DTE Energy (DTE) 8-K Other Events

Exhibit 99.2

DTE ENERGY COMPANY

Management’s Discussion and Analysis

of Financial Condition and Results of Operations

OVERVIEW

DTE Energy is a diversified energy company with approximately $7 billion in revenues in 2004 and approximately $21 billion in assets at December 31, 2004. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales and distribution services throughout southeastern Michigan. Additionally, we have numerous non-utility subsidiaries involved in energy-related businesses predominantly in the Midwest and eastern U.S.

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

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

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

• Gas Cost Recovery and gas final rate orders; and

• Electric Customer Choice program.

Synthetic fuel operations

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

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

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the synfuel production qualifying for Section 29 tax credits and the value of such credits as subsequently discussed. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

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

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

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

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

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

Assuming no synfuel tax credit phase out in future years, we expect cash flow from our synfuel business to total approximately $1.6 billion between 2005 and 2008. The source of synfuel cash flow includes

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cash from operations, asset sales, and the utilization of Section 29 tax credits carried forward from synfuel production prior to 2004.

Gas operations

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

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

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

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

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

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

Electric Customer Choice Program

Since 2002, Michigan residents and businesses have had the option of participating in the electric Customer Choice program. This program is designed to give all customers added choices and the

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opportunity to benefit from lower power costs resulting from competition. However, Detroit Edison’s rates are regulated by the MPSC, while alternative suppliers can charge market-based rates. This regulation has hindered Detroit Edison’s ability to retain customers. In addition, the MPSC has maintained regulated rates for certain groups of customers that exceed the cost of service to those customers. This has resulted in high levels of participation in the electric Customer Choice program by those customers that have the highest rates relative to their cost of service, primarily commercial and industrial businesses. As a result, our margins continue to be affected. To address this issue, we filed a revenue neutral rate restructuring proposal in February 2005 designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, Detroit Edison’s commercial and industrial rates would be lowered in 2006, but residential rates would increase over a five-year period beginning in 2007. The number and mix of customers participating in the electric Customer Choice program could be impacted under the rate restructuring.

The financial impact of electric Customer Choice was mitigated by the issuance of electric interim and final rate orders in 2004 that increased base rates, including the recovery of lost margins and transition charges. The final rate order lost margin recovery was based on a 2004 electric Customer Choice volume estimate of 9,245 gWh. The electric Customer Choice volumes in the first quarter of 2005 were 1,722 gWh as compared to 1,975 gWh in the first quarter of 2004. These lower volumes were offset by an increase in higher margin commercial customer participation in the Choice program resulting in an immaterial effect on margins. With current regulation continuing to hinder our ability to retain certain customers, we will continue working with the MPSC to address issues associated with the electric Customer Choice program including the rate restructuring proposal discussed above.

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

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

RESULTS OF OPERATIONS

Our earnings for the 2005 first quarter were $122 million, or $.70 per diluted share, compared to earnings of $190 million, or $1.11 per diluted share in the 2004 first quarter. As subsequently discussed, the comparability of earnings was impacted by our discontinued business, Southern Missouri Gas Company. Excluding discontinued operations, our earnings from continuing operations for the 2005 first quarter were $122 million, or $.70 per diluted share, compared to earnings of $197 million, or $1.15 per diluted share in the first quarter 2004. The following sections provide a detailed discussion of our segments operating performance and future outlook.

Segment Performance & Outlook– We operate our businesses through five strategic business units (Electric Utility, Gas Utility and Power and Industrial Projects, Unconventional Gas Production, Fuel Transportation and Marketing). The balance of our business consisted of Corporate & Other. This resulted in the following reportable segments.

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	Three Months Ended
(in Millions, except per share data)	March 31
	2005			2004
Net Income (Loss)
Electric Utility	$	55		$	44
Gas Utility		13			71
Non-utility Operations:
Power and Industrial Projects		68			35
Unconventional Gas Production		1			1
Fuel Transportation and Marketing		(10	)		61
Corporate & Other		(5	)		(15	)
Income from Continuing Operations
Utility		68			115
Non-utility		59			97
Corporate & Other		(5	)		(15	)
		122			197
Discontinued Operations		—			(7	)
Net Income	$	122		$	190
Diluted Earnings (Loss) per Share
Total Utility	$	.39		$	.67
Non-utility Operations		.34			.57
Corporate & Other		(.03	)		(.09	)
Income from Continuing Operations		.70			1.15
Discontinued Operations		—			(.04	)
Net Income	$	.70		$	1.11

ELECTRIC UTILITY

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

Factors impacting income:Earnings of $55 million for the 2005 first quarter increased by $11 million as compared to the $44 million earned in the 2004 first quarter. As subsequently discussed, these results primarily reflect higher rates due to the November 2004 MPSC final rate order and lower operation and maintenance expenses, partially offset by increased depreciation and amortization expenses.

	Three Months Ended
	March 31
	2005			2004
(in Millions)
Operating Revenues	$	990		$	886
Fuel and Purchased Power		301			216
Gross Margin		689			670
Operation and Maintenance		321			343
Depreciation and Amortization		150			114
Taxes Other Than Income		69			68
Operating Income		149			145
Other (Income) and Deductions		69			79
Income Tax Provision		25			22
Net Income	$	55		$	44
Operating Income as a Percent of Operating Revenues		15	%		16	%

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Gross marginsincreased $19 million in the 2005 first quarter. Operating revenues increased primarily due to rate increases as a result of the MPSC final rate order issued in November 2004 and the return of customers who in the comparable 2004 period participated in the Customer Choice program. Detroit Edison lost 13% of retail sales in the 2005 first quarter and 15% of such sales in the 2004 first quarter as a result of Customer Choice penetration. Operating revenues and fuel and purchased power costs increased in the 2005 first quarter compared to the 2004 first quarter reflecting a $3.46 per megawatt hour (MWh) (23%) increase in power cost which is a pass-through with the reinstatement of the PSCR. The increase in power supply cost is driven by higher purchase power rates, higher coal prices and increased power purchases due to the outage at our nuclear facility, Fermi 2, which was offline for 14 days during the 2005 first quarter. Pursuant to the MPSC final rate order, transmission expenses previously recorded in operation and maintenance expenses are now reflected in purchased power expenses. The PSCR mechanism provides related revenues for transmission expenses.

	Three Months Ended
	March 31
	2005		2004
Electric Sales
(in Thousands of MWh)
Retail		10,415		10,423
Wholesale and other		2,282		2,186
		12,697		12,609
Internal use and line loss		596		781
		13,293		13,390

Power Generated and Purchased
(in Thousands of MWh)
Power plant generation
Fossil		9,763		9,784
Nuclear		2,053		2,408
		11,816		12,192
Purchased power		1,477		1,198
System output		13,293		13,390
Average Unit Cost ($/MWh)
Generation (1)	$	14.40	$	12.88
Purchased power (2)	$	49.30	$	34.54
Overall average unit cost	$	18.28	$	14.82

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

Electric Deliveries
(in Thousands of MWh)
Residential	4,051	4,069
Commercial	3,364	3,491
Industrial	2,897	2,754
Wholesale	563	556
Other	104	109
	10,979	10,979
Electric Choice	1,722	1,975
Electric Choice – Self Generations*	192	167
Total Electric Deliveries	12,893	13,121

* Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements

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Operation and maintenanceexpense decreased $22 million in the first quarter of 2005. Pursuant to the MPSC final rate order, merger interest is no longer allocated to Detroit Edison. The 2005 period also experienced lower benefit costs and lower uncollectible accounts receivable expense, partially offset by increased power plant outage expense, higher costs for the funding of low-income customer assistance fund and system reliability expenses.

Depreciation and amortizationexpense increased $36 million in the first quarter of 2005. The increase reflects the income effect of recording regulatory assets, which lowers depreciation and amortization expenses. The interim and final electric rate orders in 2004 recover PA 141 costs previously deferred as regulatory assets. As a result, the regulatory asset deferrals totaled $13 million in the first quarter of 2005 compared to $42 million in the first quarter of 2004.

Other income and deductionsdecreased $10 million primarily due to lower interest expense as a result of adjustments due to settlements related to tax audits.

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

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

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

See Note 5 – Regulatory Matters.

GAS UTILITY

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

Factors impacting income:Gas Utility’s earnings decreased $58 million. As subsequently discussed, results reflect the impact of the MPSC’s April 2005 gas cost recovery and final rate orders and an increase in operation and maintenance expenses.

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 is not reflected at DTE Energy since this disallowance was previously reserved at the time of the MCN acquisition in 2001.

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	Three Months Ended
	March 31
	2005			2004
(in Millions)
Operating Revenues	$	852		$	729
Cost of Gas		644			499
Gross Margin		208			230
Operation and Maintenance		123			100
Depreciation and Amortization		26			26
Taxes Other Than Income		13			12
Asset (Gains) and Losses, net		4			(2	)
Operating Income		42			94
Other (Income) and Deductions		14			13
Income Tax Provision		15			10
Net Income	$	13		$	71
Operating Income as a Percent of Operating Revenues		5	%		13	%

Gross marginsdecreased $22 million. 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 in the first quarter of 2005. The quarter was also impacted by increased expenses associated with lost gas, partially offset by higher base rates as a result of the September 2004 interim gas rate order. Gas sales revenues and volumes in both periods reflect the impact of weather. The first quarter of 2005 was 2% colder than the first quarter of 2004. Operating revenues and cost of gas increased significantly in the 2005 first quarter compared to the 2004 first quarter reflecting higher gas prices which are recoverable from customers through the gas cost recovery (GCR) mechanism. The first quarter of 2005 also benefited by $3 million due to contractually driven adjustments to end user transportation contracts.

	Three Months Ended
	March 31
	2005		2004
Gas Markets (in Millions)
Gas sales	$	773	$	655
End user transportation		45		42
		818		697
Intermediate transportation		16		15
Other		18		17
	$	852	$	729
Gas Markets (in Bcf)
Gas sales		84		85
End user transportation		50		50
		134		135
Intermediate transportation		134		174
		268		309

Operation and maintenanceexpense increased $23 million reflecting higher reserves for uncollectible accounts receivable, increased pension and postretirement benefit costs and the adjustment for certain environmental costs resulting from the April 2005 MPSC final rate order. The increase in uncollectible accounts expense reflects higher past due amounts attributable to an increase in gas prices, continued weak economic conditions and a lack of adequate public assistance for low-income customers.

Asset Gains and Losses, netincreased $6 million due to the writeoff of certain computer equipment and related depreciation resulting from the April 2005 final rate order.

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Income taxesincreased $5 million primarily due to higher effective tax rate in the 2005 first quarter as compared to the 2004 first quarter, as a result of higher estimated annual earnings for 2005.

Outlook– Operating results are expected to vary as a result of external factors such as regulatory proceedings, weather and changes in economic conditions. Higher gas prices and economic conditions have resulted in an increase in past due receivables. We believe our allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress in collecting past due receivables would unfavorably affect operating results. Energy assistance programs funded by the federal government and the State of Michigan remain critical to MichCon’s ability to control uncollectible accounts receivable expenses. We are working with the State of Michigan and others to increase the share of funding allocated to our customers to be representative of the number of low-income individuals in our service territory. In the April 2005 final gas rate order, the MPSC adopted MichCon’s proposed tracking mechanism for uncollectible accounts receivable. Each year, MichCon will file an application comparing its actual uncollectible expense to its designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC. See Note 5 – Regulatory Matters.

NON-UTILITY OPERATIONS

Power and Industrial Projects

Power and Industrial Projects is comprised of Coal-Based Fuels, On-Site Energy Projects, non-utility Power Generation, Biomass and PepTec. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. The production of synthetic fuel from all of our synfuel plants and the production of coke from one of our coke batteries generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Non-utility Power Generation owns and operates four gas-fired peaking electric generating plants and manages and operates two additional gas-fired power plants under contract. Additionally, non-utility Power Generation develops, operates and acquires coal and gas-fired generation. Biomass develops, owns and operates landfill recovery systems throughout the United States. PepTec uses proprietary technology to produce high quality coal products from fine coal slurries typically discarded from coal mining operations.

Factors impacting income: Power and Industrial Projects earnings increased $33 million during the 2005 first quarter. As subsequently discussed, the comparability of results is affected by the gains recognized from selling interests in our synfuel plants and gains on synfuel hedges.

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	Three Months Ended
	March 31
(in Millions)	2005			2004
Operating Revenues	$	311		$	255
Operation and Maintenance		320			269
Depreciation and Amortization		25			21
Taxes other than Income		7			2
Asset (Gains) and Losses, Net		(82	)		(48	)
Operating Income		41			11
Other (Income) and Deductions		(4	)		—
Minority Interest		(53	)		(30	)
Income Taxes
Provision		37			14
Section 29 Tax Credits		(7	)		(8	)
		30			6
Net Income	$	68		$	35

Operating revenuesincreased $56 million in the first quarter of 2005, reflecting higher synfuel and coke sales, along with higher market prices for our coke production.

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

Operation and maintenanceexpense increased $51 million primarily reflecting costs associated with the increased levels of synfuel production.

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

	Pre-Tax			After-Tax
(in Millions)	Three Months Ended			Three Months Ended
Components of Synfuel Gains	March 31, 2005			March 31, 2005
Gains associated with fixed payments	$	28		$	18
Gains associated with variable payments		41			27
Deferred gains reserved on variable payments		(41	)		(27	)
Unrealized hedge gains (mark-to-market)
2005 hedge program		50			32
2006 hedge program		4			3
Net synfuel gains recorded in 2005	$	82		$	53

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Minority interestincreased $23 million in 2005, reflecting 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 taxesincreased $24 million in 2005, reflecting higher pretax income.

Outlook- Power and Industrial Projects will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. As a result of executing long-term utility services contracts in 2004, we expect solid earnings from our on-site energy business in 2005. We expect to continue to grow our Biomass and PepTec businesses. Biomass, in conjunction with the Coal Services business, has entered the coal mine methane business. We purchased coal mine methane assets in Illinois at the end of 2004, and expect to reconfigure equipment and restart operations by mid-2005. We believe a substantial market could exist for the use of PepTec’s technology. We continue to modify and test this technology.

Unconventional Gas Production

Unconventional Gas Production is primarily engaged in natural gas exploration, development and production. Our Unconventional Gas Production business produces gas from proven reserves in northern Michigan and sells the gas to the Fuel Transportation and Marketing segment. The assets of this businesses are well integrated with our other DTE Energy entities.

Factors impacting income: Unconventional Gas Production earnings remained consistent with 2004.

	Three Months Ended
	March 31
	2005		2004
(in Millions)
Operating Revenues	$	16	$	17
Operation and Maintenance		6		7
Depreciation and Amortization		4		4
Taxes Other Than Income		2		2
Operating Income		4		4
Other (Income) and Deductions		2		2
Income Tax Provision		1		1
Net Income	$	1	$	1

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

Fuel Transportation and Marketing

Fuel Transportation and Marketing consists of DTE Energy Trading and CoEnergy, Coal Services and Pipelines, Processing & Gas Storage business. DTE Energy Trading focuses on physical power marketing and structured transactions, as well as the enhancement of returns from DTE Energy’s power plants. CoEnergy focuses on physical gas marketing and the optimization of DTE Energy’s owned and contracted natural gas pipelines and gas storage capacity. To this end, both companies enter into derivative financial instruments as part of their marketing and hedging strategies, including forwards,

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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 & Storage has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing facilities and a natural gas storage field, as well as lease rights to another natural gas storage field. The assets of these businesses are well integrated with other DTE Energy entities.

Factors impacting income: Fuel Transportation and Marketing earnings decreased $71 million in the first quarter of 2005, primarily as a result of a $74 million one-time pre-tax gain from a contract modification/termination recorded in 2004 and a 2005 mark to market loss on derivative contracts used to economically hedge our gas in storage.

	Three Months Ended
	March 31
	2005			2004
(in Millions)
Operating Revenues	$	316		$	305
Fuel, Purchased Power and Gas		173			134
Operation and Maintenance		157			75
Depreciation and Amortization		1			2
Taxes Other Than Income		1			1
Operating Income (Loss)		(16	)		93
Other (Income) and Deductions		(1	)		(1	)
Income Tax Provision (Benefit)		(5	)		33
Net Income (Loss)	$	(10	)	$	61

Operating revenuesincreased $11 million in the first quarter of 2005. Coal Services experienced increased revenues due to increased business volume, while our trading operations experienced decreased revenue due to an adjustment in 2004 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 gasincreased $39 million in the first quarter of 2005. During the first quarter of 2005, expenses were negatively impacted by the economically favorable decision to delay previously planned withdrawals from gas storage due to a decrease in the current price for gas and an increase in the forward price for natural gas. We anticipate the financial impact of this timing difference will reverse when the gas is withdrawn from storage in the next storage cycle. In 2004, our trading operation recorded a gas inventory adjustment that increased expense by $12 million related to the termination of a long-term gas exchange (storage) agreement with an interstate pipeline company. 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 (Note 4).

Operation and maintenance expensesincreased $82 million in the first quarter of 2005 primarily as a result of increased coal purchases due to increased sales at Coal Services.

Income Tax Provisiondecreased $38 million in the first quarter of 2005 due to decreased operating income.

Outlook– We expect to continue to grow our Coal Services and Fuel Transportation and Marketing business where we will seek to manage its business in a manner consistent with, and complementary to, the growth of our other business segments. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This

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capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to add value.

Significant portions of the Fuel Transportation and Marketing portfolio are economically hedged. The portfolio includes financial instruments and gas inventory, as well as owned and contracted natural gas pipelines and storage assets. The financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not considered derivatives for accounting purposes. As a result, Fuel Transportation and Marketing will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which runs annually from April of one year to March of the next year. Our strategy is to economically hedge the price risk of all gas purchases for storage with sales in the over-the-counter (forwards) and futures markets. Current accounting rules require the marking to market of forward sales and futures, but do not allow for the marking to market of the related gas inventory. This results in gains and losses that are recognized in different interim and annual accounting periods. We anticipate the financial impact of this timing difference will reverse by the end of each storage cycle. See “Fair Value of Contracts” section that follows.

We anticipate further expansion of our storage facilities and Vector pipeline to take advantage of available growth opportunities. We are also seeking to secure markets for our 10.5% interest in the proposed Millennium Pipeline.

CORPORATE & OTHER

Corporate & Other includes various corporate support functions such as accounting, legal and information technology. As these functions essentially support the entire Company, their costs are fully allocated to the various segments based on services utilized and therefore the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt and investments, including assets held for sale and in emerging energy technologies. These investments include DTE Energy Technologies, which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations.

Factors impacting income: Corporate & Other’s losses decreased $10 million in the 2005 first quarter. The first quarter of 2005 included favorable tax adjustments due to settlements related to tax audits. Additionally, results reflect adjustments in both years to normalize the effective income tax rate. There was a $6 million favorable adjustment in the 2005 first quarter compared to a $6 million unfavorable adjustment in the 2004 first quarter. Corporate & Other records necessary adjustments in order that the consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. The favorability related to income taxes was partially offset by non-allocated merger interest pursuant to the November 2004 MPSC final electric rate order.

DISCONTINUED OPERATIONS

Southern Missouri Gas Company (SMGC)- We own SMGC, a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In 2004, management approved the marketing of SMGC for sale. Under U.S. generally accepted accounting principles, we classified SMGC as a discontinued operation in 2004 and recognized a net of tax impairment loss of approximately $7 million, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Regulatory approval was received in April 2005 and it is anticipated that the transaction will close in the second quarter of 2005.

See Note 3 for further discussion.

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CAPITAL RESOURCES AND LIQUIDITY

	Three Months Ended
	March 31
(in Millions)	2005			2004
Cash and Cash Equivalents
Cash Flow From (Used For):
Operating activities:
Net income	$	122		$	190
Depreciation, depletion and amortization		208			167
Deferred income taxes		51			113
Gain on sale of synfuel and other assets, net		(78	)		(52	)
Working capital and other		110			(138	)
		413			280
Investing activities:
Plant and equipment expenditures – utility		(172	)		(161	)
Plant and equipment expenditures – non-utility		(26	)		(18	)
Proceeds from sale of synfuel and other assets		65			57
Restricted cash and other investments		21			28
		(112	)		(94	)
Financing activities:
Issuance of long-term debt and common stock		395			11
Redemption of long-term debt		(628	)		(232	)
Short-term borrowings, net		36			134
Repurchase of common stock		(9	)		—
Dividends on common stock and other		(91	)		(89	)
		(297	)		(176	)
Net Increase in Cash and Cash Equivalents	$	4		$	10

Operating Activities

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

Although DTE Energy’s overall earnings were down $68 million or 36% in the 2005 first quarter, cash from operations totaling $413 million, was up $133 million or 48% from the comparable 2004 period. The operating cash flow comparison reflects a decrease of $248 million in working capital and other requirements, partially offset by a decrease of $115 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains). Working capital requirements

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during the 2004 period were higher due primarily to income tax payments made as a result of certain 2003 transactions, including the divestiture of ITC.

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

Assuming no synfuel tax credit phase out in this or future years, we expect cash flow from our synfuel business to total approximately $1.6 billion between 2005 and 2008. We have protected from risk of loss approximately 70%-75% of the expected 2005 synfuel cash flow of approximately $420 million through the purchase of option contracts, the use of prior year tax credits and cash payments received to date. Assuming no synfuel tax credit phase-out in 2005, we have protected from risk of loss approximately 55% of the expected 2006 synfuel cash flow of approximately $490 million through the purchase of option contracts and the use of prior year tax credits. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use this cash to reduce parent company debt, to continue to pursue growth investments that meet our strict risk-return and value creation criteria and to potentially repurchase common stock if adequate investment opportunities are not available. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios to improve our current credit ratings and outlook, and to more than replace the value of synfuels.

Investing Activities

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

Net cash outflows for investing activities increased $18 million in the 2005 first quarter as compared to the same 2004 period primarily due to fewer asset sales in 2005. Also affecting the comparison was higher utility and non-utility plant expenditures in the 2005 first quarter offset by higher synfuel proceeds.

Capital expenditures during the 2005 first quarter were $198 million. This represents a $19 million increase from the comparable 2004 period and was driven by spending on our electric distribution infrastructure and on DTE2, our Company-wide initiative to improve existing processes and implement new core information systems.

Outlook— Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2005 of up to $1.1 billion. The approximately $200 million increase over 2004 is primarily due to environmental spending requirements and our DTE2 investment, mitigated by lower base spending within our non-utility businesses. As previously mentioned, our strategy is to re-deploy cash generated by our synfuel monetization activities. 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

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blend as to fixed and variable interest rates and maturities. We continually evaluate our leverage target, which is currently 50% or lower, to ensure it is consistent with our objective to have a strong investment grade debt rating.

Net cash used for financing activities increased $121 million during the 2005 first quarter, compared to the same 2004 period, due mostly to a reduction in short-term debt issuances.

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

Additionally, Detroit Edison redeemed $176 million of other long-term notes during the first quarter 2005. See Note 7.

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

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

As a result of the non-recurring accounting adjustments that were required due to the MPSC gas rate orders issued on April 28, 2005, MichCon did not meet the EBITDA to interest ratio at March 31, 2005. The lenders have agreed to amend the credit facilities to exclude the EBITDA to interest ratio for the first quarter of 2005. If lenders had not amended the credit facility, MichCon’s access to the commercial paper markets would be limited. At March 31, 2005 and the date of the amendments, MichCon does not have any indebtedness under the credit facilities or any commercial paper outstanding.

We plan to seek rehearing of the MPSC orders to improve the resulting underlying cash flows at MichCon. If unsuccessful in rehearing, MichCon may file a follow on rate case in 2005. In addition, we may seek further amendments to the EBITDA to interest ratio for future periods. If MichCon experiences diminished ability to access the short-term and/or long-term capital markets, it would have to seek additional sources of liquidity. This may have a material negative impact on MichCon’s financial position and significantly harm the operation of that business. We believe that we will have sufficient internal and external capital resources to manage liquidity and to fund anticipated capital requirements.

CRITICAL ACCOUNTING POLICIES

Goodwill

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

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As of March 31, 2005, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units, with approximately $772 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). Based on our 2004 annual goodwill impairment test, we determined that the fair value of our reporting units exceed their carrying value and no impairment of goodwill existed.

We have received the MPSC final order in the gas rate case in late April 2005, but have yet to fully evaluate 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 approximates the carrying value and we expect to complete this analysis in the second quarter of 2005, and any significant changes in our valuation assumptions could result in an impairment of the carrying value of goodwill for this reporting unit.

ENVIRONMENTAL MATTERS

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

DTE2

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

NEW ACCOUNTING PRONOUNCEMENTS

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

FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and we believe provide enhanced transparency of the derivative activities and position of our Fuel Transportation and Marketing segment 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

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financial statements as Assets or Liabilities from Risk Management and Trading Activity, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the fair value of the contract, a practice known as mark to market (MTM) accounting.

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

Contracts we typically classify as derivative instruments are power and gas 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. A substantial portion of the price risk associated with these reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Liabilities from Risk Management and Trading with an offset in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and the changes therein.

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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
	Fuel Transportation and Marketing												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		1			3			32			36			11			47
Changes in fair value recorded to income		(7	)		(7	)		(46	)		(60	)		53			(7	)
Amortization of option premiums		—			—			—			—			—			—
Amounts recorded to unrealized income		(6	)		(4	)		(14	)		(24	)		64			40
Amounts recorded in OCI		—			(22	)		—			(22	)		(55	)		(77	)
Option premiums paid and other		—			—			9			9			17			26
MTM at March 31, 2005	$	(3	)	$	(3	)	$	(103	)	$	(109	)	$	(74	)	$	(183	)

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 March 31, 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
	Fuel Transportation and Marketing															Non-			Total
	Proprietary			Structured			Economic									Trading			Assets
(in Millions)	Trading			Contracts			Hedges			Eliminations			Totals			Activities			(Liabilities)
Current assets	$	67		$	136		$	187		$	(44	)	$	346		$	77		$	423
Noncurrent assets		18			56			93			(19	)		148			44			192
Total MTM assets		85			192			280			(63	)		494			121			615
Current liabilities		(70	)		(137	)		(268	)		41			(434	)		(103	)		(537	)
Noncurrent liabilities		(18	)		(58	)		(115	)		22			(169	)		(92	)		(261	)
Total MTM liabilities		(88	)		(195	)		(383	)		63			(603	)		(195	)		(798	)
Total MTM net assets (liabilities)	$	(3	)	$	(3	)	$	(103	)	$	—		$	(109	)	$	(74	)	$	(183	)

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.

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The table below shows the maturity of our MTM positions:

												Total
(in Millions)										2008 and		Fair
Source of Fair Value	2005			2006			2007			Beyond		Value
Proprietary Trading	$	(4	)	$	(6	)	$	7		$	—	$	(3	)
Structured Contracts		6			(5	)		(5	)		1		(3	)
Economic Hedges		(54	)		(21	)		(28	)		—		(103	)
Total Fuel Transportation and Marketing		(52	)		(32	)		(26	)		1		(109	)
Other Non-Trading Activities		(2	)		(57	)		(15	)		—		(74	)
Total	$	(54	)	$	(89	)	$	(41	)	$	1	$	(183	)

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

Our synfuel 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 and biomass operations are subject to phase out if domestic crude oil prices reach certain levels. We have entered into a series of derivative contracts for 2005 and 2006 to economically hedge the impact of oil prices on our synfuel cash flow.

Credit Risk

Bankruptcies

We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries. A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered at risk of probable loss. We believe our accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

Other

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

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we use treasury locks and interest rate swap agreements. Our exposure

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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 March 31, 2005, the Company had a floating rate debt to total debt ratio of approximately 11% (excluding securitized debt).

Foreign Currency Risk

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

Summary of Sensitivity Analysis

We performed a sensitivity analysis to calculate the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at March 31, 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	$	(20	)	$	20		Commodity contracts
Power Contracts	$	(32	)	$	35		Commodity contracts
Oil Contracts	$	60		$	(46	)	Commodity options
Interest Rate Risk	$	(313	)	$	329		Long-term debt
Foreign Currency Risk	$	—		$	—		Forward contracts

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