		(193	)
Working capital and other		(135	)		(175	)

		593			590


Investing activities:
Plant and equipment expenditures — utility		(564	)		(555	)
Plant and equipment expenditures — non-utility		(145	)		(52	)
Proceeds from sale of synfuel and other assets, net of cash divested		307			213
Restricted cash and other investments		(79	)		(40	)

		(481	)		(434	)


Financing activities:
Issuance of long-term debt and common stock		795			648
Redemption of long-term debt		(1,059	)		(620	)
Short-term borrowings, net		472			106
Repurchase of common stock		(12	)		—
Dividends on common stock and other		(273	)		(270	)

		(77	)		(136	)

Net Increase in Cash and Cash Equivalents	$	35		$	20

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 participation, 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.

Cash from operations, totaling $593 million, was up $3 million from the comparable 2004 period. The operating cash flow comparison reflects a decrease of $40 million in working capital and other

requirements, mostly offset by a decrease of $37 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, partially offset by cash collateral deposit requirements in 2005 within the Fuel Transportation and Marketing group.

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 also may be impacted by the delayed collection of underrecoveries of our gas supply costs and electric and gas accounts receivable as a result of recent MPSC orders. 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. Lower 2005 taxable income would shift some of the tax credit utilization into future years. 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. As a result of hedge transactions, we believe our expected 2005 synfuel cash flow is 100% protected from risk of loss from a tax credit phase-out, our estimated 2006 cash flow of $500 million is approximately 70% protected and our estimated 2007 cash flow of $500 million is approximately 25% protected. These amounts are based on current forecasts of tax credit utilization, taxable income and assume that production would be significantly curtailed in a year in which there was a tax credit phase-out. 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 DTE Energy 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 to 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 increased $47 million in the 2005 nine-month period compared to the same 2004 period primarily due to increased capital expenditures, partially offset by higher synfuel proceeds.

Capital expenditures during the 2005 nine-month period were $709 million. This represents a $102 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, and non-utility growth projects.

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, our DTE2 investment and growth expenditures for non-utility businesses, 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 of fixed and variable interest rates and maturities. We continually evaluate our leverage target, which is currently 50% or lower, to assure it is consistent with our objective to have a strong investment grade debt rating.

Net cash used for financing activities decreased $59 million during the 2005 nine-month period, compared to the same 2004 period as the issuances of long-term debt and the levels of short-term borrowings exceeded the requirements for long-term redemptions.

See Note 7 — Long Term Debt and Note 8 — Short-Term Credit Arrangements and Borrowings for more information regarding financing activities.

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

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 September 30, 2005, our goodwill totaled $2.0 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. During the second quarter, 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.

DTE 2

In 2003, we began the development of DTE2, an enterprise resource planning system (ERP) initiative to improve existing processes and to implement new core information systems related to finance, human resources, supply chain and work management. As part of this initiative, we are implementing software including, among others, products developed by SAP AG and MRO Software, Inc. The first phase of implementation commenced in July 2005 in the regulated electric fossil generation unit and will continue at minimum through 2007. The conversion of data and the implementation and operation of the ERP will be continuously monitored and reviewed and should ultimately strengthen our internal control structure.

MIDWEST INDEPENDENT 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 LMP is the market clearing price at a specific pricing location in the Midwest Energy Market that is equal to the cost of supplying the next increment of load at that location. The value of an LMP is the same whether a purchase or sale is made at that location. Detroit Edison participates in the Midwest 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. 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 PA 141. The MPSC has ordered that MISO costs charged to Detroit Edison should be recovered through the PSCR mechanism.

FEDERAL ENERGY POLICY ACT OF 2005

In August 2005, the Energy Policy Act of 2005 (Energy Act) was signed into law. Among other provisions, the Energy Act:

•

establishes mandatory electric reliability standards;

•

repeals the Public Utility Holding Company Act of 1935;

•

renews the Price Anderson Act for twenty years which provides liability protection for nuclear power plants;

•

increases funding levels for the Low-Income Home Energy Assistance Program; and

•

increases FERC oversight responsibilities for the electric utility industry.

The implementation of the Energy Act requires proceedings at the state level and development of regulations by the FERC, as well as other federal agencies. We continue to review the legislation; however, the impact will depend on the implementation of final rules and cannot be fully determined at this time.

NEW ACCOUNTING PRONOUNCEMENTS

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

FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and provide enhanced transparency of the derivative activities and position of our trading 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 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 and synfuel operations. 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. Oil-related derivative contracts have been executed to economically hedge cash flow risks related to underlying, non-derivative synfuel related positions through 2007. 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
	Trading Activities												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		(2	)		(10	)		19			7			39			46
Liquidation of in-the-money positions		—			—			(8	)		(8	)		—			(8	)
Changes in fair value recorded to income		75			(88	)		(298	)		(311	)		87			(224	)
Amortization of option premiums		—			—			(4	)		(4	)		—			(4	)

Amounts recorded to unrealized income		73			(98	)		(291	)		(316	)		126			(190	)
Amounts recorded in OCI		—			(65	)		—			(65	)		(231	)		(296	)
Option premiums paid and other		(77	)		—			—			(77	)		40			(37	)

MTM at September 30, 2005	$	(1	)	$	(140	)	$	(389	)	$	(530	)	$	(165	)	$	(695	)

The following table provides a current and noncurrent analysis of Assets and Liabilities from Risk Management and Trading Activities as reflected in the Consolidated Statement of Financial Position as of September 30, 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
	Trading Activities															Non-			Total
	Proprietary			Structured			Economic									Trading			Assets
(in Millions)	Trading			Contracts			Hedges			Eliminations			Totals			Activities			(Liabilities)
Current assets	$	642		$	460		$	290		$	(366	)	$	1,026		$	64		$	1,090
Noncurrent assets		74			113			205			(99	)		293			231			524

Total MTM assets		716			573			495			(465	)		1,319			295			1,614


Current liabilities		(636	)		(553	)		(564	)		366			(1,387	)		(179	)		(1,566	)
Noncurrent liabilities		(81	)		(160	)		(320	)		99			(462	)		(281	)		(743	)

Total MTM liabilities		(717	)		(713	)		(884	)		465			(1,849	)		(460	)		(2,309	)


Total MTM net assets (liabilities)	$	(1	)	$	(140	)	$	(389	)	$	—		$	(530	)	$	(165	)	$	(695	)

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	$	5		$	(15	)	$	7		$	2		$	(1	)
Structured Contracts		(44	)		(61	)		(36	)		1			(140	)
Economic Hedges		(151	)		(148	)		(77	)		(13	)		(389	)

Total Trading Activities		(190	)		(224	)		(106	)		(10	)		(530	)
Other Non-Trading Activities		1			(59	)		(85	)		(22	)		(165	)

Total	$	(189	)	$	(283	)	$	(191	)	$	(32	)	$	(695	)

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 Coal-Based Fuels 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 through 2007 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. Certain of our customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We regularly review contingent matters relating to these customers and our purchase and sale contracts and we record provisions for amounts considered at risk of probable 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.

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 September 30, 2005, the Company had a floating rate debt to total debt ratio of approximately 15% (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 respective 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 September 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	$	(33	)	$	31		Commodity contracts and options
Power Contracts	$	(20	)	$	20		Commodity contracts
Oil Contracts	$	66		$	(58	)	Commodity options
Interest Rate Risk	$	(453	)	$	119		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 September 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 July 5, 2005, DTE Energy’s regulated electric fossil generation unit completed its implementation of DTE2, an enterprise resource planning system (ERP) which impacted various processes and controls related to finance, human resources, supply chain and work management. The implementation was the first phase of a Company-wide initiative to replace many of its stand-alone legacy computer systems with an integrated solution. In connection with the implementation of the ERP, DTE Energy has implemented new processes and modified existing processes to facilitate added efficiencies and system-based controls. The impact of the ERP, including the initial difficulties in implementing such a comprehensive system, 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 September 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						Nine Months Ended
	September 30						September 30
(in Millions, Except per Share Amounts)	2005			2004			2005			2004
Operating Revenues	$	2,060		$	1,586		$	6,310		$	5,158


Operating Expenses
Fuel, purchased power and gas		839			316			2,446			1,434
Operation and maintenance		973			872			2,794			2,469
Depreciation, depletion and amortization		239			190			662			535
Taxes other than income		66			86			246			231
Asset (gains) and losses, net		(108	)		(55	)		(203	)		(166	)

		2,009			1,409			5,945			4,503


Operating Income		51			177			365			655


Other (Income) and Deductions
Interest expense		129			131			385			390
Interest income		(15	)		(14	)		(42	)		(41	)
Other income		(22	)		(18	)		(45	)		(62	)
Other expenses		8			10			34			39

		100			109			332			326

Income (Loss) Before Income Taxes and Minority Interest		(49	)		68			33			329

Income Tax Provision		10			37			54			136

Minority Interest		(88	)		(66	)		(209	)		(147	)


Income from Continuing Operations		29			97			188			340

Loss from Discontinued Operations, net of tax (Note 3)		(25	)		(4	)		(33	)		(22	)


Net Income	$	4		$	93		$	155		$	318


Basic Earnings per Common Share (Note 6)
Income from continuing operations	$	.17		$	.56		$	1.08		$	1.97
Loss from Discontinued operations		(.15	)		(.02	)		(.19	)		(.12	)

Total	$	.02		$	.54		$	.89		$	1.85


Diluted Earnings per Common Share (Note 6)
Income from continuing operations	$	.17		$	.56		$	1.07		$	1.96
Loss from Discontinued operations		(.15	)		(.02	)		(.18	)		(.12	)

Total	$	.02		$	.54		$	.89		$	1.84


Average Common Shares
Basic		176			173			174			172
Diluted		177			174			175			173

Dividends Declared per Common Share	$	.515		$	.515		$	1.545		$	1.545

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Financial Position


	(Unaudited)
	September 30			December 31
	2005			2004
(in Millions)
ASSETS
Current Assets
Cash and cash equivalents	$	91		$	56
Restricted cash		96			126
Accounts receivable
Customer (less allowance for doubtful accounts of $140 and $129, respectively)		1,372			880
Accrued unbilled revenues		225			378
Other		851			383
Inventories
Fuel and gas		700			509
Materials and supplies		150			159
Assets from risk management and trading activities		1,090			296
Other		411			209

		4,986			2,996


Investments
Nuclear decommissioning trust funds		634			590
Other		565			558

		1,199			1,148


Property
Property, plant and equipment		18,298			18,011
Less accumulated depreciation and depletion		(7,705	)		(7,520	)

		10,593			10,491


Other Assets
Goodwill		2,049			2,067
Regulatory assets		2,127			2,119
Securitized regulatory assets		1,367			1,438
Notes receivable		454			529
Assets from risk management and trading activities		524			125
Prepaid pension assets		185			184
Other		230			200

		6,936			6,662


Total Assets	$	23,714		$	21,297

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Financial Position


	(Unaudited)
	September 30			December 31
	2005			2004
(in Millions, Except Shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,280		$	892
Accrued interest		114			111
Dividends payable		92			90
Accrued payroll		46			33
Income taxes		—			16
Short-term borrowings		875			403
Current portion of long-term debt, including capital leases		888			514
Liabilities from risk management and trading activities		1,566			369
Other		915			581

		5,776			3,009



Other Liabilities
Deferred income taxes		1,282			1,124
Regulatory liabilities		825			817
Asset retirement obligations (Note 1)		952			916
Unamortized investment tax credit		134			143
Liabilities from risk management and trading activities		743			224
Liabilities from transportation and storage contracts		359			387
Accrued pension liability		336			265
Deferred gains from asset sales		227			414
Minority interest		94			132
Nuclear decommissioning		83			77
Other		675			635

		5,710			5,134


Long-Term Debt (net of current portion) (Note 7)
Mortgage bonds, notes and other		4,979			5,673
Securitization bonds		1,295			1,400
Equity-linked securities		175			178
Trust preferred-linked securities		289			289
Capital lease obligations		59			66

		6,797			7,606


Commitments and Contingencies (Notes 5, 9 and 10)

Shareholders’ Equity
Common stock, without par value, 400,000,000 shares authorized, 177,825,796 and 174,209,034 shares issued and outstanding, respectively		3,481			3,323
Retained earnings		2,267			2,383
Accumulated other comprehensive loss		(317	)		(158	)

		5,431			5,548


Total Liabilities and Shareholders’ Equity	$	23,714		$	21,297

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Cash Flows (Unaudited)


	Nine Months Ended
	September 30
	2005			2004
(in Millions)
Operating Activities
Net Income	$	155		$	318
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization		663			536
Deferred income taxes		121			104
Gain on sale of interests in synfuel projects		(180	)		(166	)
Gain on sale of assets, net		(31	)		(27	)
Partners’ share of synfuel project losses		(241	)		(158	)
Restructuring charges		31			—
Contributions from synfuel partners		177			71
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)		(102	)		(88	)

Net cash from operating activities		593			590


Investing Activities
Plant and equipment expenditures — utility		(564	)		(555	)
Plant and equipment expenditures — non-utility		(145	)		(52	)
Proceeds from sale of interests in synfuel projects		251			151
Proceeds from sale of other assets, net of cash divested		56			62
Restricted cash for debt redemptions		30			55
Other investments		(109	)		(95	)

Net cash used for investing activities		(481	)		(434	)


Financing Activities
Issuance of long-term debt		623			617
Redemption of long-term debt		(1,059	)		(620	)
Short-term borrowings, net		472			106
Issuance of common stock		172			31
Repurchase of common stock		(12	)		—
Dividends on common stock		(268	)		(265	)
Other		(5	)		(5	)

Net cash used for financing activities		(77	)		(136	)


Net Increase in Cash and Cash Equivalents		35			20
Cash and Cash Equivalents at Beginning of the Period		56			54

Cash and Cash Equivalents at End of the Period	$	91		$	74

See Notes to Consolidated Financial Statements (Unaudited)

DTE Energy Company

Consolidated Statement of Changes in Shareholders’ Equity

and Comprehensive Income (unaudited)


										Accumulated
										Other
	Common Stock						Retained			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		—			—			155			—			155
Dividends declared on common stock		—			—			(271	)		—			(271	)
Issuance of common stock		3,686			172			—			—			172
Repurchase of common stock		(280	)		(12	)		—			—			(12	)
Net change in unrealized losses on derivatives, net of tax		—			—			—			(163	)		(163	)
Net change in unrealized gain on investments, net of tax		—			—			—			4			4
Unearned stock compensation and other		211			(2	)		—			—			(2	)

Balance, September 30, 2005		177,826		$	3,481		$	2,267		$	(317	)	$	5,431

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


(in Millions)	2005			2004
Net income	$	155		$	318

Other comprehensive income (loss), net of tax:
Net unrealized income (losses) on derivatives:
Losses arising during the period, net of taxes of $(103) and $(21), respectively		(191	)		(38	)
Amounts reclassified to earnings, net of taxes of $15 and $(3), respectively		28			(5	)

		(163	)		(43	)
Net change in unrealized gain on investments, net of taxes of $2 and $(10)		4			(19	)

		(159	)		(62	)

Comprehensive income (loss)	$	(4	)	$	256

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 our 2004 Annual Report on Form 10-K and our Current Report on Form 8-K dated August 3, 2005 for the year ended December 31, 2004.

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.

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.

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

Gains from Sale of Interests in Synthetic Fuel Facilities

Through September 30, 2005, we have sold interests in all of our synthetic fuel production plants, representing approximately 91% 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 pretax gains of $80 million in the third quarter of 2005 and $180 million for the nine-months ended September 30, 2005 from the sale of interests in synthetic fuel facilities compared to pretax gains of $58 million and $164 million for the respective 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 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 the 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 all or a portion of 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 $57 million pretax in the third quarter of 2005 and $167 million pretax in the nine-months ended September 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.

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 follow 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						Nine Months Ended
	September 30						September 30
(in Millions, except per share amounts)	2005			2004			2005			2004
Net Income As Reported	$	4		$	93		$	155		$	318
Less: Total stock-based expense (1)		(2	)		(2	)		(5	)		(6	)

Pro Forma Net Income	$	2		$	91		$	150		$	312


Earnings Per Share
Basic — as reported	$	.02		$	.54		$	.89		$	1.85

Basic — pro forma	$	.01		$	.53		$	.86		$	1.81


Diluted — as reported	$	.02		$	.54		$	.89		$	1.84

Diluted — pro forma	$	.01		$	.52		$	.86		$	1.81


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:


	Nine Months Ended
	September 30
	2005			2004
(in Millions)
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
Accounts receivable, net	$	(654	)	$	39
Accrued unbilled receivable		153			142
Accrued GCR revenue		5			(52	)
Inventories		(190	)		(98	)
Accrued/Prepaid pensions		69			60
Accounts payable		387			66
Accrued power supply cost recovery refund		(121	)		62
Exchange gas payable		10			(42	)
Income taxes payable		(165	)		(175	)
General taxes		(5	)		(19	)
Risk management and trading activities		612			75
Other assets		(63	)		28
Other liabilities		(140	)		(174	)

	$	(102	)	$	(88	)

Supplementary cash and non-cash information follows:


	Nine Months Ended
	September 30
	2005		2004
(in Millions)
Cash Paid for
Interest (excluding interest capitalized)	$	383	$	390
Income taxes	$	79	$	202
Noncash Investing and Financing Activities
Notes received from sale of synfuel projects	$	20	$	162
Sale of assets
Note receivable	$	47	$	—
Other assets	$	45	$	—
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. We 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 nine-month period follows:


(in Millions)
Asset retirement obligations at January 1, 2005	$	916
Accretion		45
Liabilities settled		(9	)

Asset retirement obligations at September 30, 2005	$	952

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
Three Months Ended September 30	2005			2004			2005			2004
Service Cost	$	16		$	14		$	13		$	10
Interest Cost		43			43			27			23
Expected Return on Plan Assets		(54	)		(54	)		(17	)		(14	)
Amortization of
Net loss		17			16			15			12
Prior service cost		2			3			(1	)		(1	)
Net transition liability		—			—			1			2

Net Periodic Benefit Cost	$	24		$	22		$	38		$	32


Nine Months Ended September 30

Service Cost	$	49		$	44		$	41		$	31
Interest Cost		129			129			79			69
Expected Return on Plan Assets		(163	)		(162	)		(52	)		(42	)
Amortization of
Net loss		51			47			45			33
Prior service cost		6			7			(2	)		(3	)
Net transition liability		—			—			5			6

Net Periodic Benefit Cost	$	72		$	65		$	116		$	94

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 effect of this interpretation, and has not yet determined the impact on the consolidated financial statements.

NOTE 3 — DISCONTINUED OPERATIONS

DTE Energy Technologies (Dtech)

We own 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. In July 2005, management approved the restructuring of this business resulting in the identification of certain assets and liabilities to be sold or abandoned, primarily associated with standby and continuous duty operations. The systems monitoring business and certain other operations are planned to be retained. We anticipate completing the restructuring plan by mid-2006.

As of September 30, 2005, the restructuring plan met the SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” criteria to classify the assets as “held for sale.” Accordingly we recognized a net of tax restructuring loss of $23 million in the 2005 third quarter. This charge included $22 million for the write-down to fair value of the assets of Dtech, and $1 million for the accrual of employee severance and lease termination costs. Subsequent to the restructuring charge, Dtech assets are $12 million, consisting primarily of receivables and inventory, and liabilities are $3 million at September 30, 2005.

As shown in the following table, we have reported the business activity of Dtech as a discontinued operation. The amounts include the impairment loss recorded in the third quarter of 2005 and exclude general corporate overhead costs and operations that are to be retained:


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2005			2004			2005			2004
Revenues	$	3		$	8		$	13		$	30
Expenses		37			13			58			52

Loss before taxes		(34	)		(5	)		(45	)		(22	)
Income tax benefit		(9	)		(1	)		(13	)		(7	)

(Loss) from Discontinued Operations	$	(25	)	$	(4	)	$	(32	)	$	(15	)

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 the second quarter of 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 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 Restructuring Proposal

In February 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies within the current pricing structure. The proposal would adjust rates to be reflective of the full costs incurred to service the respective customer classes. 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

In February 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, in March 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. The MPSC denied this motion in August 2005. A final 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 September 30, 2005, Detroit Edison has recorded an under-recovery of approximately $135 million related to the 2005 plan year. In September 2005, the MPSC approved Detroit Edison’s 2005 PSCR plan case.

2006 Plan Year — In September 2005, Detroit Edison filed its 2006 PSCR plan case seeking approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included in base rates for residential customers and 8.29 per kWh above the amount included in base rates for commercial and industrial customers. Included in the factor for all customers are power supply costs, transmission expenses, MISO market participation costs, and nitrogen oxide emission allowance costs. Detroit Edison may self-implement the factors beginning January 1, 2006, if the MPSC has not ruled in this matter. The Company’s PSCR Plan includes a matrix which provides for different maximum PSCR factors contingent

on varying Electric Choice sales levels. The plan also includes $97 million for recovery of its projected 2005 PSCR under-collection associated with commercial and industrial customers. Additionally, the PSCR plan requests MPSC approval of expense associated with sulfur dioxide emission allowances, mercury emission allowances, and fuel additives in the PSCR.

Administrative and General Expenses Report to the MPSC

In October 2005, the MPSC ordered Detroit Edison to file a report by December 1, 2005 on why its administrative and general expenses are significantly higher than levels incurred by other large electric utilities.

Emergency Rules for Electric and Gas Bills

In October 2005, the MPSC established emergency billing practices in effect for electric and gas services rendered November 1, 2005 through March 31, 2006. These emergency rules apply to retail electric and gas customers. The rule changes 1) lengthen the period of time before a bill is due once it is transmitted to the customer; 2) prohibit shut off or late payment fees unless an actual meter read is made; 3) limit the required monthly payment on a settlement agreement; 4) increase the income level qualifying for shut-off protection and lowers the payment required to remain on shut-off protection; and 5) lessen or eliminate certain deposit requirements.

Gas Rate Case

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 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 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 reduced 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.

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.

In July 2005, the MPSC denied MichCon’s petition for rehearing of various aspects of the final order.

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. MichCon’s decision during 2001 to utilize storage gas resulted in a gas inventory decrement for the 2001 calendar year. For this reason, the MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor. 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.

2004 Plan Year — In September 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf. MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR plan case. The operational GCR year runs from April to March of the following year. To accomplish the switch, the 2004 GCR plan reflected a 15 month transitional period, January 2004 through March 2005. Under this transition proposal, MichCon filed two reconciliations pertaining to the transition period; one in June 2004 addressing January through March 2004, one filed in June 2005 addressing the remaining April 2004 through March 2005 period and consolidating the two for purposes of the case. The June 2005 filing supported the $46 million underrecovery with interest MichCon had accrued for the period ending March 31, 2005. MichCon does not expect a final order before the third quarter of 2006.

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. MichCon self-implemented quarterly contingent GCR factors of $8.54 per Mcf in July 2005 and $10.09 per Mcf in October 2005.

The market price for natural gas has continued to increase to levels that exceed the maximum $3.00 per Mcf volatility the contingent factor matrix was designed to address. In response to this increase, on September 30, 2005 MichCon filed a petition to reopen the record in the case. MichCon proposed a

revised maximum GCR factor of $13.10 per Mcf and a revised contingent factor matrix. In its order issued October 6, 2005, the MPSC reopened the record in the case. On October 28, 2005, the MPSC approved an increase in the GCR factor to a cap of $11.3851 per Mcf for the period November 2005 through March 2006. This compromise factor and its implementation will allow MichCon to mitigate its projected underrecovery. The MPSC order acknowledged that charging the maximum $11.3851 would not fully recover MichCon’s cost of gas and would result in an underrecovery that will be considered as part of the 2006-2007 GCR costs.

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

In August 2005, we successfully remarketed the senior notes comprising part of our Equity Security Units that were issued in June 2002. Part of the settlement required us to settle the stock purchase contract component of the Equity Security Units by issuing 3.7 million shares of common stock to holders of these units. The issue price was $46.79 and was calculated by using the average closing price per share of our common stock during a 20 trading-day period ending August 11, 2005.

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				Nine Months Ended
	September 30				September 30
	2005		2004		2005		2004
(Millions, except per share amounts)
Basic Earnings Per Share
Income from continuing operations	$	29.4	$	97.1	$	187.9	$	339.8
Average number of common shares outstanding		175.5		173.5		174.3		172.2

Income per share of common stock based on weighted average number of shares outstanding	$	.17	$	0.56	$	1.08	$	1.97


Diluted Earnings Per Share
Income from continuing operations	$	29.4	$	97.1	$	187.9	$	339.8

Average number of common shares outstanding		175.5		173.5		174.3		172.2
Incremental shares from stock based awards		1.1		.7		1.1		.6

Average number of dilutive shares outstanding		176.6		174.2		175.4		172.8


Income per share of common stock assuming issuance of incremental shares	$	.17	$	0.56	$	1.07	$	1.96

Options to purchase approximately 102,000 shares of common stock in 2005, and 4.8 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, in a private placement offering, issued $400 million Senior Notes in two series, $200 million 4.8% 2005 Series A Senior Notes due 2015 and $200 million 5.45% 2005 Series B Senior Notes due 2035. The proceeds were used to redeem three series of $385 million of 7.5% Quarterly Income Debt Securities (QUIDS) due 2026 to 2028. In August 2005, Detroit Edison completed the related exchange offer that allowed holders to redeem their existing notes with SEC registered notes.

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

In August 2005, DTE Energy successfully remarketed $172 million aggregate principal amount of its 5.63% Senior Notes due August 16, 2007 that were originally issued in June 2002 in connection with the sale of its 8.75% Equity Security Units. Additionally, in August 2005, DTE Energy settled the stock purchase contract component of its Equity Security Units by issuing common stock to holders of these units. The issue price determined by the average closing price per share of our common stock during a 20 trading-day period ending August 11, 2005 was $46.79 per share. Settlement of the purchase contracts resulted in DTE Energy issuing approximately 4 million shares of common stock in exchange for approximately $172 million.

In August 2005, Detroit Edison entered into a financing arrangement in which the Michigan Strategic Fund issued $119 million Variable Rate Limited Obligation Refunding Revenue Bonds (The Detroit Edison Company Exempt Facilities Project), Series 2005DT, due 2029 (the “Revenue Bonds”) and loaned the proceeds to Detroit Edison on terms substantially mirroring those of the Revenue Bonds. Interest on the obligation accrues at a variable rate. The proceeds were used to refund Detroit Edison’s 6.4% $97 million Limited Obligation Refunding Revenue Bonds, Collateralized Series 1995AA and its 6.2% $22 million Limited Obligation Refunding Revenue Bonds, Collateralized Series 1995BB.

In September 2005, DTE Energy redeemed all $250 million of its outstanding 2004 Series C Floating Rate Notes due 2007.

In September 2005, Detroit Edison closed on the issuance and sale to a group of institutional investors in a private placement transaction of $100 million aggregate principal amount of its 2005 Series C 5.19% Senior Notes due October 1, 2023 pursuant to a Note Purchase Agreement dated as of July 22, 2005, as amended by the First Amendment to Note Purchase Agreement dated as of September 29, 2005. The proceeds were used to redeem a portion of the $200 million of Detroit Edison 5.05% Senior Notes due in October 2005.

In October 2005, Detroit Edison issued $250 million 2005 Series E 5.7% Senior Notes due 2037. The proceeds were used to pay down Detroit Edison’s short-term borrowings.

NOTE 8 — SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon have entered into revolving credit facilities with similar terms. The five-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but are intended to provide liquidity support for each of the Companies’ commercial paper programs.

In October 2005, DTE Energy, Detroit Edison and MichCon entered into new five-year revolving credit agreements with an aggregate capacity of $925 million. Simultaneously, we amended our existing $975 million, five-year revolving credit facilities to provide for the substitution of some of the participating lenders, as well as modifications to pricing, conditions to borrowing, covenants, events of default and other miscellaneous provisions to conform to the terms of the new agreements. The aggregated availability under these combined facilities is $1.9 billion as shown in the following table:


(in Millions)	DTE Energy		Detroit Edison		MichCon		Total
Five-year unsecured revolving facility, dated October 2005	$	675	$	69	$	181	$	925

Five-year unsecured revolving facility, dated October 2004		525		206		244		975


Aggregate availability	$	1,200	$	275	$	425	$	1,900

Borrowings under the facilities will be available at prevailing short-term interest rates. The agreements require each of the companies to maintain a debt to total capitalization ratio of no more than .65 to l. Should either Detroit Edison or MichCon have delinquent debt obligations of at least $50 million to any creditor, such delinquency will be considered a default under DTE Energy’s credit agreements. DTE Energy, Detroit Edison and MichCon are currently in compliance with these financial covenants.

NOTE 9— DERIVATIVE INSTRUMENTS

Commodity Price Risk

Our Coal-Based Fuels and Biomass businesses generate Section 29 tax credits. We have sold interests in all of our 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, 2006 and 2007 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, 2006 and 2007 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, 2006, and 2007 are less than approximately $56, $58, and $60, per barrel, respectively, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately $56, $58, and $60, per barrel, respectively, the derivatives will yield a payment equal to the excess of the average NYMEX price over these initial strikes, multiplied by the number of barrels covered, up to a maximum price of approximately $69, $73, and $71 per barrel. The agreements do not qualify for hedge accounting. Consequently, changes in the fair value of the options are recorded currently in earnings. We recorded a mark to market gain of $46 million pretax during the 2005 third quarter. For the nine-months ended September 30, 2005, we have recorded mark to market gains of $89 million pretax. 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 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. The monthly average wellhead price per barrel of oil for the first eight months of the year has been approximately $6 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 September 30, 2005, the NYMEX daily closing price of a barrel of oil has averaged approximately $55.61, which due to the uncertainty of the wellhead/NYMEX difference, is comparable to an approximate $49.61 Reference Price (assuming that such price were to continue for the entire year and the difference between wellhead and NYMEX is $6 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. 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. We estimate Detroit Edison future capital expenditures at up to $100 million in 2005 and up to $1.8 billion of additional 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.

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. DTE Enterprises Inc. (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. 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, thereby affect 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 for 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 $40 million at September 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 September 30, 2005 totals $1.6 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 $600 million at September 30, 2005. This estimated amount fluctuates based upon commodity prices (primarily power and gas) and the provisions and maturities of the underlying agreements.

Personal Property Taxes

Detroit Edison, MichCon and other Michigan utilities have 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. After a period of abeyance the MTT issued a scheduling order in a significant number of Detroit Edison and MichCon appeals that set litigation calendars for these cases extending into mid-2006. After an extended period of settlement discussions, a Memorandum of Understanding has been reached with six principals in the litigation that should lead to settlement of all outstanding property tax disputes on a global basis. At an October 7, 2005 Status Conference, the MTT provided verbal approval of the form and terms of the settlement which is conditioned upon a significant percentage of taxing jurisdictions executing the settlement documents by December 9, 2005.

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 nine months of 2005, we purchased $29 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 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 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

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						Nine Months Ended
	September 30						September 30
(in Millions)	2005			2004			2005			2004
Operating Revenues
Electric Utility	$	1,409		$	958		$	3,434		$	2,679
Gas Utility		210			160			1,329			1,165
Non-utility Operations:
Power and Industrial Projects		349			285			1,008			809
Unconventional Gas Production		20			18			53			53
Fuel Transportation and Marketing		277			309			1,024			875

		646			612			2,085			1,737


Corporate & Other		3			11			9			16
Reconciliation & Eliminations		(208	)		(155	)		(547	)		(439	)

Total	$	2,060		$	1,586		$	6,310		$	5,158


	Three Months Ended						Nine Months Ended
	September 30						September 30
(in Millions)	2005			2004			2005			2004
Net Income (Loss)
Electric Utility	$	114		$	62		$	212		$	114
Gas Utility		161			(55	)		123			(22	)
Non-utility Operations:
Power and Industrial Projects		68			49			167			138
Unconventional Gas Production		2			1			3			4
Fuel Transportation and Marketing		(129	)		18			(139	)		78
Corporate & Other		(187	)		22			(178	)		28
Income from Continuing Operations
Utility		275			7			335			92
Non-utility		(59	)		68			31			220
Corporate & Other		(187	)		22			(178	)		28

		29			97			188			340
Discontinued Operations		(25	)		(4	)		(33	)		(22	)

Net Income	$	4		$	93		$	155		$	318

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 September 30, 2005, and the related condensed consolidated statement of operations for the three-month and nine-month periods ended September 30, 2005 and 2004, and the condensed consolidated statement of cash flows for the nine-month periods ended September 30, 2005 and 2004, and condensed consolidated statements of changes in shareholders’ equity and comprehensive income for the nine-month period ended September 30, 2005 and the nine-month periods ended September 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 (August 4, 2005 as to Note 16) (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

November 8, 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.

In June 2005, Detroit Edison was named as one of approximately 21 defendant utility companies in a class action lawsuit filed in the Superior Court of Justice in Ontario, Canada. Detroit Edison has not been served with this lawsuit. The plaintiffs, a class comprised of current and prior residents living in Ontario (and their respective family members and/or heirs), claim that the defendants emitted and continue to emit pollutants that have harmed the plaintiffs. As a result, the plaintiffs are seeking damages (in Canadian dollars) of approximately $49.1 billion for alleged negligence, approximately $4.1 billion per year until the defendants cease emitting pollutants, punitive and exemplary damages of $1 billion, and such other relief as the court deems appropriate. Detroit Edison is not able to predict or assess the outcome of this lawsuit at this time.

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 nine months ended September 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
07/01/05 — 07/31/05		5,500	$	47.80		—	$	700,000,000
08/01/05 — 08/31/05		34,500	$	45.42		—	$	700,000,000
09/01/08 — 09/30/05		—		—		—	$	700,000,000

Total		280,160	$	44.98		—


(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.

Exhibits


Exhibit
Number		Description

(i) Exhibits filed herewith:

15-18		Awareness Letter of Deloitte and Touche LLP

31-19		Chief Executive Officer Section 302 Form 10-Q Certification

31-20		Chief Financial Officer Section 302 Form 10-Q Certification

(ii) Exhibits incorporated by reference:

10-58		Form of DTE Energy Five-Year Credit Agreement, dated as of October 17, 2005, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N.A. as Co-Syndication Agents (Exhibit 10.1 to Form 8-K dated October 17, 2005).

10-59		Form of Second Amended and Restated Five-Year Credit Agreement, dated as of October 17, 2005, by and among DTE Energy, the lenders party thereto, Citibank, N.A., as Administrative Agent, and Barclays Bank PLC and JPMorgan Chase Bank, N.A. as Co-Syndication Agents (Exhibit 10.2 to Form 8-K dated October 17, 2005).

(iii) Exhibits furnished herewith:

32-19		Chief Executive Officer Section 906 Form 10-Q Certification

32-20		Chief Financial Officer Section 906 Form 10-Q Certification


		DTE ENERGY COMPANY

Date: November 8, 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	29

	Consolidated Statement of Financial Position	30

	Consolidated Statement of Cash Flows	32

	Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income	33

	Notes to Consolidated Financial Statements	34

	Report of Independent Registered Public Accounting Firm	51

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26

Item 4.	Controls and Procedures	28

Part II — Other Information

Item 1.	Legal Proceedings	52

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 6.	Exhibits	53

Signature		54
Awareness Letter of Deloitte and 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

Dth/d		Dekatherm per day